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| number = ML062300330
| number = ML062300330
| issue date = 08/18/2006
| issue date = 08/18/2006
| title = 2006/08/18-Safety Evaluation Report with Open Items Related to the License Renewal of Oyster Creek Generating Station
| title = Safety Evaluation Report with Open Items Related to the License Renewal of Oyster Creek Generating Station
| author name = Ashley D J
| author name = Ashley D
| author affiliation = NRC/NRR/ADRO/DLR/RLRA
| author affiliation = NRC/NRR/ADRO/DLR/RLRA
| addressee name = Rausch T S
| addressee name = Rausch T
| addressee affiliation = AmerGen Energy Co, LLC
| addressee affiliation = AmerGen Energy Co, LLC
| docket = 05000219
| docket = 05000219
| license number = DPR-016
| license number = DPR-016
| contact person = Ashley D J, NRR/DLR/RLRA, 415-3191
| contact person = Ashley D, NRR/DLR/RLRA, 415-3191
| case reference number = %dam200612
| case reference number = %dam200612
| document type = Safety Evaluation Report
| document type = Safety Evaluation Report
Line 18: Line 18:


=Text=
=Text=
{{#Wiki_filter:Safety Evaluation Report With Open Items Related to the License Renewal of Oyster Creek Generating Station Docket No. 50-219AmerGen Energy Company, LLC U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation August 2006 THIS PAGE IS INTENTIONALLY LEFT BLANK.
{{#Wiki_filter:}}
iii ABSTRACT This safety evaluation report (SER) documents the technical review of the Oyster Creek Generating Station (OCGS) license renewal application (LRA) by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). By letter dated July 22, 2005, AmerGen
 
Energy Company, LLC submitted the LRA for OCGS in accordance with Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54). AmerGen Energy Company, LLC requests renewal of the operating license for OCGS (Facility Operating License Number DPR-16), for a
 
period of 20 years beyond the current expiration date of midnight April 9, 2009.
OCGS is located in Lacey Township, Ocean County, New Jersey, approximately two miles south of the community of Forked River, two miles inland from the shore of Barnegat Bay, and
 
nine miles south of Toms River, New Jersey. The NRC issued the OCGS construction permit on
 
December 15, 1964, and the OCGS operating license on July 2, 1991. OCGS is a single unit
 
facility with a single-cycle, forced-circulation boiling water reactor (BWR)-2 and a Mark 1
 
containment. The nuclear steam supply system was furnished by General Electric and the balance of the plant was originally designed and constructed by Burns & Roe. OCGS licensed
 
power output is 1930 megawatt thermal with a gross electrical output of approximately
 
619 megawatt electric.
This SER presents the status of the staff's review of information submitted through July 10, 2006, the cutoff date for consideration in the SER.
The staff identified open items that must be resolved before a final determination on the application. SER Section 1.5 summarizes
 
these items. The staff will present its final conclusion on the review of the OCGS LRA in its
 
update to this SER.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
v TABLE OF CONTENTSAbstract...................................................................iiiTable of Contents............................................................vAbbreviations..............................................................xv
 
1  Introduction and General Discussion.........................................1-1 1.1  Introduction.....................................................1-1
 
===1.2 License===
Renewal Background.......................................1-21.2.1  Safety Review............................................1-3
 
====1.2.2 Environmental====
Review.....................................1-41.3  Principal Review Matters...........................................1-5
 
===1.4 Interim===
Staff Guidance.............................................1-6
 
===1.5 Summary===
of Open Items...........................................1-71.6  Summary of Confirmatory Items....................................1-15
 
===1.7 Summary===
of Proposed License Conditions............................1-15 2  Structures and Components Subject to Aging Management Review................2-16
 
===2.1 Scoping===
and Screening Methodology................................2-17 2.1.1  Introduction.............................................2-172.1.2  Summary of Technical Information in the Application.............2-17
 
====2.1.3 Scoping====
and Screening Program Review......................2-18 2.1.3.1  Implementation Procedures and Documentation Sources Used for Scoping and Screening......................2-192.1.3.2  Quality Controls Applied to LRA Development...........2-22 2.1.3.3  Training........................................2-22 2.1.3.4  Conclusion of Scoping and Screening Program Review ...2-232.1.4  Plant Systems, Structures, and Components Scoping Methodology.2-232.1.4.1  Application of the Scoping Criteria in 10 CFR 54.4(a)(1)...2-23 2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2)...2-26 2.1.4.3  Application of the Scoping Criteria in 10 CFR 54.4(a)(3)...2-31
 
2.1.4.4  Plant-Level Scoping of Systems and Structures.........2-35 2.1.4.5  Mechanical Component Scoping.....................2-37 2.1.4.6  Structural Component Scoping......................2-38 2.1.4.7  Electrical Component Scoping.......................2-39 2.1.4.8  Conclusion for Scoping Methodology..................2-40
 
====2.1.5 Screening====
Methodology...................................2-40 2.1.5.1  General Screening Methodology.....................2-40 2.1.5.2  Mechanical Component Screening...................2-42 2.1.5.3  Structural Component Screening.....................2-43 2.1.5.4  Electrical Component Screening.....................2-44 2.1.5.5  Conclusion for Screening Methodology................2-452.1.6  Conclusion for Scoping and Screening Methodology ............2-462.2  Plant-Level Scoping Results.......................................2-46 2.2.1  Introduction.............................................2-462.2.2  Summary of Technical Information in the Application.............2-46
 
====2.2.3 Staff====
Evaluation..........................................2-46 vi2.2.4  Conclusion.............................................2-472.3  Scoping and Screening Results: Mechanical..........................2-47
 
====2.3.1 Reactor====
Vessel, Internals, and Reactor Coolant System..........2-492.3.1.1  Control Rods....................................2-49 2.3.1.2  Fuel Assemblies..................................2-50 2.3.1.3  Isolation Condenser System........................2-522.3.1.4  Nuclear Boiler Instrumentation.......................2-53
 
2.3.1.5  Reactor Head Cooling System.......................2-542.3.1.6  Reactor Internals.................................2-56 2.3.1.7  Reactor Pressure Vessel...........................2-58 2.3.1.8  Reactor Recirculation System.......................2-602.3.2  Engineered Safety Features Systems........................2-622.3.2.1  Automatic Depressurization System..................2-62 2.3.2.2  Containment Spray System.........................2-63 2.3.2.3  Core Spray System...............................2-65
 
2.3.2.4  Standby Gas Treatment System (SGTS)...............2-662.3.3  Auxiliary Systems........................................2-682.3.3.1  "C" Battery Room Heating & Ventilation................2-69
 
2.3.3.2  4160V Switchgear Room Ventilation..................2-70 2.3.3.3  480V Switchgear Room Ventilation...................2-71 2.3.3.4  Battery and MG Set Room Ventilation.................2-732.3.3.5  Chlorination System...............................2-74 2.3.3.6  Circulating Water System...........................2-75 2.3.3.7  Containment Inerting System........................2-77 2.3.3.8  Containment Vacuum Breakers......................2-78 2.3.3.9  Control Rod Drive System..........................2-79 2.3.3.10  Control Room HVAC.............................2-81
 
2.3.3.11  Cranes and Hoists...............................2-82 2.3.3.12  Drywell Floor and Equipment Drains.................2-84 2.3.3.13  Emergency Diesel Generator and Auxiliary System.....2-85 2.3.3.14  Emergency Service Water System...................2-872.3.3.15  Fire Protection System............................2-89
 
2.3.3.16  Fuel Storage and Handling Equipment...............2-95 2.3.3.17  Hardened Vent System...........................2-962.3.3.18  Heating & Process Steam System...................2-97
 
2.3.3.19  Hydrogen & Oxygen Monitoring System..............2-992.3.3.20  Instrument (Control) Air System....................2-100
 
2.3.3.21  Main Fuel Oil Storage & Transfer System............2-102 2.3.3.22  Miscellaneous Floor and Equipment Drain System.....2-103 2.3.3.23  Nitrogen Supply System..........................2-1052.3.3.24  Noble Metals Monitoring System...................2-107
 
2.3.3.25  Post-Accident Sampling System...................2-1092.3.3.26  Process Sampling System........................2-110 2.3.3.27  Radiation Monitoring System......................2-112
 
2.3.3.28  Radwaste Area Heating and Ventilation System.......2-1142.3.3.29  Reactor Building Closed Cooling Water System.......2-115
 
2.3.3.30  Reactor Building Floor and Equipment Drains.........2-1172.3.3.31  Reactor Building Ventilation System................2-118
 
2.3.3.32  Reactor Water Cleanup System....................2-120 vii 2.3.3.33  Roof Drains and Overboard Discharge..............2-1222.3.3.34  Sanitary Waste System..........................2-124 2.3.3.35  Service Water System...........................2-125 2.3.3.36  Shutdown Cooling System........................2-127
 
2.3.3.37  Spent Fuel Pool Cooling System...................2-1292.3.3.38  Standby Liquid Control System (Liquid Poison System).2-131
 
2.3.3.39  Traveling In-Core Probe System...................2-1332.3.3.40  Turbine Building Closed Cooling Water System.......2-134 2.3.3.41  Water Treatment & Distribution System..............2-1362.3.4  Steam and Power Conversion Systems......................2-137 2.3.4.1  Condensate System..............................2-138 2.3.4.2  Condensate Transfer System......................2-139 2.3.4.3  Feedwater System...............................2-140 2.3.4.4  Main Condenser.................................2-142 2.3.4.5  Main Generator and Auxiliary System................2-1442.3.4.6  Main Steam System..............................2-145
 
2.3.4.7  Main Turbine and Auxiliary System..................2-147
 
===2.4 Scoping===
and Screening Results: Structures..........................2-1482.4.1  Primary Containment....................................2-1492.4.1.1  Summary of Technical Information in the Application....2-149 2.4.1.2  Staff Evaluation.................................2-151 2.4.1.3  Conclusion.....................................2-1542.4.2  Reactor Building........................................2-1542.4.2.1  Summary of Technical Information in the Application....2-154 2.4.2.2  Staff Evaluation.................................2-156 2.4.2.3  Conclusion.....................................2-1562.4.3  Chlorination Facility......................................2-1572.4.3.1  Summary of Technical Information in the Application....2-157 2.4.3.2  Staff Evaluation.................................2-157 2.4.3.3  Conclusion.....................................2-1582.4.4  Condensate Transfer Building.............................2-1582.4.4.1  Summary of Technical Information in the Application....2-158 2.4.4.2  Staff Evaluation.................................2-158 2.4.4.3  Conclusion.....................................2-1592.4.5  Dilution Structure.......................................2-1592.4.5.1  Summary of Technical Information in the Application....2-159 2.4.5.2  Staff Evaluation.................................2-160 2.4.5.3  Conclusion.....................................2-1602.4.6  Emergency Diesel Generator Building.......................2-1602.4.6.1  Summary of Technical Information in the Application....2-160 2.4.6.2  Staff Evaluation.................................2-161 2.4.6.3  Conclusion.....................................2-161
 
====2.4.7 Exhaust====
Tunnel.........................................2-1622.4.7.1  Summary of Technical Information in the Application....2-162 2.4.7.2  Staff Evaluation.................................2-163 2.4.7.3  Conclusion.....................................2-1632.4.8  Fire Pond Dam.........................................2-1632.4.8.1  Summary of Technical Information in the Application....2-163 2.4.8.2  Staff Evaluation.................................2-164 viii2.4.8.3  Conclusion.....................................2-164 2.4.9  Fire Pumphouses.......................................2-1652.4.9.1  Summary of Technical Information in the Application....2-165 2.4.9.2  Staff Evaluation.................................2-166 2.4.9.3  Conclusion.....................................2-1672.4.10  Heating Boiler House...................................2-1672.4.10.1  Summary of Technical Information in the Application...2-167 2.4.10.2  Staff Evaluation................................2-168 2.4.10.3  Conclusion....................................2-1682.4.11  Intake Structure and Canal (Ultimate Heat Sink)..............2-1682.4.11.1  Summary of Technical Information in the Application...2-168 2.4.11.2  Staff Evaluation................................2-169 2.4.11.3  Conclusion....................................2-169 2.4.12  Miscellaneous Yard Structures............................2-1702.4.12.1  Summary of Technical Information in the Application...2-170 2.4.12.2  Staff Evaluation................................2-171 2.4.12.3  Conclusion....................................2-1712.4.13  New Radwaste Building.................................2-1712.4.13.1  Summary of Technical Information in the Application...2-171 2.4.13.2  Staff Evaluation...............................2-1722.4.13.3  Conclusion....................................2-1722.4.14  Office Building.........................................2-1732.4.14.1  Summary of Technical Information in the Application...2-173 2.4.14.2  Staff Evaluation................................2-173 2.4.14.3  Conclusion....................................2-1742.4.15  Oyster Creek Substation.................................2-1742.4.15.1  Summary of Technical Information in the Application...2-174 2.4.15.2  Staff Evaluation................................2-175 2.4.15.3  Conclusion....................................2-1752.4.16  Turbine Building.......................................2-1752.4.16.1  Summary of Technical Information in the Application...2-175 2.4.16.2  Staff Evaluation................................2-177 2.4.16.3  Conclusion....................................2-1772.4.17  Ventilation Stack.......................................2-1772.4.17.1  Summary of Technical Information in the Application...2-177 2.4.17.2  Staff Evaluation................................2-178 2.4.17.3  Conclusion....................................2-178 2.4.18  Component Supports Commodity Group....................2-1792.4.18.1  Summary of Technical Information in the Application...2-179 2.4.18.2  Staff Evaluation................................2-180 2.4.18.3  Conclusion....................................2-181 2.4.19  Piping and Component Insulation Commodity Group...........2-1812.4.19.1  Summary of Technical Information in the Application...2-181 2.4.19.2  Staff Evaluation................................2-181 2.4.19.3  Conclusion....................................2-1822.5  Scoping and Screening Results: Electrical Components.................2-1822.5.1  Summary of Technical Information in the Application............2-1832.5.1.1  Electrical Systems...............................2-183
 
2.5.1.2  Electrical Commodity Groups.......................2-187 ix2.5.2  Staff Evaluation.........................................2-189
 
===2.6 Conclusion===
for Scoping and Screening..............................2-1933  Aging Management Review Results..........................................3-13.0.1  Format of the License Renewal Application...........................3-23.0.1.1  Overview of Table 1................................3-33.0.1.2  Overview of Table 2................................3-33.0.2  Staff's Review Process.....................................3-43.0.2.1  Review of AMPs...................................3-5 3.0.2.2  Review of AMR Results.............................3-6
 
3.0.2.3  UFSAR Supplement................................3-6 3.0.2.4  Documentation and Documents Reviewed..............3-63.0.3  Aging Management Programs...............................3-63.0.3.1  AMPs That Are Consistent with the GALL Report........3-12 3.0.3.2  AMPs That Are Consistent with the GALL Report with Exceptions or Enhancements........................3-39 3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in theGALL Report....................................3-199
 
====3.0.4 Quality====
Assurance Program Attributes Integral to Aging ManagementPrograms.............................................3-236 3.0.4.1  Summary of Technical Information in Application.......3-236 3.0.4.2  Staff Evaluation.................................3-236 3.0.4.3  Conclusion.....................................3-238
 
===3.1 Aging===
Management of Reactor Vessel, Internals, and Reactor Coolant System....................................................3-238
 
====3.1.1 Summary====
of Technical Information in the Application............3-238
 
====3.1.2 Staff====
Evaluation.........................................3-2383.1.2.1  AMR Results That Are Consistent with the GALL Report.3-247
 
3.1.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-255 3.1.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-2763.1.3  Conclusion............................................3-282
 
===3.2 Aging===
Management of Engineered Safety Features....................3-2823.2.1  Summary of Technical Information in the Application............3-283
 
====3.2.2 Staff====
Evaluation.........................................3-2833.2.2.1  AMR Results That Are Consistent with the GALL Report.3-292
 
3.2.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation Is Recommended.........3-295 3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-3043.2.3  Conclusion............................................3-3093.3  Aging Management of Auxiliary Systems............................3-3093.3.1  Summary of Technical Information in the Application............3-310
 
====3.3.2 Staff====
Evaluation.........................................3-3103.3.2.1  AMR Results That Are Consistent with the GALL Report.3-328 3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-335 x 3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-3603.3.3  Conclusion............................................3-369
 
===3.4 Aging===
Management of Steam and Power Conversion System............3-3693.4.1  Summary of Technical Information in the Application............3-369
 
====3.4.2 Staff====
Evaluation.........................................3-3703.4.2.1  AMR Results That Are Consistent with the GALL Report.3-379
 
3.4.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-381 3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-3903.4.3  Conclusion............................................3-401
 
===3.5 Aging===
Management of Containment, Structures, Component Supports, and Piping and Component Insulation............................3-4013.5.1  Summary of Technical Information in the Application............3-401
 
====3.5.2 Staff====
Evaluation.........................................3-4023.5.2.1  AMR Results That Are Consistent with the GALL Report.3-416
 
3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-418 3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-4413.5.3  Conclusion......................................3-4583.6  Aging Management of Electrical Components.........................3-4593.6.1  Summary of Technical Information in the Application............3-459
 
====3.6.2 Staff====
Evaluation.........................................3-4593.6.2.1  AMR Results That Are Consistent with the GALL Report.3-463
 
3.6.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-465 3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-4733.6.3  Conclusion............................................3-480
 
===3.7 Aging===
Management of Forked River Combustion Turbines (FRCT), Radio Communications System, and Meteorological Tower (Met Tower) Electrical, Mechanical, and Structural Systems and Components...............3-4813.7.1  Summary of Technical Information in the Application............3-4813.7.1.1  Electrical Components............................3-4813.7.1.2  Mechanical Components..........................3-4813.7.1.3  Structural Components...........................3-4823.7.2  Staff Evaluation.........................................3-4823.7.2.1  AMR Results That Are Consistent with The GALL Report.3-495
 
3.7.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended.........3-497 3.7.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report......................3-5113.7.3 Conclusion.............................................3-5203.8  Conclusion for Aging Management Review Results....................3-521 xi4  Time-Limited Aging Analyses...............................................4-1
 
===4.1 Identification===
of Time-Limited Aging Analyses...........................4-14.1.1  Summary of Technical Information in the Application..............4-1
 
====4.1.2 Staff====
Evaluation...........................................4-2 4.1.3  Conclusion..............................................4-34.2  Neutron Embrittlement of the Reactor Vessel and Internals................4-3
 
====4.2.1 Reactor====
Vessel Materials Upper-Shelf Energy Reduction Due to Neutron Embrittlement...............................4-54.2.1.1  Summary of Technical Information in the Application......4-5 4.2.1.2  Staff Evaluation...................................4-6
 
4.2.1.3  UFSAR Supplement................................4-84.2.1.4  Conclusion.......................................4-8
 
====4.2.2 Adjusted====
Reference Temperature for Reactor Vessel Materials due to Neutron Embrittlement.........................4-84.2.2.1  Summary of Technical Information in the Application......4-8 4.2.2.2  Staff Evaluation...................................4-9
 
4.2.2.3  UFSAR Supplement...............................4-104.2.2.4  Conclusion......................................4-10
 
====4.2.3 Reactor====
Vessel Thermal Limit Analyses: Operating Pressure -Temperature Limits......................................4-10 4.2.3.1  Summary of Technical Information in the Application.....4-10 4.2.3.2  Staff Evaluation..................................4-11
 
4.2.3.3  UFSAR Supplement...............................4-114.2.3.4  Conclusion......................................4-114.2.4  Reactor Vessel Circumferential Weld Examination Relief.........4-114.2.4.1  Summary of Technical Information in the Application.....4-11 4.2.4.2  Staff Evaluation..................................4-12
 
4.2.4.3  UFSAR Supplement...............................4-144.2.4.4  Conclusion......................................4-144.2.5  Reactor Vessel Axial Weld Examination Relief..................4-144.2.5.1  Summary of Technical Information in the Application.....4-14 4.2.5.2  Staff Evaluation..................................4-16
 
4.2.5.3  UFSAR Supplement...............................4-164.2.5.4  Conclusion......................................4-17 4.2.6  Core Reflood Thermal Shock Analysis........................4-174.2.6.1  Summary of Technical Information in the Application.....4-17 4.2.6.2  Staff Evaluation..................................4-17
 
4.2.6.3  UFSAR Supplement...............................4-174.2.6.4  Conclusion......................................4-174.2.7  Reactor Internals Components..............................4-174.2.7.1  Summary of Technical Information in the Application.....4-17 4.2.7.2  Staff Evaluation..................................4-18
 
4.2.7.3  UFSAR Supplement...............................4-204.2.7.4  Conclusion......................................4-20
 
===4.3 Metal===
Fatigue of the Reactor Vessel, Internals, and Reactor Coolant Pressure Boundary Piping and Components................................4-20
 
====4.3.1 Reactor====
Vessel Fatigue Analyses............................4-204.3.1.1  Summary of Technical Information in the Application.....4-20 4.3.1.2  Staff Evaluation..................................4-21 xii 4.3.1.3  UFSAR Supplement...............................4-234.3.1.4  Conclusion......................................4-234.3.2  Fatigue Analysis of Reactor Vessel Internals...................4-23 4.3.2.1  Low-Cycle Thermal and Flow-Induced Vibration Fatigue Analysis of the Core Shroud and Repair Hardware........4-23
 
====4.3.3 Reactor====
Coolant Pressure Boundary Piping and Component FatigueAnalysis...............................................4-24
 
4.3.3.1  Reactor Coolant Pressure Boundary Piping and Components.....................................4-24 4.3.3.2  Fatigue Analysis of the Isolation Condenser............4-26
 
====4.3.4 Effects====
of Reactor Coolant Environment on Fatigue Life of Components and Piping (Generic Safety Issue 190)......4-284.3.4.1  Summary of Technical Information in the Application.....4-28 4.3.4.2  Staff Evaluation..................................4-29
 
4.3.4.3  UFSAR Supplement...............................4-314.3.4.4  Conclusion......................................4-324.4  Environmental Qualification of Electrical Equipment.....................4-324.4.1  Summary of Technical Information in the Application.............4-32
 
====4.4.2 Staff====
Evaluation..........................................4-33
 
====4.4.3 UFSAR====
Supplement......................................4-344.4.4  Conclusion.............................................4-34 4.5  Loss of Prestress in Concrete Containment Tendons....................4-344.5.1  Summary of Technical Information in the Application.............4-34
 
====4.5.2 Staff====
Evaluation..........................................4-34
 
====4.5.3 UFSAR====
Supplement......................................4-344.5.4  Conclusion.............................................4-35
 
====4.6.1 Fatigue====
Analysis of the Primary Containment System (Includes Suppression Chamber, Vents, Vent Headers, and Downcomers, EMRV Discharge Piping inside the Suppression Chamber, External
 
Suppression Chamber Attached Piping, Associated Penetrations, and Drywell-To-Suppression Chamber Vent Line Bellows).......4-354.6.1.1  Summary of Technical Information in the Application.....4-35 4.6.1.2  Staff Evaluation..................................4-36
 
4.6.1.3  UFSAR Supplement...............................4-374.6.1.4  Conclusion......................................4-37
 
====4.6.2 Primary====
Containment Process Penetrations and Bellows Fatigue Analysis.....................................................4-384.6.2.1  Summary of Technical Information in the Application.....4-38 4.6.2.2  Staff Evaluation..................................4-38
 
4.6.2.3  UFSAR Supplement...............................4-394.6.2.4  Conclusion......................................4-394.7  Other Plant-Specific Time-Limited Aging Analyses......................4-394.7.1  Crane Load Cycle Limit....................................4-404.7.1.1  Reactor Building Crane............................4-40 4.7.1.2  Turbine Building Crane............................4-42 4.7.1.3  Heater Bay Crane................................4-434.7.2  Drywell Corrosion........................................4-444.7.2.1  Summary of Technical Information in the Application.....4-44 4.7.2.2  Staff Evaluation..................................4-45 xiii 4.7.2.3  UFSAR Supplement...............................4-744.7.2.4  Conclusion......................................4-75
 
====4.7.3 Equipment====
Pool and Reactor Cavity Walls Rebar Corrosion.......4-754.7.3.1  Summary of Technical Information in the Application.....4-75 4.7.3.2  Staff Evaluation..................................4-76
 
4.7.3.3  UFSAR Supplement...............................4-814.7.3.4  Conclusion......................................4-824.7.4  Reactor Vessel Weld Flaw Evaluations.......................4-824.7.4.1  Summary of Technical Information in the Application.....4-82 4.7.4.2  Staff Evaluation..................................4-82
 
4.7.4.3  UFSAR Supplement...............................4-834.7.4.4  Conclusion......................................4-83 4.7.5  CRD Stub Tube Flaw Analysis..............................4-834.7.5.1  Summary of Technical Information in the Application.....4-83 4.7.5.2  Staff Evaluation..................................4-84
 
4.7.5.3  UFSAR Supplement...............................4-864.7.5.4  Conclusion......................................4-864.8  Conclusion for Time-Limited Aging Analyses..........................4-86 5  Review by the Advisory Committee on Reactor Safeguards.......................5-16  Conclusions............................................................6-1 Appendices Appendix A:  Commitments for License Renewal.................................A-1 Appendix B:  Chronology....................................................B-1Appendix C:  Principal Contributors............................................C-1 Appendix D:  References....................................................D-1 TablesTable 3.0.3-1  OCGS Aging Management Programs...............................3-7 Table 3.1-1  Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant SystemComponents in the GALL Report......................................3-239 Table 3.2-1  Staff Evaluation for Engineered Safety Features Components in the GALL Report...........................................................3-284 Table 3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL Report...3-311 Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in theGALL Report......................................................3-371 xiv Table 3.5-1  Staff Evaluation for Containment, Structures, Component Supports, and Piping andComponent Insulation in the GALL Report...............................3-403Table 3.6-1  Staff Evaluation for Electrical Components in the GALL Report..........3-460 Table 3.7-1  Evaluation for FRCT, Radio Communications, and Met Tower Electrical,Mechanical, and Structural System Components in the GALL Report..........3-483Table 4.2.1Upper Shelf Energy Calculations..................................4-7Table 4.7.2Drywell Shell Thickness and the Minimum Available Thickness Margin....4-68 xv ABBREVIATIONSAACalternate ACACADatmospheric containment air dilution system ACIAmerican Concrete Institute ACRSAdvisory Committee on Reactor Safeguards ACSRaluminum conductor steel reinforced ADAMSAgency Document Access Management System ADSautomatic depressurization system AERMaging effect requiring management AFUair filtration unit AmerGenAmerGen Energy Company, LLC AMPaging management program AMRaging management review APCSBAuxiliary and Power Conversion Systems Branch APIAmerican Petroleum Institute ARTadjusted reference temperature ASAAmerican Standards Association ASMEAmerican Society of Mechanical Engineers ASTMAmerican Society for Testing and Materials ATWSanticipated transient without scramBOPbalance of plantBTPBranch Technical Position BWROGBWR Owner's Group BWRboiling water reactor BWRVIPBoiling Water Reactor Vessel and Internals ProjectCAPcorrective action programCASScast austenitic stainless steel CDFcore damage frequency
 
CFR Code of Federal RegulationsCIconfirmatory item CIScontainment inerting system CIVcontainment isolation valve CLBcurrent licensing basis CMAACrane Manufactures Association of America CRDcontrol rod drive CRLcomponent record list CScore spray CSTcondensate storage tank CUFcumulative usage factor CVBcontainment vacuum breaker CWScirculating water systemDBAdesign basis accidentDBDdesign basis document DBEdesign basis event xviDCdirect currentDFEDdrywell floor and equipment drains DGdiesel generator DWSTdemineralized water storage tankECCSemergency core cooling systemsECPelectrochemical corrosion potential or electrochemical potential ECTeddy current testing EDGemergency diesel generator EDGCWemergency diesel generator cooling water EFPYeffective full-power year EMAequivalent margin analysis EMRVelectromatic relief valve EPRIElectric Power Research Institute EPUextended power uprate EQenvironmental qualification ESFengineered safety feature ESWemergency service waterFFahrenheitFACflow-accelerated corrosion
 
F en environmental factorFFWfinal feedwater facility FHARFire Hazards Analysis Report FPfire protection FRCTForked River Combustion Turbines FSfeedwater system FSSDfire safe shutdown FWHfeedwater heaterGALLGeneric Aging Lessons LearnedGDCgeneral design criteria or general design criterion GEGeneral Electric GEISGeneric Environmental Impact Statement GLgeneric letter GPUN General Public Utilities Nuclear Corporation GSIgeneric safety issueHELBhigh-energy line breakHEPAhigh efficiency particulate air HPhigh pressure HPCIhigh pressure coolant injection (system)
HVACheating, ventilation, and air conditioning HVShardened vent system HWChydrogen water chemistry HXheat exchangerI&Cinstrumentation and controlsIASCCirradiation assisted stress corrosion cracking xviiICSisolation condenser systemIDinside diameter or identification IGSCCintergranular stress corrosion cracking ILRTintegrated leak rate test INinformation notice INPOInstitute of Nuclear Power Operations IPAintegrated plant assessment IPEindividual plant examination IRMintermediate range monitoring ISGinterim staff guidance ISIinservice inspection ISPintegrated surveillance program ITSimportant to safetyKIP1000 lb; or 1 kilo-pountksione KIP per square inch, 1000 psi kVkilovoltLBBleak-before-breatLERlicensee event report LLRTlocal leak rate test LOCAloss of coolant accident LOOPloss of offsite power LPCIlow pressure coolant injection (system)
LPRMlocal power range monitor LRlicense renewal LRAlicense renewal applicationMCCmotor control centerMELmaster equipment list Met TowerMeterolical Tower MFEDmiscellaneous floor and equipment drain MFLmagnetic flux leakage MGmotor generator MGASmain generator and auxiliary system MICmicrobiologically influenced corrosion MSIVmain steam isolation valve MSSmain steam system MTASmain turbine and auxiliary systems MUDmakeup demineralizerNDEnondestructive examinationNEINuclear Energy Institute NESCNuclear Electrical Safety Code NFPANational Fire Protection Association NITSnot important to safety NMMSnoble metals monitoring system NPSnominal pipe size NRCU.S. Nuclear Regulatory Commission xviiiNSRnonsafety-relatedNUREGU.S. Nuclear Regulatory Commission Regulatory GuideOCCWopen-cycle cooling waterOCGSOyster Creek Generating Station ODSCCoutside-diameter stress-corrosion cracking OIopen itemP&IDpiping and instrumentation diagramPASSpost accident sampling system PBDprogram basis document PCISprimary containment isolation system PDIperformance demonstration initiative PMpreventive maintenance PORCPower Operations Review Committee PPposition paper PTpenetrant testing P-T pressure-temperature limit curves PTFEpolytetrafluoroethylene PTSpressurized thermal shock PUARplant-unique analyses report PWRpressurized water reactor PWSCCprimary water stress-corrosion crackingRAIrequest for additional informationRBCCWreactor building closed cooling water RBVSreactor building ventilation system RCICreactor core isolation cooling (system)
RCPBreactor coolant pressure boundary RCSreactor coolant system RDODSroof drains and overboard discharge system RFEDreactor building floor and equipment drains RFPreactor feed pump RGregulatory guide RHCSreactor head cooling system RHRresidual heat removal (system)
ROPSreactor overfill protection system RPSreactor protection system RPTrecirculation pump trip RPVreactor pressure vessel
 
RT NDT reference temperature nil ductility transitionRVIreactor vessel internals RWCUreactor water cleanup system RWSSreactor water sample systemSBLCstandby liquid controlSBOstation blackout SCstructure and component SCCstress-corrosion cracking xixSCSshutdown cooling systemSEsafety evaluation SENsignificant event notification SEPSystemic Evaluation Program SERsafety evaluation report SFPCSspent fuel pool cooling system SGTSstandby gas treatment system SHEstandard hydrogen electrode SIStructural Integrity Associates, Inc.
SLCSstandby liquid control system SOCstatement of consideration SRsafety-related SPspecification SRsafety-related SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for Nuclear Power PlantsSSstainless steel SSCsystem, structure, and component SVsolenoid valve SWSservice water systemtthicknessTBCCWturbine building closed cooling water TDRtime domain reflectometry TIPtraveling in-core probe TLAAtime-limited aging analysis TOCtotal organic carbon TRtopical report TStechnical specificationUFSARUpdated Final Safety Analysis ReportUSASUnited States of America Standard USEupper-shelf energy UTultrasonic testingVFLDvessel flange leak detectionVTvisual examination 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 Oyster Creek Generating Station (OCGS), as filed by AmerGen Energy Company, LLC (AmerGen or the applicant). By letter dated July 22, 2005, AmerGen submitted its application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the OCGS operating license for
 
an additional 20 years. The NRC staff (the staff) prepared this report, which summarizes the
 
results of its safety review of the LRA for compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." The NRC license renewal project manager for the OCGS
 
license renewal review is Donnie J. Ashley. Mr. Ashley can be contacted by telephone at
 
301-415-3191 or by electronic mail at dja1@nrc.gov. Alternatively, written correspondence may be sent to the following address:
License Renewal and Environmental Impacts Program U.S. Nuclear Regulatory Commission
 
Washington, D.C. 20555-0001
 
Attention: Donnie J. Ashley, Mail Stop 0-11F1 In its July 22, 2005, submittal letter, the applicant requested renewal of the operating license issued under Section 104b (Operating License No. DPR-16) of the Atomic Energy Act of 1954, as amended, for OCGS for a period of 20 years beyond the current license expiration date of
 
midnight April 9, 2009. OCGS is located in Lacey Township, Ocean County, New Jersey, approximately two miles south of the community of Forked River, two miles inland from the shore of Barnegat Bay, and nine miles south of Toms River, New Jersey. The NRC issued the
 
OCGS construction permit on December 15, 1964, and the OCGS operating license on July 2, 1991. OCGS is a single unit facility with a single-cycle, forced-circulation boiling water reactor (BWR)-2 and a Mark 1 containment. The nuclear steam supply system was furnished by
 
General Electric (GE) and the balance of the plant was originally designed and constructed by
 
Burns & Roe. OCGS's licensed power output is 1930 megawatt thermal with a gross electrical
 
output of approximately 619 megawatt electric. The updated final safety analysis report (UFSAR) contains details concerning the plant and the site.
The license renewal process consists of two concurrent reviews: (1) a technical review of safety issues and (2) an environmental review. The NRC regulations found in 10 CFR Parts 54 and 51, respectively, set forth the requirements against which license renewal applications are
 
reviewed. The safety review for the OCGS license renewal is based on the applicant's LRA and
 
responses to the staff's requests for additional information. The applicant supplemented its LRA
 
and provided clarifications through its responses to requests for additional information in audits, meetings, and docketed correspondence. Unless otherwise noted, the staff reviewed and
 
considered information submitted through July 10, 2006, and after this date on a case-by-case
 
basis depending on the stage of the safety review and on the volume and complexity of the
 
information. The public may view the LRA and all pertinent information and materials, including 1-2 the UFSAR, at the NRC Public Document Room 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
 
Lacey Branch - Ocean County Library, 10 East Lacey Road, Forked River, NJ 08731. In
 
addition, the public may find the LRA, as well as materials related to the license renewal review, on the NRC Web Site at www.nrc.gov.
This SER summarizes the results of the staff's safety review of the LRA and describes the technical details considered in evaluating the safety aspects of the proposed operation for an
 
additional 20 years beyond the term of the current operating license. The staff reviewed the LRA
 
in accordance with NRC regulations and the guidance of NUREG-1800, Revision 1, "Standard
 
Review Plan for Review of License Renewal App lications for Nuclear Power Plants" (SRP-LR), dated September 2005.
SER Sections 2 through 4 address the staff's review and evaluation of license renewal issues considered during the review of the application. Section 5 is reserved for the report of the
 
Advisory Committee on Reactor Safeguards (ACRS). Conclusions of this report are presented
 
in Section 6.
SER Appendix A contains a table that identifies the applicant's commitments for the renewal of the operating license. Appendix B provides a chronology of the principal correspondence
 
between the staff and the applicant on the review of the application. Appendix C is a list of the
 
principal contributors to this SER. Appendix D is a bibliography of the references in support of
 
the review.
In accordance with 10 CFR Part 51, the staff prepared a draft, plant-specific supplement to NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear
 
Plants (GEIS)". This supplement discusses the envir onmental considerations for renewal of the OCGS license. The staff issued Draft Supplement 28 to NUREG-1437, "Generic Environmental
 
Impact Statement for License Renewal of Nucl ear Plants, Regarding Oyster Creek Generating Station, Draft Report for Comment," in June 2006.1.2  License Renewal Background Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating
 
licenses for commercial power reactors are issued for 40 years. These licenses can be renewed
 
for up to 20 additional years. The original 40-year license term was selected on the basis of
 
economic and antitrust considerations rather than on technical limitations; however, some
 
individual plant and equipment designs may have been engineered for an expected 40-year
 
service life.
In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power plant aging. This workshop led the staff to establish a comprehensive program plan for nuclear
 
plant aging research. With the results of that research, a technical review group concluded that
 
many aging phenomena are readily manageable and pos e no technical issues that would preclude life extension for nuclear power plants. In 1986, the staff published a request for
 
comment on a policy statement that would address major policy, technical, and procedural
 
issues related to license renewal for nuclear power plants.
1-3 In 1991, the staff published the license renewal rule in 10 CFR Part 54 (the Rule), (56 FR 64943 dated December 13, 1991). The staff participated in an industry-sponsored demonstration
 
program to apply the Rule to a pilot plant and to gain experience necessary to develop
 
implementation guidance. To establish a scope of review for license renewal, the Rule defined
 
age-related degradation unique to license renewal; however, during the demonstration program, the staff found that adverse aging effects t hat occur to plant systems and components are managed during the period of initial license. In addition, the staff found that the scope of the
 
review did not allow sufficient credit for existing programs, particularly the implementation of the
 
Maintenance Rule, which also manages plant-aging phenomena. As a result, the staff amended
 
the Rule in 1995 (60 FR 22461 dated May 8, 1995). The amended Rule established a regulatory
 
process simpler, more stable, and more predictable than the previous Rule. In particular, the
 
staff amended the Rule to focus on managing the adverse effects of aging rather than on
 
identifying age-related degradation unique to license renewal. The staff initiated these Rule
 
changes to ensure that important systems, st ructures, and components (SSCs) will continue to perform their intended functions during the period of extended operation. In addition, the revised
 
Rule clarified and simplified the integrated plant assessment process to be consistent with the
 
revised focus on passive, long-lived structures and components (SCs).
In parallel with these efforts, the staff pursued a separate rulemaking effort and developed an amendment to 10 CFR Part 51 to focus the scope of the review of environmental impacts of
 
license renewal and fulfill the NRC's responsibilities under the National Environmental Policy
 
Act of 1969.1.2.1  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 provide and maintain an acceptable level of safety, with the possible
 
exception of the detrimental effects of aging on the functionality 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 those SSCs (1) that are safety-related, (2) whose failure could affect safety-related
 
functions, and (3) that are relied on for 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), an applicant for a renewed license must review all SSCs within the scope of the Rule to identify SCs subject to an aging management review (AMR). Those
 
SCs subject to an AMR perform an intended function without moving parts or without a change
 
in configuration or properties and are not subject to replacement based on a qualified life or
 
specified time period. As required by 10 CFR 54.21(a), an applicant for a renewed license must
 
demonstrate that the effects of aging will be managed in such a way that the intended
 
function(s) of those SCs will be maintained, consistent with the current licensing basis (CLB), for
 
the period of extended operation; however, active equipment is considered to be adequately 1-4 monitored and maintained by existing programs. In other words, the detrimental effects of aging that may affect active equipment are more readily detectable and can be identified and
 
corrected through routine surveillance, performance monitoring, and maintenance activities. The
 
surveillance and maintenance activities programs for active equipment, as well as other aspects
 
of maintaining the plant's design and licensing basis, are required throughout the period of
 
extended operation.
Pursuant to 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement with a summary description of the applicant's programs and activities for managing the effects of aging
 
and an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.
License renewal also requires identification and updating of TLAAs. During the design phase for a plant, certain assumptions about the length of time that the plant can operate are incorporated
 
into design calculations for several of the plant's SSCs. In accordance with 10 CFR 54.21(c)(1),
the applicant must either show that these calculations will remain valid for the period of
 
extended operation, project the analyses to the end of the period of extended operation, or
 
demonstrate that the effects of aging on the intended function(s) will be adequately managed for
 
the period of extended operation.
In 2001, the staff developed and issued Regulatory Guide 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses." This regulatory guide
 
endorses Nuclear Energy Institute (NEI) 95-10, "Industry Guideline for Implementing the
 
Requirements of 10 CFR Part 54 - The License Renewal Rule," dated March 2001. NEI 95-10
 
details an acceptable method of implementing the Rule. The staff also used the SRP-LR to
 
review the application.
In the LRA, the applicant fully utilized the process defined in NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," dated S eptember 2005. The GALL Report provides the staff with a summary of staff-approved agi ng management programs (AMPs) for the aging of many SCs subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA can be greatly
 
reduced, thereby improving the efficiency and effectiveness of the license renewal review
 
process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the industry. The
 
report also serves as a reference for both applicants and staff reviewers to quickly identify
 
AMPs and activities that the staff determined can provide adequate aging management during
 
periods of extended operation.
 
====1.2.2 Environmental====
Review Part 51 of 10 CFR governs environmental protection regulations. 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 of renewed licenses for 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 1-5 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 the National Environmental Policy Act of 1969 and the requirements of 10 CFR Part 51, the staff reviewed the plant-specific environmental impacts of license renewal, including whether the GEIS had not considered new and significant information. As part of its
 
scoping process, the staff held a public meeting November 1, 2005, in Toms River, New Jersey, to identify environmental issues specific to the plant. The draft, plant-specific Supplement 28 to
 
the GEIS, dated June 2006, documents the results of the environmental review and includes a
 
preliminary recommendation on the license renewal action. The staff held another public
 
meeting on July 12, 2006, in Toms River, New Jersey, to discuss draft GEIS Supplement 28.
After considering comments on the draft, the staff will separately published the final, plant-specific GEIS Supplement 28. 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 the requirements of 10 CFR Part 54. 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.
Section 54.19(a) of 10 CFR requires license renewal applicants to submit general information.
The applicant provided this general information in LRA Section 1. The staff reviewed LRA
 
Section 1 and found that the applicant had submitted the information required by
 
10 CFR 54.19(a).
Section 54.19(b) of 10 CFR requires each to 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." In the LRA, the applicant stated the following regarding this issue:
The current indemnity agreement (No. B-37) for Oyster Creek states in Article VII that the agreement shall terminate at the time of expiration of the licenses
 
specified in Item 3 of the Attachment to the agreement. Item 3 of the Attachment
 
to the indemnity agreement lists license number, DPR-16. Applicant requests
 
that any necessary conforming changes be made to Article VII and Item 3 of the
 
Attachment, and any other sections of the indemnity agreement as appropriate to ensure that the indemnity agreement continues to apply during both the terms of
 
the current license and the terms of the renewed license. Applicant understands
 
that no changes may be necessary for this purpose if the current license number
 
is retained.
The staff intends to maintain the original license number upon issuance of the renewed license, if approved. Therefore, conforming changes to the indemnity agreement need not be made and the requirements of 10 CFR 54.19(b) have been met.
Section 54.21 of 10 CFR requires each LRA to contain (a) an integrated plant assessment, (b) a description of any CLB changes that occurred during the staff's review of the LRA, (c) an
 
evaluation of TLAAs, and (d) a UFSAR supplement. LRA Sections 3, 4, and Appendix B 1-6 address the license renewal requirements of 10 CFR 54.21(a), (b), and (c). LRA Appendix A contains the license renewal requirements of 10 CFR 54.21(d).
Section 54.21(b) of 10 CFR requires that each year, following submission of the LRA, and at least three months before the scheduled completion of the staff's review, the applicant must
 
submit an amendment to the LRA that identifies any changes to the facility's CLB materially
 
affecting the contents of the LRA, including the UFSAR supplement. The applicant submitted an
 
update to the LRA, by letter dated July 18, 2006, which summarizes the changes to the CLB
 
that have occurred during the staff's review of the LRA. This submission satisfies the
 
requirements of 10 CFR 54.21(b) and is still under staff review.
Section 54.22 of 10 CFR 54.22 requires the LRA to include changes or additions to the technical specifications necessary to manage the effects of aging during the period of extended
 
operation. In LRA Appendix D, the applicant stated that it had not identified any technical
 
specification changes necessary to support issuance of the renewed operating license for
 
OCGS. This statement adequately addresses the requirement specified in 10 CFR 54.22.
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 provided by 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 review of the LRA and associated SER. SER Section 5 will incorporate the ACRS report, once it is issued. SER Section 6 documents the findings required by 10 CFR 54.29.
The final, plant-specific GEIS Supplement 28 will document the staff's evaluation of the environmental information required by 10 CFR 54.23 and will specify the considerations related
 
to renewing the license for OCGS. The staff will prepare this supplement separately from this
 
SER.1.4  Interim Staff Guidance The license renewal program is a living program. The staff, industry, and other interested
 
stakeholders gain experience and develop lessons learned with each renewed license. The
 
lessons learned address the staff's performance goals of maintaining safety, improving
 
effectiveness and efficiency, reducing regulatory burden, and increasing public confidence.
 
Interim staff guidance (ISG) is documented for use by the staff, industry, and other interested
 
stakeholders until it is incorporated into such license renewal guidance documents as the
 
SRP-LR and the GALL Report.
The following table provides the current ISG, issued by the staff, as well as the SER sections in which the staff addresses each ISG issue.
1-7 ISG Issue(Approved ISG No.)PurposeSER SectionNickel-alloy components in the reactor pressure boundary (LR-ISG-19B)Cracking of nickel-alloy componentsin the reactor pressure boundary.
ISG under development. NEI andEPRI-MRP will develop an
 
augmented inspection program for GALL AMP XI.M11-B. This AMP will
 
not be completed until the NRC
 
approves an augmented inspection program for nickel-alloy base metal components and welds as proposed by EPRI-MRP. N/A (PWRs only)Corrosion of drywell shell in Mark I containments(LR-ISG-2006-01)To address concerns related tocorrosion of drywell shell in Mark I
 
containments.
3.0.3.1.8 3.0.3.2.22
 
3.5 4.7.21.5  Summary of Open Items As a result of its review of the LRA, including additional information submitted to the staff through July 10, 2006, the staff identified the following open items (OIs). An issue is considered
 
open if the applicant has not presented sufficient information or if the staff has not completed its
 
review. Each OI has been assigned a unique identifying number.
OI 4.7.2-1.1: (Section 4.7.2 - Drywell Corrosion)
In RAI 4.7.2-1 dated March 10, 2006, the staff requested that the applicant provide the following information: For the drywell corrosion during the late 1980s and the new corrosion found during
 
the subsequent inspections, provide the process used to establish confidence that the sampling
 
done to identify the areas of corrosion has been adequate.
In its response dated April 7, 2006, the applicant emphasized that it employs a robust process to establish confidence that the nature and locations of sampling done and areas considered for
 
identifying the areas of corrosion have been adequate. The applicant stated that the elements of
 
process had been developed over several years and defined in several technical documents
 
submitted to the NRC in the 1990s. In addition, the applicant stated that OCGS has conducted
 
extensive examinations to identify the cause of drywell corrosion, employed a robust sampling process, quantified with reasonable assurance the extent of drywell shell thinning due to
 
corrosion, and assessed its impact on the drywell's structural integrity.
The staff's review of the applicant's response determined that there had been no UT measurements taken in the lower portion of the spherical area above the sand-pocket area. The
 
staff requested that the applicant clarify its UT sampling plan for the entire drywell shell assessment.
1-8 In its supplemental response dated June 20, 2006, the applicant stated:
A review of the drywell fabrication and installation details show that the welds that attach the 0.770 inches (the correct thickness is 0.770 inches, not 0.722 inch
 
as indicated in the meeting notes) nominal plates to the 1.154 inch nominal
 
plates at elevation 23 ft 6 7/8 inch are double bevel full penetration welds. The
 
external edge of the 1.154 inches plates is tapered to 3 to 12 minimum as
 
required by ASME Section VIII, Subsection UW-35, while the internal edge of the
 
1.154 inch plates are flush with the 0.770 inch plates. Thus there are no ledges
 
that could retain water leakage and result in more severe corrosion than in areas
 
included in the inspection program. Also, this joint is located below the equatorial
 
center of the sphere. Therefore, in the event that water may run down the gap
 
between the drywell shell and the concrete wall it would not collect on this joint.
In 1991, Oyster Creek performed random inspections of the drywell shell.
Ultrasonic testing inspections were conducted at 19 locations on either the 1.154
 
inch thick plates or on the 0.770 inch thick plates. The UT measurements were
 
taken on a 6 inch x 6 inch grid (49 UTs) at each location. The UT measurement
 
results show that thinning of the plates at these locations is less severe than the
 
areas that are included in the corrosion-monitoring program. For this reason, the
 
transition area was not added to the corrosion-monitoring program. Based on the
 
above, AmerGen concludes that areas monitored under the drywell corrosion
 
monitoring program bound the transition (from 1.154 inches to 0.770 inch thick
 
plates) area of the drywell shell. Nevertheless, UT measurements will be taken
 
on the 0.770 inch thick plate, just above the weld, prior to entering the period of
 
extended operation.
The measurements will be conducted at one location using the 6 inch x 6 inch grid. A second set of UT measurements will be taken two refueling outages later
 
at the same location. The results of the measurements will be analyzed and
 
evaluated to confirm that the rate of corrosion in the transition is bounded by the
 
rate of corrosion of the monitored areas in the upper region of the drywell. If
 
corrosion in the transition area is found to be greater than areas monitored in the
 
upper region of the drywell, UT inspections in the transition area will be
 
performed on the same frequency as those performed on the upper region of the
 
drywell (every other refueling outage).
Similarly, a review of fabrication and installation details of the containment drywell shell shows that the weld that connects the 2.625" knuckle plates to the
 
0.640"cylinder plates at elevation 71 ft 6 inch is a double bevel full penetration
 
weld. The edges of the 2.625 inch plates were fabricated with a 3 to 12 taper to
 
provide a smooth transition from the thicker to the thinner plate as required by
 
ASME Section VIII, Subsection UE-35. Thus there are no ledges that could retain
 
water leakage and result in more severe corrosion than the areas included in the
 
inspection program.
In 1991, Oyster Creek performed random inspections of the drywell shell.
Ultrasonic testing (UT) inspections were conducted at 18 locations on the 2.625
 
inch thick knuckle plate and at four (4) locations on the 0.640 inch thick cylinder 1-9 plate. The UT measurements were taken on a 6 inch x 6 inch grid (49 UTs) at each location. The UT measurement results showed that thinning of the plates at
 
these locations was less severe than the areas that are included in the corrosion
 
monitoring program. For this reason the knuckle area was not added to the
 
corrosion monitoring program. Based on the above, AmerGen concludes that
 
areas monitored under the drywell corrosion monitoring program bound the
 
knuckle area of the drywell shell. However, UT measurements will be taken
 
above the 2.625 inch knuckle plate in the 0.640 inch thick plate prior to entering
 
the period of extended operation.
The measurements will be taken at one location using the 6 inch" x 6 inch grid. A second set of UT measurements will be taken two refueling outages later at the
 
same location. The results of the measurements will be analyzed and evaluated
 
to confirm that the rate of corrosion in the transition is bounded by the rate of
 
corrosion of the monitored areas in the upper region of the drywell. If corrosion in
 
the transition area is found to be greater than areas monitored in the upper
 
region of the drywell, UT inspections in the transition area will be performed on
 
the same frequency as those performed on the upper region of the drywell (every
 
other refueling outage).
The staff believes that random sampling of UT measurement is valuable if the likelihood of corrosion is almost equal at every place in the region considered for UT measurements. If the
 
geometry of the region and water flow in the air gap suggest that one area is more likely to have
 
corrosion than another then the sampling plan must consider areas more likely to have
 
corrosion in addition to the randomly selected areas. If the water flow in the air gap is high, the
 
applicant's argument that the weld transition will not allow water accumulation would be
 
accurate. However, if the water flow is slow, the applicant's argument may not hold true. During
 
the forthcoming outage, the applicant plans UT measurements at one location on each of the
 
transition areas. The staff believes that measurement at four locations in each transition area
 
would be more conservative. The locations along the thickness transition should be consistent
 
with the areas that have large water accumulation and corrosion in the sand bed region. This
 
item has been identified as an OI.
OI 4.7.2-1.2: (Section 4.7.2 - Drywell Corrosion)
In RAI 4.7.2-1 dated March 10, 2006, the staff requested that the applicant provide the following information: For the drywell corrosion during the late 1980s and the new corrosion found during
 
the subsequent inspections, provide the process used to establish confidence that the sampling
 
done to identify the areas of corrosion has been adequate.
The staff's review of the April 7, 2006, response determined that the most susceptible bays in the sand pocket region of the drywell shell had been incorporated in the sampling. However, it
 
was not clear to the staff whether the junction at elevation 6' 10.25" had been represented in the
 
sampling. To determine whether the readings are taken at the vulnerable locations and reliable
 
techniques are used, the staff requested that the applicant explain why this area should not be
 
included in the sampling plan.
In its response dated June 20, 2006, the applicant noted that the drywell construction and fabrication details show that the presence of the drywell skirt prevents moisture intrusion into 1-10 the plate. The applicant also noted that AmerGen has extensively investigated drywell corrosion, including the embedded shell. Plant-specific and industry operating experience
 
indicate that corrosion of the embedded steel in concrete is not significant because the shell is
 
protected by the high alkalinity of concrete. Corrosion could become significant only if the
 
concrete environment is aggressive. The applicant also stated that historical data show that the
 
environment in the sand bed region is not aggressive, and thus any water in contact with the
 
embedded shell is not aggressive. The data show that corrosion of the drywell shell in the sand
 
bed region is galvanic and impurities like chlorides and sulfates are not fundamentally involved in the anodic and cathodic corrosion reactions. Thus, only limited corrosion is anticipated for the
 
drywell embedded shell.
The applicant concluded that corrosion monitoring of the sand bed region of the drywell shell is bounding with respect to corrosion that may have occurred on the drywell embedded shell
 
before 1992. After 1992 and through the period of extended operation, corrosion of the
 
embedded shell has not been not significant because of the mitigative measures implemented
 
and the robust drywell corrosion AMP.
The staff understands the applicant's technical basis to support the applicant's view that the inaccessible portion of the drywell shell (i.e., embedded between the concrete floor inside, and
 
concrete outside) is not likely to be subject to the same type of severe corrosion as experienced
 
in the sand bed area. However, the general corrosion in the liner plates embedded in concrete
 
of a number of pressurized water reactor (PWR) and BWR containments suggests that certain
 
irregularities during the construction (i.e. foreign objects or voids in the concrete) could trigger
 
corrosion not arrested by the concrete environment. This suggestion is particularly significant for
 
the plates potentially subject to water seepage. The applicant's position that the uniformly
 
reduced thickness used in the GE analysis compensates for any corrosion that may have
 
occurred before the area was sealed in 1992 has some validity. The staff is still evaluating this
 
item; therefore, it has been identified as an OI.
OI 4.7.2-1.3: (Section 4.7.2 - Drywell Corrosion)
In RAI 4.7.2-1 dated March 10, 2006, the staff requested that the applicant provide the following information: A summary of the factors considered in establishing the minimum required drywell
 
thickness.
In its response dated April 7, 2006, the applicant explained that the factors considered in establishing the minimum required drywell thickness at various elevations of the drywell are
 
described in detail in engineering analyses documented in two GE reports, Index Nos. 9-1, 9-2, and 9-3, 9-4.
In the applicant's discussion, a summary of the methods and assumptions used in the buckling analysis of the shell in the sand-pocket area has been given. Although the NRC has not
 
approved ASME Code Case N-284 for use on a generic basis, the staff does not take exception
 
to the use of average compressive stress across the metal thickness for buckling analysis of the
 
as-built shell. However, if the corrosion has reduced the strength of the remaining metal through
 
the cross section, this use may not be valid. The staff requested that the applicant address this
 
issue.
1-11 In its response dated June 20, 2006, the applicant discussed its use of ASME Code Case N-284:
Although Revision 1 of Code Case 284 had not yet been issued when the report (An ASME Section VIII Evaluation of Oyster Creek Drywell for Without Sand
 
Case, Part II - Stability Analysis," GE Report, Index No. 9-4, Revision 0, DRF #
 
00664) was written, the authors consulted with the primary author of the revision.
 
Based on those discussion, the plasticity correction factors used in the evaluation
 
are the same as those in Figure 1610-1 of Code Case N-284 Revision 1.
The applicant stated that the technical approach used in the stability evaluation of Reference 2 is entirely consistent with the guidelines in ASME Code Case N-284, Revision 1. In addition, the
 
applicant concluded that the corrosion on the outside surface of the shell will not introduce
 
eccentricities that would significantly impact the "e/t" value of 1.0 assumed in ASME Code
 
Case N-284. The applicant also stated that it expected additional eccentricity from shell
 
corrosion in service to be accommodated within the allowable limit for imperfections.
The staff believes that the applicant has provided a thorough explanation of the factors considered in applying the ASME Code Case N-284-1 for buckling analysis of the corroded shell
 
in the sand bed area of the drywell shell. However, the applicant did not address whether it is
 
appropriate to assume the same strength across the corroded section of the shell. The
 
incorporation of the "e/t" corrosion concept with a representative distribution of strength along
 
the corroded section that recognize the lower strength at the corroded side and full strength at
 
the inside surface, could support the claim of conservatism in the analysis. This has been
 
identified as an OI.
OI 4.7.2-1.4: (Section 4.7.2 - Drywell Corrosion)
In RAI 4.7.2-1 dated March 10, 2006, the staff requested that the applicant provide the following information: A summary of the factors considered in establishing the minimum required drywell
 
thickness.
In its response dated April 7, 2006, the applicant explained that the factors considered in establishing the minimum required drywell thickness at various elevations of the drywell are
 
described in detail in engineering analyses documented in two GE reports, Index Nos. 9-1, 9-2, and 9-3, 9-4.
For the localized thin areas, the applicant uses the provision of NE-3213.10 of Subsection NE of ASME Code Section III. This provision, although not directly applicable to the randomly thin areas caused by corrosion, if used with care and adequate conservatism, could provide
 
information about the primary stress levels at the junction of the thin and thick areas. The staff
 
requested that the applicant provide a summary of the process used to address this issue.
In its response dated June 20, 2006, the applicant noted that "although provisions in ASME Code Section III, Subsection NE-3213.10 are not directly applicable to the randomly thin areas
 
caused by corrosion, AmerGen believes that the provisions are applicable to the analysis of
 
Oyster Creek drywell shell based on the following:"
1-12
* The stress analysis of Oyster Creek drywell presented in Reference 1 satisfies the local primary stress requirements of NE-3213.10.
 
Conservatism in the allowable primary stress intensity value, the
 
assumed peak pressure during the LOCA condition and the assumption
 
of local corroded thickness in the entire region of the drywell provide
 
additional structural margin.
* The Code primary stress limits are satisfied in the corroded condition and the number of fatigue cycles is small, the surface discontinuities from
 
corrosion do not represent a significant structural integrity concern.
* The applicant indicated that UT measurements of the drywell shell above the sand bed region had shown that the measured general thickness
 
contains significant margin. The applicant stated that the ongoing
 
corrosion in that region is insignificant and that the margin could be
 
applied to offset uncertainties related to surface roughness.
* The applicant stated that UT measurements of the drywell shell in the sand bed region show that the measured general thickness is greater
 
than the 0.736'" thickness assumed in the buckling analysis by significant
 
margins except in two bays, 17 and 19. (Refer to response to
 
RAI 4.7.2-1(d), Table-2). The margin in the general thickness of the two
 
bays is 0.074" and 0.064" respectively. As significant additional corrosion
 
is not expected in the sand bed region, the applicant applied the margin
 
to offset uncertainties related to the surface roughness.
The staff is still evaluating this item; therefore, it has been identified as an OI.
OI 4.7.2-3: (Section 4.7.2 - Drywell Corrosion)
In RAI 4.7.2-3 dated March 10, 2006, the staff noted that leakage from the refueling seal has been identified as one of the reasons for accumulation of water and contamination of the
 
sand-pocket area. The refueling water passes through the gap between the shield concrete and
 
the drywell shell in the long length of inaccessible areas. As there is a potential for corrosion, ASME Code Subsection IWE would require augmented inspection of this area. The staff
 
requested that the applicant provide a summary of inspections (visual and NDE) and mitigating
 
actions to prevent water leaks from the refueling seal components.
In its response dated April 16, 2006, the applicant stated that the refueling seals at OCGS consist of stainless steel bellows. In the mi d-to-late 1980s, GPU conducted extensive visual and NDE inspections to determine the source of water intrusion into the seismic gap between the
 
drywell concrete shield wall and the drywell shell and accumulation in the sand bed region. The
 
inspections concluded that the refueling bellows (seals) were not the source of water leakage.
 
The bellows were repeatedly tested by helium (external) and air (internal) with no indication of
 
leakage. Furthermore, any minor leakage from the refueling bellows would be collected in a
 
concrete trough below the bellows. The concrete trough is equipped with a drain line that would
 
direct any leakage to the reactor building equipment drain tank and prevent it from entering the
 
seismic gap. The drain line has been checked before refueling outages to confirm that it is not
 
blocked. The only other seal is the gasket for the reactor cavity steel trough drain line. This 1-13 gasket was replaced after the tests showed that it was leaking. However, the gasket leak was ruled out as the primary source of water observed in the sand bed drains because there is no
 
clear leakage path to the seismic gap. Minor gasket leaks would be collected in the concrete
 
trough below the gasket and would be removed by the drain line like leaks from the refueling
 
bellows.In addition, the applicant noted that additional visual and NDE (dye penetrant) inspections on the reactor cavity stainless steel liner had identified a significant number of cracks, some
 
throughwall. Engineering analysis concluded that the cracks were most probably caused by
 
mechanical impact or thermal fatigue, not intergranular stress corrosion cracking (IGSCC).
 
These cracks were determined to be the source of refueling water that passed through the
 
seismic gap. To prevent leakage through the cracks, GPU installed an adhesive-type stainless
 
steel tape to bridge any observed large cracks and subsequently applied a strippable coating.
 
This repair greatly reduced leakage and was implemented every refueling outage while the
 
reactor cavity was flooded.
The applicant noted that OCGS has a long-time commitment to monitor the sand bed region drains for water leakage. A review of plant documentation provided no objective evidence that
 
the commitment had been implemented since 1998. OCGS Issue Report No. 348545 was
 
issued, in accordance with the corrective action process, to document the lapse in implementing
 
the commitment and to reinforce strict compliance with commitment implementation in the
 
future, including during the period of extended operation.
The applicant also committed (Commitment No. 33) to augmented inspections of the drywell inaccordance with ASME Code Section Xl, Subsection IWE. These inspections consist of UT
 
examinations of the upper region of the drywell and visual examinations of the protective
 
coating on the exterior of the drywell shell in the sand bed region. UT measurements will
 
supplement the visual inspection of the coating measurements from inside the drywell once
 
before entering the period of extended operation and every 10 years during the period of
 
extended operation.
The staff's review of the applicant's response determined that the epoxy coating applied in the sand-bed region of the shell has a limited life and that water leakage from the air gap has not
 
been prevented. With these observations, the staff requested that the applicant provide a
 
systematic program of examination of the coat ing for confidence that the preventive measure is adequately implemented at all locations in the sand-pocket areas.
In its response dated June 20, 2006, the applicant stated:
AmerGen committed that it will monitor the sand bed region drains on a daily basis during refueling outages and take the following actions if water is detected.
 
The actions will be completed prior to exiting the outage.
* The source of water will be investigated and diverted, if possible, from entering the gap between the drywell shell and the drywell shield wall.
* The water will be chemically analyzed to aid in determining the source of leakage.
1-14
* A remote inspection will be performed in the trough drain area to determine if the trough drains are operating properly.
* The condition of the coating and the moisture barrier (seal) in the affected bays will be inspected.
* If the coating is degraded and visual inspection indicates corrosion is taking place, then UT thickness measurements will be taken in the
 
affected areas of the sand bed region. The measurements will be taken
 
from either inside or outside the drywell to ensure that the shell thickness
 
in areas affected by water leakage is measured. UT thickness
 
measurements and evaluation will be consistent with the existing
 
program.
* The degraded coating and/or the seal will be repaired in accordance with station procedures.
* UT measurements will be taken in the upper region of the drywell consistent with the existing program.
The applicant also committed (Commitment No. 27) to monitor the sand bed region drains quarterly during the operating cycle. The applicant stated that, if water is detected, actions listed
 
below will be taken. Actions that can only be completed during an outage will be completed
 
during the next scheduled refueling outage.
* The leakage rate will be quantified to determine a representative flow rate. The leakage rate will be trended.
* The source of water will be investigated and diverted, if possible, from entering the gap between the drywell shell and the drywell shield wall.
* The water will be chemically analyzed to determine the source of leakage.
* The condition of the coating and the moisture barrier (seal) in the affected bays will be inspected during the next refueling outage or an outage of
 
opportunity.
* If the coating is degraded and visual inspection indicates corrosion has taken place, then UT thickness measurements will be taken in the
 
affected areas of the sand bed region from either inside or outside the
 
drywell to ensure that the shell thickness in areas affected by water
 
leakage is measured. UT thickness measurements and evaluation of the
 
results will be consistent with the existing program.
* UT measurements will be taken in the upper region of the drywell consistent with the existing program.
* The degraded coating or the seal will be repaired in accordance with station procedures.
1-15 The staff believes that applicant has not provided sufficient information regarding the extent that coated surfaces will be examined during each inspection. This has been identified as an OI.1.6  Summary of Confirmatory Items The staff's review of the LRA, including additional information submitted to the staff through
 
July 10, 2006, identified no confirmatory items (CIs). An issue was considered confirmatory if
 
the staff and the applicant have reached a satisfactory resolution, but such information has not
 
yet been submitted to the staff.1.7  Summary of Proposed License Conditions As a result of its review of the LRA, including subsequent information and clarifications from the
 
applicant, the staff, at present, proposes three 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, as required by 10 CFR 50.71(e), following the
 
issuance of the renewed license.
The second license condition requires future activities identified in the UFSAR supplement to be completed prior to the period of extended operation.
The third license condition requires all surveillance capsules placed in storage to be maintained for future insertion. Any changes to storage requirements must be approved by the staff as
 
required by 10 CFR Part 50, Appendix H.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
2-17 SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW
 
===2.1 Scoping===
and Screening Methodology
 
====2.1.1 Introduction====
Title 10, Section 54.21 of the Code of Federal Regulations (10 CFR Part 54.21), "Contents of Application Technical Information," requires each license renewal application (LRA) to contain
 
an integrated plant assessment (IPA) listing those structures and components (SCs) subject to
 
an aging management review (AMR) from all of the systems, structures, and components (SSCs) within the scope of license renewal in accordance with 10 CFR 54.4.
In LRA Section 2.1, "Scoping and Screening Methodology," the applicant described the methodology used to identify the SSCs at the Oyster Creek Generating Station (OCGS) within
 
the scope of license renewal and the SCs subject to an AMR. The staff reviewed the AmerGen
 
Energy Company, LLC (AmerGen or the applicant) scoping and screening methodology to determine whether it meets the scoping requirements of 10 CFR 54.4(a) and the screening
 
requirements of 10 CFR 54.21.
In developing the scoping and screening methodology for the LRA, the applicant considered the requirements of 10 CFR 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, "Industry Guideline for Implementing the Requirements of
 
10 CFR Part 54 - The License Renewal Rule," Revision 5. Additionally, in developing this
 
methodology, the applicant considered the correspondence between the staff and other
 
applicants and/or the NEI.2.1.2  Summary of Technical Information in the Application LRA Sections 2.0 and 3.0 provide the technical information required by 10 CFR 54.21(a). LRA Section 2.1 describes the process to identify SSCs meeting the license renewal scoping criteria
 
under 10 CFR 54.4(a) and the process to identify SCs subject to an AMR, as required by
 
10 CFR 54.21(a)(1). In addition, the applicant provided the results of the process to identify the
 
SCs subject to an AMR in the following LRA sections:
* Section 2.2, "Plant Level Scoping Results"
* Section 2.3, "Scoping and Screening Results: Mechanical"
* Section 2.4, "Scoping and Screening Results: Structures"
* Section 2.5, "Scoping and Screening Results: Electrical Components" 2-18 LRA Section 3, "Aging Management Review Results," contains the applicant's aging management results in the following LRA sections:
* Section 3.1, "Aging Management of Reactor Vessel, Internals, and Reactor CoolantSystems"
* Section 3.2, "Aging Management of Engineered Safety Features Systems"
* Section 3.3, "Aging M anagement of Auxiliary Systems"
* Section 3.4, "Aging Management of Steam and Power Conversion System"
* Section 3.5, "Aging Management of Containment, Structures, Component Supports, and Piping and Component Insulation"
* Section 3.6, "Aging Management of Electrical Components" LRA Section 4.0, "Time-Limited Aging Analyses," contains the applicant's identification and evaluation of time-limited aging analyses (TLAAs).
 
====2.1.3 Scoping====
and Screening Program Review The staff evaluated the LRA scoping and screening methodology in accordance with the guidance of Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,"
(SRP-LR). 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 plant structures and systems within the scope of the Rule*10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods utilized by the applicant to identify plant SCs subject to an AMR As parts of the applicant's scoping and screening methodology, the staff reviewed the activities described in the following sections of the LRA using the guidance of SRP-LR:*Section 2.1 to ensure that the applicant described a process for identifying SSCs within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a).*Section 2.2 to ensure that the applicant described a process for determining SCs 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 OCGS in New Jersey during the week of September 19 through 23, 2005. The audit focused on ensuring
 
that the applicant had developed and implemented adequate guidance to conduct the scoping
 
and screening of SSCs in accordance with the methodologies described in the LRA and the
 
requirements of the Rule. The staff reviewed implementation of the project level instructions and
 
position papers describing the applicant's scoping and screening methodology. In addition, the
 
staff conducted detailed discussions with the applicant on the implementation and control of the 2-19 license renewal programs and reviewed adminis trative control documentation and selected design documentation used by the applicant during the scoping and screening process. The
 
staff reviewed the applicant's processes for quality assurance (QA) as to development of the
 
LRA. The staff evaluated the quality attributes of the applicant's aging management program (AMP) activities described in LRA Appendix B, "Aging Management Programs." The staff also
 
reviewed the training and qualification of the LRA development team. The staff reviewed
 
scoping and screening results reports for the isolation condenser system (ICS) and reactor
 
building to ensure that the applicant had appropriately implemented the methodology outlined in
 
the administrative controls and that the results were consistent with the current licensing basis (CLB) documentation. The staff documented its review in an audit trip report issued on
 
October 21, 2005. The report identified several issues which required additional information
 
from the applicant prior to completion of the review.
2.1.3.1  Implementation Procedures and Documentation Sources Used for Scoping and Screening The staff reviewed the applicant's scoping and screening implementation procedures to verify that the process used to identify SCs subject to an AMR was consistent with the LRA and the
 
SRP-LR. Additionally, the staff reviewed the scope of CLB documentation sources and the
 
process used by the applicant to ensure that CLB commitments had been appropriately
 
considered and that the applicant had adequately implemented the procedural guidance during
 
the scoping and screening process.
2.1.3.1.1  Summary of Technical Information in the Application
 
In LRA Section 2.1.2, "Information Sources Used for Scoping and Screening," the applicant reviewed the following information sources during the license renewal scoping and screening
 
process:
* design basis documents (DBDs)
* component record list (CRL)
* updated final safety analysis report (UFSAR)
* fire hazards analysis report
* engineering drawings, evaluations, and calculations
* environmental qualification master list
* maintenance rule database
* NRC safety evaluation reports The license renewal boundary drawings (LRBDs) show the systems within the scope of license renewal highlighted in color.
2.1.3.1.2  Staff Evaluation
 
Scoping and Screening Implementation Procedures. The staff reviewed the following scoping and screening methodology implementation procedures:
* Position Paper (PP)-01, "License Renewal Systems & Structures," Revision 3
* PP-02, "10 CFR 54.4(a)(1) Safety Related Systems and Structures," Revision 2 2-20
* PP-03, "10 CFR 54.4(a)(2) Systems and Structures," Revision 3
* PP-04, "Systems and Structures Relied Upon to Demonstrate Compliance with 10 CFR 50.63 - Station Blackout," Revision 2
* PP-05, "Systems and Structures Relied Upon to Demonstrate Compliance with 10 CFR 50.62 - ATWS," Revision 1
* PP-06, "Systems and Structures Relied Upon to Demonstrate Compliance with 10 CFR 50.49 - Environmental Qualification," Revision 1
* PP-07, "Systems and Structures Relied Upon to Demonstrate Compliance with 10 CFR 50.48 - Fire Protection," Revision 3
* PP-08, "Structures, Components and Commodity Types with Active, Passive, Short Lived Determinations and Intended Functions," Revision 2
* PP-13, "Abnormal Operating Occurrence," Revision 2
* Project Level Instruction (PLI)-02, "Scoping of Systems and Structures," Revision 4
* PLI-03, "Screening of Systems, Structures and Components," Revision 2
* PLI-04, "Boundary Drawings," Revision 2 The staff found the overall process to implement 10 CFR 54 requirements included in the PLIs.
Guidance for determining plant SSCs within the scope of the Rule, including guidelines for
 
determining which component types of the SCs within the scope of license renewal were subject
 
to an AMR, were found by the staff in the PPs. During the review of these procedures, the staff
 
focused on the consistency of the detailed procedural guidance with information in the LRA, including in the implementation of NRC staff positions documented in the SRP-LR and interim
 
staff guidance (ISG) documents.
After reviewing the LRA and supporting documentation, the staff finds the scoping and screening methodology instructions consistent with LRA Section 2.1. The applicant's
 
methodology has sufficient detail for concise guidance on the scoping and screening
 
implementation process followed during LRA activities.
Sources of Current Licensing Basis Information. The staff reviewed the scope and depth of the applicant's CLB information to verify that the applicant's methodology had comprehensively
 
identified SSCs within the scope of license renewal as well as components types requiring an
 
AMR. As defined in 10 CFR 54.3(a), the CLB is applicable NRC requirements, written licensee
 
commitments for ensuring compliance with, and operation within, applicable NRC requirements, and plant-specific design bases docketed and in effect. The CLB includes certain NRC
 
regulations, orders, license conditions, exempt ions, technical specifications, design-basis information documented in the most recent UFSAR, and licensee commitments made in such
 
docketed licensing correspondence as licensee responses to NRC bulletins, generic letters, and
 
enforcement actions as well as licensee commitments documented in NRC safety evaluations
 
or licensee event reports.
During the audit, the staff reviewed pertinent information sources utilized by the applicant. The staff reviewed samples of information utilized by the applicant, including the 2-21 UFSAR, DBDs, controlled plant reference drawings, LRBDs, and Maintenance Rule information.
In addition, the applicant developed and implemented a CLB database comprised of primarily
 
licensing correspondence, UFSAR, technical spec ifications, fire hazards analysis, safety evaluations, and design documentation. This database enabled the applicant to search specific
 
keywords and phrases to find licensing references applicable to license renewal. The applicant
 
formally trained the license renewal staff on the CLB database and described the contents and
 
practical experience in its use. Training lesson plans reviewed by the staff during the audit
 
contained detailed information on important definitions related to the licensing basis, descriptions of the sources of documents which comprised the CLB, and descriptions of the
 
programs and processes that contain the CLB source information. The applicant's detailed
 
PLI-02 Section 6.0 requires use of the CLB source information in developing scoping
 
evaluations. The applicant used the CLB electronic database, in part, for this process
 
requirement.
The CRL is the applicant's primary repository for component safety classification information.
During the audit, the staff reviewed the applicant's administrative controls for CRL safety
 
classification data and has that the applicant had established adequate measures to control
 
data integrity and reliability. Therefore, the staff concludes that the CRL provided a sufficiently
 
controlled source of component data to support scoping and screening evaluations.
During the staff's review of the applicant's CLB evaluation process, the applicant discussed updates to the CLB and the process for their adequate incorporation into the license renewal
 
process. The applicant provided the staff with PLI-16 and discussed the process defined for
 
such updates. As part of the license renewal effort, the applicant ensured that all engineering
 
change requests approved up to within three months of the LRA submission that could have
 
affected it had been factored in. In addition, PLI-16 guides the evaluation of CLB change
 
documentation that could impact the LRA, describes the process for annual updates to the LRA, and includes a series of checklists to facilitate the evaluation and ensure adequate
 
documentation of the results.
The staff determines that LRA Section 2.1 provides a description of the CLB and related documents used during the scoping and screening process consistent with SRP-LR guidance.
 
In addition, the staff reviewed technical reports supporting identification of SSCs relied upon for
 
compliance with the safety-related criteria, nonsafety-related criteria, and the five regulated
 
events of 10 CFR 54.4(a). PLI-02 and PLI-16 comprehensively lists documents supporting
 
scoping and screening evaluations. The staff finds these design documentation sources useful
 
in ensuring that the initial scope of SSCs identified by the applicant is consistent with the plant's
 
CLB.2.1.3.1.3  Conclusion
 
On the basis of review of information in LRA Section 2.1, the detailed scoping and screening implementation procedures, and the results from the scoping and screening audit, the staff
 
concludes that the applicant's scoping and screening methodology had considered CLB
 
information consistently with SRP-LR and NEI 95-10 guidance and is, therefore, acceptable.
2.1.3.2  Quality Controls Applied to LRA Development 2.1.3.2.1  Staff Evaluation 2-22 The staff reviewed the applicant's quality controls to ensure that scoping and screening methodologies in the LRA had been adequately implemented. Although the applicant did not
 
develop the LRA under a 10 CFR 50, Appendix B, QA program, the applicant utilized the
 
following QA processes during the LRA development:
* The scoping and screening methodology was governed by written procedures, guidelines, PPs, PLIs, and project checklist packages.
* The applicant studied staff requests for additional information (RAIs) from the Dresden, Quad Cities, Nine Mile Point, and Beaver Valley plants to ensure that applicable issues
 
were addressed in the OCGS LRA.
* The LRA was examined and approved by the applicant's Nuclear Safety Review Board and Plant Operations Review Committee.
* The applicant planned to retain certain license renewal documents as quality records or control documents.
* The applicant performed six independent party examinations of LRA development activities.
* Nuclear Oversight performed two self-assessments of the implementation of LRA.
2.1.3.2.2  Conclusion
 
On the basis of review of pertinent LRA development guidance, discussion with the applicant's license renewal personnel, and review of the quality audit reports, the staff concludes that these
 
QA activities provided additional assurance that LRA development activities had been in
 
accordance with the LRA descriptions.
2.1.3.3  Training 2.1.3.3.1  Staff Evaluation The staff reviewed the applicant's training process for consistent and appropriate performance of the guidelines and methodology for scoping and screening. PLI-12 guided the training of the
 
applicant's license renewal project team and site personnel and required them to review
 
applicable license renewal regulations, NEI 95-10, and associated procedures. The applicant
 
developed periodic production meetings in which the license renewal project team members shared their knowledge and experience. The staff reviewed the training records of the
 
applicant's license renewal personnel and noted no discrepancies.
2.1.3.3.2  Conclusion
 
Based on discussions with the applicant's license renewal personnel responsible for the scoping and screening process and a review of selected documentation supporting the process, the staff
 
concludes that the applicant's personnel understood the requirements and adequately
 
implemented the scoping and screening methodology documented in the LRA. The staff
 
concludes that the license renewal personnel were adequately trained and qualified for license
 
renewal activities.
2-23 2.1.3.4  Conclusion of Scoping and Screening Program Review On the basis of review of information in LRA Section 2.1, review of the applicant's detailed scoping and screening implementation procedures, discussions with the applicant's LRA
 
personnel, and review of the results from the scoping and screening audit, the staff concludes
 
that the applicant's scoping and screening program is consistent with SRP-LR guidance and, therefore, acceptable.2.1.4  Plant Systems, Structures, and Components Scoping Methodology In LRA Section 2.1, the applicant described the methodology for scoping SSCs pursuant to 10 CFR 54.4(a) and the scoping process for the plant in terms of systems and structures, identified system/structure level functions, and evaluated these functions against the
 
10 CFR 54.4(a) scoping criteria to determine whether they perform a license renewal intended
 
function. The applicant evaluated the components in the systems and structures within the
 
scope of license renewal. The in-scope boundary was depicted on the LRBDs. The applicant's
 
scoping methodology, as described in the LRA, is discussed in the sections below.
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 2.1.5.1, "Safety Related - 10 CFR 54.4(a)(1)," the applicant described the 10 CFR 54 scoping methodology and the 10 CFR 54.4(a)(1) safety-related criteria. The
 
applicant stated that safety-related SCs are identified in the CRL and that safety-related
 
classifications for SSCs are based on descriptions and analyses in the UFSAR or on DBDs like
 
engineering drawings, evaluations or calculations. SSCs identified as safety-related in the
 
UFSAR, in DBDs, or in the CRL were classified under 10 CFR 54.4(a)(1) and included within
 
the scope of license renewal. The applicant also confirmed that all plant conditions, including
 
normal operation, abnormal operational transients, design-basis accidents, internal and external
 
events, and natural phenomena for which the plant must be designed, had been considered for
 
license renewal scoping under 10 CFR 54.4(a)(1) criteria.
The CLB definition of "safety-related" is not identical to the definition in the Rule. The applicant evaluated the differences between the CLB and Rule definitions and documented the evaluation
 
in LRA Section 2.1.3.2, "Identification of Safety-Related Systems and Structures," as well as in
 
PP-02 and PP-13.
2.1.4.1.2  Staff Evaluation Under 10 CFR 54(a)(1), the applicant must consider all safety-related SSCs relied upon to remain functional during and following a design basis event (DBE) to ensure (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 in 10 CFR
 
50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11.
As to identification of DBEs, SRP-LR Section 2.1.3 states:
2-24 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
 
defined in 10 CFR 50.49(b)(1)) to ensure the functions described in
 
10 CFR 54.4(a)(1).
The applicant scoped SSCs for the 10 CFR 54.4(a)(1) criterion following PP-01, -02, -13, and PLI-02, which guided the preparation, review, verification, and approval of the scoping
 
evaluations to ensure adequate results. The staff reviewed these guidance documents governing
 
the applicant's evaluation of safety-related SSCs and sampled the applicant's scoping results
 
reports to ensure that the methodology had been implemented in accordance with those written
 
instructions. In addition, the staff discussed the methodology and results with the applicant's
 
personnel responsible for the evaluations.
Specifically, the staff reviewed a sample of the license renewal scoping results for the ICS and the reactor building for additional assurance that the applicant has adequately implemented their
 
safety-related scoping methodology. The staff verified that the scoping results for the sampled
 
system and structure had been developed consistent ly with the methodology, that the SSCs credited for performing intended functions had been identified, and that the bases for the results
 
as well as the intended functions had been adequately described. The staff 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 10 CFR 54.4(a)(1).
To help facilitate the identification of SSCs within the scope of license renewal in accordance with 10 CFR 54.4(a), the applicant developed a license renewal database with detailed design
 
description information about each plant system and structure and their relevant functions. A list
 
of safety-related plant systems and structures was initially identified from the existing components list in the CRL which is part of the plant information management system. The CRL safety classification field was studied to ensure that any plant system and structure with a
 
safety-related component had been considered for inclusion within the scope of license renewal.
 
Additionally the CRL safety classification and asso ciated plant system drawings provided starting points for identifying specific components required to meet the 10 CFR 54.4(a)(1) criterion.
 
During the audit, the applicant described the process for evaluating components classified as
 
safety-related that performed no safety-related intended functions. The applicant stated that the
 
safety classification of several components was reevaluated to reconcile differences between
 
scoping determinations and facility database or CLB information. Identified safety-related
 
components that performed no intended functions and the rationales for their exclusion from
 
scope of license renewal were explicitly descr ibed in PP-02. Examples included the containment leak rate testing system, drywell c ooling system, and service air system.
The staff reviewed the safety classification criteria to verify consistency between the CLB definition and the Rule definition and reviewed the applicant's evaluation of the differences
 
between the Rule definition and the site-specific definition of "safety-related" to ensure that all
 
potential 10 CFR 54.4(a)(1) SSCs had been adequately addressed. The applicant documented 2-25 its evaluation in PP-02, stating that the site-specific definition of "safety-related" was nearly identical to the Rule definition with the following three exceptions.  (1)The CLB defines a safety-related SSC as designed to remain functional for all design basis conditions whereas the Rule defines it as designed to remain functional for all
 
DBEs.    (2)The CLB definition requires that the reactor be shut down and maintained in a safe (hot) shutdown condition whereas the Rule definition requires that the reactor be maintained in
 
a safe shutdown condition.  (3)The CLB definition refers to potential 10 CFR Part 100 off-site exposure limits whereas the Rule definition refers also to comparable guidelines in 10 CFR 50.34(a)(1) and
 
10 CFR 50.67(b)(2).
As to the first exception the staff questioned how non-accident DBEs, particularly those that may not be described in the UFSAR, had been considered during scoping. The applicant responded
 
by identifying applicable DBEs, including external hazards like fire, earthquakes, flooding, wind
 
and missiles, and high-energy line breaks. The additional DBEs were evaluated in PP-13, prepared by the applicant as a primary source for identifying structures and systems within the
 
scope of license renewal. The staff reviewed PP-13, discussed it with the applicant, and finds it a
 
concise and detailed evaluation of these events, including appropriate references to CLB
 
documentation supporting the evaluation, and of systems and structures relied upon to remain
 
functional during and following DBEs. The staff concludes that the applicant has considered a
 
scope of DBEs consistent with SRP-LR guidance.
As to the second exception the applicant verified that all SSCs required to shut down the reactor and maintain it in a cold shutdown condition were considered safety-related at the facility and
 
included within the scope of license renewal in accordance with 10 CFR 54.4(a)(1).
As to the third exception the applicant verified that the comparable guidelines of the cited regulations did not affect the scoping evaluation because the applicant had not revised the
 
current accident source term used in the design basis radiological analysis (10 CFR 50.67(b)(1))
 
and because 10 CFR 50.34(a)(1)(ii) dose limits pertain only to applicants that applied for
 
construction permits on or after January 10, 1997, which is not the case for OCGS. In addition, the applicant stated that 10 CFR 50.34(a)(1)(i) refers to 10 CFR Part 100 only, as does the CLB.
The staff reviewed the applicant's evaluation and discussed it with the applicant's license renewal team. The staff determines that the differences between the applicant's "safety-related"
 
definition and the Rule definition had been adequately evaluated by the applicant and had not
 
caused any additional components to be considered safety-related beyond those identified in the
 
CLB.2.1.4.1.3  Conclusion
 
Based on this sample review, discussions with the applicant, and review of the applicant's scoping process, the staff determines that the applicant's methodology for identifying systems
 
and structures meets 10 CFR 54.4(a)(1) scoping criteria and is, therefore, acceptable.
2.1.4.2  Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 2-26 2.1.4.2.1  Summary of Technical Information in the Application In LRA Section 2.1.5.2, "Nonsafety-related affecting safety-related - 10 CFR 54.4(a)(2)," the applicant described the scoping methodology for 10 CFR 54.4(a)(2) nonsafety-related criteria.
 
The applicant evaluated SSCs under 10 CFR 54.4(a)(2) with four categories. A summary
 
description of the four categories:    (1)Nonsafety-related SSCs required for functions that support safety-related system intended functions. The nonsafety-related SSCs credited in the CLB that support safety-related system intended functions were included within the scope of license
 
renewal under 10 CFR 54.4(a)(2) and the scoping evaluation for each system was
 
documented. When a system was included within the scope of license renewal pursuant
 
to 10 CFR 54.4(a)(1), the scoping evaluation included the identification of any additional
 
systems required to support the safety-related system intended function(s).    (2)Nonsafety-related systems connected to and providing structural support for safety-related SSCs. Nonsafety-related systems connec ted to safety-related systems were entirely within the scope of license renewal under 10 CFR 54.4(a)(2) up to and
 
including the first seismic anchor past the safety-related and nonsafety-related interface, up to a flexible hose or joint not capable of load transfer, or up to the end of the piping
 
run. An anchor or three mutually perpendicular restraints as described in the CLB were
 
considered equivalent to a seismic anchor. Grouted walls or slab penetrations or such
 
anchored components as pumps, heat exchangers, or turbines were also considered
 
equivalent to seismic anchors. Underground piping was also considered equivalent.  (3)Nonsafety-related systems with a potential for spatial interaction with safety-related SSCs. Nonsafety-related systems not direct ly connected to safety-related piping or components or connected downstream from the first seismic or equivalent anchors were
 
within the scope of license renewal pursuant to 10 CFR 54.4(a)(2) if their failure could
 
adversely impact the performance of safe ty-related SSC intended functions. Failures considered included nonsafety-related piping failures on adjacent SSCs (e.g., pipe whip, jet impingement, spray, flooding, etc.) and loss of nonsafety-related piping supports
 
causing piping to fall on safety-related SSCs (seismic II/I). To determine which
 
nonsafety-related SSCs were within the scope of license renewal, the applicant evaluated
 
two options, mitigative or preventive.
The mitigative option considered the failure of nonsafety-related systems on safety-related SSCs with the effects controlled by some feature(e.g. whip restraints, spray
 
shields, supports, barriers, etc) installed on the safety-related SSCs. With this mitigation
 
the failure of the nonsafety-related syst em will not prevent the performance of a 10 CFR 54.4(a)(1) safety-related system intended function. With the mitigative option the
 
mitigative feature (whip restraints, spray shields, supports, barriers, etc.) is included
 
within the scope of license renewal pursuant to 10 CFR 54.4(a)(2). The nonsafety-related
 
systems can be excluded from the scope of license renewal provided the mitigative features are adequate to address all potential failure locations that could result from
 
aging.For the preventive option, vulnerable safe ty-related systems in proximity to the nonsafety-related systems are identified by pl ant walkdowns to identify nonsafety-related systems or portions with the potential for spatial interaction (pipe whip, spray, flooding, 2-27 etc.) with safety-related equipment, assuming a failure anywhere along the length of the safety-related system. Nonsafety-relat ed SSCs also include heavy load-lifting equipment that could drop on and damage safety-related equipment.
The applicant applied the preventive option for 10 CFR 50.54(a)(2) scoping without consideration of mitigative features. However, certain mitigative features of the CLB were
 
also included within the scope of license renewal. Nonsafety-related systems that contain
 
water, oil, or steam located inside structures with safety-related systems were included
 
within the scope of license renewal for potential spatial interaction under
 
10 CFR 54.4(a)(2). All supports for nonsafety-related systems with a potential for spatial
 
interaction with safety-related SSCs were included within the scope of license renewal as
 
commodities.    (4)Certain nonsafety-related mitigative plant design features that were part of the CLB
.Nonsafety-related SSCs identified as mitigative plant design features in the CLB included
 
turbine building walls (missile protection), walls, dikes, curbs, seals (flood protection), and spray shields.
Air and gas systems were not included within the scope of license renewal because they are not hazards to other plant equipment. Plant-specific operating experience verified that they have not
 
adversely affected other plant equipment. Industr y operating experience also reveals no events of this nature. Therefore, the applicant concluded that the air/gas systems are not within the
 
scope of license renewal. However, supports for air/gas systems with a potential to fall on
 
safety-related systems were included within the scope of license renewal as commodities.
2.1.4.2.2  Staff Evaluation
 
Pursuant to 10 CFR 54(a)(2), the applicant must consider all nonsafety-related SSCs the failure of which could prevent satisfactory performance of safety-related SSCs relied upon 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 cause potential
 
offsite exposures comparable to those of 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or
 
10 CFR 100.11.
By letters dated December 3, 2001, and March 15, 2002, the NRC issued a staff position to the NEI with expectations for identifying 10 CFR 54.4(a)(2) SSCs. The December 3 rd letter provides specific examples of operating experience with pipe failure events (summarized in NRC
 
Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor") and the
 
approaches the NRC considers acceptable to determine which piping systems should be
 
included within the scope of license renewal for 10 CFR 54.4(a)(2). The March 15 th letter further described the staff's expectations for the evaluation of non-piping SSCs to determine which
 
additional nonsafety-related SSCs are within the scope of license renewal. The position states
 
that applicants should not consider hypothetical failures but rather should base their evaluation
 
on the plant's CLB, engineering judgement and analyses, and relevant operating experience.
 
The letter further describes operating experience as all documented plant-specific and industry
 
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, such
 
industry reports as safety operational event reports, and engineering evaluations.
2-28 The staff reviewed LRA Section 2.1.5.2, PLI-02, PP-01, PP-03, and PP-13 Table 2, "Systems and Structures Credited with Operating (Not for Performance of Section 54.4(a)(1) Function)
 
During and Following Non DBA DBEs." PP-01 identifies systems and structures subject to
 
10 CFR 54.4. PP-01 Attachment 1 lists the 109 systems and 40 structures requiring review for
 
license renewal. PLI-02 describes the process for reviewing these 109 systems and 40
 
structures and the requirements for entering the results of the review into the license renewal
 
database. The applicable PP, system/structure functions, intended functions, determination of
 
scope of license renewal, supporting systems, and 10 CFR 54.4(a) evaluations were addressed
 
in PLI-02.
The applicant evaluated 10 CFR 54.4(a)(2) SSCs with the four categories taken from the NRC guidance to the industry on identification and treatment of such SSCs:  (1) Nonsafety-related SSCs required for functions that support safety-related SSCs. PLI-2 Sections 6.7 and 6.11, and PP-13 Table 2 implement this process. PLI-2 Section 6.7
 
provides guidance for identifying support sy stems. Support systems that support a safety-related system in performing intended functions had to be identified. PLI-2
 
Section 6.11 required inclusion in the license renewal database scoping input form of the
 
functional support by nonsafety-related SSCs enabling safety-related systems to perform intended functions. PP-13 Table 2 lists nonsafety-related systems not credited with
 
10 CFR 54.4(a)(1) functions but credited with operating during and following an event.
 
This list was used to determine nonsafety-related systems that support safety-related
 
systems in performing intended functions.
The staff finds that the applicant has implemented an acceptable method for scoping of nonsafety-related systems that perform f unctions that support safety-related intended functions.
For the remaining three categories, PP-03 provides the criteria for identifying SSCs within the scope of license renewal under 10 CFR 50.54.4(a)(2). PP-03 Section 4.3 states that a spaces
 
approach was used to identify such nonsafety-related SSCs. Initially, structures that house
 
safety-related systems were identified. Structur e safety classifications, safety-related system design drawings, and the locations of safety-related components identified in the CRL were used
 
to identify structures that house safety-related components. Seven structures (primary
 
containment, reactor building, emergency diesel generator building, exhaust tunnel, heating
 
boiler house, office building, and turbine building) were identified as containing safety-related
 
systems with components that could fail under wet conditions. These structures, structural
 
components, and component supports were identified as within the scope of license renewal.
Although there are safety-related and nonsafety-related equipment in the miscellaneous yard structure and intake structure, the nonsafety-related equipment in these structures was not
 
included within the scope of license renewal under 10 CFR 50.54(a)(2) because these structures
 
are open to the environment and designed for wet c onditions. Nonsafety-related systems in the miscellaneous yard structure are underground with no potential for spacial interaction between
 
safety-related and nonsafety-related systems. The inta ke structure is classified as safety-related and included within the scope of license renewal pursuant to 10 CFR 50.54(a)(1). Therefore, all
 
intake structural components and component supports were included within the scope of license
 
renewal pursuant to 10 CFR 50.54(a)(1).
2-29 All nonsafety-related systems in the primary containment, reactor building, emergency diesel generator building, exhaust tunnel, heating boiler house, office building, and turbine building
 
were evaluated:  (2)Nonsafety-related systems connected to and providing structural support for safety-related SSCs. PLI-02 Section 6.11 and PLI-03 Section 4.5 implement this process.
Section 6.11 requires that the establishment of license renewal boundaries between
 
nonsafety-related systems connected to sa fety-related systems be documented in the license renewal database scoping form. PP-03 Section 4.5 states that the entire
 
nonsafety-related system is within the scope of license renewal under 10 CFR 54.4(a)(2)
 
up to and including the first seismic anchor past the safety-related and nonsafety-related
 
interface, up to a flexible hose or joint not capable of load transfer, or up to the end of the
 
piping run. An anchor or three mutually perpendicular restraints as described in the CLB
 
were considered equivalent to a seismic anchor. Large components like pumps or heat
 
exchangers, piping anchored to walls or slabs, and piping routed underground were also
 
considered equivalent to a seismic anchor. Large components, walls, or slabs were
 
included within the scope of license renewal when credited as seismic anchors.
NEI 95-10 states that an equivalent seismic anchor is typically defined as at least two rigid supports in each of the three orthogonal directions. However, the CLB (Specification
 
1302-12-294, "Technical Specifications for Oyster Creek Pipe Stress Analysis,"
 
Revision 2) states that at least one rigid support in each of the three orthogonal directions
 
is equivalent to a seismic anchor. The staff considered the CLB definition for equivalent
 
seismic anchor in Specification 1302-12-294 appropriate. The staff's review of the LRA, implementing procedures, grouted penetrations, and underground piping 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. PP-03 Section 4.5.1 provides instructions for establishing system boundaries for nonsafety-related piping systems connected di rectly to safety-related piping systems.
One of the acceptable methods in PP-03 for establishing license renewal piping system
 
boundaries is to extend the piping system boundary up to a wall or slab past the
 
safety-related and nonsafety-related interface and credit the grouted wall or slab piping
 
penetration as equivalent to a seismic anchor. The applicant stated that 13 grouted wall
 
or slab piping penetrations were credited as equivalent anchors. Two of the 13 grouted
 
wall or slab piping penetrations were included in stress calculation C-1302-251-5320-004, Revision 4, which demonstrated that these two grouted wall or piping penetrations were
 
equivalent to seismic anchors. No technical analysis demonstrated that the remaining 11
 
grouted wall or slab piping penetrations were equivalent to seismic anchors.
In RAI 2.1.5.2-1 dated November 9, 2005, the staff requested that the applicant provide technical basis demonstrating that the 11 grouted wall or slab piping penetrations are
 
equivalent to seismic anchors.
In its response dated December 9, 2005, the applicant stated that 7 of the 11 grouted penetrations credited as equivalent to seismic anchors for license renewal had been
 
addressed in the CLB piping analysis. The applicant provided an acceptable technical
 
justification for crediting the remaining 4 grouted piping penetrations as equivalent to
 
seismic anchors in its response. The staff reviewed the applicant's response and 2-30 concludes that the applicant has adequately described its process for establishing the use of grouted wall penetrations as equivalent to seismic anchors. The staff's concern
 
described in RAI 2.1.5.2-1 is resolved.
LRA Section 2.1.5.2 describes the applicant's screening and scoping methodology for nonsafety-related systems connected to safety-related systems. This section of the LRA states that piping that exits a structure and is routed underground is credited as
 
equivalent to a seismic anchor. This same methodology is described in PP-03
 
Section 4.5.1.3. During the audit, the applicant clarified that, although described in the
 
LRA and PP-03, this methodology was not used.
In RAI 2.1.5.2-2 dated November 9, 2005, the staff requested that the applicant verify that underground piping was not credited as equivalent to a seismic anchor.
In its response dated December 9, 2005, the applicant stated that underground piping was not credited as an equivalent anchor for license renewal. The staff reviewed the
 
applicant's response and concludes that it has adequately described the process for
 
establishing equivalence to seismic anchors. The staff's concern described in
 
RAI 2.1.5.2-2 is resolved.
 
  (3)Nonsafety-related SSCs not directly connected to safety-related SSCs. PLI-02 Section 6.11 and PP-03 Section 4.6 implement this process. PLI-02 Section 6.11 requires
 
documentation in the license renewal database scoping form of evaluations of any
 
potential adverse interactions between nonsafety-related and safety-related SSCs not
 
physically connected. PLI-03 Section 4.6 st ates that, although non-liquid systems are not within the scope of license renewal, supports for non-liquid systems in areas of potential
 
seismic interaction with safety-related sy stems are included. All high-energy lines that contain water, oil, or steam were within the scope of license renewal. All moderate- and
 
low-energy lines that contain water, oil, or steam during plant operation were included
 
within the scope of license renewal. Supports for seismic Class II piping, cranes, monorails, and hoists were also included within the scope of license renewal.    (4)Certain nonsafety-related mitigative plant design features in the CLB. PP-03 Section 4.4 stated that nonsafety-related missile barriers (walls), flood barriers (walls, slabs, curbs, drains, and seals), and spray shields addressed in the CLB are within the scope of
 
license renewal under 10 CFR 54.4(a)(2). Structures with mitigative plant design features
 
were listed in PP-01.
2.1.4.2.3  Conclusion
 
On the basis of its review and the RAI responses, the staff determines that the applicant's methodology for identifying systems and structures meets 10 CFR 54.4(a)(2) scoping criteria and
 
is, therefore, acceptable. This determination is based on a review of sample systems, discussions
 
with the applicant, and review of the applicant's scoping process, 2-31 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 2.1.3.4, "Systems and Structures Credited for Regulated Events," the applicant described the scoping methodology for SSCs relied upon in safety analyses or plant evaluation
 
reports performing intended functions. SSCs for fire protection, environmental qualification (EQ),
anticipated transient without scram (ATWS), and station blackout (SBO) were included within the
 
scope of license renewal in accordance with 10 CFR 54.4(a)(3). The methodology used to
 
determine the scope of SSCs required by 10 CFR 54.4(a)(3) is described in LRA Section 2.1.3.4.
 
The applicant utilized PPs, PLIs, and the CRL for input to the scoping process.
Fire Protection. In LRA Sections 2.1.3.4, 2.1.4.7, 2.1.6.3, and 2.3.3.15, the applicant described the scoping of SSCs required to demonstrate compliance with 10 CFR 50.48 fire protection
 
requirements. The applicant's technical PP and CLB references for fire protection include (1)
 
PP-07, (2) the Fire Hazard Analysis Report (FHAR), (3) the Fire Safe Shutdown (FSSD) Analysis, (4) UFSAR Section 9.5.1, and (5) the CRL fire protection data field. Using these information
 
sources, the applicant identified components required to support fire protection safe shutdown
 
functions and added them to the license renewal database. SSCs relied upon in safety analyses
 
or plant evaluations to perform functions for co mpliance with NRC fire protection regulations were included within the scope of license renewal.
Environmental Qualification. In LRA Section 2.1.3.4, the applicant described the scoping of SSCs required to demonstrate compliance with 10 CFR 50.49 EQ requirements. PP-06 summarizes the
 
results of the study of EQ program docum ents. The applicant selected electrical equipment required for EQ from the EQ Master List. PP-06 lists systems that include EQ components from the EQ Master List of the CRL.
Pressurized Thermal Shock. These requirements are not applicable to OCGS, a boiling water reactor (BWR).
Anticipated Transient Without Scram. In LRA Section 2.1.3.4, the applicant described the scoping of SSCs required to demonstrate compliance with 10 CFR 50.62 ATWS requirements. PP-05
 
summarizes the CLB as to ATWS and lists systems required by 10 CFR 50.62 to reduce the risk
 
of an ATWS event and structures physically supporting and protecting the credited ATWS systems. Station Blackout. In LRA Section 2.1.3.4, The applicant described the scoping criteria and in PP-04, the applicant summarizes the CLB as to SBO and lists systems and structures credited
 
with mitigating SBO events.
In accordance with ISG-02, the applicant identified SSCs required to recover from the SBO event and included within the scope of the license renewal. For OCGS, this portion of the plant electrical
 
system connects safety-related buses to onsit e emergency power and offsite power to recover from SBO events. Disconnection switches on the supply side of switch yard circuit breakers
 
connecting the 34.5 kV OCGS substation to the plant and continuing through the startup
 
transformers to the switchgear breakers of the plant 4160 alternating current (AC) breakers were
 
included within the scope of license renewal.
2.1.4.3.2  Staff Evaluation 2-32 Pursuant to 10 CFR 54.4(a)(3), the applicant must consider all SSCs relied on in safety analyses or plant evaluations to perform functions for co mpliance with NRC regulations for fire protection, EQ, ATWS, and SBO.
SRP-LR Section 2.1.3.1.3, "Regulated Events," states that all SSCs relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant-specific operating experience, industry operating experience (as appropriate), and safety analyses or plant evaluations to perform functions for compliance
 
with NRC regulations under 10 CFR 54.4(a)(3) must be included within the scope of license
 
renewal. However, hypothetical failures that could result from system interdependencies not part
 
of the CLB and not been previously experienced need not be included.
The staff reviewed the applicant's approach to identifying SSCs relied upon to perform functions related to the four regulated events applicable to BWRs as described in 10 CFR 54.4(a)(3). As
 
part of this review, the staff discussed the methodology with the applicant's license renewal team, reviewed the supporting documentation, and evaluated a sample of the SSCs identified as within
 
the scope of license renewal under 10 CFR 54.4(a)(3).
Fire Protection. For the fire protection regulated event, the staff reviewed the LRA sections noted and PP-07. Components that satisfy fire protection safe shutdown requirements were listed in the
 
FHAR, the FSSD, the CRL fire protection data field, and Appendix R Safe Shutdown Path
 
drawings. The applicant's fire protection confirmation process downloaded CRL fire protection
 
data fields into a database and compared them to FSSD components. This process identified no
 
additional fire protection components.
In addition, LRA Section 2.1.6.3 states in part that equipment stored on site for installation in response to a DBE is considered within the scope of license renewal. The stored equipment
 
credited for 10 CFR Part 50, Appendix R, repairs includes cables and connectors, hoses, tubing, fittings, screws, butts, washers, exhaust fans, and flexible duct. These components were within
 
the scope of license renewal. Tools and supplies used to place stored equipment in service were
 
not within the scope of license renewal. The staff finds the LRA identification of stored equipment
 
within the scope of license renewal acceptable.
In PP-07, Table 1, "Systems Credited for FSSD with Associated FSSD Functions," the applicant listed all FSSD components. In PP-07, Table 2, "Systems Credited for Fire Detection and
 
Suppression," the applicant listed from UFSAR Section 9.5.1 systems required for fire detection
 
and suppression. PP-07, Table 3, "Additional Systems Credited in Commitments Made in
 
Response to Appendix A to Branch Technical Position (BTP) APSCB 9.5-1," the applicant
 
identified additional commitments for systems and components that remove smoke and water and
 
prevent water damage after a fire. The applicant consolidated the three PP-07 tables in Table 4, "Consolidated Table of Systems Relied Upon to Demonstrate Compliance with 10 CFR 50.48." In
 
addition, PP-07, Table 5, "Structures Required to Demonstrate Compliance with 10 CFR 50.48,"
 
lists structures and structural support components that comply with fire protection requirements.
 
In the LRA, the applicant used the last two tables to consolidate the scoping effort at the structure
 
and system level.
The staff's review of the LRA 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 RAIs as discussed below.
2-33 PP-07 Section 4 states that first-level, primar y support systems necessary for equipment credited in the FHAR or safe shutdown analysis to function for compliance with 10 CFR 54.48 are included
 
within the scope of license renewal. PP-07 Table 1 lists the standby gas engine (propane)
 
generator as within the scope of license renewal. However, LRA Section 2.5.1.15 does not list the
 
backup gas (propane) engine generator as within the scope of license renewal. The applicant
 
stated during the audit that LRA Section 2.5.1.15 is correct and that the backup gas (propane)
 
generator was removed from the scope of license renewal because it is not the radio
 
communication system's primary power source.
In RAI 2.5.1.15-1 dated November 9, 2005, the staff requested that the applicant:
  (1)Verify that the CLB, plant-specific experience, industry experience (as appropriate), and safety analyses or plant evaluations do not require the backup gas (propane) generator to
 
perform a function for compliance with NRC regulations under 10 CFR 54.4(a)(3).  (2)Verify that second-, third-, or fourth-level support systems were included within the scope of license renewal if the CLB, plant-specific experience, industry experience (as
 
appropriate), and safety analyses or plant evaluations require such support systems to
 
perform functions for compliance with NRC regulations under 10 CFR 54.4(a)(3).
In its responses dated October 12, November 11, and December 9, 2005, and May 18 and June 7, 2006, the applicant stated that it had determined that the repeater located at the
 
Meteorological Tower (Met Tower) is credited for communication capabilities for some
 
10 CFR Part 50, Appendix R, scenarios. Therefore, the repeater and associated support
 
equipment, including the backup gas (propane) engine generator located at the Met Tower, are
 
now within the scope of license renewal and subject to an AMR. The applicant also stated that the
 
second-, third-, and fourth-level support systems were included within the scope of license
 
renewal if the CLB, plant-specific experience, industry experience, and safety analyses or plant evaluations require these systems to perform functions for compliance with 10 CFR 54.4(a)(3).
 
The staff reviewed the applicant's response and concludes that it is adequate. The staff's
 
concerns described in RAI 2.1.5.15-1 are resolved.
Based on the review of the LRA, PP-07, and ISGs the staff finds that the fire protection implementing documents for license renewal meet 10 CFR 54.4(a)(3) requirements.
Environmental Qualification. For the EQ regulated event, the staff evaluated LRA Section 2.1.3.4 and PP-06. The UFSAR Section 3.11.1.1.1, "Criteria for Selection of Equipment," identifies the
 
scope of electrical equipment and components that must be environmentally qualified for use in harsh environments. The electrical components in the EQ Master List were entered into the CRL, which CRL includes an EQ data field for identifying EQ components. In PP-06 Table 1, "Systems
 
Subject to 10 CFR 50.49 EQ Requirements," the applicant identified mechanical, electrical, and
 
instrumentation and control (I&C) systems with EQ equipment within the scope of license
 
renewal. PP-06 Table 1 was compared to the EQ Master List to verify that the EQ Master List was
 
consistent with the CRL. In PP-06 Table 2, "Structures Associated with EQ Environmental
 
Boundaries," the applicant identified structures that provide physical boundaries for postulated
 
harsh environments with EQ electrical equipment included within the scope of license renewal:
 
the containment, reactor building, turbine building, standby gas treatment exhaust tunnel, containment electrical penetrations, and EQ barriers in the 4160V switchgear.
2-34 The staff finds that the LRA and PP-06 adequately identified the scope of EQ electrical systems, electrical penetrations, cable routing and terminations, and structures within the scope of license
 
renewal. Anticipated Transient Without Scram. For the ATWS regulated event, the staff evaluated LRA Section 2.1.3.4 and PP-05. PP-05, Attachment 1, identifies systems within the scope of license
 
renewal. PP-05, Attachment 2, identifies the primary containment, reactor building, turbine
 
building, and the component supports commodity group as within the scope of license renewal.
 
The staff finds that the LRA and PP-05 adequately identify ATWS SSCs within the scope of
 
license renewal.
Station Blackout. For the SBO regulated event, the staff evaluated LRA Sections 2.1.3.4 and 2.1.4 and several mechanical, structural, and electrical systems in LRA Sections 2.3, 2.4, and
 
2.5. The staff compared the LRA information to that of PP-04, Table I, "Systems and Structures
 
Credited to Cope with an SBO Event," Table II, "Systems Credited for Safe Shutdown During a
 
Station Blackout," Table III, "Systems Required to Recover from a Station Blackout Event," and
 
Table IV, "Structures Required For Station Blackout Event," where the applicant identified the
 
SBO electrical and mechanical systems and components and support structures that house SBO
 
equipment within the scope of license renewal needed under 10 CFR 54.4(a)(3) to meet the SBO
 
regulated event.
In PP-04, the applicant stated that it had added the alternate AC (AAC) power supply system to the existing plant configuration to comply with the SBO rule. The AAC source is provided by one of two non-Class IE combustion turbines located at the Forked River site adjacent to OCGS. The
 
AAC source supplies power to OCGS via a connection to the non-1E 4160V "1B" switchgear. In
 
PP-04, Table II, the AAC combustion turbines and thei r sub-systems, the turbine lube oil system, the fuel system, the direct current (DC) power system, and the SBO transformer are parts of the AAC Power Supply System within the scope of license renewal for the SBO regulated event under
 
10 CFR 54.4(a)(3). In PP-04, Table IV, the applicant identified the Forked River Combustion
 
Turbine (FRCT) buildings as support structures pr otecting relay cables, I&C cables, combustion turbines, and other equipment.
In LRA Table 2.5.1.19, the ACC combustion turbines are identified as one combustion turbine power plant unit within the scope of license renewal and subject to an AMR. As described in SER
 
Section 2.5.5.2), in its response to RAI 2.5.1.19-1, the applicant stated that it had revised the
 
combustion turbine power plant unit scoping and screening methodology. Mechanical, electrical, and structural component types were itemized in detail consistent with scoping and screening
 
methodology for other the other license renewal systems and structures.
The staff finds that the LRA, as revised in the response to RAI 2.5.1.19-1, and the methodology as described in PP-04 has adequately identified SSCs within the scope of license renewal for the
 
SBO regulated event.
2.1.4.3.3  Conclusion
 
Based on the sample review, RAI responses, discussions with the applicant, and review of the applicant's scoping process, the staff determines that the applicant's methodology for identifying
 
systems and structures meets 10 CFR 54.4(a)(3) scoping criteria and is, therefore, acceptable.
2.1.4.4  Plant-Level Scoping of Systems and Structures 2-35 2.1.4.4.1  Summary of Technical Information in the Application System and Structure Level Scoping. In LRA Section 2.1, the applicant described the scoping methodology for safety-related and nonsafety-related systems and structures and equipment relied upon for functions for 10 CFR 54.4(a)(3) regulated events. The scoping methodology is
 
consistent with guidance by the NRC in the SRP-LR and by the industry in NEI 95-10. In LRA
 
Section 2.2, using the methodology described in LRA Section 2.1, the applicant evaluated
 
systems and structures to determine whether they were within the scope of license renewal. The
 
results of plant scoping are provided in LRA Table 2.2-1.
Component Level Scoping. The applicant identified the systems and structures within the scope of license renewal and determined the components within each mechanical system and structure.
 
The structural and mechanical components supporting intended functions were considered within
 
the scope of license renewal and screened to determine whether AMRs were required. All
 
electrical components of in-scope mechanical and electrical systems were included as commodity groups. The applicant considered three component classifications during this stage of the scoping
 
methodology: mechanical, structural, and electrical. The CRL lists plant components
 
comprehensively. The database identifies components by type and unique number, LRA Table 2.2-1 identifies them by component type only.
Commodity Groups Scoping. All electrical components of in-scope of mechanical and electrical systems were included as commodity groups. Many active electrical commodity groups were screened out and not subject to an AMR. In LRA Section 2.5.1, the applicant described the
 
commodity groups used to evaluate all in-sc ope electrical components subject to an AMR.
Structural components were grouped as component types based on design function, materials of construction, and environments. LRA Section
 
===2.4 states===
that such component types as component supports and piping and component insulation were placed in commodity groups.
Insulation. LRA Section 2.4.19 states that insulation installed on hot piping or components of structures within the scope of license renewal (with the exception of miscellaneous yard
 
structures) were included within the scope of license renewal as a commodity group. All insulation
 
was considered nonsafety-related. Therefore, the piping and component insulation commodity
 
group is within the scope of license renewal under 10 CFR 54.4(a)(2) because insulation performs
 
a function that supports a 10 CFR 54.4(a)(1) system. Piping and component insulation in the
 
miscellaneous yard structure is not within the scope of license renewal because its failure does
 
not impact an safety-related intended function.
Consumables. LRA Section 2.1.6.4, the applicant discussed consumables, using the guidance in SRP-LR Table 2.1-3 to categorize and evaluate consumables. Consumables were divided into the
 
following four categories for the purpose of license renewal: (a) packing, gaskets, component
 
seals, and o-rings, (b) structural sealants, (c) oil, grease, and component filters, and (d) system
 
filters, fire extinguishers, fire hoses, and air packs.
Group (a) subcomponents are not relied on to form a pressure-retaining function and, therefore, are not subject to an AMR. Group (b) structural sealants for structures within the scope of license
 
renewal require an AMR. Group (c) subcomponents are periodically replaced in accordance with
 
plant procedures and therefore are not subject to an AMR. Group (d) consumables are subject to
 
replacement based on National Fire Protection Association standards in accordance with plant
 
procedures and, therefore, are not subject to an AMR.
2-36 2.1.4.4.2  Staff Evaluation The staff reviewed the applicant's methodology for scoping plant systems and components for consistency with 10 CFR 54.4(a). The methodology used to determine the systems and
 
components within the scope of license renewal is documented in PP-01, PP-02, PP-04, PP-05, PP-06, PP-07, PP-08, PP-13, and PLI-02, and plant level scoping results are identified in LRA
 
Table 2.2-1. The scoping process defined the entire plant in terms of systems and structures.
 
Specifically, PP-01 identifies systems and structures subject to 10 CFR 54.4 review. PLI-02
 
describes the process for entering process results into the license renewal database. PP-02 and
 
PP-13 were used to determine whether the system or structure was safety-related. PP-03 was
 
used to determine whether failure of a nonsafety-related system or structure could prevent a safety-related system or structure from per forming an intended function. PP-04 (SBO), PP-05 (ATWS), PP-06 (EQ), and PP-07 (fire protection) were used to determine whether the system or
 
structure is relied upon for compliance with NRC regulation of such events. PP-01, PP-03, and
 
PP-08 describe the commodity groups. The process was completed for all systems and structures
 
to ensure that the entire plant was addressed. The applicant's personnel initially evaluated
 
systems and structures identified in the CLB.
The staff noted that a system or structure was presumed to be within the scope of license renewal if it performed one or more safety-related functions or met other scoping criteria pursuant to the
 
Rule as determined by CLB review. Mechanical and structural component types that supported
 
intended functions were considered within the scope of license renewal. All component types in
 
electrical systems within the scope of license renewal were considered within the scope of license
 
renewal and placed in commodity groups. The elec trical commodity groups were further screened to determine whether they required AMRs. The staff finds no discrepancies with the methodology
 
used by the applicant.
The staff reviewed the methodology used by the applicant to generate commodity groups. Three separate commodity groups are identified in PP-01 (electrical, component supports, and piping
 
and component insulation). The staff reviewed the commodity group level functions evaluated by
 
the applicant in accordance with 10 CFR 54.4(a). This process determined whether the
 
commodity group had been considered within the scope of license renewal. The staff finds the
 
methodology acceptable.
The staff reviewed the results of the scoping process documented in accordance with PLI-02.
This documentation describes the system or st ructure and its 10 CFR 54.4(a) scoping criteria.
The staff also reviewed a sample of the applicant's scoping documentation and concludes that it
 
contains an appropriate level of detail to document the scoping process.
The applicant examined the CLB and determined that insulation installed on hot piping or components in structures within the scope of license renewal (with the exception of miscellaneous
 
yard structures) was included within the scope of license renewal as a commodity subject to an
 
AMR. The staff concludes that the applicant's methods and conclusions as to insulation were
 
acceptable.
The staff reviewed the scoping and screening of consumables and finds that the applicant had followed the process described in the SRP-LR.
2-37 2.1.4.4.3  Conclusion Based on review of the LRA, CRL, scoping and screening implementation procedures, and a sampling of system scoping results during the audit, the staff concludes that the applicant's
 
scoping methodology for plant SSCs, commodity groups, insulation, and consumables is
 
acceptable. In particular, the staff determines that the applicant's methodology reasonably
 
identifies systems, structures, component ty pes, and commodity groups within the scope of license renewal and their intended functions.2.1.4.5  Mechanical Component Scoping 2.1.4.5.1  Summary of Technical Information in the Application In LRA Sections 2.1.5.5 and 2.3.1, the applicant discussed the scoping methodology for mechanical systems and components. For me chanical systems, mechanical components supporting system intended functions are included within the scope of license renewal.
 
Mechanical system diagrams are marked to create LRBDs showing in-scope components that support safety-related functions for regulated events highlighted in green; nonsafety-related
 
components connected to safety-related components and providing structural support at the
 
connections or components the failure of which could prevent satisfactory accomplishment of a
 
safety-related function due to spatial interaction with safety-related SSCs are highlighted in red. A
 
computer sort from the CRL compared the LR BDs confirmed the scope of components in the system. For additional information, the applic ant performed plant walkdowns when required.
2.1.4.5.2  Staff Evaluation
 
The staff evaluated LRA Sections 2.1.5.5 and 2.3.1 and the guidance in PLI-02 and PLI-04 to complete the review of the mechanical scoping process. PLI-04 utilizes information in PP-01
 
through PP-07 to complete the mechanical scoping process.
PLI-2 provides instructions for filling out system data fields in the license renewal database. The license renewal database was used to develop license renewal system and structure scoping
 
forms for subsequent review, approval, and document retention. The CLB documents were
 
utilized when determining whether a system or component was within the scope of
 
10 CFR 54.4(a). The CLB includes the UFSAR, the facility description safety analysis report, separate ATWS, EQ, fire protection, and SBO documents, technical specifications, SERs, the
 
Integrated Plant Safety Assessment Report, and NRC orders. Other documents included the
 
CRL, flow diagrams, licensed operator training plans, and the Maintenance Rule database. In the
 
event of differences between CLB documents and other documents, the CLB documents took
 
precedence.
The license renewal database scoping input forms included the following information: license renewal system name, system grouping, DBD if applicable, UFSAR sections, drawings, other reference documents, and system intended functions. The applicant then evaluated the
 
10 CFR 54.4(a) scoping criteria against the identified system intended functions to determine
 
which criteria applied. The applicant also identified support system intended functions which
 
provide the functional and physical support required to accomplish safety-related intended
 
functions. Using PLI-04, the applicant then created LRBDs for mechanical systems.
 
2-38 The staff finds the PLIs and PPs acceptable in identifying mechanical components and support structures in mechanical systems within the scope of license renewal.
Scoping Methodology for the Isolation Condenser System. In LRA Section 2.3.1.3, the applicant provided the scoping and screening methodology results for SSCs within the ICS. The ICS is a
 
safety-related system credited with mitigating the effects of feedwater loss and specific high-
 
energy line breaks. The ICS license renewal scoping boundary includes those portions of
 
nonsafety-related piping and equipment extending beyond the safety-related and
 
nonsafety-related interface. The scoping results indicated that the ICS contains seven system
 
functions within and two system functions not within the scope of license renewal. The staff
 
identified no issues with the ICS scoping results. The staff reviewed the applicant's methodology
 
for identifying ICS mechanical and electrical component types with scoping criteria as defined in
 
the Rule. The staff also reviewed a sample of the scoping methodology implementation
 
procedures and discussed the methodology and results with the applicant. The staff verified that
 
the applicant had used pertinent engineering and licensing information to identify the ICS
 
mechanical, structural, and electrical component types within the scope of license renewal.
2.1.4.5.3  Conclusion
 
Based on the staff's review of the information in the LRA, PLIs, PPs, and the system sample and discussions with the applicant, the staff concludes that the applicant's methodology for identifying
 
mechanical systems for 10 CFR 54(a) scoping criteria 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 the applicant described the methodology used for structural scoping.
Additional details of the scoping methodology for structures is provided in PP-01, PP-02, PP-03, PP-013, and PLI-02. Following the initial identification of all structures, the applicant identified
 
intended functions as the bases for including specific structures within the scope of license
 
renewal. The structure intended functions are based on applicable CLB reference documents.
 
The applicant then identified all structural components that support the intended functions and
 
included them within the scope of license renewal as component types. The structural
 
components were identified from a review of applicable plant design drawings of the structure and
 
supplemental plant walkdowns when required for additional confirmation. A single site plan layout
 
drawing was marked up to create an LRBD showing in-scope structures.
2.1.4.6.2  Staff Evaluation
 
Structural scoping ensured that all plant buildings, yard structures and their constituent parts were considered for license renewal. Initially PP-01 was prepared to establish a comprehensive list of
 
license renewal structures and to document the basis for the list. The structures list was then
 
compared to the CRL, including the UFSAR, plant design drawings, the maintenance rule
 
database, and other plant design documents to ensure that it was comprehensive and consistent
 
with the CLB. The resultant list of structures was categorized as "Structures and Component
 
Supports" for further evaluation.
Following identification of all plant structures, the applicant implemented PLI-02 to evaluate them, identify their functions, and determine which are intended functions required for compliance with 2-39 one or more 10 CFR 54.4(a) criteria. Various other PPs (PP-02 through PP-07) were developed to support the evaluation of each structure in accordance with the scoping criteria. For each
 
structure, the applicant further studied the drawings and plant databases to identify specific
 
structural components and features. The structural component intended functions were identified
 
based on the guidance of Regulatory Guide 1.188, "Standard Format and Content for Applications
 
to Renew Nuclear Power Plant Operating Licenses," NEI 95-10, and the SRP-LR. Procedures
 
also described the source design documentation used for the evaluation of structures including
 
the various technical PPs developed by the applicant to support the LRA. For structures, the
 
evaluation boundaries were determined from a complete description of each structure according
 
to intended functions performed and its components per PLI-04. The license renewal database
 
was used to compile the structural evaluation results. The database contains a list of structures, structural component types, evaluation results for each of the 10 CFR 54.4(a) criteria for each
 
structure, a description of structural intended functions and source reference information for the
 
functions, and a reference to pertinent plant layout drawing(s) for each structure. Plant structures
 
within the scope of license renewal were captured on a plant layout drawing. The boundaries of
 
the structures were identified from the physical representation of the structure on the layout
 
drawing.The staff conducted detailed discussions with the applicant's license renewal team and reviewed documentation pertinent to the scoping process. The staff assessed whether the scoping
 
methodology and procedures outlined in the LRA had been appropriately implemented and
 
whether the scoping results were consistent with CLB requirements. The staff also reviewed
 
structural scoping evaluation results for the reactor building for proper implementation of the
 
scoping process for structural components and compared a sample of structural components
 
identified in the reactor building structural drawings to the structural list in the license renewal
 
database for consistency. In these audit activities, the staff identified no discrepancies between
 
the methodology documented and the implementation results.
2.1.4.6.3  Conclusion
 
Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, and a sampling of structural scoping results, the staff concludes that the applicant's
 
methodology for identification of structural component types within the scope of license renewal
 
meets 10 CFR 54.4(a) requirements and is, therefore, acceptable.
2.1.4.7  Electrical Component Scoping 2.1.4.7.1  Summary of Technical Information in the Application LRA Sections 2.1.1 and 2.1.5.4 describe the scoping process for electrical systems and components. All electrical systems were eval uated in accordance with 10 CFR 54.4(a) scoping criteria. A system was included within the scope of license renewal if it performed one or more
 
intended functions. The entire system was included within the scope of license renewal if any
 
portion of the system met 10 CFR 54.4(a) scoping criteria. A single electrical boundary drawing
 
was prepared to show schematically portions of t he plant electrical distribution system included within the scope of license renewal. The CRL was used to identify electrical components. All
 
electrical components of electrical and mechanical systems within the scope of license renewal
 
were included within the scope of license renewal as commodity groups.
2-40 2.1.4.7.2  Staff Evaluation The staff evaluated LRA Sections 2.1.1 and 2.1.5.4 and implementing procedures PP-01, PP-04, PP-05, PP-06, PP-07, PP-08, and PLI-02. The staff also evaluated the single electrical boundary
 
drawing specifically developed for license renewal showing portions of the plant electrical
 
distribution system included within the scope of license renewal. The staff reviewed the electrical
 
systems and electrical components in mechanical systems identified in the ICS scoping form. The staff discussed the electrical scoping methodology with the applicant's LRA team.
The CRL and UFSAR were used primarily to identif y electrical systems and electrical components in mechanical systems within the scope of lic ense renewal. PP-01 identifies the systems within the scope of license renewal. PP-04, PP-05, PP-06, and PP-07 specifically identify the electrical
 
and mechanical systems credited for meeting SBO , ATWS, EQ, and fire protection regulatory requirements. The electrical commodity groups are identified in PP-08. PLI-2 provides instructions
 
for filling out system data fields in the license renewal database.
2.1.4.7.3  Conclusion
 
Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, and a sampling of electrical scoping results, the staff concludes that the applicant's
 
methodology for identification of electrical components within the scope of license renewal meets
 
10 CFR 54.4(a) requirements, and is, therefore, acceptable.2.1.4.8  Conclusion for Scoping Methodology Based on a review of the LRA and the scoping implementation procedures, the staff determines that the applicant's scoping methodology is consistent with SRP-LR guidance and identified
 
safety-related SSCs the failure of which could affect safety-related functions and which are
 
necessary for compliance with the NRC's regulations for fire protection, EQ, ATWS, and SBO.
 
Therefore, the staff concludes that the applicant's methodology meets 10 CFR 54.4(a)
 
requirements.
 
====2.1.5 Screening====
Methodology2.1.5.1  General Screening Methodology After identifying systems and structures within the scope of license renewal, the applicant implemented a process for identifying SCs subject to an AMR, in accordance 10 CFR 54.21.
2.1.5.1.1  Summary of Technical Information in the Application
 
LRA Section 2.1.6, the applicant discussed the method of identifying components of in-scope systems and structures subject to an AMR. The identification method consisted of the following
 
steps:  (1)Identification of long-lived or passive components for each in-scope mechanical system, structure, and electrical commodity group.  (2)Identification of the license renewal intended function(s) for all mechanical and structural component types and electrical commodity groups.
2-41 Active components were screened out and required no AMR. The screening process also identified short-lived components and consumables.
Short-lived components are not subject to an AMR. Consumables are a special class that includes packing, gaskets, component seals, o-rings, oil, grease, component filters, system filter s, fire extinguishers, fire hoses, and air packs.
Structural sealants were the only consumables within the scope of license requiring an AMR.
 
2.1.5.1.2  Staff Evaluation Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope of license renewal and subject to an AMR. The IPA must identify components that perform intended
 
functions without moving parts or a change in configuration or properties (passive) as well as
 
components not subject to periodic replacement based on a qualified life or specified time period (long-lived). The IPA includes a description and justification of the methodology used to identify
 
passive and long-lived SCs and a demonstration that the effects of aging on those SCs will be
 
adequately managed so that intended function(s) will be maintained under all design conditions
 
imposed by the CLB for the period of extended operation.
The staff reviewed the methodology used by the applicant to determine whether mechanical and structural component types and electrical comm odity groups within the scope of license renewal should be subject to an AMR. The applicant implemented a process for determining which SCs
 
were subject to an AMR in accordance with 10 CFR 54.21(a)(1) requirements. In LRA
 
Section 2.1.6, the applicant discussed screening of component types and commodity groups
 
within the scope of license renewal.
The screening process evaluated these in-sc ope component types and commodity groups to determine which were long-lived and passive and, therefore, subject to an AMR. The staff
 
reviewed LRA Sections 2.3, 2.4, and 2.5 that provide the results of the process used to identify
 
component types and commodity groups subject to an AMR. The staff also reviewed the
 
screening results reports for the ICS and the reactor building.
The applicant discussed with the staff in detail the processes for each discipline and provided administrative documentation that described the screening methodology. Specific methodology for mechanical, electrical, and structural is discussed below.
2.1.5.1.3  Conclusion
 
On the basis of review of the LRA, the screening implementation procedures, and a sampling of screening results, the staff determines that the applicant's screening methodology is consistent
 
with SRP-LR guidance and capable of identifying passive, long-lived components within the
 
scope of license renewal and subject to an AMR. The staff determines that the applicant's
 
process for identifying component types and co mmodity groups subject to an AMR meets 10 CFR 54.21 requirements and is, therefore, acceptable.2.1.5.2  Mechanical Component Screening 2.1.5.2.1  Technical Information in the Application In LRA Section 2.1.6.1, the applicant discussed the screening methodology for identifying passive and long-lived mechanical components and their support structures subject to an AMR. The
 
mechanical system screening process began with the results from the scoping process. The 2-42 applicant studied LRBDs to identify passive and long-lived components, then entered them into the license renewal database. The applicant also examined components in the CRL to confirm
 
that all system components had been considered.
Where the LRBDs did not provide sufficient detail, as for large vendor-supplied components (e.g., compressors, emergency diesel
 
generators), the applicant examined associated component drawings or vendor manuals. The applicant also performed plant walkdowns to confirm which components required an AMR.
 
Finally, the applicant benchmarked passive and long-lived components for a system against previous LRAs with similar systems.
2.1.5.2.2  Staff Evaluation
 
The staff evaluated the mechanical screening methodology in LRA Section 2.1.6.1, PLI-03, and PP-08. Using PLI-03 for mechanical systems, the applicant downloaded a listing of components
 
from the CRL to assist in identifying system passive, long-lived component types.
An important function in the screening form is the "Intended Function" column. The list of potential intended functions is identified in PP-08 and included in the pull-down menu for the intended
 
functions database field. For components like restricting orifices or heat exchangers, the
 
appropriate intended function depends on the specific application within the system or structure.
 
For example, the in-scope heat exchanger has a pressure boundary intended function, but the
 
tubes have a heat transfer function if required to support a system intended function under
 
10 CFR 54.4(a). All in-scope passive, long-lived mechanical components have at least one
 
intended function.
Based on the mechanical screening methodology in LRA Section 2.1.6.1, PLI-03, and PP-08, the staff finds the mechanical screening process acceptable.
Screening Methodology for the Isolation Condenser System. In LRA Table 2.3.1.3, the applicant identified the following isolation condenser system component types and intended functions
 
subject to an AMR:
* bird screen - filter
* closure bolting - mechanical closure
* gauge snubbers - pressure boundary
* heat exchangers (isolation condensers) - heat transfer and pressure boundary
* piping and fittings - pressure boundary
* thermowell - pressure boundary
* valve body - leakage and pressure boundary
 
The staff questioned the applicant to determine whether instrument lines had been included within
 
the scope of license renewal and subject to an AMR. The applicant stated that instrument lines
 
that penetrate the ICS and serve pressure boundary functions were covered under piping and
 
fittings. The ICS and structure screening form lists ICS steam supply instrument lines. The staff
 
also questioned the applicant about expansion joints on the isolation condenser outlet to
 
atmosphere from the isolation condenser heat exchangers. The applicant stated that expansion
 
joints are pipe fittings included within the scope of license renewal and subject to an AMR.
The applicant used PP-08 and PLI-03 to identify the components subject to an AMR.
 
2.1.5.2.3  Conclusion 2-43 Based on a review of the LRA, the screening implementation procedures, and a sample of isolation condenser system screening results, the staff determines that the applicant's mechanical
 
component screening methodology is consistent with SRP-LR guidance. The staff concludes that
 
the applicant's methodology for identification of mechanical components subject to an AMR meets
 
10 CFR 54.21(a)(1) requirements.
2.1.5.3  Structural Component Screening 2.1.5.3.1  Summary of Technical Information in the Application The applicant described the methodology for structural screening in LRA Section 2.1.6.1.
Additional details related to the implementation of the screening methodology for structures is
 
provided by PP-08 and PLI-03. The applicant's structure screening process began with the results
 
from the scoping process. For all in-scope structures, the applicant reviewed the completed
 
scoping packages, which included written descriptions of each structure or structure portion as
 
well as the structure drawings to identify the passive, long-lived SCs. The SRP-LR and NEI 95-10
 
Appendix B were used to identify passive SCs. These were then entered into the license renewal
 
database and the component listings compared against the CRL to confirm that all structural
 
components had been considered. Plant walkdowns were performed when required for
 
confirmation. Finally, the list of identified passive, long-lived SCs was benchmarked against
 
previous LRAs. Components which support or interf ace with electrical components, for example, cable trays, conduits, instrument racks, panels and enclosures, were assessed as structural
 
components.
2.1.5.3.2  Staff Evaluation
 
The staff reviewed the applicant's methodology for structural screening described in LRA Section 2.1.6.1 and in implementing guidance in PP-08 and PLI-03. The scoping results
 
show that the applicant screened per the PLI and used the screening data forms within the
 
license renewal database to capture pertinent structure design information, component or
 
commodity types, materials, environments, and aging effects. As to the component type, the staff verified that the applicant had used the lists of passive SCs embodied in the regulatory guidance
 
as a starting point and supplemented that list with additional items unique to the site or for which a
 
direct match to the generic lists did not exist (i.e., material/environment combinations). As one of
 
the general rules for structural screening, the applicant determined that components which
 
support or interface with electrical components, (e.g., cable trays, conduits, instrument racks, panels and enclosures,) were assessed as structural components.
The staff reviewed the methodology used by the applicant to determine whether structures within the scope of license renewal would be subject to further AMR. For structures, the applicant
 
determined the types of structural elements utilized and the various materials and environments
 
to be considered in the AMR. Generally, the boundary for a structure is the entire building
 
including base slabs, foundations, walls, beams, slabs, and steel superstructure. A listing of all
 
the systems and component types in each plant structure was developed identifying the various
 
structural elements, materials, and environments. The applicant created a database to compile
 
the results. The database identified each SC and indicated whether the component type was
 
subject to an AMR. Each component type was identified as a component (e.g., door, gate, anchor
 
support, strut, fastener, or siding) or as a material (e.g., concrete, polymer, or steel). From this
 
identification a screening report for each plant structure was developed. The applicant described 2-44 and discussed with the staff in detail the screening methodology as well as the screening reports for a selected group of structures.
The staff reviewed the applicant's results from the implementation of this methodology for one of the plant structures (reactor building) identified as within the scope of license renewal. The staff
 
also reviewed the various reactor building structural drawings to verify that the applicant had
 
performed a comprehensive evaluation and had identified the relevant structures and structural
 
elements in the evaluation. The review included in-scope components, the corresponding
 
component-level intended functions, and the resulting list of component types subject to an AMR.
 
The staff also discussed the process and its results with the applicant. The staff identified no
 
discrepancies between the methodology documented and the implementation results.
2.1.5.3.3  Conclusion
 
Based on review of information in the LRA, the applicant's detailed screening implementation procedures, and a sampling of structural screening results, the staff concludes that the applicant's
 
methodology for identification of structural component types subject to an AMR meets
 
10 CFR 54.21(a)(1) requirements.
2.1.5.4  Electrical Component Screening 2.1.5.4.1  Summary of Technical Information in the Application In LRA Sections 2.1.6 and 2.5.2, the applicant discussed the method for identifying electrical components in systems within the scope of license renewal. Initially, electrical component types in the electrical and mechanical systems within the scope of license renewal were identified.
 
Component types from drawings and the CRL were grouped into approximately 52 electrical commodity groups based on guidance in NEI 95-10 Appendix B and NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report,"
dated September 2005. Forty of the commodity groups were classified as active and therefore not subject to an AMR. Two of the remaining
 
twelve commodity groups were not subjec t to an AMR because they performed no license renewal intended functions. Components in the EQ program replaced prior to expiration of their
 
qualified lives were screened out from requiring an AMR. The remaining eight commodity groups
 
were subject to an AMR. Insulated cables and connections, electrical penetrations, high voltage
 
insulators, transmission conductors and connections, fuse holders, wooden utility poles, cable
 
connections (metallic parts), and uninsulated ground conductors were the commodity groups
 
identified by the applicant in the LRA subject as to an AMR.
In its response to RAI 2.5.1.19-1, the applicant stated that it had revised its approach to aging management for the SBO combustion turbine power plant. Table 2.5.2A of the RAI response
 
identifies nine SBO electrical commodity groups. Cable connections (metallic parts), high voltage
 
insulators, insulated cables and connections, insulated inaccessible medium-voltage cables, phase bus connections, phase bus enclosure assemblies, phase bus insulators, transmission
 
conductor and connections, and uninsulated ground conductors were identified as commodity
 
groups in the RAI response.
2.1.5.4.2  Staff Evaluation
 
The staff evaluated the applicant's methodology for electrical screening in LRA Sections 2.1.6 and 2.5.2, PP-08, and the response to RAI 2.5.1.19-1. The applicant used the screening process 2-45 described in PP-08, PLI-02, and the RAI response to identify the electrical commodity groups subject to an AMR. Components types within el ectrical systems determined to require an AMR were placed in commodity groups. The commodi ty groups established for passive, long-lived component types were evaluated to determine whet her they were subject to replacement based on a qualified life or specified time period (short-lived) or not (long-lived).
The applicant stated in the LRA that most electrical commodity groups were active. Using NEI 95-10 Appendix B as guidance, the applicant screened out active commodity groups as not
 
requiring an AMR pursuant to 10 CFR Part 54.
The staff reviewed the applicant's approach to scoping and screening of electrical fuse holders in accordance with ISG-05, "Identification and Treatment of Electrical Fuse Holders for License
 
Renewal," which states that, consistent with 10 CFR 54.4(a) specified requirements, fuse holders (including fuse clips and fuse blocks) are considered passive electrical components. Fuse holders
 
should be scoped, screened, and included in the AMR in the same manner as terminal blocks and
 
other types of electrical connections treated in the process. ISG-05 also states that fuse holders
 
of an active component assembly (i.e., switchgear, power supplies, power inverters, battery
 
chargers and circuit boards) are not subject to an AMR.
The staff reviewed and discussed the applicant's evaluations of fuse holders. The applicant examined fuse holders not included in the EQ pr ogram or inside active equipment and determined that such fuse holders were subject to an AMR.
2.1.5.4.3  Conclusion
 
The staff reviewed the LRA, procedures, license renewal electrical schematic, a sample of the results of the screening methodology, and the applicant's response to RAI 2.5.1.19-1. The staff
 
determines that the applicant's methodology is consistent with the description in LRA and with the
 
applicant's implementing procedures. Based on review of information in the LRA, the applicant's
 
screening implementation procedures, and a sampling of electrical screening results, the staff
 
concludes that the applicant's methodology for identification of electrical commodity groups
 
subject to an AMR meets 10 CFR 54.21(a)(1) requirements.2.1.5.5  Conclusion for Screening Methodology After review of the LRA and the screening implementation procedures, discussions with the applicant's staff, and a sample review of screening results, the staff determines that the
 
applicant's screening methodology is consistent with SRP-LR guidance and has identified those
 
passive, long-lived components within the scope of license renewal and subject to an AMR. The
 
staff concludes that the applicant's methodology meets 10 CFR 54.21(a)(1) requirements and is, therefore, acceptable.
 
====2.1.6 Conclusion====
for Scoping and Screening Methodology The staff reviewed the information presented in LRA Section 2.1, the supporting information in the scoping and screening implementation procedures and reports, the information presented during
 
the scoping and screening methodology audit, and the applicant's responses to RAIs 2.5.1.19-1, 2.1.5.2-1, and 2.5.1.2-2. The staff concludes that the applicant's methodology for identifying SSCs
 
within the scope of license renewal and SCs requiring an AMR is consistent with 10 CFR 54.4
 
and 10 CFR 54.21(a)(1) requirements.
2-46 2.2  Plant-Level Scoping Results
 
====2.2.1 Introduction====
In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to
 
identify SSCs within the scope of license renewal. The staff reviewed the plant-level scoping
 
results to determine whether the applicant had pr operly identified all plant-level systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1), or the failure of which
 
could prevent satisfactory performance of any of the safety-related functions, as required by 10 CFR 54.4(a)(2), as well as the systems and structures relied on in safety analysis or plant
 
evaluations for functions required by one of the regulations to which 10 CFR 54.4(a)(3) refers.2.2.2  Summary of Technical Information in the Application In LRA Table 2.2-1, the applicant provided a list of the plant systems, structures, and commodity groups evaluated to determine whether they are within the scope of license renewal. Based on
 
the DBEs considered in the plant's CLB, other CLB information on nonsafety-related systems and
 
structures and certain regulated events, the app licant identified those plant-level systems and structures within the scope of license renewal, as defined by 10 CFR 54.4.
 
====2.2.3 Staff====
Evaluation In LRA Section 2.1, the applicant described its methodology for identifying systems and structures within the scope of license renewal and subject to an AMR. The staff reviewed the scoping and
 
screening methodology and its evaluation is in SER Section 2.1. To verify that the applicant had
 
properly implemented its methodology, the staff focu sed its review on the implementation results shown in LRA Table 2.2-1 to confirm that ther e were no omissions of plant-level systems and structures within the scope of license renewal.
The staff determined whether the applicant had properly identified 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 had not identified as within the scope of license renewal
 
to verify whether they had 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 of SRP-LR Section 2.2, "Plant-Level Scoping Results."
The staff sampled the contents of the UFSAR based on the systems and structures listed in LRA Table 2.2-1 to determine whether there were any systems or structures that may have intended
 
functions within the scope of license renewal, as defined by 10 CFR 54.4, but had been omitted
 
from the scope of license renewal. The staff identified no omissions.
 
====2.2.4 Conclusion====
The staff reviewed LRA Section 2.2 and the supporting information in the UFSAR to determine whether any systems and structures within t he scope of license renewal had not been identified by the applicant. No omissions were identified. On the basis of this review, the staff concludes
 
that there is reasonable assurance that the applicant has adequately identified the systems and
 
structures within the scope of license renewal, in accordance with 10 CFR 54.4.
2-47 2.3  Scoping and Screening Results: Mechanical This section documents the staff's review of the applicant's scoping and screening results for mechanical systems. Specifically, this section discusses the following systems:
* reactor vessel, internals, and reactor coolant system (RCS)
* engineered safety feature (ESF) systems
* auxiliary systems
* steam and power conversion systems In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and list passive, long-lived SCs within the scope of license renewal and subject to an AMR. To verify that
 
the applicant properly implemented its methodology, the staff focused its review on the
 
implementation results. This approach allowed the staff to confirm that there were no omissions of
 
mechanical system components that meet the scoping criteria and are subject to an AMR.
Staff Evaluation Methodology. The staff's evaluation of the information in the LRA was the same for all mechanical systems. The objective was to determine whether the components and
 
supporting structures for a specific system, that appeared to meet the scoping criteria specified in
 
the Rule, had been identified by the applicant as within the scope of license renewal, in
 
accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to
 
verify that all long-lived, passive components were subject to an AMR in accordance with
 
10 CFR 54.21(a)(1).
Scoping. To perform its evaluation, the staff reviewed the applicable LRA sections and associated component drawings, focusing on components that had not been identified as within the scope of
 
license renewal. The staff reviewed relevant licensing basis documents, including the UFSAR, for
 
each mechanical system to determine whether the applicant had omitted components with
 
intended functions under 10 CFR 54.4(a) from the scope of license renewal. The staff also
 
reviewed the licensing basis documents to determine whether all intended functions under
 
10 CFR 54.4(a) had been specified in the LRA. If omissions were identified, the staff requested
 
additional information to resolve them.
Screening. After completing its review of the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions, the staff sought to determine whether
 
(1) the functions are performed with moving parts or a change in configuration or properties or
 
(2) 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 meeting neither of these criteria, the staff sought to confirm that
 
these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were
 
identified, the staff requested additional information to resolve them.
Two-Tier Scoping Review Process for Balance of Plant Systems. In the LRA there are 80 mechanical systems of which 31 are balance of plant (BOP) systems that include most of the
 
auxiliary and all the steam and power conversion sy stems. The staff performed a two-tier scoping review for these BOP systems.
In the two-tier scoping review, the staff reviewed the LRA and UFSAR description focusing on the system intended function to screen all the BOP systems into two groups based on the following screening criteria:
2-48
* safety importance/risk significance
* potential for system failure to cause failure of redundant safety system trains
* operating experience indicating likely passive failures
* systems subject to omissions based on previous LRA reviews Examples of safety and risk significant sy stems are the feedwater, the emergency diesel generator (EDG), auxiliary, and the emergency service water (ESW) systems based on the individual plant examination results for OCGS. An example of a system the failure of which could cause failure of redundant trains is a drain system for flood protection. Examples of systems with operating experience indicating likely passive failures include the main steam, feedwater, and
 
ESW systems. Examples of syst ems with omissions identified in previous LRA reviews include spent fuel cooling system and makeup water sources to safety systems.
From the 31 BOP systems, the staff selected 16 sy stems for a Tier-2 (detailed) scoping review as described above. For the remaining 15 BOP systems, the staff performed a Tier-1 (not requiring
 
detailed boundary drawings) review of the LRA and UFSAR that would identify apparently missing
 
components for an AMR. However, Tier-2 requires the review of detailed boundary drawings in
 
accordance with SRP-LR Section 2.3. The following is a list of the 15 Tier-1 systems:
* chlorination system
* condensate system
* cranes and hoists
* fuel storage and handling system
* heating and process steam system
* main condenser
* main fuel oil storage and transfer system
* main generator and auxiliary system
* main turbine and auxiliary systems
* miscellaneous floor and equipment drain system
* process sampling system
* radiation monitoring system
* reactor building floor and equipment drains
* roof drains and overboard discharge system
* sanitary waste system The staff verified that there is no risk-significant syst em in this list by examining the results of the OCGS integrated plant assessment (IPA). None of the 15 systems is a dominant contributor to core damage frequency (CDF), nor are these system s involved in the dominant initiating events.
The following lists the 16 Tier-2 systems:
* circulating water system
* drywell floor and equipment drains
* emergency diesel generator and auxiliary system
* emergency service water system
* instrument (control) air system
* nitrogen supply system
* post-accident sampling system
* reactor building closed cooling water system
* reactor water cleanup system 2-49
* service water system
* spent fuel pool cooling system
* turbine building closed cooling water system
* water treatment and distribution system
* condensate transfer system
* feedwater system
* main steam system2.3.1  Reactor Vessel, Internals, and Reactor Coolant System In LRA Section 2.3.1, the applicant identified the SCs of the reactor vessel, internals, and RCS subject to an AMR for license renewal.
The applicant described the supporting SCs of the reactor vessel, internals, and RCS in the following sections of the LRA:
* 2.3.1.1control rods
* 2.3.1.2fuel assemblies
* 2.3.1.3isolation condenser system
* 2.3.1.4nuclear boiler instrumentation
* 2.3.1.5reactor head cooling system
* 2.3.1.6reactor internals
* 2.3.1.7reactor pressure vessel
* 2.3.1.8reactor recirculation system The staff's review findings on LRA Sections 2.3.1.1 - 2.3.1.8 are presented in SER Sections 2.3.1.1 - 2.3.1.8, respectively.
2.3.1.1  Control Rods 2.3.1.1.1  Summary of Technical Information in the Application In LRA Section 2.3.1.1, the applicant described the control rods. The control rods are replaceable, mechanical components consisting of cruciform-shaped stainless steel assemblies containing
 
neutron-absorbing material, designed for flux shaping and for reactivity control during reactor
 
startup, power level changes, and shutdown. The reactor contains 137 control rods the purpose of
 
which is to absorb neutrons in the reactor core, thereby providing the means to adjust core power
 
shape, compensate for reactivity changes caused by fuel and burnable poison depletion, and fully
 
shut down the nuclear reaction. They accomplish this purpose, in conjunction with their
 
positioning system (evaluated with the control rod drive system), by continuous regulation of the core excess reactivity and reactivity distribut ion and by sufficient reactivity compensation to render the reactor adequately subcritical from its most reactive condition. Control rod absorption
 
of neutrons chemically depletes the absorber material and control rod lifetime is monitored.
 
Control rods reaching prescribed thresholds are scheduled for replacement during refueling
 
outages.The control rods contain safety-related components relied upon to remain functional during and following DBEs.
No intended functions within the scope of license renewal are applicable for the controls rods.
2-50 In LRA Table 2.3.1.1, the applicant identified no control rods component types within the scope of license renewal and subject to an AMR because all components are short-lived.
2.3.1.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.1 and UFSAR Sections 4.3.2.4 and 4.6.4.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3, "Scoping and Screening Results: Mechanical Systems."
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.1.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the control rods components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.1.2  Fuel Assemblies 2.3.1.2.1  Summary of Technical Information in the Application In LRA Section 2.3.1.2, the applicant described the fuel assemblies, high-integrity components containing the fissionable material that sustains the nuclear reaction when the reactor core is
 
made critical. The purpose of the fuel assemblies is to allow efficient heat transfer from the
 
nuclear fuel to the reactor coolant and to maintain structural integrity providing a controllable, coolable bundle geometry and fission product barrier. They accomplish this purpose by satisfying
 
the thermal-mechanical, nuclear, and hydraulic requirements of the nuclear fuel design conditions
 
within the reactor. Each fuel assembly is comprised of a fuel bundle and a channel that surrounds
 
it. The fuel rods of each bundle are spaced and supported in a square array by the stainless steel
 
upper and lower tie plates and intermediately placed zircaloy spacer assemblies. The bundle
 
channel is fabricated from zircaloy and provides the flow path outer periphery for bundle coolant
 
flow, supplies structural stiffness to the bundle and transmits seismic loadings to the core internal
 
structures, provides a heat sink during a loss of cooling accident (LOCA), and supplies a surface
 
for control rod guidance within the reactor core. The reactor contains 560 fuel bundle assemblies.
 
During each refueling outage, approximately one-third of the highest depletion bundles are
 
replaced and the positions of the remaining bundles are shuffled as required by the nuclear core
 
design to optimize cycle energy, operating c onditions, and fuel economics. Cycle-specific evaluations of the thermal mechanical design known as supplemental reload licensing submittals
 
are produced to ensure that the safety and operational requirements of the fuel product line are
 
met.
2-51 The fuel assemblies contain safety-related components relied upon to remain functional during and following DBEs.
No intended functions within the scope of license renewal are applicable for the fuel assemblies.
 
In LRA Table 2.3.1.2, the applicant identified no fuel assembly component types within the scope of license renewal and subject to an AMR because all components are short-lived.
2.3.1.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 4.2.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.2.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the fuel assemblies components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.1.3  Isolation Condenser System 2.3.1.3.1  Summary of Technical Information in the Application In LRA Section 2.3.1.3, the applicant described the ICS. The ICS is a standby, high-pressure system designed for removal of fission product decay heat when the reactor vessel is isolated
 
from the main condenser. This condition can occur when the main steam isolation valves (MSIVs)
 
have closed or the main condenser is otherwise unavailable for use as a heat sink. The purpose
 
of the system is to prevent overheating of the reactor fuel, control the reactor pressure rise, and
 
limit the loss of reactor coolant through the relief valves. The ICS accomplishes this purpose by
 
depressurizing the reactor and removing residual and decay heat. ICS operation is initiated
 
automatically by reactor vessel high pressure or low-low water level or can be initiated manually.
The ICS is comprised of two independent loops, each with one condenser shell containing two
 
tube bundles. When a loop is in operation, both tube bundles are in service. For ICS initiation, normally both condensers are placed in operation simultaneously, and either loop can be
 
activated or shut down separately by manual control. The ICS operates by natural circulation
 
without the need for driving power other than the direct current (DC) electrical system used to
 
open an isolation valve on each condensate return line, initiating ICS operation.
2-52 The ICS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the ICS could potentially prevent the satisfactory
 
accomplishment of a safety-related function. In addition, the ICS performs functions that support
 
fire protection, SBO and EQ.
The intended functions within the scope of license renewal include:
* provides filtration
* provides heat transfer
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.1.3, the applicant identified the following ICS component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* gauge snubber
* heat exchangers (isolation condensers)
* piping and fittings
* thermowell
* valve body 2.3.1.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.3 and UFSAR Sections 3.6.2.6 and 6.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.3.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the ICS components within the scope of 2-53 license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1.4  Nuclear Boiler Instrumentation 2.3.1.4.1  Summary of Technical Information in the Application In LRA Section 2.3.1.4, the applicant described the nuclear boiler instrumentation. The nuclear boiler instrumentation system is designed to prov ide the means to measure parameters of level, pressure, temperature, flow, core differential pressure, and core spray pipe integrity. The purpose
 
of the system is to provide signals to the r eactor protection system and emergency core cooling system (ECCS) logic for initiation of such prot ective system functions as reactor scram, ECCS and ESF system initiation, primary containment is olation, recirculation pump trip, and alternate rod insertion. The feedwater control function is provided input from this system. Nuclear boiler instrumentation also provides the operator with indications of reactor level, pressure, temperature, and flow during normal and transient conditions to support procedural activities during normal and
 
post-accident operation. It accomplishes these purposes by utilizing specific instruments to
 
monitor level, pressure (including differential pressure), flow, and temperature. Reactor vessel
 
level is measured by comparing the differential pressure between the variable level of water in the
 
reactor vessel and the pressure from a reference water column of a known height. Reactor
 
pressure is measured by pressure instruments utilizing the same piping used to measure the
 
pressure in the water level instrument reference legs. Temperature is measured through
 
thermocouples placed in specific locations on the reactor vessel shell, heads, flange, and skirt to
 
indicate vessel metal temperature.
The nuclear boiler instrumentation contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the nuclear boiler
 
instrumentation potentially could prevent the sa tisfactory accomplishment of a safety-related function. In addition, the nuclear boiler instrumentation performs functions for fire protection, ATWS, SBO, and EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.1.4, the applicant identified the following nuclear boiler instrumentation component types within the scope of license renewal and subject to an AMR:
* closure bolting
* condensing chamber
* gauge snubber
* piping and fittings
* valve body 2-54 2.3.1.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.4 and UFSAR Section 7.6.1.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.4.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the nuclear boiler instrumentation
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.1.5  Reactor Head Cooling System 2.3.1.5.1  Summary of Technical Information in the Application In LRA Section 2.3.1.5, the applicant described the reactor head cooling system (RHCS) designed for use in conjunction with reactor vessel flooding and the shutdown cooling system (SCS) for condensing steam formed in the vessel head and for cooling the flanges and the upper
 
portions of the reactor pressure vessel during shutdown operation. The RHCS condenses steam
 
and condensable gases in the vessel dome to assist in vessel head cooling during shutdown, prevents repressurization as the vessel is flooded to levels above the vessel flange and main
 
steam nozzles to cool the upper portions of the vessel metal, and permits reactor pressure to be
 
reduced to atmospheric while reducing vessel head temperature. A cross-connect line between
 
the head cooling line and the head vent line prevents accumulation of hydrogen and other
 
non-condensable gases in the head cooling line above the reactor vessel during normal power
 
operation. The RHCS is comprised of a single spray nozzle located inside the top of the reactor
 
pressure vessel head spraying through a cone angle which does not strike the head metal
 
surface. The head spray water is supplied by t he standby control rod drive (CRD) system feed pump.The RHCS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RHCS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the RHCS performs
 
functions that support EQ.
The intended functions within the scope of license renewal include:
2-55
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.1.5, the applicant identified the following RHCS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* flow element
* piping and fittings
* restricting orifice
* valve body 2.3.1.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.5 and UFSAR Section 5.4.11 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.5.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the RHCS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.1.6  Reactor Internals 2.3.1.6.1  Summary of Technical Information in the Application In LRA Section 2.3.1.6, the applicant described the reactor internals. The reactor internals support the core and other internal components, maintain the fuel in a coolable geometry during normal
 
and accident conditions, and properly distribute the coolant delivered to the vessel. Major
 
components of the reactor internals include the shroud, steam separator assembly, recirculation
 
outlet, inlet plenum, shroud support ring, cone support ring, upper core grid (top guide), bottom 2-56 core support plate, and the peripheral fuel assemblies. The shroud is a stainless steel cylinder that surrounds the reactor core and provides a barrier to separate the upward flow of the coolant
 
through the reactor core from the downward recirculation flow. Bolted on top of the shroud is the
 
steam separator assembly, which forms the t op of the core discharge plenum and provides a mixing chamber for the steam-water mixture before it enters the steam separator. The
 
recirculation outlet and inlet plenum are separated by the shroud support ring (support cone),
which joins the bottom of the shroud to the vessel wall. The cone support ring carries all the
 
vertical weight of the shroud, steam separator and dryer assembly, upper core grid (top guide),
bottom core support plate, and the peripheral fuel assemblies. The shroud support ring also
 
sustains the differential upward pressure loading on the shroud under operating conditions and
 
the vertical and lateral seismic loads developed during an earthquake. The control rod guide
 
tubes extend up from the control rod drive housing through holes in the core plate. Each tube is
 
designed as a lateral guide for the control rod and as the vertical support for the fuel support
 
piece, which holds the four fuel assemblies surrounding the control rod. Except for the weight of
 
the peripheral fuel assemblies, the entire weight of the fuel is carried by the guide tubes and
 
transmitted to the bottom head through the CRD housings and stub tubes.
The reactor internals contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the reactor internals potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the reactor
 
internals performs functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides conversion of fluid into spray
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.1.6, the applicant identified the following reactor internals component types within the scope of license renewal and subject to an AMR:
* CRD assembly (housing and guide tube)
* core plate (lower core grid)
* core plate (lower core grid) wedges
* core shroud
* core spray line spray nozzle elbows
* core spray lines, thermal sleeves, spray rings (sparger), and spray nozzles
* core spray ring (sparger) repair hardware
* fuel support piece
* incore neutron monitor dry tubes, guide tubes, and housings
* shroud repairs (tie rods and lug/clevis assemblies)
* shroud support structure
* top guide (upper core grid)
* vessel steam dryer 2-57 2.3.1.6.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.6 and UFSAR Sections 3.9.5 and 4.5.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of the LRA 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 2.3.1.6-1 dated March 10, 2006, the staff noted that LRA Section 2.3.1.6 states that the reactor vessel head spray nozzle supports no intended functions delineated in the Rule and, therefore, is not included within the scope of license renewal, and that a safety assessment for
 
this component was performed and reported in Boiling Water Reactor Vessel and Internals
 
Project (BWRVIP)-06. However, the staff could not locate the safety assessment in the
 
referenced document. Therefore, the staff requested clarification.
In its response dated April 7, 2006, the applicant agreed that the BWRVIP-06 does not include an assessment of the reactor vessel head spray nozzle as stated in LRA Section 2.3.1.6; therefore, the reference to BWRVIP-06 was an error. The applicant, however, added that the head spray
 
nozzle performs no safety-related function, that it is not credited for any regulated event, and that
 
no postulated failure of the head spray nozzle could cause failure of safety-related equipment.
 
Therefore, the applicant maintains its position as stated in the LRA, that the head spray nozzle
 
supports no intended functions and is not included within the scope of license renewal.
During a teleconference April 7, 2006, the information provided in the UFSAR supplement on the reactor pressure vessel (RPV) head cooling system was discussed. The applicant stated that the
 
nozzle does not meet the criteria for in-scope components and is used only for normal shutdown.
 
The applicant and the staff also discussed the requirements identified in the UFSAR and in
 
10 CFR Part 50, Appendix R. The applicant stated that the nozzle is not needed to meet
 
Appendix R safe shutdown requirements. The staff understood the applicant to exclude the
 
nozzle from the scope of license renewal and concludes that the response was acceptable. The
 
staff's concern described in RAI 2.3.1.6-1 is resolved.
2.3.1.6.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the reactor internals
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-58 2.3.1.7  Reactor Pressure Vessel 2.3.1.7.1  Summary of Technical Information in the Application In LRA Section 2.3.1.7, the applicant described the RPV, which contains the reactor core, the reactor internals, and reactor core coolant moderator. The RPV forms part of the reactor coolant
 
pressure boundary (RCPB) and serves as a high-integrity barrier against leakage of radioactive
 
materials to the drywell. The RPV is a vertical, cylindrical pressure vessel with hemispherical
 
heads. The cylindrical shell and bottom hemispherical head of the RPV are of welded construction
 
fabricated of low-alloy steel plate. The removable top head attached to the cylindrical shell flange
 
with studs and nuts includes two concentric seal rings in the head flange. The RPV is supported
 
by a steel skirt, the top of which is welded to the bottom of the vessel. The base of the skirt is
 
continuously supported by a ring girder fastened to a concrete foundation, which carries the load
 
through the drywell to the reactor building foundation slab. The major RPV safety function is to
 
provide a radioactive material barrier.
The RPV contains safety-related components relied upon to remain functional during and following DBEs. In addition, the RPV performs functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.1.7, the applicant identified the following RPV component types within the scope of license renewal and subject to an AMR:
* nozzle (bottom head drain)
* nozzle safe ends (core spray, isolation condenser, and CRD return)
* nozzle safe ends (feedwater and main steam)
* nozzle safe ends (recirculation inlet and outlet)
* nozzle thermal sleeves (CRD return line)
* nozzle thermal sleeves (feedwater nozzle)
* nozzles (core spray)
* nozzles (CRD return)
* nozzles (feedwater)
* nozzles (main steam and isolation condenser)
* nozzles (recirculation inlet and outlet)
* penetrations (CRD stub tubes)
* penetrations (instrumentation including safe ends)
* penetrations (standby liquid control)
* RPV support skirt and attachment welds
* top head closure studs and nuts
* top head enclosure (head and nozzles)
* top head enclosure vessel flange leak detection penetration 2-59
* top head flange
* vessel bottom head
* vessel shell (upper, upper intermediate, lower intermediate, lower, and belt line welds)
* vessel shell attachment welds
* vessel shell flange 2.3.1.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.7 and UFSAR Sections 5.1 and 5.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of the LRA 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 2.3.1.7-1 dated March 10, 2006, the staff noted that LRA Table 2.3.1.7 lists the component type "Top Head Enclosure Vessel Flange Leak Detection Penetration" as within the scope of
 
license renewal and subject to an AMR. However, it was not clear whether the tubes/pipes
 
connected to the penetration also were included within the scope of license renewal. Therefore, the staff requested that the applicant confirm whether the subject tubes/pipes had been included
 
within the scope of license renewal and, if not, that the applicant include the subject components
 
within the scope of license renewal requiring an AMR.
In its response dated April 7, 2006, the applicant stated that the vessel leak-off piping was included within the scope of license renewal and considered part of the nuclear boiler
 
instrumentation system. The applicant further stated that the subject component was in LRA
 
Table 2.3.1.4 in component types "pipings and fittings" and "valve body." The staff finds the
 
response acceptable. The staff's concern described in RAI 2.3.1.7-1 is resolved.
2.3.1.7.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the RPV components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-60 2.3.1.8  Reactor Recirculation System 2.3.1.8.1  Summary of Technical Information in the Application In LRA Section 2.3.1.8, the applicant described the reactor recirculation system, a reactivity control system that provides forced circulation of reactor coolant through the core. The reactor
 
recirculation system consists of the reactor reci rculation main loop piping, recirculation pumps and motors, recirculation motor-generator sets, recirculation system flow control, and recirculation
 
pump trip logic. The purpose of the reactor recirculation system, to provide forced circulation of
 
reactor coolant through the core, controls reactor power within a limited range without the need
 
for manipulation of the control rods. It accomplishes this purpose by delivering recirculated water
 
flow to the reactor vessel through five separate pumped loops, each with an individually
 
controllable variable speed pump. Under normal reactor power conditions, all five recirculation
 
loops are in operation, with all pumps operating at the same speed. Plant operation has been
 
analyzed with up to two recirculation loops out of service. Recirculation pump trip (RPT) is an
 
instrument-controlled function of the reactor recirculation system that decreases the pressure and
 
temperature transient during an ATWS event. The reactor protection system (RPS) supplies a signal to the RPT system causing a trip of all five recirculation pumps on a vessel low-low level
 
signal. On a vessel high-pressure signal from RPS, RPT trips three recirculation pumps
 
immediately and trips the remaining two pumps after a timed delay if the vessel high-pressure
 
condition still exists.
The reactor recirculation system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the reactor
 
recirculation system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the reactor recirculation system performs functions that support fire
 
protection, ATWS, and SBO.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.1.8, the applicant identified the following reactor recirculation system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (oil)
* filter housing (oil)
* flow element
* fluid drive (MG set coupling) - reservoir
* oil mist eliminator - reservoir
* piping and fittings
* pump casing
* sight glasses (oil) 2-61
* thermowell
* valve body 2.3.1.8.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.1.8 and UFSAR Sections 5.4.1, 7.6.1, and 7.6.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.1.8.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the reactor recirculation system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2  Engineered Safety Features Systems In LRA Section 2.3.2, the applicant identified the SCs of the ESF systems subject to an AMR for license renewal.
The applicant described the supporting SCs of the ESF systems in the following sections of the LRA:
* 2.3.2.1automatic depressurization system
* 2.3.2.2containment spray system
* 2.3.2.3core spray system
* 2.3.2.4standby gas treatment system (SGTS)
The staff's review findings on LRA Sections 2.3.2.1 - 2.3.2.4 are presented in SER Sections 2.3.2.1 - 2.3.2.4, respectively.
2.3.2.1  Automatic Depressurization System 2.3.2.1.1  Summary of Technical Information in the Application In LRA Section 2.3.2.1, the applicant described the automatic depressurization system (ADS), a standby ECCS designed to provide a controlled blow down of the primary system to rapidly reduce pressure during a small pipe break. Depressurization following a LOCA permits the low-pressure
 
core spray system to achieve timely rated flow of injection water into the reactor core to prevent 2-62 fuel clad melting. For larger breaks the vessel depressurizes sufficiently to permit core spray injection without ADS assistance. The ADS equipment also provides an overpressure protection
 
function for the RPV. The ADS is one of the systems that comprise the ECCS and as such is
 
designed to function throughout the post-accident period. The purpose of the ADS is to
 
depressurize the RCS either during a small break LOCA or in the event of an overpressure condition in the RPV. The ADS accomplishes this purpose by opening the electromatic relief
 
valves (EMRVs) to provide a controlled blowdow n of the primary coolant system and rapidly reduce reactor vessel pressure during a small pipe break or overpressure condition. Additionally, manual ADS actuation of the EMRVs is credited for pressure control during an isolation
 
condenser high-energy line break. The ADS automatic depressurization function, the
 
overpressure function, and the manual operation of the EMRVs are all controlled through the ADS
 
logic network.
The ADS contains safety-related components relied upon to remain functional during and following DBEs. In addition, the ADS performs functions that support fire protection, SBO, and
 
EQ.The intended functions within the scope of license renewal include:
* provides emergency core cooling where t he equipment provides coolant directly to the core
* provides an RCPB
* provides a sensor of process conditions and generates signals for reactor trip or ESF actuation
* relied upon 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)
* relied upon in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for EQ (10 CFR 50.49)
* relied upon in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for SBO (10 CFR 50.63)
The applicant identified the following ADS component types, which are evaluated with the main steam system (LRA Section 2.3.4.6), within the scope of license renewal and subject to an AMR:
* EMRV assemblies
* vacuum breakers
* piping and associated components
* Y-quenchers located in the torus 2.3.2.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.1 and UFSAR Sections 3.6.2.6.1, 5.2.2, 6.3.1.2, and 7.3.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those 2-63 components that the applicant had identified as within the scope of license renewal to verify that it had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.2.1.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the ADS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.2.2  Containment Spray System 2.3.2.2.1  Summary of Technical Information in the Application In LRA Section 2.3.2.2, the applicant described the containment spray system, a standby system designed to be used with the core spray system to remove the reactor core decay heat from the
 
containment in the event of a LOCA. The ESW system cools the containment spray heat exchangers, thereby providing the heat sink for the energy released during a LOCA. The containment spray system has the alternate capability of cooling the water in the torus pool during
 
normal, shutdown, and post-accident conditions. The containment spray system is comprised of
 
two redundant loops that deliver water from the torus pool to the spray headers in the drywell and
 
torus. The containment spray system is manually in itiated from switches in the control room. The containment spray pumps can be started manually for containment spray service if the proper containment spray initiation permissives are met. Two independent mode select switches are
 
provided, one for each loop, each with two modes, "drywell spray" and "torus cooling."
The containment spray system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the containment spray system performs
 
functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* provides filtration
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides conversion of fluid into spray In LRA Table 2.3.2.2, the applicant identified the following containment spray system component types within the scope of license renewal and subject to an AMR:
2-64
* closure bolting
* flow element
* piping and fittings
* pump casing
* spray nozzle
* strainer (ECCS suction)
* thermowell
* valve body 2.3.2.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 6.2.2 and 6.5.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed components
 
that the applicant had identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.2.2.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the containment spray system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.2.3  Core Spray System 2.3.2.3.1  Summary of Technical Information in the Application In LRA Section 2.3.2.3, the applicant described the core spray system, a low-pressure ECCS designed to provide cooling water for removal of decay heat from the reactor core following a
 
LOCA. Large-to-intermediate pipe breaks in the RCS cause a reactor pressure reduction
 
sufficient to permit the core spray system to achieve its rated injection flow prior to fuel cladding
 
melt. To accommodate the remaining intermediate-to-small pipe breaks, the ADS provides the
 
initial controlled depressurization to reduce reactor pressure and thus permit timely core spray
 
injection. In this manner, the core spray system pr ovides core cooling to prevent fuel clad melting for the entire spectrum of postulated LOCAs. The core spray system provides a supply of cooling
 
water to the reactor core independent of the feedwater system and operable on emergency
 
power. The core spray system is comprised of two independent loops, each containing full flow
 
test, keep-fill, and minimum flow pump protection features. Initiation of both loops of the core
 
spray system occurs upon receipt of a high drywell pressure or low-low reactor vessel level
 
signal. These signals also start both EDGs to supply power to the core spray pumps in the event
 
of loss of normal electric power supply. The core spray system also can be initiated manually.
2-65 The core spray system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the core spray system
 
potentially could prevent the satisfactory accomp lishment of a safety-related function. In addition, the core spray system performs functions that support fire protection, SBO, and EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.2.3, the applicant identified the following core spray system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* cyclone separator
* flow element
* gauge snubber
* piping and fittings
* pump casing (fill pumps)
* pump casing (main and booster pumps)
* restricting orifice
* sight glasses
* thermowell
* valve body 2.3.2.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.2.3 and UFSAR Sections 6.3.1 and 6.3.1.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.2.3.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable 2-66 assurance that the applicant has adequately identified the core spray system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.2.4  Standby Gas Treatment System (SGTS) 2.3.2.4.1  Summary of Technical Information in the Application In LRA Section 2.3.2.4, the applicant described the SGTS, a plant ESF ventilation system that filters and exhausts the reactor building atmosphere and drywell atmosphere to the stack during
 
secondary containment isolation conditions and drywell purging operations. The purpose of the
 
system is to limit post-accident radioactive releas es to the environs by collecting, filtering, and transporting fission products to the plant stack for elevated release. It accomplishes this purpose
 
by maintaining a negative pressure of 0.25 inch of water within the reactor building as to the
 
outside atmosphere to minimize unfiltered leakage of fission products from the reactor building
 
and by exhausting filtered release of the primary and secondary containments through the
 
ventilation stack. It also purges primary containment prior to outages when increased radioactivity
 
is present and backs up the reactor building ventilation system for this function. During normal
 
operation, the reactor building ventilation system is operating with the SGTS in standby. During a design basis accident (DBA), the SGTS fans are automatically started and effluents are filtered
 
prior to release through the ventilation stack.
The SGTS contains safety-related components relied upon to remain functional during and following DBEs. In addition, the SGTS performs functions that support EQ.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.2.4, the applicant identified the following SGTS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* damper housing
* door seal
* ductwork
* fan housing
* filter housing
* flexible connection
* flow element
* heater housing
* piping and fittings
* restricting orifice
* thermowell
* valve body 2-67 2.3.2.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.4 and UFSAR Sections 6.5.1, 7.3, 9.4.2, and 11.3.2.5 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with
 
the guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed components
 
that the applicant had identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
2.3.2.4.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the SGTS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).2.3.3  Auxiliary Systems In LRA Section 2.3.3, the applicant identified t he SCs of auxiliary systems subject to an AMR for license renewal.
The applicant described the supporting SCs of the aux iliary systems in the following sections of the LRA:
* 2.3.3.1"C" battery room heating and ventilation
* 2.3.3.24160V switchgear room ventilation
* 2.3.3.3480V switchgear room ventilation
* 2.3.3.4battery and MG set room ventilation
* 2.3.3.5chlorination system
* 2.3.3.6circulating water system
* 2.3.3.7containment inerting system
* 2.3.3.8containment vacuum breakers
* 2.3.3.9control rod drive system
* 2.3.3.10control room HVAC
* 2.3.3.11cranes and hoists
* 2.3.3.12drywell floor and equipment drains
* 2.3.3.13emergency diesel generator and auxiliary system
* 2.3.3.14emergency service water system
* 2.3.3.15fire protection system
* 2.3.3.16fuel storage and handling equipment
* 2.3.3.17hardened vent system
* 2.3.3.18heating and process steam system
* 2.3.3.19hydrogen and oxygen monitoring system 2-68
* 2.3.3.20instrument (control) air system
* 2.3.3.21main fuel oil storage and transfer system
* 2.3.3.22miscellaneous floor and equipment drain system
* 2.3.3.23nitrogen supply system
* 2.3.3.24noble metals monitoring system
* 2.3.3.25post-accident sampling system
* 2.3.3.26process sampling system
* 2.3.3.27radiation monitoring system
* 2.3.3.28radwaste area heating and ventilation system
* 2.3.3.29reactor building closed cooling water system
* 2.3.3.30reactor building floor and equipment drains
* 2.3.3.31reactor building ventilation system
* 2.3.3.32reactor water cleanup system
* 2.3.3.33roof drains and overboard discharge
* 2.3.3.34sanitary waste system
* 2.3.3.35service water system
* 2.3.3.36shutdown cooling system
* 2.3.3.37spent fuel pool cooling system
* 2.3.3.38standby liquid control system (liquid poison system)
* 2.3.3.39traveling in-core probe system
* 2.3.3.40turbine building closed cooling water system
* 2.3.3.41water treatment and distribution system The staff's review findings on LRA Sections 2.3.3.1 - 2.3.3.41 are presented in SER Sections 2.3.3.1 - 2.3.3.41, respectively.
2.3.3.1  "C" Battery Room Heating & Ventilation 2.3.3.1.1  Summary of Technical Information in the Application In LRA Section 2.3.3.1, the applicant described the "C" battery room heating and ventilation system. The "C" battery room heating and ventilati on system is a forced air ventilation system designed to maintain the "C" battery room within a specified temperature range and remove
 
hydrogen produced by battery charging. This condi tion exists when the battery chargers are in operation and hydrogen is produced by the battery charging function. The "C" battery room ventilation system is a nonsafety-related sy stem designed to support the 125V DC station "C" battery operation.
The failure of nonsafety-related SSCs in the "C" battery room heating and ventilation system potentially could prevent the satisfactory a ccomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides filtration
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system) 2-69 In LRA Table 2.3.3.1, the applicant identified the following "C" battery room heating and ventilation system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* damper housing
* door seal
* ductwork
* fan housing
* filter housing
* flexible connection
* flow element
* louvers
* piping and fittings 2.3.3.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.1 and UFSAR Sections 8.3.2.1 and 9.4.3.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed components
 
that the applicant had identified as within the scope of license renewal to verify that it had not
 
omitted any passive and long-lived components subject to an AMR in accordance with the
 
requirements of 10 CFR 54.21(a)(1).
 
2.3.3.1.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the "C" battery room heating and
 
ventilation system components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.2  4160V Switchgear Room Ventilation 2.3.3.2.1  Summary of Technical Information in the Application In LRA Section 2.3.3.2, the applicant described the 4160V switchgear room ventilation system, a continuously operating forced air-flow system designed to remove heat produced by the operation
 
of the switchgear and also to remove smoke in the event of a fire. The 4160V switchgear room
 
ventilation system accomplishes this purpose by supplying the required air flow through the vaults necessary to keep the room temperatures within the design limits of the switchgear and to meet the smoke removal requirements of 10 CFR 50.48. The switchgear areas served by this
 
ventilation system are in the turbine building with in the 1C and 1D switchgear vaults. Each vault roof ventilation penetration is provided with a three-hour rated fire damper.
2-70 The 4160V switchgear room ventilation system perfo rms functions that support fire protection and SBO.The intended functions within the scope of license renewal include:
* provides filtration
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.2, the applicant identified the following 4160V switchgear room ventilation system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* damper housing
* fan housing 2.3.3.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 9.4.3.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the subsystems functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.2.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the 4160V switchgear room ventilation
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.3  480V Switchgear Room Ventilation 2.3.3.3.1  Summary of Technical Information in the Application In LRA Section 2.3.3.3, the applicant described the 480V switchgear room ventilation system, a continuously operating forced air flow system designed to remove the heat produced by the
 
operation of the 480V switchgear, and to also remove any smoke produced by a fire. The purpose
 
of the system is to provide adequate ventilati on to maintain the equipment environment within 2-71 design temperature limits. The system accomplis hes this purpose by utilizing supply and exhaust fans, a recirculation flow path, and ducting, dampers, and controls. The system consists of two
 
independent ventilation trains, Train "A" for ventilation for 480V switchgear room A and train "B"
 
for 480v switchgear room B. Train "A" also includes an alternate exhaust fan with intake and
 
exhaust dampers. No heating or cooli ng is provided by this system.
The 480V switchgear room ventilation system c ontains safety-related components relied upon to remain functional during and following DBEs. In addition, the 480V switchgear room ventilation
 
system performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include:
* provides filtration
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.3, the applicant identified the following 480V switchgear room ventilation system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* damper housing
* door seal
* ductwork
* fan housing
* filter housing
* flexible connection
* louvers
* piping and fittings
* sensor element
* valve body 2.3.3.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.3 and UFSAR Section 9.4.5.2.6 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the subsystems functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
 
2-72 2.3.3.3.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the 480V switchgear room ventilation
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.4  Battery and MG Set Room Ventilation 2.3.3.4.1  Summary of Technical Information in the Application In LRA Section 2.3.3.4, the applicant described the battery and motor generator (MG) set room ventilation system, a continuously operating forc ed air flow system designed to remove the heat produced by operating equipment. The system is also designed to remove gasses produced by
 
the A and B station batteries and to remove any smoke produced by a fire. The purpose of the
 
system is to provide adequate ventilation to ma intain the equipment environment within design temperature limits and to remove any hydrogen released from the batteries. The system is supplemented with an air conditioning unit to provide additional MG set cooling when required.
 
The system accomplishes this purpose by utilizing supply and exhaust fans, a recirculation flow
 
path, and an air conditioning unit with ducting, dampers, and controls. The supply system flow
 
splits to supply both the battery room and the MG room, and the exhaust system draws air from both rooms. This system is actuated when the motor approaches or exceeds a set temperature.
The system is manually initiated and normally in operation.
The battery and MG set room ventilation system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the battery and MG set room
 
ventilation system performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include:
* provides filtration
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.4, the applicant identified the following battery and MG set room ventilation system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* damper housing
* door seal
* ductwork
* fan housing
* filter housing
* flexible connection 2-73
* flow element (pitot tube)
* louvers
* piping and fittings
* sensor element (temperature)
* valve body 2.3.3.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.4 and UFSAR Section 9.4.5.2.5 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the subsystems functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.4.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the battery and MG set room ventilation
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.5  Chlorination System 2.3.3.5.1  Summary of Technical Information in the Application In LRA Section 2.3.3.5, the applicant described the chlorination system, which operates year-round and is designed to inject sodium hypochlorite to various points in the circulating water, service water, and emergency service water system
: s. The purpose of the system is to eliminate or reduce biofouling while maintaining residual chlorine concentration at the discharge canal
 
within federal and state regulations. The system accomplishes the purpose by treatment of
 
systems using bay water as a heat sink in order to minimize micro and macro biofouling of heat
 
exchangers. Biofouling, if left unchecked, will affect performance. It accomplishes this check by
 
chlorine bonding with amines in the marine environment to form toxic chloramine compounds. It
 
also displaces bromine and iodine, both essential marine salts. Marine life, dependent upon a
 
stable balance of chemistry, dies. The chlorination system is comprised of two hypochlorite
 
storage tanks, two eductors, and the required piping, valves, instrumentation, and controls. The
 
sodium hypochlorite is stored in two 6500-gallon plastic storage tanks. The system is located within the chlorination building and adjacent pad with the exception of the piping routed below
 
grade and in the turbine building.
The failure of nonsafety-related SSCs in the chlo rination system potentially could prevent the satisfactory accomplishment of a safety-related function.
2-74 The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.5, the applicant identified the following chlorination system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* piping and fittings
* valve body 2.3.3.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.5 and UFSAR Section 10.4.5.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.5.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the chlorination system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.6  Circulating Water System 2.3.3.6.1  Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant described the circulating water system (CWS), a low-pressure, high-volume open-cycle cooling water system designed to provide cooling water to
 
the main condenser and the main source of cooling water for the turbine building closed cooling
 
water (TBCCW) heat exchangers. If TBCCW heat exchanger cooling water is not available from
 
the CWS, the service water system (SWS) provides the cooling water to the TBCCW heat
 
exchangers. The CWS pumps are located at the intake structure in separate chambers. The
 
pumps draw sea water from the intake canal and discharge the water into large diameter pipe
 
lines that deliver the cooling water to the intake tunnel. Each pump discharge line has an isolation
 
valve and local pressure instrumentation. From the intake tunnel the water flows into large 2-75 individual pipes that supply the cooling water to each condenser shell. Each of these cooling water supply lines has an isolation valve and a chlorination system connection. Heat is absorbed
 
by the cooling water, increasing the water discharge temperature. The heated water is discharged
 
through large lines to the discharge tunnel. Each discharge line has an isolation valve. The
 
discharge tunnel delivers the water to the discharge canal and the water flows from the canal into
 
Barnegat Bay. Deicing recirculation is provided during cold weather operation.
The failure of nonsafety-related SSCs in the CWS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.6, the applicant identified the following CWS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* expansion joint
* flow glass
* flow indicator
* level glass
* piping and fittings
* strainer body
* thermowell
* valve body 2.3.3.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.6 and UFSAR Section 10.4.5 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.6.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the CWS components within the scope of 2-76 license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.7  Containment Inerting System 2.3.3.7.1  Summary of Technical Information in the Application In LRA Section 2.3.3.7, the applicant described the containment inerting system (CIS), a pressurized gas system designed to maintain an inert atmosphere within the primary containment
 
to preclude energy releases from a possible hydrogen-oxygen reaction following a postulated
 
LOCA. The purpose of the CIS is to provide primary containment purging and makeup in order to
 
control the oxygen concentration inside the primary containment. To ready the primary containment for power operation, the CIS accomplishes the purpose of purging by introducing
 
nitrogen to displace the oxygen from the free volume in the primary containment. During power
 
operation, the CIS accomplishes the purpose of makeup by introducing nitrogen to maintain a low
 
oxygen concentration in the primary containment. During power operation, when nitrogen makeup
 
is not in service, the nitrogen atmosphere is isolated within the primary containment and
 
recirculated by the drywell cooling system. Following a DBA LOCA, the CIS accomplishes the
 
purpose of purging by introducing nitrogen into the primary containment to control post-LOCA
 
hydrogen and oxygen concentrations to below combustible levels. CIS operation in both the purge
 
and makeup modes is initiated manually. The CIS receives vaporized nitrogen through two headers from the nitrogen supply system, the purge header and the nitrogen makeup header.
The CIS contains safety-related components relied upon to remain functional during and following DBEs. In addition, the CIS performs functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.7, the applicant identified the following CIS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* drain trap
* flow element
* piping and fittings
* thermowell
* valve body 2.3.3.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.7 and UFSAR Section 6.2.5 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended 2-77 functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.7.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the CIS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.8  Containment Vacuum Breakers 2.3.3.8.1  Summary of Technical Information in the Application In LRA Section 2.3.3.8, the applicant described the containment vacuum breaker (CVB) system, two systems designed to prevent torus water fr om backing up into the drywell during various reactor leakage and suppression condensation modes and limit negative pressure differentials on
 
the drywell in conjunction with the reactor build ing to torus vacuum relief system. These systems are the torus to drywell and the reactor building to torus vacuum relief systems. The purpose of
 
the torus to drywell vacuum relief system is to prevent the drywell pressure from dropping significantly below the pressure in the torus airspace. The reactor building to torus vacuum relief
 
system is intended to prevent the torus air spac e pressure from dropping significantly below the ambient atmospheric pressure in the reactor building. The reactor building to torus vacuum
 
breakers accomplish their purpose by opening automatically at a predetermined differential
 
pressure. The torus to drywell vacuum breakers accomplish theirs by venting non-condensable
 
gas (carryover to the torus during an accident) ba ck to the drywell from the torus. The primary containment has a vacuum breaker system to equalize the pressure between the drywell and the torus and between the torus and the reactor building. The CVB system assures that the external
 
design pressure limits of the two chambers are not exceeded.
The CVB system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the CVB system performs functions that support fire protection and
 
EQ.The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.8, the applicant identified the following CVB system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* expansion joint 2-78
* piping and fittings
* valve body
* valve body (vacuum breakers) 2.3.3.8.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.8 and UFSAR Section 6.2.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.8.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the CVB system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.9  Control Rod Drive System 2.3.3.9.1  Summary of Technical Information in the Application In LRA Section 2.3.3.9, the applicant described the CRD system, the primary purpose of which is to rapidly insert negative reactivity to shut down the reactor under accident or transient conditions
 
and to manage reactivity in the reactor core by in serting or withdrawing control rods at a limited rate, one rod at a time, for power level control and flux shaping during normal reactor operation.
 
The CRD system accomplishes this purpose by providing water at the required operating
 
pressures to the control rod drives for cooling and for all types of control rod motion in response to
 
inputs from the reactor manual control system (RMCS) and RPS. The secondary purpose of the CRD system is to supply the reactor head cooling system (RHCS). It accomplishes this purpose
 
by providing water at the required pressure to the reactor vessel head spray nozzle used to cool
 
the upper head region during plant cooldown. The CRD system is comprised of CRD mechanisms
 
and the CRD hydraulic system. Each of the CRDMs is a double-acting, mechanically-latched, hydraulic cylinder with reactor grade water as the operating fluid. Each CRD mechanism is
 
capable of inserting or withdrawing the attached control rod at a slow, controlled rate as well as
 
rapidly in an emergency. A locking mechanism allows a drive to be positioned during stroking to
 
hold the control rod in a fixed position.
The CRD system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the CRD system potentially could 2-79 prevent the satisfactory accomplishment of a safety-related function. In addition, the CRD system performs functions that support fire protection, SBO, and EQ.
The intended functions within the scope of license renewal include:
* provides filtration
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.3.9, the applicant identified the following CRD system component types within the scope of license renewal and subject to an AMR:
* accumulator
* closure bolting
* filter
* filter housing
* flow element
* gauge snubber
* gear box
* piping and fittings
* pump casing
* restricting orifice
* rupture disks
* strainer
* strainer body
* valve body 2.3.3.9.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.9 and UFSAR Sections 3.9.4, 4.5, 4.6, and 15.8 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-80 2.3.3.9.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the CRD system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.10  Control Room HVAC 2.3.3.10.1  Summary of Technical Information in the Application In LRA Section 2.3.3.10, the applicant described the control room heating, ventilation, and air conditioning (HVAC) system that serves the contro l room envelope, which consists of the control room and lower cable spreading room. The control room HVAC system is evaluated with the separate miscellaneous HVAC license renewal sy stem. The purpose of the control room HVAC system is to maintain a comfortable tem perature and provide ventilation for personnel and equipment during normal operation. It also incorporates three incident modes of operation to
 
provide a habitable environment for control room operators and equipment cooling after radiological releases from DBAs during or after toxic chemical releases and for fires inside the
 
control room. The normally operating system is in itiated into incident modes manually. In addition to normal operation, three incident modes of partial recirculation, full recirculation, and purge are
 
available. In the event of a DBA manual selection of the partial recirculation mode maintains the
 
control room envelope at a positive pressure with minimal infiltration. During toxic gas releases, the full recirculation mode uses no outside air for minimal intrusion of toxic gases. In the event of
 
smoke in the control room envelope, purge mode selection supplies all outdoor air to avoid recirculation and clear smoke and fumes.
The control room HVAC system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the control room HVAC system performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include:
* provides filtration
* provides heat transfer
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.10, the applicant identified the following control room HVAC system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* damper housing
* door seal 2-81
* ductwork
* fan housing
* filter housing
* flexible connection
* heat exchangers (condensing coil)
* heat exchangers (evaporator coil)
* heater housing
* louvers
* piping and fittings 2.3.3.10.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.10 and UFSAR Sections 9.4.1, 6.4.1, and 12.3.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
The staff reviewed the subsystems functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.10.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the control room HVAC system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.11  Cranes and Hoists 2.3.3.11.1  Summary of Technical Information in the Application In LRA Section 2.3.3.11, the applicant described the cranes and hoists system comprised of load handling overhead bridge cranes, monorails, jib cranes, and hoists throughout the facility to
 
support operation and maintenance activities. The system includes cranes and hoists required to
 
comply with the requirements of NUREG-0612, "Control of Heavy Loads," and hoists for handling
 
light load. Major cranes include the reactor building and the turbine building cranes. The reactor
 
building crane services the operating floor and is used to lift all heavy loads that must travel over
 
the spent fuel pool. The crane is also used to handle new fuel and transport the spent fuel cask
 
and has been upgraded to a single failure-proof criterion in accordance with NUREG-0612 and
 
NUREG-0554. The turbine building crane handles heavy loads in the turbine building, primarily
 
supporting turbine repairs or maintenance. Included in the evaluation boundary of cranes and
 
hoists system are load handling systems in various areas of the facility. Cranes and hoists are classified non-safety related and designed to seismic Class II criteria.
2-82 The cranes and hoists system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the cranes and
 
hoists system potentially could prevent the sati sfactory accomplishment of a safety-related function.
The intended function, within the scope of license renewal, is to provide structural support or structural integrity to preclude nonsafety-related component interactions that could prevent
 
satisfactory accomplishment of a safety-related function.
In LRA Table 2.3.3-11, the applicant identified the following cranes and hoists system component types within the scope of license renewal and subject to an AMR:
* crane (bridge; trolley)
* crane (bridge; trolley; girders )
* jib cranes (columns; beams; anchorage)
* monorails, and hoists (beams; plates)
* rail system (rail, plates, clips)
* structural bolts 2.3.3.11.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.11 and UFSAR Section 9.1.4.2.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.11.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the cranes and hoists system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.12  Drywell Floor and Equipment Drains 2.3.3.12.1  Summary of Technical Information in the Application In LRA Section 2.3.3.12, the applicant described the drywell floor and equipment drains (DFEDs) comprised of both gravity and pumped fluid lines designed for the collection of drainage from floor
 
and equipment drains located in the drywell structure and transfer of the drainage to the radwaste
 
system. They also include that portion of the RCPB leak detection function comprised of the 2-83 instrumentation monitoring the drywell floor drain sump fill time and pump flow rates from the drywell floor drain sump and drywell equipment drain tank. The DFED accomplish this purpose by
 
collecting floor drainage and condensed steam from the drywell air coolers in the drywell floor
 
drain sump and equipment drainage in the drywell equipment drain tank and using submersible
 
pumps from the sump and duplex pumps from the drain tank to transfer the collected drainage to radwaste system collection tanks for processing. Both identified and unidentified leakage are
 
collected by the DFEDs.
The DFEDs contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the DFEDs potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the DFEDs performs
 
functions that support EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.12, the applicant identified the following DFEDs component types within the scope of license renewal and subject to an AMR:
* closure bolting
* flow element
* flow glass
* heat exchanger
* piping and fittings
* pump casing
* tanks
* valve body 2.3.3.12.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.12 and UFSAR Sections 5.2.5, 9.3.3, and 11.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2-84 2.3.3.12.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the DFEDs components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.13  Emergency Diesel Generator and Auxiliary System 2.3.3.13.1  Summary of Technical Information in the Application In LRA Section 2.3.3.13, the applicant described the EDG and auxiliary system, the purpose of which is to provide sufficient power independently to energize all equipment required for safely
 
shutting down the reactor. It accomplishes this purpose using two diesel generator units located in
 
separate rooms of a stand-alone, reinforced concrete structure. Each diesel engine powers a
 
generator at a voltage compatible to the plant electrical distribution systems with sufficient output
 
capacity to meet plant shutdown loads. Each diesel generator is equipped with its own starting
 
system, cooling system, lubric ation system, combustion air and equipment cooling system, a fuel oil storage and transfer system, and all the auxiliaries that allow it to perform its function. The
 
diesels are automatically started by a reactor lo w-low level, a high drywell pressure signal, by an undervoltage condition in the 4160V AC system, or by a low diesel generator lube oil temperature.
The diesels can be remotely manually started fr om the control room or at the local EDG switchgear panels.
The EDG and auxiliary system contains safe ty-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the EDG and
 
auxiliary system potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the EDG and auxiliary system performs functions that support fire protection and SBO.The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides filtration
* provides rated fire barrier
* provides heat transfer
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary
* provides flow restriction 2-85 In LRA Table 2.3.3.13, the applicant identifi ed the following EDG and auxiliary system component types within the scope of license renewal and subject to an AMR:
* bird screen
* closure bolting
* ductwork
* exhaust stack
* fan housing (dust bin blower fan)
* fan housing (radiator fan)
* filter (inertial air bin)
* filter (oil bath)
* filter housing (air cooling)
* filter housing (fuel oil)
* filter housing (lube oil)
* flame arrester (fuel oil tank)
* flexible hose
* heat exchanger (lube oil cooler)
* heat exchangers (radiator)
* louvers
* muffler
* piping and fittings
* pump casing (fuel oil)
* pump casing (lube oil)
* restricting orifice
* sensor element (lube oil)
* sensor element (temperature control manifold)
* sight glasses
* strainer
* strainer body
* tanks (fuel day tank)
* tanks (fuel oil tank)
* tanks (immersion heater)
* tanks (water tank)
* temperature control manifold (water cooling)
* thermowell
* valve body 2.3.3.13.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.13 and UFSAR Sections 8.3.1.1.5, 9.5.4, 9.5.5, 9.5.6, 9.5.7, 9.5.8, and 9.5.9 using the evaluation methodology of SER Section 2.3. The staff conducted its
 
review in accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2-86 2.3.3.13.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the EDG and auxiliary system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.14  Emergency Service Water System 2.3.3.14.1  Summary of Technical Information in the Application In LRA Section 2.3.3.14, the applicant described the ESW system, which, along with the containment spray system, comprise the contai nment heat removal systems. The purpose of this system is to aid the containment spray system in removing fission product decay heat from the primary containment following a design-basis LO CA. This system is also used during normal operation to cool the torus when necessary. It accomplishes this purpose by supplying cooling
 
water, from the ultimate heat sink (intake canal), to the containment spray heat exchangers and
 
transferring the heat energy to the environment via the discharge canal. During normal plant
 
operations, when ESW is in standby, the SWS supplies a constant flow of water through the
 
containment spray heat exchangers to maintain them full of chlorinated water. Sodium
 
hypochlorite is injected into the ESW system via the SWS keep fill line. Additionally, ESW can be
 
cross-connected with the SWS to allow ESW to provide an alternate cooling path during plant
 
shutdown and during SWS maintenance.
The ESW system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the ESW system potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the ESW system
 
performs functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* provides heat transfer
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary
* provides flow restriction In LRA Table 2.3.3.14, the applicant identified the following ESW system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* expansion joint
* flow element 2-87
* heat exchangers (containment spray)
* piping and fittings
* pump casing (ESW pumps)
* pump casing (HTXR drain pumps)
* restricting orifice
* sight glasses
* thermowell
* valve body 2.3.3.14.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.14 and UFSAR Sections 6.2.2, 7.3.1 and 9.2.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.14 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 2.3.3.14-1 dated December 28, 2005, the staff stated that several strainers not identified on LRA Table 2.3.3.14 as requiring aging management are indicated as within the scope of
 
license renewal on its license renewal drawing. The staff requested that the applicant clarify
 
whether these long-lived passive components are subject to an AMR or justify their exclusion
 
from LRA Table 2.3.3.14.
In its response dated January 26, 2006, the applicant stated:
The strainer symbols shown on license r enewal drawing LR-BR-2005, Sheet 4 at drawing coordinates C-7, C-8, F-7, and F-8 are depicting the diaphragm seal that is
 
integral to the pressure indicator assembly. The diaphragm seal is not specifically
 
called out in LRA Table 2.3.3.14 since it is considered part of the "active" pressure
 
instrument. Diaphragm seals isolate pressu re instruments from the process media while allowing the instrument to sense the process pressure. A diaphragm, together with a fill fluid, transmits pressure from the process medium to the
 
pressure element assembly of the instrument. There would be no need to filter the
 
medium prior to the diaphragm seal.
Because these diaphragm seals are part of the pressure indicator assembly, which is an "active" component, they are not subject to aging management review.
The staff's review finds the applicant's response acceptable because it adequately clarified that the components in question are active (parts of an instrument assembly) and not subject to an
 
AMR under 10 CFR 54.21(a)(1). The staff's concern described in RAI 2.3.3.14-1 is resolved.
2-88 2.3.3.14.3  Conclusion The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the ESW system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.15  Fire Protection System 2.3.3.15.1  Summary of Technical Information in the Application In LRA Section 2.3.3.15, the applicant described the fire protection system, a normally operating mechanical system designed to provide for the rapid detection and suppression of a fire at the
 
plant. The purpose of the fire protection system is to promptly detect, contain, and extinguish fires if they occur, maintain the capability to safely shut down the plant if fires occur, and prevent the
 
release of a significant amount of radiation in the event of a fire. The fire protection system
 
accomplishes this purpose by providing fire protection in the form of detection, alarms, fire
 
barriers, and suppression for selected areas of the plant. The fire protection system consists of
 
the fire protection water system, carbon dioxide (CO
: 2) gas systems, halon systems, portable foam equipment, portable fire extinguishers, and fire detection and signaling systems. These systems work in conjunction with physical plant design features to provide overall fire protection for OCGS.
 
The physical plant design features consist of fire barrier walls and slabs, fire barrier penetration
 
seals, fire doors, fire-rated enclosures (including steel fire wrap), and dikes credited for containing
 
oil spills.
The fire protection system performs an intended function for compliance with fire protection regulations. The fire protection system works in conjunction with fire barriers and other plant
 
design features and established safe-shutdown systems and procedures for compliance with
 
10 CFR 50.48. The failure of nonsafety-related SSCs in the fire protection system potentially
 
could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides filtration
* provides rated fire barrier (dikes to contain oil spill)
* provides rated fire barrier (confine fire from spreading to or from adjacent areas of the plant)
* provides heat transfer
* provides mechanical closure
* provides pressure-retaining boundary so that sufficient flow at adequate pressure is delivered
* provides conversion of liquid into spray
* provides flow restriction 2-89 In LRA Table 2.3.3.15, the applicant identified the following fire protection system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* dikes
* expansion joint
* fire barrier penetration seals
* fire barrier walls and slabs
* fire doors
* fire hydrant
* fire rated enclosures
* flexible hose
* flow element (Annubar)
* gas bottles (CO 2 , halon storage cylinders)
* gauge snubber
* gear box
* heat exchangers
* hose manifold
* odorizer
* piping and fittings
* pump casing (redundant fire pump)
* pump casing (vertical turbine)
* restricting orifice
* spray nozzle (CO 2 , halon)
* sprinkler heads
* strainer
* strainer body
* tank heater
* tanks (CO
: 2)
* tanks (fuel oil)
* tanks (retarding chamber)
* tanks (water storage)
* thermowell
* valve body
* water motor alarm 2.3.3.15.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.15 and UFSAR Section 9.5.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-90 The staff also reviewed the approved fire protection SER dated March 3, 1978, and supplements for OCGS. This report, referenced directly in the fire protection CLB, summarizes the fire
 
protection program and commitments to 10 CFR 50.48 with the guidance of Appendix A to BTP
 
Auxiliary and Power Conversion Systems Branch (APC SB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants, Docketed Prior to July 1, 1976," dated August 23, 1976. The staff then
 
reviewed those components that the applicant had identified as within the scope of license
 
renewal to verify that it had not omitted any passive and long-lived components subject to an AMR under 10 CFR 54.21(a)(1). The applicant provided a technical position paper which
 
summarizes the results of the study of the fi re protection program documents and the systems and structures necessary for compliance with 10 CFR 50.48.
The staff's review of LRA Section 2.3.3.15 identified areas in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.3.3.15-1 dated January 5, 2006, the staff stated that drawing LR-JC-19479, sheet 2, shows the sprinkler system valve for sprinkler systems 17A and 17B (C-1) colored in green (i.e., within the scope of license renewal). Drawing LR-JC-19479, sheet 3, shows sprinkler
 
systems 17A and 17B (A-6) as not within the scope of license renewal. The staff requested that
 
the applicant verify whether sprinkler valves 17A and 17B are within the scope of license renewal
 
in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with
 
10 CFR 54.21(a)(1) or, if excluded from the scope of license renewal and not subject to an AMR, justify the exclusion.
 
In its response dated February 3, 2006, the applicant stated that drawing LR-JC-19479, sheet 2, inadvertently identified sprinkler systems 17A and 17B as within the scope of license renewal, that these systems are not within the scope of license renewal, and that the basis for exclusion is
 
documented in PP-07, "Systems and Structures Relied upon to Demonstrate Compliance With
 
10 CFR Part 50.48 - Fire protection:" These sprinkler systems, downstream of t he isolation valve V-9-913, are classified as not important to safety (NITS) on the flow diagram and in TDR-622, "ITS/NITS
 
Classification of Suppression Systems and Fire Detection Systems." The
 
component record list does not identify any safety-related components in the areas
 
covered by these sprinkler systems. The OCGS fire hazards analysis report does
 
not identify any fire safe-shutdown equipment in these areas. A fire in these areas
 
does not significantly increase the risk of radioactive releases to the environment.
 
These sprinkler systems are not included in the scope of license renewal.
The applicant further stated that drawing LR-JC-19479, sheet 2, will be revised to show details for sprinkler systems 17A and 17B as black and not within the scope of license renewal.
The staff's review finds the applicant's response to RAI 2.3.3.15-1 acceptable. The applicant explained that sprinkler systems 17A and 17B are not within the scope of license renewal and not
 
subject to an AMR because they do not protect any safety-related components in the areas they
 
cover. The license renewal drawing inadvertently included highlighted portions of the sprinkler
 
system in error. The staff concludes that the components had been correctly excluded from the scope of license renewal and from AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.15-1 is resolved.
2-91 In RAI 2.3.3.15-2 dated January 5, 2006, the staff stated that in the fire protection SER dated March 3, 1978, Sections 3.1.5 and 5.9 discuss the halon 1301 system for the cable spreading
 
room (CSR). The LRA does not list the halon 1301 system for the CSR. The staff requested that
 
the applicant verify whether the halon 1301 system and components are within the scope of
 
license renewal under 10 CFR 54.4(a) and subject to an AMR under 10 CFR 54.21(a)(1) or, if
 
excluded from the scope of license renewal and not subject to an AMR, justify the exclusion.
In its response dated February 3, 2006, the applicant stated that the referenced fire protection SER includes items marked with asterisks to indicate that the staff would require additional
 
information for them. Section 3.1.5 of the fire protection SER is marked with an asterisk and the
 
additional information was provided to the NRC by letter dated August 31, 1979. In this letter, halon systems were proposed for the 480V swit chgear room, control room panels, and A and B battery rooms. These proposed modifications were accepted by the staff, as indicated in
 
supplement 3 to the fire protection SER dated August 25, 1980. These halon systems are shown
 
as within the scope of license renewal on drawing LR-JC-19629, sheet 2. Halon systems are
 
included in the fire protection system for license renewal.
The staff's review finds the applicant's response to RAI 2.3.3.15-2 acceptable because the CSR halon system had been replaced by the deluge spri nkler system during modifications. This replacement was confirmed by drawing LR-JC-19479, sheet 2. Also the staff confirmed that the CSR deluge sprinkler system is within the scope of license renewal under 10 CFR 54.4(a) and
 
subject to an AMR under 10 CFR 54.21(a). Therefore, the staff's concern described in
 
RAI 2.3.3.15-2 is resolved.
In RAI 2.3.3.15-3, dated January 5, 2006, the staff stated that in the SER dated March 3, 1978, Section 3.1.6 discusses automatic water spray and detection systems to protect safety-related
 
cabling on the 23- and 51-foot levels of the reactor building and safety-related cables below the
 
4160V switchgear vault. The LRA does not list automat ic spray systems for these areas. The staff requested that the applicant verify whether the automatic spray system and components are within the scope of license renewal under 10 CFR 54.4(a) and subject to an AMR under
 
10 CFR 54.21(a)(1) or, if excluded from the scope of license renewal and not subject to an AMR, that the applicant justify the exclusion.
In its response dated February 3, 2006, the applicant stated that the referenced SER includes items marked with asterisks to indicate that the NRC staff will require additional information for
 
them, that Section 3.1.6 is marked with an asterisk, and that additional information was provided
 
to the staff by letter dated August 31, 1979. In this letter, water spray systems were proposed for
 
the 23- and 51-foot levels of the reactor building and for the CSR. These proposed modifications
 
were accepted by the staff, as indicated in supplement 3 to the fire protection SER dated
 
August 25, 1980. These systems identified as del uge systems 4A, 4B, 5, 6, 7 and 8 on drawing LR-JC-19479 sheet 2 (F-2) are shown as within the scope of license renewal on drawings
 
LR-JC-19629 sheet 2 (typical details) and sheet 3 (B-4, F-5, C-5, G-5, B-5). Automatic spray
 
systems are included in the fire protection system for license renewal.
The staff's review finds the applicant's response to RAI 2.3.3.15-3 acceptable because it adequately explained that the fire suppression systems in question are within the scope of license
 
renewal under 10 CFR 54.4(a) and subject to an AMR under 10 CFR 54.21(a). Further, the
 
applicant properly identified fire suppression as deluge systems represented in the drawings LR-JC-19479, sheet 2, and LR-JC-19629, sheet 2. Therefore, the staff's concern described in
 
RAI 2.3.3.15-3 is resolved.
2-92 In RAI 2.3.3.15-4 dated January 5, 2006, the staff stated that the SER dated March 3, 1978,Section 3.1.7, discusses sprinkler systems for:
* the metal deck roof at the 119-foot level of the reactor building
* spent fuel pool cooling pumps
* the monitor and change room above and below the suspended ceiling to protect cables above the ceiling
* diesel-driven fire pumps and outside fuel oil storage tanks
* the turbine building above cable trays at the ceiling level of the condenser bay along the west wall.
The staff requested that the applicant verify whether the sprinkler system and components are within the scope of license renewal under 10 CFR 54.4(a) and subject to an AMR under
 
10 CFR 54.21(a)(1) or, if excluded from the scope of license renewal and not subject to an AMR, that the applicant justify the exclusion.
In its response dated February 3, 2006, the applicant stated that the referenced SER includes items marked with asterisks to indicate that the staff would require additional information for them.
 
In the SER dated March 3, 1978, Section 3.1.7 is marked with an asterisk, and the additional
 
information was provided to the staff by letter dated August 31, 1979. In this letter, sprinkler
 
systems were proposed for the 119-foot level of the reactor building, spent fuel pool cooling
 
pumps, the monitor and change area, the fire water pump house, diesel fuel tanks, condenser
 
bay, and turbine building basement. These proposed modifications were accepted by the staff, as
 
indicated in supplement 3 to the fire protection SER dated August 25, 1980. These systems are
 
identified as sprinkler systems 1, 2, 3, 10, 11 and 12, and deluge system 9 on drawing
 
LR-JC-19479, sheet 2 (F-2, G-2) and as within the scope of license renewal on drawing
 
LR-JC-19629, sheet 2 (typical details), and sheet 3 (D-5, G-7, E-4, C-4, E-9). Sprinkler systems
 
are included in the fire protection system for license renewal.
The staff's review finds the applicant's response to RAI 2.3.3.15-4 acceptable because it adequately explained that the fire suppression systems in question are within the scope of license
 
renewal under 10 CFR 54.4(a) and subject to an AMR under 10 CFR 54.21(a). Further, the
 
applicant properly identified fire suppression as deluge systems represented in the drawings LR-JC-19479, sheet 2, and LR-JC-19629, sheet 2. Therefore, the staff's concern described in
 
RAI 2.3.3.15-4 is resolved.
In RAI 2.3.3.15-5 dated January 5, 2006, the staff stated that in the SER dated March 3, 1978, Section 3.1.21 discusses water shields, dikes, or other protection that will be provided where
 
breaks of suppression system piping may dam age safety-related equipment. The staff requested that the applicant clarify whether these water shields had been installed and, if so, whether they
 
are within the scope of license renewal under 10 CFR 54.4(a) and subject to an AMR under
 
10 CFR 54.21(a)(1) or, if excluded from the scope of license renewal and not subject to an AMR, that the applicant justify the exclusion.
In its response dated February 3, 2006, the applicant stated that the referenced SER includes items marked with asterisks to indicate that the staff would require additional information for them.
 
In the SER dated March 3, 1978, Section 3.1.21 is marked with an asterisk, and the additional
 
information was provided to the staff by letter dated August 31, 1979. This letter describes the 2-93 specific design features to preclude fire protection system water damage to safety-related equipment. Curbs, drains and water shields were installed. These proposed modifications were
 
accepted by the staff, as indicated in supplement 3 to the fire protection SER dated
 
August 25,1980. The in-scope curbs and spray shields are identified with the reactor building
 
structure. The in-scope drains are identified as parts of the reactor building floor and equipment
 
drains system, the miscellaneous floor and equipm ent drain system, and the roof drains and overboard discharge system shown on draw ings LR-JC-147434, sheet 3, and LR-JC-2005, sheet 2.The staff's review finds the applicant's response to RAI 2.3.3.15-5 acceptable because it adequately explained that the components in question are within the scope of license renewal in
 
accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a) and
 
correctly identified them on drawings LR-JC-147434, sheet 3, and LR-JC-2005, sheet 2 as within
 
the scope of license renewal and subject to an AMR. Therefore, the staff's concern described in
 
RAI 2.3.3.15-5 is resolved.
2.3.3.15.3  Conclusion
 
The staff reviewed the LRA and the RAI responses to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions
 
were identified. In addition, the staff determined whether any components subject to an AMR had
 
not been identified by the applicant. No omissions were identified. The staff's review concludes
 
that there is reasonable assurance that the applicant has adequately identified the fire protection
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.16  Fuel Storage and Handling Equipment 2.3.3.16.1  Summary of Technical Information in the Application In LRA Section 2.3.3.16, the applicant described the fuel storage and handling equipment system, the purpose of which is to support, transfer, and provide for storage of nuclear fuel in a manner
 
that precludes inadvertent criticality. The fuel storage and handling equipment system is
 
comprised of the spent fuel storage pool and racks, the new fuel storage vault and racks, the cask
 
drop protection system, and fuel handling equipment. The spent fuel storage pool is enclosed and
 
an integral part of the reactor building structure. It is a reinforced concrete structure completely
 
lined with seam-welded stainless steel liner plate that serves as a watertight barrier. The pool
 
contains 14 high-density stainless steel poison racks for storage of spent fuel, ten equipped with
 
Boraflex and four with Boral poison. The pool is filled with 38 feet of demineralized water (25 feet
 
above the fuel) for adequate shielding for normal building occupancy by operating personnel.
 
Water temperature is maintained within acceptabl e limits by the spent fuel pool cooling system.
The spent fuel storage pool and the racks are classified as safety-related seismic Class I
 
structures. The new fuel storage vault is located within the reactor building adjacent to the spent
 
fuel storage pool. The reinforced concrete vault contains aluminum racks for dry storage of new
 
fuel bundles. The new fuel storage vault and the racks are classified as seismic Class I structures.
 
The cask drop protection system is a cylindric al stainless steel guide structure assembly permanently installed in the northeast corner of the spent fuel storage pool. The guide structure
 
assembly consists of an upper guide cylinder and a lower dashpot cylinder. The cask drop
 
protection system rests on the bottom of the spent fuel pool and is laterally braced from the pool
 
walls. The structure is classified seismic Class I. Fuel handling equipment consists of the reactor 2-94 building overhead bridge crane, jib cranes, the refueling platform, fuel preparation machines, and special purpose tools for handling new fuel, spent fuel, and reactor vessel internals and
 
components.
The fuel storage and handling equipment system c ontains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the fuel
 
storage and handling equipment system potentially c ould prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides neutron absorption in spent fuel pool
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.16, the applicant identified the following fuel storage and handling equipment system component types within the scope of license renewal and subject to an AMR:
* cask drop protection cylindrical structure
* fuel grapple/mast
* fuel preparation machine
* new fuel storage racks
* refueling platform
* spent fuel storage racks
* structural bolt
 
2.3.3.16.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.16 and UFSAR Section 9.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.16.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the fuel storage and handling equipment
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-95 2.3.3.17  Hardened Vent System 2.3.3.17.1  Summary of Technical Information in the Application In LRA Section 2.3.3.17, the applicant described the hardened vent system (HVS), the purpose of which is to vent the primary containment via the torus (primary path) or drywell (secondary path)
 
during severe accident sequences that involve loss of decay heat removal capability (the torus is
 
the preferred vent path because of the scrubbing effect of the torus water). The HVS
 
accomplishes this purpose by providing a vent path to the ventilation stack from either the torus or drywell through the CIS nitrogen purge header and its drywell and torus nitrogen purge inlet
 
pressure control valves. The HVS is designed for the mitigation of severe accident sequences
 
beyond the DBA.
The failure of nonsafety-related SSCs in the HVS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation for fission product retention; or containment, holdup, and plateout function In LRA Table 2.3.3.17, the applicant identified the following HVS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* enclosure boot
* piping and fittings
* valve body 2.3.3.17.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.17 and UFSAR Section 6.2.7 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
The staff reviewed the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.17.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the HVS components within the scope of 2-96 license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.18  Heating & Process Steam System 2.3.3.18.1  Summary of Technical Information in the Application In LRA Section 2.3.3.18, the applicant described the heating and process steam system, the purpose of which is to provide steam in sufficient capacity for operation of the radwaste
 
concentrator for evaporative processing of liquid radioactive waste, for plant area heating, and for
 
oxygen-free boiler feedwater. It accomplishes its purpose through two fuel oil-fired boilers and
 
their supporting systems, including steam di stribution and condensate systems, and through chemical addition. Operation of the heating and pr ocess steam system is not required to perform or support any safety-related function and c onsequently the system is nonsafety-related.
The failure of nonsafety-related SSCs in the heat ing and process steam system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.18, the applicant identified the following heating and process steam system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (sample)
* flexible connection
* flow element
* heat exchangers
* piping and fittings
* pump casing - chemical addition pump CH-P-11
* pump casing - condensate return pumps P-13-1A/B, chemical feed addition pumps CH-P-6A/B, boiler No. 1 feed pumps CHP-4A/B, boiler No. 2 feed pumps
 
CH-P-3A/B, deaerator feed pumps CH-P-5A/B, chemical recirculation pump CH-P-10
* restricting orifice
* sight glasses
* soot blowers
* steam trap
* strainer body 2-97
* tanks - chemical feed addition tanks CHT-3A/B
* tanks - deaerator CH-T-2, condensate return unit T-13-1, heating boiler condensate storage tank T-13-2, heating boiler flash tank T-13-3
* valve body 2.3.3.18.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.18 and UFSAR Section 10.4.8 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.18.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the heating and process steam system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.19  Hydrogen & Oxygen Monitoring System 2.3.3.19.1  Summary of Technical Information in the Application In LRA Section 2.3.3.19, the applicant descr ibed the hydrogen and oxygen monitoring system, which consists of the drywell hydrogen/oxygen monitoring subsystem and the drywell and torus
 
oxygen monitoring subsystem. The purpose of t he hydrogen and oxygen monitoring system is to monitor the primary containment atmosphere to ensure that oxygen and hydrogen levels do not
 
approach flammability limits. The hydrogen and o xygen monitoring system accomplishes this purpose post-accident and during normal power operations. During post-accident operation the
 
drywell hydrogen/oxygen monitoring subsystem processes a drywell atmosphere sample through
 
one of two redundant hydrogen and oxygen measuring loops. During normal power operation the
 
drywell hydrogen/oxygen monitoring subsystem is in the standby mode except for calibration or maintenance and the drywell and torus oxygen monitoring subsystem is in service to monitor the
 
oxygen concentration of the atmosphere in the drywell and torus areas.
The hydrogen and oxygen monitoring system cont ains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the
 
hydrogen and oxygen monitoring system potent ially could prevent the satisfactory accomplishment of a safety-related function. In addition, the hydrogen and oxygen monitoring
 
system performs functions that support EQ.
2-98 The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides flow restriction In LRA Table 2.3.3.19, the applicant identified the following hydrogen and oxygen monitoring system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* drain trap (O 2 analyzers)
* filter housing (O 2 analyzers)
* flexible hose
* flow element
* heat exchangers (air cooled)
* moisture separator (H 2 O 2 analyzers)
* piping and fittings
* pump casing
* restricting orifice
* sensor element
* tanks (volume chamber)
* valve body
* water separator (O 2 analyzers) 2.3.3.19.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.19 and UFSAR Sections 6.2.5 and 7.6.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
The staff reviewed the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
2.3.3.19.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the 2-99 applicant. No omissions were identified. The staff's review concludes that there is reasonable assurance that the applicant has adequately identified the hydrogen and oxygen monitoring
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.20  Instrument (Control) Air System 2.3.3.20.1  Summary of Technical Information in the Application In LRA Section 2.3.3.20, the applicant described the instrument air system, the purpose of which is to provide clean and dried compressed air to pneumatically-operated instruments and valves.
To accomplish this purpose, the instrument air sy stem receives compressed air from the service air system and processes it through air dryers for distribution to components in support of plant
 
operation. The instrument air system also penetrates the drywell and is isolated by the closing of
 
the instrument air containment isolation valve. This instrument air supply to the drywell is charged
 
with nitrogen during power operation to reduce combustible gas in the drywell and torus with
 
compressed air as a backup. During normal plant operation the service air compressors operate
 
continuously to supply the source of the plant's required instrument and control air and keep the
 
accumulators charged. Where required, pneumatically-operated devices are designed to fail-safe
 
upon loss of air or are provided with accumulators to provide a stored volume of compressed air
 
when the compressors or other nonsafety-related sections of the instrument air system are
 
unavailable. Accumulators are isolated by check valves to ensure backup air for components
 
credited to function during or following DBEs.
The instrument air system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the instrument air system
 
potentially could prevent the satisfactory accomp lishment of a safety-related function. In addition, the instrument air system performs functions that support fire protection, SBO, and EQ.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary or containment isolation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.20, the applicant identified the following instrument air system component types within the scope of license renewal and subject to an AMR:
* accumulator
* closure bolting
* filter housing
* flexible hose
* flow element
* piping and fittings
* valve body 2-100 2.3.3.20.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.20 and UFSAR Section 9.3.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.20.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the instrument air system components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.21  Main Fuel Oil Storage & Transfer System 2.3.3.21.1  Summary of Technical Information in the Application In LRA Section 2.3.3.21, the applicant described the main fuel oil storage and transfer system, a mechanical system designed to store and transfer fuel oil to the heating and process steam
 
system and to the emergency diesel generator fuel storage tank under normal plant operating
 
conditions. The main fuel oil storage and transfer sy stem receives fuel oil from tank trucks and stores it in a tank located in the yard. Fuel oil is conveyed to the Nos. 1 and 2 heating boilers by a
 
transfer pump, pressurized by boiler fuel pumps, and fed to the boilers for combustion. The
 
system supplies bottled propane to both heating boilers for ignition and atomizing air to the
 
No. 2 heating boiler. The system can be aligned to provide fuel oil to the EDG fuel oil tank but is
 
not credited for diesel generator operation.
The failure of nonsafety-related SSCs in the main fuel oil storage and transfer system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.21, the applicant identified the following main fuel oil storage and transfer system component types within the scope of license renewal and subject to an AMR:
2-101
* closure bolting
* flexible hose
* flow meter
* piping and fittings
* pump casing
* sight glasses
* strainer body
* valve body 2.3.3.21.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.21 and UFSAR Sections 9.5.4 and 10.4.8 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.21.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the main fuel oil storage and transfer
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.22  Miscellaneous Floor and Equipment Drain System 2.3.3.22.1  Summary of Technical Information in the Application In LRA Section 2.3.3.22, the applicant described the miscellaneous floor and equipment drain (MFED) system, the purpose of which is to collect floor drains and equipment drains in various
 
locations throughout the site and transfer the collected drainage to the radwaste system for
 
processing, overboard discharge, or disposal. The MFED system accomplishes this purpose
 
though use of gravity drain lines, sumps, tanks, pumps, and monitoring instruments used to
 
collect and classify waste drainage. The MFED system is designed to accommodate the volumes
 
of fluids from maintenance activities, system fl ushing, rinsing operations, and other plant work and is sized to minimize any potential for plant flooding. Floor drains in the cable spreading rooms of
 
the turbine building are credited in existing analyses with accommodating water flow from
 
actuation of the fire suppression systems in thos e rooms. The MFED system consists of turbine building floor and equipment drains, offgas building floor and equipment drains, radwaste floor
 
and equipment drains, laundry and laboratory drains, miscellaneous building sumps, condensate
 
transfer building sump, and miscellaneous oil drain systems.
2-102 The failure of nonsafety-related SSCs in the MFED system potentially could prevent the satisfactory accomplishment of a safety-rela ted function. The MFED system also performs functions that support fire protection.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary In LRA Table 2.3.3.22, the applicant identified the following MFED system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* flexible hose
* piping and fittings
* pump casing (lab drain tank pump P-22-003)
* pump casing (laundry drain tank pump P-22-002)
* pump casings (regeneration waste transfer pumps P-22-28A,B and P-22-29A,B)
* strainer body
* tanks (lab drain tank T-22-003)
* tanks (laundry drain tank T-22-002)
* tanks (oil separator DS-Y-105 and oil receiver DS-T-1)
* tanks (regeneration system waste tank 1-1 low and high conductivity compartments)
* valve body 2.3.3.22.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.22 and UFSAR Sections 9.3.3 and 11.2.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
LRA Section 2.3.3.22 states that the heating boiler house contains some liquid-filled portions of the MFED system in proximity to equipment per forming a safety-related function and thus within the scope of license renewal because they perform a 10 CFR 54.4(a)(2) function. LRA
 
Section 2.4.10 states that the old heating boiler house contains several safety-related electrical
 
components and that major components housed in the buildings (old and new heating boiler
 
houses) include oil-fired boilers, heating boiler feed pumps, fuel oil pumps, deaerator, chemical
 
tanks and feed pumps, boiler condensate storage tank, and system piping. The staff determined
 
that there was insufficient information to deter mine which MFED system component types in the 2-103 old heating boiler house are within the scope of license renewal. The staff referred this issue to NRC Region I for review to verify which MFED sy stem components, if any, located in proximity to the safety-related components in the old heating boiler house are within the scope of license
 
renewal for the purposes of 10 CFR 54.4(a)(2).
Subsequently, the NRC resident inspector reviewed the applicant's piping and instrumentation drawings and did a system walkdown of the MFED equipment located in the old heating boiler
 
house. The resident inspector concludes that the only safety-related equipment in the boiler
 
house is the motor control center for the standby gas treatment system exhaust fans. The remaining equipment is boiler-related or diesel fuel oil transfer from the storage tank not
 
safety-related or credited in the design bases. The resident inspector verified that the MFED
 
equipment including the piping, fittings, valves and oil separator is located within the old heating
 
boiler house near the safety-related standby gas treatment motor control center. Based on this
 
information the staff concludes that the MFED equipment shown on drawing LR-JC-147434
 
sheet 2, is correctly identified as within the scope of license renewal. The staff's concern is
 
resolved.
2.3.3.22.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes with reasonable assurance
 
that the applicant has adequately identified the MFED system components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.23  Nitrogen Supply System 2.3.3.23.1  Summary of Technical Information in the Application In LRA Section 2.3.3.23, the applicant described the nitrogen supply system, the purpose of which is to supply vaporized nitrogen at a specified pressure and temperature to the CIS, drywell
 
nitrogen subsystem, traveling in-core probe (T IP) system indexing mechanisms, and feedwater heaters. The nitrogen supply system accomplishes this purpose by processing stored liquid
 
nitrogen through a vaporizer, heaters, and pressure regulating valves and providing it to the CIS, drywell nitrogen sub-system, TIP system i ndexing mechanisms, and feedwater heaters on demand. The nitrogen supply system also provides nitrogen to the reactor water cleanup (RWCU)
 
system recirculation pump surge tank and the CRD system accumulator nitrogen charging system. This portion of the nitrogen supply system consists of local bottled nitrogen supplies, pressure regulators, and piping. The nitrogen supply system is manually initiated to support its
 
users. The nitrogen supply to the TIP system indexing mechanisms penetrates the primary containment and is provided with containment isolation devices.
The nitrogen supply system contains safety-related components relied upon to remain functional during and following DBEs. In addition, the nitrogen supply system performs functions that
 
support fire protection.
The intended functions within the scope of license renewal include:
2-104
* provides filtration
* provides heat transfer
* provides mechanical closure
* provides pressure-retaining boundary or containment isolation
* provides flow restriction In LRA Table 2.3.3.23, the applicant identified the following nitrogen supply system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* drip leg
* heat exchangers (electric heater)
* heat exchangers (trim heater)
* heat exchangers (vaporizer)
* piping and fittings
* pressure building coils
* restricting orifice
* rupture disks
* sight glasses (flow indication)
* strainer
* strainer body
* tanks
* thermowell
* valve body 2.3.3.23.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.23 and UFSAR Sections 1.9.21, 3.1.37, 6.2.5, and Table 6.2-12 using the evaluation methodology of SER Section 2.3. The staff conducted its review
 
in accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.23 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.23-1 dated December 28, 2005, the staff stated that although the LRA Section 2.3.3.23 drawing shows a 3/8-inch nitrogen supply line to the neutron monitoring system
 
penetrating primary containment to have an intended function outside containment it has no
 
intended function inside containment. No explanation is given for the change in intended function
 
for the nitrogen line. Therefore, the staff requested that the applicant confirm whether the nitrogen 2-105 line has no intended function inside containment as the neutron monitoring system has components within the scope of license renewal.
In its response dated January 26, 2006, the applicant stated:The 3/8" line penetrating the drywell at penetration X-45 as shown on license renewal drawing LR-SN-13432.19-1, drawing coordinate A-3, is the "TIP purge
 
instrumentation reference leg piping" as described in the system boundary
 
discussion of LRA Section 2.3.3.23 for the nitrogen supply system.
LRA Section 2.3.3.23 states, "The Nitrogen Supply System supports the primary containment boundary intended function. This portion of the system includes the
 
nitrogen supply to the TIP System indexers starting from the automatic
 
containment isolation valve and continuing to the containment penetration. Also
 
included is the TIP purge instrumentation reference leg piping from the
 
containment penetration up to and including the manual isolation valve." Inboard of
 
the TIP purge and TIP purge instrumentation reference leg piping containment
 
isolation valves is also discussed in the system boundary discussion of LRA
 
Section 2.3.3.23.
As stated in LRA Section 2.3.3.23, the nitrogen supply lines up to these valves are included in scope as they define the nitrogen supply system pressure boundary
 
necessary to support the intended function for fire protection.
The nitrogen piping inside the primary containment associated with the TIP system is not required to functionally support the intended functions of the neutron
 
monitoring system (NMS). Furthermore, as stated in LRA Section 2.1.5.2, nonsafety-related systems containing air or gas are not included in the scope of
 
license renewal for 10 CFR 54.4(a)(2) spatial interaction.
Therefore, AmerGen has concluded that the 3/8" nitrogen supply to the NMS is not within the scope of license renewal. Additionally, the supports for the nitrogen
 
supply system piping inside of the primary containment are included in scope to
 
prevent the piping from falling and pot entially impacting safety-related SSCs.
These supports are evaluated on a commodity level and are not included in the
 
evaluation of the nitrogen supply system.
The staff's review finds the applicant's response acceptable because the TIP system nitrogen piping inside the primary containment is nonsafety-related and does not functionally support the
 
intended functions of the NMS. As such, the piping in question satisfies none of the
 
10 CFR 54.4(a) scoping criteria. Therefore, the staff's concern described in RAI 2.3.3.23-1 is
 
resolved.2.3.3.23.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the nitrogen supply 2-106 system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.24  Noble Metals Monitoring System 2.3.3.24.1  Summary of Technical Information in the Application In LRA Section 2.3.3.24, the applicant described the noble metals monitoring system (NMMS), a reactor coolant monitoring system designed for determining the effectiveness of the noble metal
 
chemical addition injection process performed during the 1R19 refueling outage. The purpose of
 
the NMMS is to track and trend the integrity of the noble metals film applied to the reactor
 
internals and recirculation piping to ensure its ability to support hydrogen water chemistry (HWC)
 
in the mitigation of intergranular stress corrosion cracking (IGSCC). The NMMS accomplishes this
 
purpose by monitoring the electrochemical corrosion potential of the reactor coolant, simulating
 
and trending noble metals deposition, and monitoring and recording NMMS parameters. Manual
 
valves local to the NMMS are used to place t he system in service. The NMMS is operated when the plant is at power and the RWCU system is in operation.
The failure of nonsafety-related SSCs in the NMMS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.24, the applicant identified the following NMMS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* flow element
* piping and fittings
* sensor element
* valve body 2.3.3.24.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.24 and UFSAR Section 5.2.3.4 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-107 2.3.3.24.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the NMMS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.25  Post-Accident Sampling System 2.3.3.25.1  Summary of Technical Information in the Application In LRA Section 2.3.3.25, the applicant described the post-accident sampling system (PASS) designed to obtain liquid and gaseous samples from the primary containment, gaseous samples
 
from the secondary containment, and liquid samples from the reactor vessel for radiological and
 
chemical analysis to estimate post-accident core damage and coolant corrosiveness. Reactor
 
coolant samples can be drawn from reactor recirculation Loop A, the liquid poison system piping, and the SCS piping. A torus water sample can be drawn from the core spray system piping. The
 
samples pass through sample coolers located in the reactor building TIP room and continue to the
 
sample station in the PASS room. All liquid samples are returned to the primary containment
 
through the core spray pumps suction line during accident conditions. Gaseous atmosphere
 
samples can be obtained from the drywell and wetwell through the hydrogen and oxygen
 
monitoring system. A secondary containment atmosphere sample also can be drawn into the
 
PASS station. Primary containment gas samples are returned to the drywell, and secondary
 
containment gas samples are returned to the reactor building atmosphere. The PASS was
 
originally installed as required by the NRC and as described in NUREG-0737. While no longer
 
required by the technical specifications, the PASS continues to be maintained and operation of
 
the system is described in approved plant procedures.
The PASS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the PASS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the PASS performs functions
 
that support EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; or containment isolation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.25, the applicant identified the following PASS component types within the scope of license renewal and subject to an AMR:
2-108
* closure bolting
* piping and fittings
* valve body 2.3.3.25.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.25 and UFSAR Sections 1.9 and 11.5.2.12 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.25.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the PASS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.26  Process Sampling System 2.3.3.26.1  Summary of Technical Information in the Application In LRA Section 2.3.3.26, the applicant described the process sampling system designed to permit a representative sample to be taken in a form which can be used in the laboratory and which
 
safeguards against change in the constituents to be examined, minimizes the contamination and
 
radiation at the sample point, and reduces decay and sample line plateout as much as possible.
 
The purpose of the process sampling system is to monitor the operation of equipment and to
 
supply information for making operating decisions where these are influenced by water chemistry.
It accomplishes this purpose by collecting steam, gaseous, and liquid samples throughout the
 
facility. Sample stream flow rates are selected to maintain turbulent flow for more accurate
 
sampling. The process sampling system is comprised of the following subsystems: reactor
 
sampling subsystem, radwaste sampling subsys tem, composite sample subsystem, hydrogen detection/sampling subsystem, and the off-gas sample subsystem. The reactor sampling
 
subsystem consists of the reactor water sample station and the final feedwater facility. The
 
reactor water sample station provides sample and analysis capabilities for reactor water and the
 
RWCU system. The final feedwater facility system consists of sampling of the turbine building
 
primary systems. The radwaste sampling system monitors activity at various points of the radwaste system, which is a liquid and solid radioactive waste management system. In the composite sample subsystem, composite samples of condenser cooling water are taken locally at
 
the plant's intake and outfall. The hydrogen detection/sampling subsystem monitors the
 
augmented off-gas recombiner subsystem. The off-gas sample subsystem takes a sample at the 2-109 air ejectors to measure activity release and H 2 0 2 and air leakage, a sample at the stack to measure particulate and iodine release, and a sample at the inlet and outlet of the offgas filter to
 
determine filter efficiency.
The failure of nonsafety-related SSCs in the pr ocess sampling system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.26, the applicant identified the following process sampling system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers
* evaporator
* flexible hose
* flow element
* piping and fittings
* pump casing
* sensor element
* sight glasses
* tanks (reservoir)
* thermowell
* valve body 2.3.3.26.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.26 and UFSAR Section 9.3.2 and Table 9.3-3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.26 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.26-1 dated December 28, 2005, the staff stated that on drawing LR-GU-3E-551-21-1000 the feedwater sample sink and the condensate sample sink are shown
 
within the scope of license renewal; however, "sinks" are not listed as components subject to an 2-110 AMR. Therefore, the staff requested that the applicant indicate whether the sinks are included within a component type subject to an AMR or justify their exclusion from an AMR.
In its response dated January 26, 2006, the applicant stated:
The feedwater and condensate sample sinks are correctly shown on license renewal drawing LR-GU-3E-551-21-1000 as in scope for spatial interaction
 
(10 CFR 54.4(a)(2)). LRA Table 2.3.3.26 for process sampling system components
 
subject to aging management review and LRA Table 3.3.2.1.26 for process
 
sampling system aging management evaluation should have included a component type of "sinks," or equivalently named component, with an intended
 
function of "leakage boundary." Attachment I to this enclosure identifies the addition of "sinks" to Tables 2.3.3.26 and 3.3.2.1.26.
The staff's review finds the applicant's response acceptable because it appropriately added "sinks" as a component type subject to an AMR in accordance with 10 CFR 54.21(a)(1) and
 
identified the component intended function. Therefore, the staff's concern described in
 
RAI 2.3.3.26-1 is resolved.
2.3.3.26.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the process sampling
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.27  Radiation Monitoring System 2.3.3.27.1  Summary of Technical Information in the Application In LRA Section 2.3.3.27, the applicant described the radiation monitoring system, the purpose of which is to detect the release of radioactivity, monitor radiation levels in key locations throughout
 
the plant, and monitor radioactivity concentration levels of major process system discharge
 
streams. The system accomplishes its purpose by utilizing radiation detectors and circuitry to
 
monitor and indicate radiation levels. The radiation monitoring system consists of process and
 
effluent radiological monitoring, area radiation and airborne radioactivity monitoring, and
 
containment atmosphere particulate and gaseous radioactivity monitoring. The process and
 
effluent radiological monitoring system is designed to detect radioactive gaseous and liquid
 
leakage, provide warning and automatic control as appropriate when radioactivity in a process
 
stream reaches a preset limit, provide inform ation on fuel and radioactive processing equipment performance, provide a record of radioactivity present in various plant systems, and provide a record of radioactivity released to the environment for compliance with regulatory limits. The area
 
radiation and airborne radioactivity monitoring system is designed to monitor the level of radiation in areas where personnel access may be required, assist in maintaining occupational radiation
 
exposures as low as reasonably achievable, alarm when radiation levels exceed preset limits, and 2-111 provide a continuous record of radiation levels in key locations throughout the plant. The containment atmosphere particulate and gaseous r adioactivity monitoring system provides a diverse means of RCS leak detection by detecting the release of radioactivity from a leak and subsequent flashing to steam. The system is designed to detect both particulate and noble gas
 
radiation.
The radiation monitoring system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the radiation
 
monitoring system potentially could prevent the sa tisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; or containment isolation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.27, the applicant identified the following radiation monitoring system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* piping and fittings
* valve body 2.3.3.27.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.27 and UFSAR Sections 5.2.5.1.3, 11.5, and 12.3.4 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with
 
the guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.27 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.27-1 dated December 28, 2005, the staff noted that LRA Section 2.4.17 states that effluents through the ventilation stack are monitored to ensure that 10 CFR Part 20 limits, which
 
apply to releases during normal operation, and 10 CFR Part 100 limits, which apply to accidental
 
releases, are not exceeded. LRA Section 2.3.3.27 states that the stack and turbine building
 
radioactive gaseous effluents monitors do not support a license renewal intended function and are
 
not included within the scope of license renewal. These two statements appear to be
 
contradictory; therefore, the staff requested that the applicant clarify this apparent contradiction 2-112 and indicate whether the ventilation stack radiation monitors are within the scope of license renewal.In its response dated January 26, 2006, the applicant stated:
LRA Section 2.4.17 does suggest that the radiation monitors are required to monitor accident releases, but that was not the intent. While they may be used for
 
post-accident monitoring, the stack radiation monitors are not credited for accident
 
mitigation and are not safety-related. These radiation monitors do not have an
 
intended function for license renewal and are therefore not in scope.
The staff's review finds the applicant's response acceptable because it stated that the stack radiation monitors have no intended function for license renewal and that the LRA statement was
 
unintentional. As such, the radiation monitors in question satisfy none of the 10 CFR 54.4(a)
 
scoping criteria. Therefore, the staff's concern described in RAI 2.3.3.27-1 is resolved.
2.3.3.27.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the radiation
 
monitoring system components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.28  Radwaste Area Heating and Ventilation System 2.3.3.28.1  Summary of Technical Information in the Application In LRA Section 2.3.3.28, the applicant described the radwaste area heating and ventilation system, a normally operating mechanical ventilation system to the radwaste areas of the plant including the old radwaste building, the new radwaste building, the new radwaste heat exchanger
 
building, the offgas building, and the hot machine shop in the new maintenance building. The
 
purpose of the system is to provide ventilation, heating, and cooling to control area temperatures, to control air movement from low contamination areas to high contamination areas, and to provide
 
means for filtering and monitoring the exhaust air before discharging to atmosphere. It
 
accomplishes this purpose by means of five independent HVAC systems, incorporating the necessary fans, filters, and ducting to accommodate the individual requirements of the processes
 
within each of the five buildings. The radiological design objectives of the radwaste area heating
 
and ventilation system are to limit the average in-p lant airborne radioactivity levels below the 10 CFR Part 20 guideline limits and to reduce offsite releases of radioactivity to as low as
 
reasonably achievable levels (10 CFR Part 50, Appendix I).
The failure of nonsafety-related SSCs in the radwaste area heating and ventilation system potentially could prevent the satisfactory a ccomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides mechanical closure 2-113
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.28, the applicant identified the following radwaste area heating and ventilation
 
system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* damper housing
* door seal
* ductwork
* fan housing
* flexible connection 2.3.3.28.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.28 and UFSAR Sections 9.4.4 and 12.3.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
The staff reviewed the subsystem functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any components with intended
 
functions under 10 CFR 54.4(a). The staff then reviewed components that the applicant had
 
identified as within the scope of license renewal to verify that it had not omitted any passive and
 
long-lived components subject to an AMR in accordance with the requirements of
 
10 CFR 54.21(a)(1).
 
2.3.3.28.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the radwaste area heating and ventilation
 
system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.29  Reactor Building Closed Cooling Water System 2.3.3.29.1  Summary of Technical Information in the Application In LRA Section 2.3.3.29, the applicant described the reactor building closed cooling water (RBCCW) system, a closed-loop system designed to provide inhibited demineralized cooling water to reactor building and primary containment equipment subject to radioactive
 
contamination. Included in the RBCCW system is a corrosion inhibiting chemical treatment system designed for intermittent injection of a chemical solution into the demineralized water
 
contained within the system. The purpose of the RBCCW system is to remove heat from loads
 
during various modes of reactor operation. The RBCCW system accomplishes this purpose by
 
transferring heat from these loads to the service water system through the RBCCW heat
 
exchangers. Flow and temperature control are achieved through manual/remote manipulation of RBCCW system valves. A surge tank at the high poi nt of the system is sized to hold the expected maximum expansion of the RBCCW system. A safety injection signal (reactor vessel low-low level 2-114 or drywell high pressure) trips the RBCCW pumps. Then, during operation from the EDGs, both RBCCW pumps start automatically after a tim ed delay unless a LOCA signal is present. The RBCCW system acts as a buffer between radioactive ly contaminated systems, which it cools, and the service water system, which is the heat sink for the RBCCW system.
The RBCCW system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RBCCW system potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
RBCCW system performs functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* provides heat transfer
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; or containment isolation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.29, the applicant identified the following RBCCW system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (cleanup auxiliary pump)
* coolers (cleanup pre-coat pump)
* coolers (cleanup recirculation pumps lube oil)
* coolers (containment spray pump room)
* coolers (core spray pump room)
* coolers (drywell cooling units)
* coolers (post-accident sample)
* coolers (sample)
* coolers (shutdown cooling pumps)
* coolers (tunnel)
* filter housing
* flow element
* gauge snubber
* heat exchangers (augmented fuel pool cooling)
* heat exchangers (cleanup non-regenerative)
* heat exchangers (drywell equipment drain tank)
* heat exchangers (fuel pool cooling)
* heat exchangers (shutdown cooling)
* level glass
* piping and fittings
* pump casing (chemical feed pump)
* pump casing (RBCCW pumps)
* rupture disks 2-115
* strainer body
* tanks (chemical mixing tank)
* tanks (RBCCW surge tank)
* thermowell
* valve body 2.3.3.29.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.29 and UFSAR Sections 3.1, 9.2, 7.3, and Table 6.2-12 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.29.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the RBCCW system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.30  Reactor Building Floor and Equipment Drains 2.3.3.30.1  Summary of Technical Information in the Application In LRA Section 2.3.3.30, the applicant described the reactor building floor and equipment drains (RFEDs). The purpose of the RFEDs is to collect floor drains and equipment drains located in the
 
reactor building outside of the primary containment and to transfer the collected drainage to the
 
radwaste system for processing. The RFEDs accomplish this purpose by directing floor drains
 
first to the torus room and then to one of two sumps in the reactor building basement and
 
directing equipment drains through a ring header to the reactor building equipment drain tank. A
 
single pump transfers drainage from the reactor building equipment drain tank to the radwaste
 
system collection tanks. Each level of the reactor building with the exception of the 119-foot is
 
equipped with sufficient floor drainage capability to pass the maximum credible floor drain flow
 
rate from actuation of the fire suppression system or a pipe break. The 119-foot level does not
 
require a floor drain network as stairwells and equipment storage pools are sufficient to prevent
 
flooding of this area.
The failure of nonsafety-related SSCs in the RFEDs potentially could prevent the satisfactory accomplishment of a safety-related function. The RFEDs also performs functions that support fire
 
protection.
2-116 The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary In LRA Table 2.3.3.30, the applicant identified the following RFEDs component types within the scope of license renewal and subject to an AMR:
* closure bolting
* piping and fittings
* pump casing
* tanks
* valve body 2.3.3.30.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.30 and UFSAR Sections 9.3.3 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.30.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the RFEDs components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.31  Reactor Building Ventilation System 2.3.3.31.1  Summary of Technical Information in the Application In LRA Section 2.3.3.31, the applicant described the reactor building ventilation system (RBVS), a continuously operating ventilation system wi th primary containment purge capability and an isolation mode. The system is designed to provi de a controlled environment so that the maximum allowable ambient temperature for standard rat ed electrical equipment is not exceeded. It also regulates the static pressure within certain areas of the plant to minimize the spread of airborne 2-117 radioactive contamination from controlled to uncontrolled areas and disposes of airborne contaminants safely. It accomplishes this regulation by maintaining a negative pressure within the
 
reactor building as to outside atmosphere while ventilating the reactor building with fresh
 
tempered air exhausted through the ventilation stack. The RBVS is also used during inerting and
 
deinerting of primary containment and provides the flow paths for the SGTS and the CIS in DBEs.
 
During normal operation, the RBVS operates with the SGTS in standby. During a DBA, the RBVS
 
secondary containment isolation valves are closed, the RBVS fans stopped, the SGTS fans
 
automatically started, and effluents filtered prior to elevated release through the ventilation stack.
The RBVS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RBVS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the RBVS performs functions
 
that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.31, the applicant identified the following RBVS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* closure bolting (containment isolation components)
* damper housing
* door seal
* ductwork
* piping and fittings
* piping and fittings (primary containment isolation valves)
* sensor element (temperature)
* valve body
* valve body (primary containment isolation) 2.3.3.31.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.31 and UFSAR Sections 9.4.2 and 11.3.2.5 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-118 2.3.3.31.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the RBVS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.3.32  Reactor Water Cleanup System 2.3.3.32.1  Summary of Technical Information in the Application In LRA Section 2.3.3.32, the applicant described the RWCU system, a filtration and demineralization system that maintains the purity of the water in the RCS. It can be operated
 
during startup, shutdown, and refueling modes as well as during power operation.
The purposes of the RWCU system are:
* to reduce the deposition of water impurities on fuel surfaces, thus minimizing heat transfer surface fouling
* to reduce secondary sources of beta and gamma radiation by removing corrosion products, impurities, and fission products from the reactor coolant
* to reduce the concentration of chloride ions to protect steel components from chloride stress corrosion
* to maintain or lower water level in the reactor vessel during startup, shutdown, and refueling operations in order to accommodate reactor coolant swell during heatup and to
 
accommodate water inputs from the CRD system and the head cooling system.
Portions of the RWCU System are consi dered RCPB. The RWCU system will automatically undergo partial or complete isolation depending upon the initiating event. Partial isolation
 
removes the system from service without fully is olating it from the RCPB. Partial isolation will occur for RWCU system/component protection in response to RWCU system anomalies or for SLCS flow. Full isolation of the RWCU system from the RCPB occurs in response to low-low
 
reactor water level or high drywell pressure RPS engineered safety feature system actuation
 
parameters, or indications of an RWCU high-energy line break (HELB).
The RWCU system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the RWCU system potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the RWCU
 
system performs functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping) 2-119
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation In LRA Table 2.3.3.32, the applicant identified the following RWCU system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (cleanup pre-coat pump)
* coolers (cleanup recirculation pumps lube oil)
* demineralizer (cleanup demineralizer)
* filter housing (cleanup filter)
* flow element
* gauge snubber
* heat exchangers (cleanup non-regenerative)
* heat exchangers (cleanup regenerative)
* piping and fittings
* pump casing (cleanup auxiliary pump)
* pump casing (cleanup filter aid pumps)
* pump casing (cleanup filter precoat pump)
* pump casing (cleanup recirc pumps)
* pump casing (cleanup sludge pump)
* restricting orifice
* sensor element
* sight glasses
* strainer body
* tanks (cleanup backwash tank)
* tanks (cleanup filter aid mix tank)
* tanks (cleanup filter and precoat tank)
* tanks (cleanup filter sludge receiver)
* tanks (cleanup recirculation pump surge tank)
* tanks (cleanup recirculation pumps lube oil)
* thermowell
* valve body 2.3.3.32.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.32 and UFSAR Sections 5.4.3, 5.4.8, and 6.2.4 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.32 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
2-120 In RAI 2.3.3.32-1 dated December 28, 2005, the staff stated that, "Note 5 on license renewal drawing LR-GE-148F444 states that the inner tube of sample cooler (at location H-8) is evaluated
 
with the reactor water cleanup system. However, LRA Table 2.3.3.32 does not list sample cooler (tubes) as a component subject to an AMR." The staff requested that the applicant confirm that
 
sample cooler tubes are subject to an AMR or, if not, justify their exclusion.
In its response dated January 26, 2006, the applicant stated:
The sample cooler shown on license renewal drawing LR-GE-148F444 at drawing coordinate H-8 is a dual heat transfer coil type (tube-in-tube) with reactor building
 
closed cooling water (RBCCW) in the annulus between the outer and inner tubes
 
and reactor water cleanup (RWCU) water in the inner tube. Note 5 on license
 
renewal drawing LR-GE-148F444 indicates that the inner tube of the sample cooler
 
is evaluated with the RWCU system. The inner tube is not required for leakage
 
boundary for license renewal as it is contained by the outer tube (which is scoped
 
and screened with the RBCCW system). As shown on LR-GE-148F444, the inner
 
tube is colored black indicating that the inner tube is not within the scope of license
 
renewal (for spatial interaction) and is not subject to AMR.
The staff's review finds the applicant's response acceptable because the inner tube has no potential for spatial interaction; therefore, it does not satisfy the 10 CFR 54.4(a)(2) criterion. The
 
outer tube, which has a leakage boundary intended function, is within the scope of license
 
renewal and subject to an AMR pursuant to 10 CFR 54.21(a)(1). Therefore, the staff's concern
 
described in RAI 2.3.3.32-1 is resolved.
2.3.3.32.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the RWCU system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.33  Roof Drains and Overboard Discharge 2.3.3.33.1  Summary of Technical Information in the Application In LRA Section 2.3.3.33, the applicant described the roof drains and overboard discharge system (RDODS), a passive drainage system designed to collect and discharge effluents from the plant
 
to the discharge canal. The purpose of the RDODS is to collect and discharge effluents from plant
 
open cooling water systems, plant building drainage systems, and yard area storm drains. The
 
RDODS accomplishes this purpose through a 30-inch overboard discharge line that starts outside
 
the reactor building, runs below grade, and terminates at the discharge canal. It carries service
 
water discharge from the RBCCW heat exchangers, ESW from the containment spray system
 
heat exchangers, turbine building sump 1 through 5 effluent, roof, floor, and equipment drainage
 
from various plant buildings, and yard area storm water. The RDODS does not include process
 
liquid monitoring, which is performed prior to the effluents entering the overboard discharge line.
 
The process liquid monitoring subsystems have been designed to measure, indicate, and record 2-121 the radioactivity concentration levels of majo r process system discharge streams continuously.
These monitors assure that plant releases do no exceed the limits specified in 10 CFR Part 20
 
and Part 50, Appendix I.
The failure of nonsafety-related SSCs in the RDODS potentially could prevent the satisfactory accomplishment of a safety-related function. The RDODS also performs functions that support fire
 
protection.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary In LRA Table 2.3.3.33, the applicant identified the following RDODS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* piping and fittings 2.3.3.33.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.33 and UFSAR Sections 9.3.3.2.9 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.33.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the RDODS components within the scope
 
of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2-122 2.3.3.34  Sanitary Waste System 2.3.3.34.1  Summary of Technical Information in the Application In LRA Section 2.3.3.34, the applicant described the sanitary waste system, the purpose of which is to provide the path for the sanitary waste and drains to the sewage collection tank. The sanitary
 
waste system consists of the plumbing and dr ainage system and the sewage lift station system.
The sanitary waste system is comprised of sanitary waste piping and fixtures in the office and
 
turbine buildings, including floor drains in the office building. Additional sanitary drains from the
 
various plant buildings join the main sanitary drain line. Domestic waste water from all plant
 
locations enters a concrete equalizing tank that discharges through two self-priming diaphragm
 
pumps (transfer pumps) to the Lacey Municipal Utilities Authority sewer system and subsequently to the Ocean County Utilities Authority regional collection system via a gravity line. A radiation
 
monitoring system continuously monitors radiation levels in the effluent of the transfer pumps. As a backup, manual samples may be taken from the sewage pit for laboratory analysis. The
 
radiation monitor alarms below 50 percent of the 10 CFR Part 20, Appendix B, Table 1, Column 2, value for cobalt-60. Procedures require immediate notification of the control room for investigation
 
of the alarm. If levels continue to rise, the sewage transfer pumps trip automatically below the
 
100 percent value identified in 10 CFR Part 20.
The failure of nonsafety-related SSCs in the sanita ry waste system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended function, within the scope of license renewal, is to provide maintenance of mechanical and structural integrity to prevent spatial interactions that could cause failure of
 
safety-related SSCs (includes the required structural support when the nonsafety-related leakage
 
boundary piping is also attached to safety-related piping).
In LRA Table 2.3.3.34, the applicant identified the piping and fittings component type of the sanitary waste system within the scope of license renewal and subject to an AMR.
2.3.3.34.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.34 and UFSAR Sections 9.2.4.3 and 9.3.3.2.7 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.34.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable 2-123 assurance that the applicant has adequately identified the sanitary waste system components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.35  Service Water System 2.3.3.35.1  Summary of Technical Information in the Application In LRA Section 2.3.3.35, the applicant described the SWS, an open-loop cooling system designed to provide seawater to various users during normal plant operation and shutdown. The purpose of
 
the SWS is to provide seawater cooling to the tube side of the two RBCCW heat exchangers. The
 
SWS accomplishes this purpose by supplying seawater from the plant intake structure to the
 
RBCCW system heat exchangers and transferring t he heat energy to the environment through the RDODS. The SWS provides alternate seawater cooling to the tube side of the two TBCCW
 
system heat exchangers normally serviced by the CWS by supplying seawater from the plant intake structure to the TBCCW system heat exchangers and transferring the heat energy to the
 
environment through the plant discharge structure and canal. The SWS also keeps the ESW side
 
of the containment spray heat exchangers full through a crosstie between the normally operating
 
SWS and the standby ESW system. The SWS has several interfaces with the chlorination system, which delivers sodium hypochlorite to the SWS headers for the control of biofouling. Process
 
liquid monitoring is for the gross radioactivity of the service water effluent from the RBCCW heat
 
exchangers. During outages when maintenance is performed on the SWS, the ESW system can
 
be aligned to support SWS loads through a cross-connect line between the ESW and SWS.
The failure of nonsafety-related SSCs in the SWS potentially could prevent the satisfactory accomplishment of a safety-related function. The SWS also performs functions that support fire
 
protection.
The intended functions within the scope of license renewal include:
* provides filtration
* provides heat transfer
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary
* provides flow restriction In LRA Table 2.3.3.35, the applicant identified the following SWS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* eductor
* expansion joint
* flow element
* gauge snubber
* heat exchangers (RBCCW) 2-124
* heat exchangers (TBCCW)
* piping and fittings
* pump casing (rad monitor sample pump)
* pump casing (service water pumps)
* restricting orifice
* rotameter
* sample chamber
* sight glasses
* strainer
* strainer body
* tanks (service water pump oil reservoir)
* thermowell
* valve body 2.3.3.35.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.35 and UFSAR Section 9.2.1.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.35 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.35-1 dated December 28, 2005, the staff noted that LRA Table 2.3.3.35 lists the component types "strainer" with the intended function "filter" and "strainer body" with the intended
 
function "pressure boundary." The radiation monitor duplex strainer is indicated in parentheses for
 
these intended functions. According to the boundaries in LRA Section 2.3.3.35 and as indicated
 
on the license renewal drawings the following components are within the scope of license renewal
 
and serve intended functions but are not listed in LRA Table 2.3.3.35. The staff requested that the
 
applicant confirm that they are subject to an AMR or, if not, justify their exclusion.  (1)Strainers located at F8 and G-7 on drawing LR-BR-2005, sheet 2, that provide a pressure boundary function.  (2)The strainer S-3-035 in the seal well at B-3/4 on drawing LR-BR-2005, sheet 2, providing a filtration function. The seal well is included as part of the miscellaneous yard structures.
 
However, there is no strainer included in this system.
2-125 In its response dated January 26, 2006, the applicant stated:  (1)The strainer symbols shown on license renewal drawing LR-BR-2005, Sheet 2 at drawing coordinates F-8 and G-7 are depicting the diaphragm
 
seal that is integral to the pressure indicator assembly. The diaphragm seal
 
is not specifically called out in LRA Table 2.3.3.35 since it is considered
 
part of the "active" pressure instrument. Diaphragm seals isolate pressure
 
instruments from the process media while allowing the instrument to sense
 
the process pressure. A diaphragm, together with a fill fluid, transmits
 
pressure from the process medium to the pressure element assembly of the instrument. There would be no need to filter the medium prior to the
 
diaphragm seal. Because these diaphragm seals are part of the pressure
 
indicator assembly, which is an "active" component, they are not subject to
 
aging management review.    (2)Seal well strainer S-3-035 on drawing LR-BR-2005, Sheet 2 coordinate B-3/4 is incorrectly shown as in scope. This strainer was originally the
 
supply/suction point of the service water radiation monitoring system. This
 
strainer is no longer used and was abandoned in-place following a plant
 
modification to the service water radiation monitoring system. This strainer
 
does not perform an intended function for license renewal, is not in scope, and is not subject to AMR.
The staff's review finds the applicant's response acceptable because the strainers in question are either parts of active components or no longer in use and satisfy none of the 10 CFR 54.4(a)
 
criteria. Therefore, the staff's concern described in RAI 2.3.3.35-1 is resolved.
2.3.3.35.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the SWS components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.36  Shutdown Cooling System 2.3.3.36.1  Summary of Technical Information in the Application In LRA Section 2.3.3.36, the applicant described the shutdown cooling system (SCS), a high-pressure system designed to remove fission product decay heat during shutdown. The
 
system is normally isolated and not in service dur ing plant power operation. Immediately following shutdown of the reactor, the initial cooling and removal of decay heat is accomplished by means
 
of the turbine bypass system, which directs steam to the main condenser. When coolant
 
temperature has been reduced to the point where the main condenser can no longer be used as a
 
heat sink, the SCS operates to reduce reactor coolant temperature and complete the cooling. The
 
SCS is not an ECCS; however, the SCS may be placed in service if available during 2-126 emergencies, following initial reactor cooldown and depressurization, to assist the ECCS in removing decay heat.
The SCS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the SCS potentially could prevent the
 
satisfactory accomplishment of a safety-related function. In addition, the SCS performs functions
 
that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.3.36, the applicant identified the following SCS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (shutdown cooling pumps)
* flow element
* heat exchangers (shutdown cooling)
* piping and fittings
* pump casing
* restricting orifice
* thermowell
* valve body 2.3.3.36.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.36 and UFSAR Section 5.4.7 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.3.3.36 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.
2-127 LRA Table 2.3.3.36 lists heat exchangers for shutdown cooling as a component type within the scope of license renewal. However, for these heat exchangers leakage/pressure boundary was
 
identified as the sole intended function requiring aging management, not their heat transfer
 
function. The staff believes that the heat transfer function also should be identified as an intended
 
function of the component type and appropriate an AMP designated for reasonable assurance
 
that this safety-related function does not degrade over the period of extended operation.
In RAI 2.3.3.36-1 dated March 10, 2006, the staff requested that the applicant clarify why the heat transfer function of the shutdown cooling heat exchangers, in addition the leakage/ pressure
 
boundary function, had not been identified as an intended function to be preserved during the
 
period of extended operation.
In its response dated April 7, 2006, the applicant stated that the shutdown cooling heat exchangers were identified with intended functions of heat transfer and pressure boundary in the
 
LRA but not in Section 2.3.3.36. The subject components were listed in LRA Table 2.3.3.36 as
 
requiring an AMR without heat removal as an intended function because heat removal is not
 
credited as a 10 CFR 54.4(a)(1) function. However, the system is relied upon for a function for
 
compliance with 10 CFR 54.4(a)(3) for fire protection. Consequently, the shutdown cooling heat
 
exchangers are listed in LRA Table 2.3.3.29 for RBCCW system components subject to an AMR and with both intended functions of heat transfer and pressure boundary.
The staff finds the response acceptable as a clarification. The staff's concern described in RAI 2.3.3.36-1 is resolved.
2.3.3.36.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the SCS components
 
within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.37  Spent Fuel Pool Cooling System 2.3.3.37.1  Summary of Technical Information in the Application In LRA Section 2.3.3.37, the applicant described the spent fuel pool cooling system (SFPCS), which consists of two systems located in the reactor building that operate independently from
 
each other except for a common suction flow path and a common discharge flow path. The first
 
system is the SFPCS designed to remove heat from the spent fuel pool and maintain fuel storage
 
pool water clarity. The other system is the augmented SFPCS added after plant construction due
 
to higher than anticipated spent fuel storage requirements. This system operates during refueling
 
due to the higher heat loads. The SFPCS is designed for both normal and accident conditions of
 
loss of offsite power coincident with a single active component failure. The augmented SFPCS is
 
designed to provide a seismically qualified cooling loop capable of providing cooling during such
 
conditions. The system is designed to prevent reduc tion in fuel storage coolant inventory during accident conditions. In addition, the system is designed with sufficient monitoring systems to detect conditions that could cause loss of decay heat removal and to initiate appropriate safety 2-128 actions. Telltale drains with annunciated flow-indicating switches detect leakage through the bellows seal at the reactor vessel to drywell joint and leakage into the space between the
 
refueling gates. There is a curb around the cavities to direct any overflow to drains.
The SFPCS has safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the SFPCS potentially could prevent the
 
satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation In LRA Table 2.3.3.37, the applicant identified the following SFPCS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* diffuser
* flow element
* piping and fittings
* pump casing (fuel pool cooling pumps and augmented fuel pool cooling pumps)
* thermowells
* valve body 2.3.3.37.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.37 and UFSAR Sections 1.2, 3.1, 3.2, 7.5, 9.1, and 11.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.3.37 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.3.37-1 dated December 28, 2005, the staff noted that LRA Section 2.3.3.37 states that the piping that discharges into the reactor cavity, equipment storage cavity, and spent fuel pool is
 
included in the scoping boundary for the SPFCS. However, drawing LR-GE-237E756 (location 2-129 E-9) does not highlight the piping and diffusers that discharge into the reactor cavity as within the scoping boundary. Therefore, the staff requested that the applicant clarify this discrepancy.
In its response dated January 26, 2006, the applicant stated:
The piping and return diffusers located within the reactor cavity are correctly shown on license renewal Drawing LR-GE-237E756 as not in scope (black). The piping up
 
to the reactor cavity is in scope, but the piping within the reactor cavity does not
 
perform or support a system intended function. The intent of the discussion in LRA
 
Section 2.3.3.37 was not to exactly define the components or portion of piping that
 
was in scope, but rather to describe this section in general terms. The exact
 
boundary of in scope/not in scope piping is defined by the license renewal drawing.
The staff's review finds the applicant's response acceptable because the piping and diffusers that discharge into the reactor cavity support or perform no system intended function and satisfy no
 
10 CFR 54.4(a) criteria . Therefore, the staff's concern described in RAI 2.3.3.37-1 is resolved.
2.3.3.37.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the SFPCS
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.3.38  Standby Liquid Control System (Liquid Poison System) 2.3.3.38.1  Summary of Technical Information in the Application In LRA Section 2.3.3.38, the applicant described the standby liquid control system (SLCS) or the liquid poison system, a standby and redundant sodi um pentaborate injection system designed to bring the reactor to a shutdown condition at any time in core life independent of control rod
 
capabilities. The SLCS operates independently from the CRD system. The most severe
 
requirement for which the system is designed is shutdown from a full power operating condition assuming complete failure of the CRD system to respond to a scram signal. The SLCS provides
 
sufficient capacity for controlling the reactivity difference between the steady state rated operating
 
condition of the reactor and the cold shutdown condition, including shutdown margin, thereby
 
ensuring complete shutdown capability from the most reactive condition at any time in core life.
 
The SLCS accomplishes this purpose by injecting sodium pentaborate solution into the reactor
 
vessel to absorb thermal neutrons. The SLCS is not provided as a backup for reactor trip
 
functions, since most transient conditions requiring reactor trip occur too rapidly to be controlled
 
by the SLCS. The SLCS is manually initiated from the main control room through the use of a keylock switch to start the selected pump and ac tuate its explosive actuated valve. This manual initiation ensures that switching on the system is a deliberate act. Following system initiation, the explosive valve of the selected pump is actuated to provide a flow path to the reactor vessel.
The SLCS contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the SLCS potentially could prevent the 2-130 satisfactory accomplishment of a safety-related function. In addition, the SLCS performs functions that support ATWS.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.3.3.38, the applicant identified the following SLCS component types within the scope of license renewal and subject to an AMR:
* accumulator
* closure bolting
* flow element
* piping and fittings
* pump casing
* tanks (liquid poison tank)
* tanks (liquid poison test tank)
* thermowell
* valve body 2.3.3.38.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.38 and UFSAR Sections 3.1, 4.6.4.1, 7.4.1, 9.3.5, and 15.8 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.3.3.38.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the SLCS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2-131 2.3.3.39  Traveling In-Core Probe System 2.3.3.39.1  Summary of Technical Information in the Application In LRA Section 2.3.3.39, the applicant described the TIP system, an electrical instrumentation system designed to provide neutron flux data fo r calibration of the local power range monitor (LPRM) detectors and determination of axial neutron flux levels for core power distribution
 
measurements. The purpose of the TIP system is to measure core neutron flux at various positions throughout the core. The TIP system accomplishes its purpose by utilizing a set of
 
fission chamber detector instruments identical to those used by the LPRM system and a positioning system capable of moving the fission chamber detectors to various locations in the
 
core corresponding to the locations of the LPRM detectors. The moveable TIP detectors, as with
 
the fixed LPRM detectors, generate signals processed to indicate neutron flux levels in the vicinity
 
of each detector. As the TIP detectors may be fully withdrawn from the core and outside of
 
primary containment, the TIP system contains mechanical components designed to assure
 
primary containment integrity. The TIP system does not generate any rod block or scram signals for protection of the reactor; however, the portion responsible for providing primary containment
 
integrity is within the scope for license renewal.
The TIP system contains safety-related components relied upon to remain functional during and following DBEs.
The intended functions within the scope of license renewal include:
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
In LRA Table 2.3.3.39, the applicant identified the following TIP system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* piping and fittings
* valve body 2.3.3.39.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.39 and UFSAR Section 7.5.1.8.8 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-132 2.3.3.39.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the TIP system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.40  Turbine Building Closed Cooling Water System 2.3.3.40.1  Summary of Technical Information in the Application In LRA Section 2.3.3.40, the applicant described the TBCCW system, a closed-loop system designed to provide inhibited demineralized cooling water to the reactor recirculation pump
 
MG sets and turbine building equipment not subject to radioactive contamination. Included in the
 
TBCCW system is a corrosion-inhibiting chemic al treatment system designed for intermittent injection of a chemical solution into the demineralized water within the system. The purpose of the
 
TBCCW system is to remove heat from various loads during all modes of reactor operation. The
 
TBCCW system accomplishes this purpose by transferring heat from these loads to either the
 
CWS (normal cooling water supply to TBCCW heat exchangers) or the SWS (alternate cooling
 
supply to TBCCW heat exchangers) through the TBCCW heat exchangers. Except for TBCCW
 
flow to the hydrogen coolers, all system valvi ng is manual. TBCCW flow to the hydrogen coolers is through an air-operated valve that can be operated in a temperature-regulated automatic or
 
manual mode.
The failure of nonsafety-related SSCs in the TBCCW system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.3.40, the applicant identified the following TBCCW system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* coolers (condensate pump motor)
* coolers (condenser vacuum pump)
* coolers (control room AC)
* coolers (feedwater and main steam sample)
* coolers (feedwater pump lube oil)
* coolers (final feedwater facility)
* coolers (hydrogen)
* coolers (reactor recirculation pump M-G sets)
* coolers (service air compressor aftercooler) 2-133
* coolers (service air compressor cylinders)
* coolers (service air compressor intercooler)
* coolers (stator winding liquid)
* coolers (thermal control unit)
* coolers (turbine lube oil)
* filter housing
* flexible connection
* flow element
* flow glass
* gauge snubber
* heat exchangers (generator bus)
* heat exchangers (TBCCW)
* level glass
* piping and fittings
* pump casing (TBCCW pumps, chemical feed pump)
* strainer body
* tanks (surge, chemical mixing, closed cooling water)
* thermowell
* valve body 2.3.3.40.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.3.40 and UFSAR Sections 9.2, 10.4, 5.4, and 9.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.40.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the TBCCW system components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).
2.3.3.41  Water Treatment & Distribution System 2.3.3.41.1  Summary of Technical Information in the Application In LRA Section 2.3.3.41, the applicant described the water treatment and distribution system, the purpose of which is to be the source of all potable water, demineralized water, and condensate for
 
the station. It accomplishes this purpose by drawing fresh water from a deep well for processing 2-134 in the pretreatment system. After treatment, par t of the water goes to the domestic water system and the rest is further treated in the makeup demineralizer (MUD) system. The water treatment and distribution system consists of the following subsystems: pretreatment subsystem, domestic water and domestic water distribution subsyste m, MUD subsystem, and demineralized water transfer subsystem. The pretreatment subsystem is trailer-mounted and designed to filter the raw
 
water drawn from the well pit by the deep well pumps. The domestic water subsystem is designed
 
to provide a supply of fresh water for use by all site facilities including laundry, drinking fountains, kitchens, bathrooms, eye wash stations, decontamination showers, HVAC (air washers and SEB
 
computer room), select sump pump bearing coolers, and the MUD subsystem. The domestic
 
water subsystem consists of two subsystems, the original domestic water subsystem and the north yard domestic water subsystem. The domes tic water distribution subsystem is designed to distribute potable water throughout the facility. A chemical feed subsystem treats the original
 
domestic water prior to use. The MUD subsystem is designed to take pretreated water from the
 
domestic water system and process it to meet the high purity standards of water for makeup
 
purposes. The original MUD subsystem was replaced by a mobile demineralizer unit for purifying filtered well water before transfer to the demineralized water storage tank (DWST). The
 
demineralized water transfer subsystem is designed to store demineralized water in the DWST
 
and to supply an adequate amount for various plant uses. The demineralized water transfer
 
subsystem is normally kept in operation at all times. During a loss of offsite power, either transfer
 
pump may be started manually and operated from t he EDGs if there is a demand on the system.
The water treatment and distribution system c ontains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the water
 
treatment and distribution system potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary In LRA Table 2.3.3.41, the applicant identified the following water treatment and distribution system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* filter housing (including purifier M-12-1)
* flexible hose
* flow element
* flow meter
* piping and fittings
* restricting orifice
* tanks (including hot water heater H-12-1)
* valve body 2-135 2.3.3.41.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.41 and UFSAR Sections 9.2.3 and 6.4.2.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.3.41.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the water treatment and distribution system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4  Steam and Power Conversion Systems In LRA Section 2.3.4, the applicant identified t he SCs of the steam and power conversion systems subject to an AMR for license renewal.
The applicant described the supporting SCs of the steam and power conversion systems in the following sections of the LRA:
* 2.3.4.1condensate system
* 2.3.4.2condensate transfer system
* 2.3.4.3feedwater system
* 2.3.4.4main condenser
* 2.3.4.5main generator and auxiliary system
* 2.3.4.6main steam system
* 2.3.4.7main turbine and auxiliary system The staff's review findings on LRA Sections 2.3.4.1 - 2.3.4.7 are presented in SER Sections 2.3.4.1 - 2.3.4.7, respectively.
2.3.4.1  Condensate System 2.3.4.1.1  Summary of Technical Information in the Application In LRA Section 2.3.4.1, the applicant described the condensate system (CNDS) designed to transfer sub-cooled condensate from the main condenser hotwell to the feedwater system. It to
 
transfers condensate water from the main condenser through the condensate demineralizer and
 
supplies the reactor feed pump at a suitable pressure and required purity level. The CNDS 2-136 includes the condensate system and the condensat e demineralizer system. During normal plant operations, the purpose of the CNDS is to purify condensate by removing corrosion products, dissolved solids, chemicals, and other impurities that may enter the reactor coolant cycle. The
 
CNDS accomplishes this purpose by processing the condensate through demineralizers. In the
 
likely event that station auxiliary power is available, the condensate and feedwater systems provide additional emergency core cooling capability.
The failure of nonsafety-related SSCs in the CNDS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.4.1, the applicant identified the following CNDS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* expansion joint
* filter housing
* flow element
* heat exchangers
* piping and fittings
* pump casing
* restricting orifice
* sensor element
* sight glasses
* strainer body
* tanks
* thermowell
* valve body 2.3.4.1.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.1 and UFSAR Sections 10.1, 10.4.6, and 10.4.7 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the
 
guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2-137 2.3.4.1.3  Conclusion The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the CNDS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
2.3.4.2  Condensate Transfer System 2.3.4.2.1  Summary of Technical Information in the Application In LRA Section 2.3.4.2, the applicant described the condensate transfer system, a condensate storage, makeup, and supply system designed to distribute water to the control rod drive, core
 
spray, condensate, isolation condenser, reactor water clean up, spent fuel pool cooling, radwaste
 
and the heater, drains, and vent and pressure systems. The purpose of the condensate transfer
 
system is to provide bulk storage of condensate, surge volume capability for the condensate
 
system, condensate supply for the condensate demineralizer resin transfer, flushing, resin
 
regeneration, and makeup to the isolation condensers and spent fuel pool. Condensate is also
 
supplied by the condensate transfer system for pump bearing cooling and makeup supply for
 
various plant systems. It accomplishes these purposes by continuously delivering condensate from the condensate transfer pumps to individual plant systems. It also provides a flow path between plant water supplies and various pumps and equipment when the appropriate manual or
 
remote manual line-ups are made. The system is normally filled by the demineralized water transfer system and has an emergency fill from t he fire protection system. The system operates continuously during plant power operation and is credited to support the isolation condensers for
 
plant shutdown.
The condensate transfer system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the condensate
 
transfer system potentially could prevent the sa tisfactory accomplishment of a safety-related function. In addition, the condensate transfer system performs functions that support fire
 
protection and SBO.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary
* provides flow restriction In LRA Table 2.3.4.2, the applicant identified the following condensate transfer system component types within the scope of license renewal and subject to an AMR:
* closure bolting 2-138
* expansion joint
* flow element
* gauge snubber
* piping and fittings
* pump casing
* restricting orifice
* tanks
* valve body 2.3.4.2.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.2 and UFSAR Sections 10.4.7, 7.4, 6.3, 15.2.6, and 9.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.2.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the condensate transfer system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.3.4.3  Feedwater System 2.3.4.3.1  Summary of Technical Information in the Application In LRA Section 2.3.4.3, the applicant described the feedwater system, a reactor water level control system that provides reheated condensate water to the RPV during normal operation at a
 
flow rate equivalent to what is generated into steam by boil-off and removed by the main steam
 
system. Essential for power operations, the feedwat er system provides cooling water to the core during a LOCA but is not credited in accident analyses, not considered part of the ECCS, nor
 
credited to support safe shutdown. The feedwater system includes the feedwater control system, the reactor feed pump lube oil system, and the zi nc injection system. The feedwater control system is a digital control function of the feedw ater system. Reactor water level is controlled by the positions of the low flow or main feedwater regulating valves controlling feedwater flow rate to
 
the reactor vessel. The zinc injection system injects depleted zinc oxide into the RCS to reduce
 
deposits and shutdown dose rates in RCS piping and components.
The feedwater system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the feedwater system potentially 2-139 could prevent the satisfactory accomplishment of a safety-related function. In addition, the feedwater system performs functions that support fire protection.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary or containment isolation In LRA Table 2.3.4.3, the applicant identified the following feedwater system component types within the scope of license renewal and subject to an AMR:
* closure bolting
* dissolution column
* expansion joint
* filter housing
* flow element
* heat exchangers
* piping and fittings
* pump casing
* strainer body
* tanks
* thermowell
* valve body 2.3.4.3.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.3 and UFSAR Sections 7.6.1.1, 7.7.1.4, 10.1, 10.4.7, and 15.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in
 
accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted 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 2.3.4.3 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 2.3.4.3-1 dated December 28, 2005, the staff noted that, although LRA Section 2.3.4.3 includes the feedwater system within the scope of license renewal for a fire protection intended
 
function, in its license renewal drawing of components with intended functions it is not obvious
 
which feedwater system components actually are credited with a fire protection intended function in accordance with 10 CFR 54.4(a)(3). Therefore, the staff requested that the applicant identify 2-140 those portions of the feedwater system with fire protection functions required for 10 CFR 54.4(a)(3).
In its response dated January 26, 2006, the applicant stated:
LRA Section 2.3.4.3 for the feedwater system does not specifically identify the portion of the system relied upon for fire protection. The feedwater control system, which is included in the feedwater system license renewal system, is the portion relied upon for fire protection. The feedwater control system is not shown on
 
license renewal drawing LR-BR-2003 for feedwater.
The feedwater control system provides a digital control function for the feedwater system and consists of two computers with dual links to the digital controllers. The
 
computers contain the feedwater logic software. The Appendix R safe shutdown
 
analysis requires demonstration of adequate plant process monitoring capability to
 
achieve and maintain safe shutdown during and following postulated fire events.
 
The Oyster Creek safe shutdown analysis credits reactor level monitoring
 
instrumentation, including associated control and indication circuits that are part of
 
the feedwater control system.
The staff's review finds the applicant's response acceptable because it identified the portions of the feedwater system relied upon for fire protection in accordance with 10 CFR 54.4(a)(3).
 
Therefore, the staff's concern described in RAI 2.3.4.3-1 is resolved.
2.3.4.3.3  Conclusion
 
The staff reviewed the LRA and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concludes that
 
there is reasonable assurance that the applicant has adequately identified the Feedwater system
 
components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.4  Main Condenser 2.3.4.4.1  Summary of Technical Information in the Application In LRA Section 2.3.4.4, the applicant described the main condenser, a heat sink for the turbine exhaust steam, turbine bypass steam, and other flows. It also deaerates and stores the condensate for reuse after a period of radioactive decay. Additionally, the main condenser
 
provides for post-accident containment, holdup, and plateout of MSIV bypass leakage.
The main condenser is designed to:
  (1)accept a portion of turbine bypass steam flow without exceeding the turbine exhaust pressure and temperature limitations  (2)receive, in addition to the main turbine exhaust, vents and drains from the regenerative feedwater heating system and from various other components and systems of the heatcycle 2-141  (3)provide time for radioactive isotope decay by retaining sufficient water in the hotwell without makeup and with turbine throttle valves wide open The purpose of the system is to condense low-pressure turbine exhaust from each of the low-pressure turbines and allow for the decay of short-lived isotopes. The main condenser
 
accomplishes this purpose by transferring heat to the circulating water system and by ensuring
 
sufficient retention time in the hotwell to allow for the decay of short-lived isotopes.
The failure of nonsafety-related SSCs in the main condenser potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended function, within the scope of license renewal, is to provide post-accident containment, plateout of iodine, and hold-up of iodine and noncondensible gases before release.
In LRA Table 2.3.4.4, the applicant identified the following main condenser component types within the scope of license renewal and subject to an AMR:
* main condenser shell
* main condenser tubes
* main condenser tubesheet 2.3.4.4.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.4 and UFSAR Section 10.4.1 using the evaluation methodology of SER Section 2.3. The staff conducted its review in accordance with the guidance
 
of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.4.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the main condenser components within the
 
scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).2.3.4.5  Main Generator and Auxiliary System 2.3.4.5.1  Summary of Technical Information in the Application In LRA Section 2.3.4.5, the applicant described the main generator and auxiliary system (MGAS), a normally operating system designed to conver t the mechanical energy of the turbine into 2-142 electrical energy fed to the main transmission lines and also used to satisfy in-house loads. The MGAS is comprised of the following subsystems: main generator, main generator exciter, stator
 
cooling, hydrogen cooling, hydrogen seal oil, and the generator isolated phase bus. The main
 
generator consists of a casing, a rotor, and a stator. The casing forms a gas-tight boundary. The
 
rotor consists of the rotor body with two shaft extensions. Hydrogen flows into the rotor near each
 
retaining ring to cool the copper windings. Two axial blower-type fans, one at each end of the
 
rotor, circulate cooling hydrogen gas around the generator and through the coolers. The stator
 
contains the main generator armature windings and consists of the stator core and stator
 
windings. The stator windings are directly water-cooled by stator cooling water which removes
 
heat produced in the stator bars of the main generator. The main exciter supplies the main
 
generator field with excitation voltage through a slip ring/brush rigging arrangement and the main
 
exciter output circuit breaker. The hydrogen seal oil subsystem maintains the hydrogen inside the
 
generator casing. The isolated phase bus connects the main generator to the main transformers, auxiliary transformer, and generator neutral connection.
The failure of nonsafety-related SSCs in the MGAS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.4.5, the applicant identified the following MGAS component types within the scope of license renewal and subject to an AMR:
* closure bolting
* filter housing
* flow element
* gauge snubber
* heat exchangers
* piping and fittings
* pump casing
* restricting orifice
* sensor element
* sight glasses
* strainer body
* tanks
* valve body 2.3.4.5.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.5 and UFSAR Sections 8.1.2, 8.2.1, 8.3.1.1, 9.2.1, and 10.2.2 using the evaluation methodology of SER Section 2.3. The staff conducted its review
 
in accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the 2-143 scope of license renewal any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.5.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the MGAS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).2.3.4.6  Main Steam System 2.3.4.6.1  Summary of Technical Information in the Application In LRA Section 2.3.4.6, the applicant described the main steam system, a normally pressurized system designed to deliver steam generated from the RPV system to the main turbine and auxiliary system. The purpose of the main steam sy stem is to provide a primary containment and RCPB function; it serves as the pressure relief system and steam distribution system. It accomplishes the primary containment and RCPB function with piping and valves to limit radiation
 
release rates from the primary containment below the 10 CFR 100 guidelines. It accomplishes the
 
pressure relief function for the RCPB by way of automatic and manual actuation of relief valves. It
 
also provides manual and automatic emergency depr essurization by relief valves supporting the core spray system. Distribution of steam to t he main turbine and auxiliary system is accomplished by piping distribution branches in the turbine building.
The main steam system contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the main steam system
 
potentially could prevent the satisfactory accomp lishment of a safety-related function. In addition, the main steam system performs functions that support fire protection and EQ.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup, and plateout (main steam system)
* provides flow restriction In LRA Table 2.3.4.6, the applicant identified the following main steam system component types within the scope of license renewal and subject to an AMR:
* closure bolting 2-144
* condensing chamber
* coolers (sample)
* eductor
* expansion joint
* flow element (main steam line)
* gauge snubber
* piping and fittings
* sparger (Y-quencher)
* steam trap
* strainer body
* thermowell
* valve body
* valve body (bypass valves)
* valve body (steam chest) 2.3.4.6.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.6 and UFSAR Sections 5.2.2, 5.2.6.2, 5.4.4, 5.4.5, 6.3.1.2, 7.3, 10.3, and 15.1.5 using the evaluation methodology of SER Section 2.3. The staff conducted
 
its review in accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-2 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of
 
license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.6.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the main steam system components within
 
the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as
 
required by 10 CFR 54.21(a)(1).2.3.4.7  Main Turbine and Auxiliary System 2.3.4.7.1  Summary of Technical Information in the Application In LRA Section 2.3.4.7, the applicant described the main turbine and auxiliary systems (MTAS), the purpose of which is to produce rotational energy from the steam generated in the
 
reactor and to discharge exhaust steam into the main condenser. The system accomplishes the
 
purpose by extracting energy from the reactor st eam entering the high-pressure turbine through the main stop valves and control valves. Some of the steam is extracted and sent to the first stage
 
reheater. The remaining steam exhausts to the moisture separators and then to the reheaters.
 
Superheated steam from the reheaters is directed to the low-pressure turbines through the
 
combined reheat intercept/stop valves. From there the steam is exhausted to the main condenser.
2-145 The main turbine and auxiliary system consists of the following subsystems: main turbine (high-pressure and low-pressure turbine sections), mechanical-hydraulic controls front standard, heater
 
drains, vent and pressure relief, moisture separators, reheaters, turbine lubrication oil, lubrication
 
oil purification and transfer, steam seal, turning gear and lift pumps, exhaust hood spray and
 
turbine hood spray, reheat steam, turbine extraction, turbine bypass and the necessary control
 
and protective devices, and operating and supervisory instrumentation.
The failure of nonsafety-related SSCs in the MTAS potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides mechanical closure In LRA Table 2.3.4.7, the applicant identified the following MTAS component types within the scope of license renewal and subject to an AMR:
* accumulator
* closure bolting
* coolers
* expansion joint
* filter housing
* flexible hose
* flow element
* heat exchangers
* piping and fittings
* pump casing
* restricting orifice
* sight glasses
* steam trap
* strainer body
* tanks
* thermowell
* turbine casing
* valve body 2.3.4.7.2  Staff Evaluation
 
The staff reviewed LRA Section 2.3.4.7 and UFSAR Sections 3.5, 7.7.1.5, 10.1, 10.2, 10.3, 10.4, 15.1, and 15.2 using the evaluation methodology of SER Section 2.3. The staff conducted its
 
review in accordance with the guidance of SRP-LR Section 2.3.
In conducting its Tier-1 review of the BOP two-tier review process, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the
 
scope of license renewal any components with intended functions under 10 CFR 54.4(a). The
 
staff then reviewed those components that the applicant had identified as within the scope of 2-146 license renewal to verify that it had not omi tted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
2.3.4.7.3  Conclusion
 
The staff reviewed the LRA to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the
 
applicant. No omissions were identified. The staff's review concludes that there is reasonable
 
assurance that the applicant has adequately identified the MTAS components within the scope of
 
license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
 
===2.4 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 discusse s the following structures and commodity groups:
* primary containment
* reactor building
* chlorination facility
* condensate transfer building
* dilution structure
* emergency diesel generator building
* exhaust tunnel
* fire pond dam
* fire pumphouses
* heating boiler house
* intake structure and canal (ultimate heat sink)
* miscellaneous yard structures
* new radwaste building
* office building
* OCGS substation
* turbine building
* ventilation stack
* component supports commodity group
* piping and component insulation commodity group 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 had 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
 
structures and components that meet the scoping criteria and are subject to an AMR.
Staff Evaluation Methodology. The staff's evaluation of the information in the LRA was the same for all structures. The objective was to determine whether the components and supporting
 
structures for a specific structure or commodity group, that appeared to meet the scoping criteria
 
specified in the Rule, had been identified by the applicant as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to 2-147 verify that all long-lived, passive components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).
Scoping. For its evaluation, the staff reviewed the applicable LRA sections and associated component drawings, focusing its review on components that had not been identified as within the
 
scope of license renewal. The staff reviewed relevant licensing basis documents, including the
 
UFSAR, for each structure and commodity group to determine whether the applicant had omitted
 
components with intended functions under 10 CFR 54.4(a) from the scope of license renewal.
 
The staff also reviewed the licensing basis documents to determine whether all intended functions
 
under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested
 
additional information to resolve them.
Screening. After completing its review of the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions, the staff sought to determine whether
 
(1) the functions are performed with moving parts or a change in configuration or properties or
 
(2) 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 meeting neither of these criteria, the staff sought to confirm that
 
these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were
 
identified, the staff requested additional information to resolve them.2.4.1  Primary Containment 2.4.1.1  Summary of Technical Information in the Application In LRA Section 2.4.1, the applicant described the primary containment structure comprised of the primary containment, containment penetrations, and internal structures. The structure is enclosed
 
by the reactor building, which provides secondary containment, structural support, shielding, shelter, and protection to the containment and components housed within against external design
 
basis events. The primary containment is a General Electric (GE) Mark I design and consists of a drywell, a pressure suppression chamber, and a vent system connecting them. It is designed, fabricated, inspected, and tested in accordance with the requirements of Section VIII of the ASME
 
Boiler and Pressure Vessel Code and Code Cases 1270N-5, 1271N and 1272N-5. The
 
containment is a safety-related, seismic Class I structure. The purpose of the primary containment
 
is to accommodate, with a minimum of leakage, pressures and temperatures resulting from the
 
break of any enclosed process pipe to limit the release of radioactive fission products to offsite
 
dose rate values below 10 CFR Part 100 guideline limits. It also provides a source of water for the
 
ECCS and for pressure suppression in a LOCA. The primary containment is penetrated at several
 
locations by piping, instrument lines, ventilation ducts, and electric leads. Internal structures
 
consist of a fill slab, reactor pedestal, biological shield wall and its lateral support, and structural
 
steel. The primary containment and internal structures also provide structural support to the
 
reactor pressure vessel, the reactor coolant systems, and other safety and nonsafety-related
 
SSCs housed within. The biological shield wall has the added function of radiation shielding to
 
maintain drywell environment within equipment qualification parameters.
The primary containment structure contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the primary
 
containment structure potentially could prev ent the satisfactory accomplishment of a safety-related function. In addition, the primary containment structure performs functions that
 
support fire protection, ATWS, and EQ.
The intended functions within the scope of license renewal include:
2-148
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides HELB shielding
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides pressure-retaining boundary; fission product barrier; containment isolation; or containment, holdup and plateout (main steam system)
* provides shielding against radiation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.1, the applicant identified the following primary containment structure component types within the scope of license renewal and subject to an AMR:
* access hatch covers
* beam seats
* biological shield wall - concrete
* biological shield wall - lateral support
* biological shield wall - liner plate
* biological shield wall - structural steel
* cable tray
* class MC pressure retaining bolting
* concrete embedment
* conduits
* downcomers
* drywell head
* drywell penetration bellows
* drywell penetration sleeves
* drywell shell
* drywell support skirt
* liner (sump)
* locks, hinges, and closure mechanisms
* miscellaneous steel (catwalks, handrails, ladders, platforms, grating, and associated supports)
* panels and enclosures
* penetration closure plates and caps (spare penetrations)
* personnel airlock and equipment hatch 2-149
* reactor pedestal
* reinforced concrete floor slab (fill slab)
* seals, gaskets, and o-rings
* shielding blocks and plates
* structural bolting
* structural steel (radial beams, posts, bracing, plate, connections, etc.)
* suppression chamber penetrations
* suppression chamber ring girders
* suppression chamber shell
* suppression chamber shell hoop straps
* thermowells
* vent header
* vent header deflector
* vent jet deflectors
* vent line bellows
* vent line 2.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.1 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4, "Scoping and
 
Screening Results: Structures."
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.1 identified areas in which additional information was necessary to complete the review of the applicant's scoping and screening results. The applicant
 
responded to the staff's RAIs as discussed below.
In RAI 2.4.1-1 dated March 20, 2006, the staff noted that LRA Table 2.4.1 indicates that drywell seismic support and anchorages are not within the scope of license renewal though relied upon
 
for drywell stability. A component type, "Biological Shield Wall - Lateral Support," is in the table.
 
The staff requested that the applicant justify not including the drywell seismic lateral supports
 
within the scope of license renewal In its response dated April 18, 2006, the applicant stated that the drywell seismic lateral supports are within the scope of license renewal and subject to AMR. The lateral supports are not
 
specifically identified by name they are included in ASME Class MC component supports and 2-150 evaluated with the "component supports" commodity group in LRA Section 2.4.18. Their AMR is presented in LRA Table 3.5.2.1-18.
The staff's review of LRA Table 3.5.2.1-18 indicates that the seismic lateral supports are not explicitly included. However, from the first sentence of the response, the staff considers the
 
supports included under the component type "supports for ASME Class MC components." Their aging will be managed by the ASME Section XI, S ubsection IWF Program. From the response, the staff finds that the seismic lateral supports are included within the scope of license renewal.
 
The staff's concern described in RAI 2.4.2-1 is resolved.
 
In RAI 2.4.1-2 dated March 20, 2006, the staff stated that LRA Tables 2.4.1 and 2.4.2 do not
 
include refueling cavity seal components within the scope of license renewal though the plant has
 
experienced significant corrosion (as described in item number 3.5.2.2-4 of LRA Section 3.5.2.2)
 
of the drywell from leakage from the seal. The staff requested that the applicant include the seal
 
within the scope of license renewal or justify not including it.
In its response dated April 18, 2006, the applicant explained that LRA Section 2.4.2 describes the refueling cavity seals and refers to them as refueling bellows, which are classified as
 
nonsafety-related and perform their design function only when the plant is shut down for refueling.
 
Moreover, the applicant noted that refueling bellows are not credited in the CLB for DBEs or
 
accidents, that their failure would not impact a safety function, and that scoping had determined
 
that they perform no 10 CFR 54.4 (a) intended function; thus, they are not included in LRA
 
Table 2.4.2.
The applicant also stated that the cavity seals are addressed in RAI 4.7.2-3. In its response to RAI 4.7.2-3 dated April 7, 2006, the applicant provided the following information:
The refueling seals at Oyster Creek consist of stainless steel bellows. In the mid to late 1980's, GPU conducted extensive visual and NDE inspections to determine
 
the source of water intrusion into the seismic gap between the drywell concrete
 
shield wall and the drywell shell, and its accumulation in the sand bed region. The
 
inspections concluded that the refueling bellows (seals) were not the source of
 
water leakage. The bellows were repeatedly tested using helium (external) and air (internal) without any indication of leakage. Furthermore, any minor leakage from
 
the refueling bellows would be collected in a concrete trough below the bellows.
 
The concrete trough is equipped with a drain line that would direct any leakage to
 
the reactor building equipment drain tank and prevent it from entering the seismic
 
gap (see Figures 1 and 2). The drain line has been checked before refueling
 
outages to confirm it is not blocked.
The only other seal is the gasket for the reactor cavity seal trough drain line. This gasket was replaced after the tests showed that it was leaking (see Figure 2).
 
However the gasket leak was ruled out as the primary source of water observed in
 
the sand bed drains because there is no clear leakage path to the seismic gap.
 
Minor gasket leakage would be collected in the concrete trough below the gasket
 
and would be removed by the drain line similar to leaks from the refueling bellows.
Additional visual and NDE (dye penetrant) inspections on the reactor cavity stainless steel liner identified a significant number of cracks, some of which were
 
through wall cracks. Engineering analysis concluded that the cracks were most 2-151 probably caused by mechanical impact or thermal fatigue and not intergranular stress corrosion cracking (IGSCC). These cracks were determined to be the
 
source of refueling water that passes through the seismic gap. To prevent leakage
 
through the cracks, GPU installed an adhesive type stainless steel tape to bridge
 
any observed large cracks, and subsequently applied the strippable coating. This
 
repair successfully greatly reduced leak age and is implemented every refueling outage while the reactor cavity is flooded. Oyster Creek is currently committed to
 
monitor the sand bed region drains for water leakage. A review of plant
 
documentation did not provide objective evidence that the commitment has been
 
implemented since 1998. Issue Report #348545 was issued in accordance with the
 
Oyster Creek corrective action process to document the lapse in implementing the commitment and to reinforce strict compliance with commitment implementation in
 
the future, including during the period of extended operation.
In addition to the commitment to monitor the sand bed region drains and the reactor cavity concrete trough drains for water leakage (see Figures 1 and 2),
Oyster Creek is committed to performing augmented inspections of the drywell in accordance with ASME Section Xl, Subsection IWE during the period of extended
 
operation. These inspections consist of periodic UT examinations of the upper
 
region of the drywell and visual examinations of the protective coating on the
 
exterior of the drywell shell in the sand bed region. The visual inspection of the
 
coating will be supplemented by UT meas urements from inside the drywell once prior to entering the period of extended operation, and every 10 years thereafter
 
during the period of extended operation.
The staff agreed with the applicant that the refueling seal (bellows) is nonsafety-related. However, its malfunction (including that of the trough drains) could jeopardize the integrity of the drywell
 
shell and, pursuant to 10 CFR 54.4(a)(2), the seal and its components (e.g., drains) must be
 
included within the scope of license renewal.
In addition, the response indicated that the stainless steel liner had cracked at several places.
However, from the discussion in LRA Section 2.4.2, the staff understood that the refueling cavity
 
floors and walls (including the stainless steel liner) are within the scope of license renewal and
 
that degradation of these structures and components is managed by the Structures Monitoring
 
Program. Therefore, the staff requested that the applicant include the refueling seal and
 
associated components within the scope of license renewal.
In its supplemental response dated July 7, 2006, the applicant revised Commitment No. 27 to include the following statement:
The reactor cavity concrete trough drain will be verified to be clear from blockage once per refueling cycle. Any identified issues will be addressed via the corrective
 
action process.
The staff believes that in a failure of the bellows or the seal gasket water will accumulate in the trough and, if the drainage from the trough is blocked, water from the trough is likely to get into
 
the air gap between the drywell and the shield concrete. As the applicant committed to monitor
 
the trough drains during each refueling cycle, the potential for water to get into the air gap is
 
reduced substantially. With the applicant's commitment (Commitment No. 27) to utilize the 2-152 strippable coating during each refueling cycle, the staff finds the applicant's response acceptable.
The staff's concern described in RAI 4.7.2-3 is resolved.
2.4.1.3  Conclusion The staff reviewed the LRA, related structural components, and the RAI responses to determine whether any SSCs that should be within the scope of license renewal had not been identified by
 
the applicant. No omissions were identified. In addition, the staff determined whether any
 
components subject to an AMR had not been identified by the applicant. No omissions were
 
identified. The staff's review concludes that the applicant has adequately identified the primary
 
containment structure components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.2 Reactor====
Building 2.4.2.1  Summary of Technical Information in the Application In LRA Section 2.4.2, the applicant described the reactor building as designed to completely enclose both the reactor pressure vessel and the primary containment structure, providing a
 
secondary containment. The building is designed to seismic Class I criteria and constructed of
 
reinforced concrete to the refueling floor level. Above the refueling floor, the structure is steel
 
framework with insulated, corrosion-resistant metal siding. The purpose of the reactor building is
 
to provide secondary containment when the primar y containment is in service and to provide primary containment during reactor refueling and maintenance operations when the primary
 
containment system is open. The primary objective of the building is to minimize ground level
 
release of airborne radioactive materials and to provide for controlled, elevated release through
 
the ventilation stack to the atmosphere under accident conditions. During normal plant operation, a slight negative pressure is maintained in the building by the reactor building heating and
 
ventilation system so that any leakage is into t he building. In an emergency condition, the reactor building heating and ventilation system is is olated and the SGTS serves the building.
The reactor building contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the reactor building potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the reactor
 
building performs functions that support fire protection, ATWS, SBO, and EQ.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides flood protection barrier (internal and external flood event)
* provides HELB shielding
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides missile barrier (internal or external)
* provides pipe whip restraint 2-153
* provides shielding against radiation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides an essentially water leak-tight boundary In LRA Table 2.4.2, the applicant identified the following reactor building component types within the scope of license renewal and subject to an AMR:
* cable tray
* concrete embedments
* conduits
* curb
* door
* equipment foundation
* fuel pool gates
* fuel pool liner
* fuel pool skimmer surge tank liner
* hatch plugs
* instrument racks
* liner (sump)
* masonry block walls
* metal deck (roof)
* metal siding
* miscellaneous steel: catwalks, handrails, ladders, platforms, grating
* panels and enclosures
* penetration seals
* pipe whip restraints
* reinforced concrete foundation
* reinforced concrete walls (above and below grade)
* reinforced concrete: beams, columns
* reinforced concrete: walls, slabs, drywell shield wall
* roofing
* scuppers: pipe sleeve, flashing, bolts
* seals
* spray shields
* structural bolts
* structural steel: beams, columns, girders, plates, bracing, trusses
* tube tray 2.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.2 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it 2-154 had not omitted any passive and long-lived components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.2 identified an area in which additional information was necessary to complete the evaluation of the applicant's scoping and screening results. The
 
applicant responded to the staff's RAIs as discussed below.
In RAI 2.4.2-1 dated March 20, 2006, the staff stated that structural seals are within the boundary of evaluation, as stated in LRA Section 2.4.8, but that the applicant had not explained what they
 
were. The staff requested that the applicant identify all structural seals in the reactor building.
In its response dated April 18, 2006, the applicant stated that component type structural seals or"seals" designates seals other than those specifically used to fill penetrations. For the reactor
 
building, these seals consist of elastomers used as sealant for the superstructure metal siding, flood door seals, HELB door seals, secondary containment door seals, and seals in expansion
 
joints of exterior concrete walls of the building. The seals perform a leakage boundary intended
 
function as designated in LRA Table 3.5.2.1.2.
 
The applicant clarified what the seals were and listed all the seals in the reactor building. The
 
staff's concern described in RAI 2.4.2-1 is resolved.
2.4.2.3  Conclusion The staff reviewed the LRA, related structural components, and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by
 
the applicant. No omissions were identified. In addition, the staff determined whether any
 
components subject to an AMR had not been identified by the applicant. No omissions were
 
identified. The staff's review concludes that there is reasonable assurance that the applicant has
 
adequately identified the reactor building components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.3 Chlorination====
Facility 2.4.3.1  Summary of Technical Information in the Application In LRA Section 2.4.3, the applicant described the chlorination facility consisting of the chlorination building, spill retention pit, foundation pad for hypochlorite storage tanks, and foundation pads
 
required to support chlorination components. The purpose of the chlorination facility is to provide
 
structural support, shelter, and protection to chlorination, and a 480V motor control center which
 
provides power to the condensate transfer pumps located in the adjacent condensate transfer
 
building. The building is a single-story steel structure with insulated metal siding located west of
 
the reactor building. The base slab is founded on reinforced concrete piers supported from the
 
circulating water tunnel located directly below the building. Foundations for the hypochlorite tanks
 
and other equipment are reinforced concrete pads founded on a common slab with the building
 
and piers supported from the circulating water tunnel. The facility is an nonsafety-related, seismic
 
Class II structure.
The chlorination facility performs functions that support fire protection.
 
The intended functions within the scope of license renewal include:
2-155
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.3, the applicant identified the following chlorination facility component types within the scope of license renewal and subject to an AMR:
* conduits
* door
* metal deck
* metal siding
* panels and enclosures
* reinforced concrete foundation
* seals
* structural bolts
* structural steel: beams, columns 2.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.4.3 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.3.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
chlorination facility components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.4 Condensate====
Transfer Building 2.4.4.1  Summary of Technical Information in the Application In LRA Section 2.4.4, the applicant described the condensate transfer building as a single-story steel structure with metal siding located west of the reactor building. The purpose of the
 
condensate transfer building is to provide structural support, shelter, and protection for the
 
condensate transfer pumps, demineralized water transfer pumps, and service water booster
 
pump. The base slab is founded on reinforced concrete piers supported from the circulating water
 
tunnel located directly below the building. A half-ton hoist is incorporated in the design of the 2-156 structure to facilitate removal and maintenance of equipment. The structure is classified as nonsafety-related, seismic Class II.
The condensate transfer building performs functions that support fire protection.
 
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.4, the applicant identified the following condensate transfer building component types within the scope of license renewal and subject to an AMR:
* conduits
* door
* equipment foundation
* metal deck
* metal siding
* panels and enclosures
* reinforced concrete foundation (includes piers)
* seals
* structural bolts
* structural steel: beams, columns 2.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.4.4 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.4.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
condensate transfer building components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-157 2.4.5  Dilution Structure 2.4.5.1  Summary of Technical Information in the Application In LRA Section 2.4.5, the applicant described the dilution structure located west of the reactor building on the west bank of the intake canal. The purpose of the dilution structure is to house the
 
dilution system and its supporting systems. The st ructure provides physical support, shelter, and protection to nonsafety-related components designed to divert water from the intake canal to the
 
discharge canal for thermal dilution. Additionally, the structure in conjunction with earthen dikes
 
forms the intake canal boundary and separates it from the discharge canal. The structure is of
 
reinforced concrete, approximate 83 feet long and divided into three bays, each with two trash
 
racks and one dilution pump. The three dilution pumps discharge into a common reinforced
 
concrete tunnel that delivers dilution water from the intake canal to the discharge canal. Sheet
 
metal and wooden enclosures located on the top slab of the structure at grade level provide
 
shelter for pump motors and other dilution system components. The foundation for the structure
 
consists of a reinforced concrete slab, with shear keys, founded on soil 30 foot below grade level.
 
Stop logs are incorporated into the structure's design to isolate each bay from the intake canal.
 
The structure is classified as nonsafety-related, seismic Class II.
The failure of nonsafety-related SSCs in the dilution structure potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides an essentially water leak-tight boundary In LRA Table 2.4.5, the applicant identified the following dilution structure component types within the scope of license renewal and subject to an AMR:
* reinforced concrete foundation
* reinforced concrete walls 2.4.5.2  Staff Evaluation The staff reviewed LRA Section 2.4.5 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.5.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No 2-158 omissions were identified. In addition, the staff determined whether any components subject to an AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
dilution structure components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.6  Emergency Diesel Generator Building 2.4.6.1  Summary of Technical Information in the Application In LRA Section 2.4.6, the applicant described the EDG building as a single-story structure located southwest of the reactor building. The purpose of the EDG building is to provide support, shelter, and protection for each EDG, the diesel oil storage tank, and components of the fuel transfer
 
system. The reinforced concrete structure consists of two compartments, one for each EDG, and
 
an appendage vault to the building containing the diesel oil storage tank. Personnel entrances to
 
the building have reinforced concrete labyrinth walls for missile protection and a 6-inch high curb
 
for flood protection. The building foundation is reinforced concrete slab on grade. The building is
 
classified as safety-related, designed to seismic Class I. Each EDG is also housed in a metal
 
enclosure which provides protection against rain, snow, and dust that may enter the building
 
through the air intake and exhaust openings on the roof. The building also houses and supports
 
such nonsafety-related components as grating, lighting conduit, and electrical enclosures.
The EDG building contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the EDG building potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the EDG building
 
performs functions that support fire protection and SBO.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides flood protection barrier (internal and external flood event)
* provides missile barrier (internal or external)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.6, the applicant identified the following EDG building component types within the scope of license renewal and subject to an AMR:
* concrete embedments
* conduits
* curb
* EDG enclosure
* miscellaneous steel (catwalks, handrails, ladders, platforms, grating, and associated supports)
* panels and enclosures 2-159
* reinforced concrete foundation
* reinforced concrete walls, slabs (includes removable roof slab)
* structural bolts
* structural steel (plate) 2.4.6.2  Staff Evaluation The staff reviewed LRA Section 2.4.6 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.6.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
EDG building components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
====2.4.7 Exhaust====
Tunnel 2.4.7.1  Summary of Technical Information in the Application In LRA Section 2.4.7, the applicant described the exhaust tunnel, which consists of an underground reinforced concrete box that connects the ventilation stack, the reactor building, turbine building, and the old radwaste building. The purpose of the exhaust tunnel is to provide
 
structural support, shelter, and protection for the SGTS components and ductwork and for
 
4160V AC and 480V AC electrical cables. It also provides structural support, shelter, and
 
protection for nonsafety-related system piping and ductwork routed within the tunnel. The tunnel
 
houses major components of the SGTS with the exception of the exhaust fans and outlet valves.
 
The tunnel also routes reactor building ventilation, turbine building ventilation, and old radwaste
 
building ventilation exhaust ductwork to the ventilation stack as well as process piping and drain
 
lines routed between the buildings. Also routed through the tunnel are 4160V AC system cables, which feed core spray pumps, and 480V AC system power to the SGTS components. In addition, the tunnel contains heating steam piping routed from the heating boiler house to the buildings.
 
The exhaust tunnel is classified as an nonsafety-related, seismic Class II structure.
The failure of nonsafety-related SSCs in the exhaust tunnel potentially could prevent the satisfactory accomplishment of a safety-related function. The exhaust tunnel also performs
 
functions that support fire protection and EQ.
2-160 The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.7, the applicant identified the following exhaust tunnel component types within the scope of license renewal and subject to an AMR:
* concrete embedments
* conduits
* curb
* door
* hatch cover
* masonry block walls
* panels and enclosures
* penetration seals
* reinforced concrete slabs
* seals (gap)
* walls 2.4.7.2  Staff Evaluation The staff reviewed LRA Section 2.4.7 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.7.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
exhaust tunnel components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-161 2.4.8  Fire Pond Dam 2.4.8.1  Summary of Technical Information in the Application In LRA Section 2.4.8, the applicant described the fire pond dam constructed across the OCGS stream outside the protected area and approximatel y 1/4 mile from the reactor building. The purpose of the fire pond dam is to contain fresh water for use in the fire protection system. Water
 
from the pond is supplied to the fire protection system by two pumps housed in the fresh water pump house adjacent to the dam. The dam is 130 feet long and consists of two parallel lines of
 
tongue and grooved wood sheeting 5 feet apart and driven into the channel bottom. The area
 
between the upstream and downstream sheeting is lined with a 4-inch reinforced concrete slab
 
which forms a shallow open channel that directs water flow to a 45-foot wide stream spillway.
 
Rip-rap is placed downstream of the spillway to protect the stream from erosion. The pond formed by the dam covers over 6 acres of land and has a volume equivalent to 7.2 million gallons of
 
water. The dam, classified safety Class III, is subject to State of New Jersey Department of
 
Environmental Protection and Energy dam safety regulations.
The fire pond dam performs functions that support fire protection.
 
The intended function, within the scope of license renewal, is to provide an essentially water leak-tight boundary.
In LRA Table 2.4.8, the applicant identified the component type fire pond dam structure as within the scope of license renewal and subject to an AMR.
2.4.8.2  Staff Evaluation The staff reviewed LRA Section 2.4.8 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.8 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 RAIs as discussed below.
In RAI 2.4.8-1 dated March 30, 2006, the staff noted that in LRA Section 2.4.8 the fire pond dam is classified as safety Class III. The staff requested that the applicant identify in the LRA or
 
UFSAR the definition of safety Class Ill. If the definition was not in the LRA or UFSAR, the staff
 
requested that the applicant provide a definition.
In its response dated April 18, 2006, the applicant stated that the fire pond dam classification is related to the hazard potential of property damage or loss of life if the dam failed, not to nuclear
 
safety, and is not defined in the UFSAR. The term is not defined in the LRA because it does not
 
affect scoping, screening, and aging management of the dam. The fire pond dam is within the 2-162 scope of license renewal under 10 CFR 54.4(a)(3) and is relied upon in the safety analyses and plant evaluations to perform a function for compliance with NRC fire protection regulations. As
 
described in LRA Section 2.4.8, the dam is classified safety Class Ill and subject to State of New
 
Jersey Department of Environment Protection and Energy dam safety regulations. The safety Class Ill classification is assigned by the State of New Jersey to dams the failure of which would
 
not cause loss of life or significant property dam age. This classification is synonymous with the"low-hazard potential" assigned to dams in the Federal Emergency Management Agency
 
guidelines for dam safety.
The staff concludes that the applicant's response had provided an adequate explanation of safety Class Ill. The staff's concern described in RAI 2.4.8-1 is resolved.
2.4.8.3  Conclusion The staff reviewed the LRA, related structural components, and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by
 
the applicant. No omissions were identified. In addition, the staff determined whether any
 
components subject to an AMR had not been identified by the applicant. No omissions were
 
identified. The staff's review concludes that there is reasonable assurance that the applicant has
 
adequately identified the fire pond dam components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.9  Fire Pumphouses 2.4.9.1  Summary of Technical Information in the Application In LRA Section 2.4.9, the applicant described the fire pumphouses, the purpose of which is to provide structural support, shelter, and protection for fire protection system components and for
 
components supporting the intended function of the system. The fire pumphouses are comprised
 
of the fresh water pumphouse and the redundant fire protection pumphouse. The fresh water
 
pumphouse is located west of the reactor building outside the protected area. It consists of a
 
prefabricated sheet metal enclosure, an intake reinforced concrete structure, and foundations for
 
two fuel oil tanks. The intake structure is divided into three separate pump intake bays, one for
 
each of the two vertical centrifugal diesel engine-driven fire pumps and one for two electric pond
 
pumps. The inlet into the bays is protected with trash racks and stationary water screens. The two
 
diesel-driven pumps supply primary fire water, drawn from a pond formed by a small dam, to the fire protection system. The two electric pond pumps maintain fire water system pressure. The pumps, the diesel engines, and their supporting systems are inside the enclosure supported from
 
the roof slab of the intake bays. The fuel oil tanks are outside the enclosure within a diked area
 
and independently supported by reinforced concrete foundations. A monorail outside the
 
enclosure, supported on structural frames, provides the means for cleaning and servicing the
 
stationary water screens. The pumphouse and the tank foundations are classified as
 
nonsafety-related, seismic Class II. The redundant fire protection pumphouse is northwest of the
 
reactor building inside the protected area. It consists of a prefabricated sheet metal enclosure, foundation slab on grade, and foundation for the redundant fire protection water tank. The
 
structure houses a motor-driven electric fire pump and its supporting electrical systems. This pump and its tank constitute an emergency supply when the primary supply is not available. The pumphouse is classified as nonsafety-related, seismic Class II.
2-163 The fire pumphouses perform functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.9, the applicant identified the following fire pumphouses component types within the scope of license renewal and subject to an AMR:
* conduits
* metal deck
* metal siding
* panels and enclosures
* reinforced concrete foundation
* reinforced concrete slab
* reinforced concrete walls
* seals
* structural bolts
* structural steel 2.4.9.2  Staff Evaluation The staff reviewed LRA Section 2.4.9 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.4.9 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 RAIs as discussed below.
In RAI 2.4.9-1 dated March 30, 2006, the staff stated that LRA Section 2.4.9 classifies the pumphouse and the tank foundations as nonsafety-related, seismic Class II. The staff requested
 
that the applicant identify in the LRA or UFSAR the definition of "nonsafety-related, seismic
 
Class II." If the definition was not in the LRA or UFSAR, the staff requested that the applicant
 
provide a definition.
In its response dated April 18, 2006, the applicant stated:
Seismic classification of structures is defined in UFSAR Section 3.8.3.2, Applicable Codes, Standards and Specifications, and Section 3.8.4.1, Description of the
 
Structures. According to these sections, there are two classes of structures for
 
which earthquake design requirements apply as follows:
2-164
* Class I: Structures and equipment whose failure could cause significant release of radioactivity or which are vital to a proper shutdown of the plant
 
and the removal of decay heat.
* Class II: Structures and equipment which are both essential and nonessential to the operation of the station, but which are not essential to a
 
proper shutdown.
The Fire Pumphouses and tank foundations are classified Seismic Class II structures based on UFSAR definition above. For license renewal, the Fire
 
Pumphouses and the tank foundations meet 10 CFR 54.4(a)(3) because they are
 
relied upon in the safety analyses and plant evaluations to perform a function that
 
demonstrates compliance with the Commission's regulations for fire protection
 
(10 CFR 50.48). The pumphouses and the tank foundations do not meet
 
10 CFR 54.4(a)(1) because they are not safety-related structures that are relied on
 
to remain functional during and following design basis events. The pumphouses
 
and the tank foundations do not meet 10 CFR 54.4(a)(2) because failure of
 
non-safety related portions of the structures would not prevent satisfactory
 
accomplishment of function(s) identified for 10 CFR 54.4(a)(1). The structures are
 
not relied upon in any safety analyses or plant evaluations to perform a function
 
that demonstrates compliance with the Commission's regulation for Environmental
 
Qualification (10 CFR 50.49), ATWS (10 CFR 50.62), or Station Blackout
 
(10 CFR 50.63).
The staff concludes that the applicant's response was acceptable as it clearly defined the seismic Class II pumphouse and the tank foundation. The staff's concern described in RAI 2.4.9-1 is
 
resolved.
2.4.9.3  Conclusion The staff reviewed the LRA, related structural components, and the RAI response to determine whether any SSCs that should be within the scope of license renewal had not been identified by
 
the applicant. No omissions were identified. In addition, the staff determined whether any
 
components subject to an AMR had not been identified by the applicant. No omissions were
 
identified. The staff's review concludes that there is reasonable assurance that the applicant has
 
adequately identified the fire pumphouse components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.10  Heating Boiler House 2.4.10.1  Summary of Technical Information in the Application In LRA Section 2.4.10, the applicant described the heating boiler house license renewal structure comprised of the old and the new heating boiler house. The purpose of the structures is to house
 
the nonsafety-related heating and process st eam system components and supporting systems.
Major components housed in the buildings include oil-fired boilers, heating boiler feed pumps, fuel
 
oil pumps, deaerator, chemical tanks and feed pumps, boiler condensate storage tank, and
 
system piping. Each heating boiler house is a single-story steel structure located southeast of the
 
reactor building. The buildings are enclosed with insulated metal siding, roof metal deck, and
 
built-up roofing. Foundations for the structures consist of reinforced concrete isolated footings and 2-165 a reinforced concrete base slab on grade. The old heating boiler house is adjacent and provides access to the ventilation stack through a double door airlock. It also houses two safety-related
 
electrical load centers, electrical panels and enclosures, a transformer, and electrical conduits
 
required for the operation of the SGTS fans. The new heating boiler house does not house any
 
SSCs. The two heating boiler houses are classified as nonsafety-related, seismic Class II.
The failure of nonsafety-related SSCs in the heating boiler house potentially could prevent the satisfactory accomplishment of a safety-related function. The heating boiler house also performs
 
functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.10, the applicant identified the following heating boiler house component types within the scope of license renewal and subject to an AMR:
* conduits
* door
* equipment foundation
* metal deck
* metal siding
* panels and enclosures
* reinforced concrete foundation
* removable panel (in siding)
* seals
* structural bolts
* structural steel: beams, columns, girts, bracing, connection plates and angles 2.4.10.2  Staff Evaluation The staff reviewed LRA Section 2.4.10 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.10.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the 2-166 heating boiler house components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.11  Intake Structure and Canal (Ultimate Heat Sink) 2.4.11.1  Summary of Technical Information in the Application In LRA Section 2.4.11, the applicant described the intake structure and canal (ultimate heat sink).
The purpose of the intake structure and canal is to provide seawater to dissipate waste heat from
 
the plant during normal, shutdown, and accident conditions. The intake structure also provides
 
structural support for pumps and components that deliver seawater to the plant. In addition, the
 
structure provides structural support and access to electrical, mechanical, and structural
 
components required to support the function and operation of the CWS, SWS, ESW system, screen wash system, and new radwaste SWS, including sluice gates, stop logs, trash racks, trash
 
cart, traveling water intake screens, platforms, ladders, and stairs. The intake structure is
 
composed of reinforced concrete slabs, beams, and shear walls. The structure is largely buried
 
underground or submerged in seawater. Its foundation is a reinforced concrete mat founded on
 
Cohansey sand with a concrete apron that extends into and below the intake canal. The intake
 
canal draws seawater from Barnegat Bay and conveys it to the intake structure. The canal is
 
140 feet wide, dredged to 10 feet below mean sea level, and separated from the discharge canal
 
by the dilution pump structure and an earthen dike at the intake structure. The canal banks are
 
lined with asphalt bonded stone for protection against erosion. The canal is the ultimate heat sink, required to provide cooling water for emergency shutdown as well as during normal plant
 
operation.
The intake structure and canal contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the intake structure and
 
canal potentially could prevent the satisfactory accomplishment of a safety-related function. In addition, the intake structure and canal perform functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides filtration
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides an essentially water leak-tight boundary In LRA Table 2.4.11, the applicant identified the following intake structure and canal component types within the scope of license renewal and subject to an AMR:
* conduits
* earthen water control structures (intake canal, embankments)
* reinforced concrete foundation
* reinforced concrete slab
* reinforced concrete walls
* trash racks 2-167 2.4.11.2  Staff Evaluation The staff reviewed LRA Section 2.4.11 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.11.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
intake structure and canal components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.12  Miscellaneous Yard Structures 2.4.12.1  Summary of Technical Information in the Application In LRA Section 2.4.12, the applicant described the miscellaneous yard structures comprised of concrete and steel structures throughout the yard area. Concrete structures include foundations
 
for outdoor tanks, SGTS fan pads, material storage area pads, transformer foundations, electrical
 
substation components, transmission towers, electrical bus duct supports, trailers, and lighting
 
poles. Concrete structures also include the SWS seal well, sanitary waste system underground
 
concrete tank, trenches, duct banks, manholes, drainage catch basins, concrete retaining walls, concrete curbs, and concrete dikes. Steel structures are comprised of trailers, transmission
 
towers, component supports in the yard (including supports for offsite power system and SBO
 
components), electrical enclosures, 480V switc hgear room ventilation fan platforms, and yard storm drainage piping. The purpose of miscellaneous yard structures is to provide structural
 
support, shelter, and protection for safety-related and nonsafety-related components and
 
commodities, including offsite power, SBO, and components credited for fire protection. The
 
purpose of SWS seal well is to reduce the head requirements of the SWS by providing a siphon
 
discharge and a flow path for the SWS. The purpose of curbs and dikes is to contain fluid spills for
 
controlled release. The curb at the entrance to the emergency diesel generator building prevents
 
water intrusion into the building during high floods. Trailers provide additional office space and
 
house nonsafety-related equipment and components not within the scope of license renewal.
The failure of nonsafety-related SSCs in the miscellaneous yard structures potentially could prevent the satisfactory accomplishment of a safety-related function. The miscellaneous yard
 
structures also perform functions that support fire protection and SBO.
The intended functions within the scope of license renewal include:
2-168
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides flood protection barrier (internal and external flood event)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides an essentially water leak-tight boundary In LRA Table 2.4.12, the applicant identified the following miscellaneous yard structures component types within the scope of license renewal and subject to an AMR:
* concrete embedments
* conduits
* curb
* equipment and component foundations (startup, unit substation, and SBO transformers, nitrogen supply, SGTS fans and motors, HVAC components, etc.)
* miscellaneous steel (manhole covers)
* miscellaneous steel (platforms)
* panels and enclosures (startup, unit substation, and SBO transformers)
* reinforced concrete trench, manhole, ductbank
* reinforced concrete walls, slabs (SWS seal well)
* structural bolts
* tank foundations (CST, fire water, CO 2 , nitrogen, fuel oil)
* transmission towers 2.4.12.2  Staff Evaluation The staff reviewed LRA Section 2.4.12 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.12.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the 2-169 miscellaneous yard structure components within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.13  New Radwaste Building 2.4.13.1  Summary of Technical Information in the Application In LRA Section 2.4.13, the applicant described the new radwaste building as a three-story structure located northeast of the reactor building. The purpose of the new radwaste building is to
 
house the liquid radwaste system, which is classified as nonsafety-related and designed in
 
accordance with the recommendations of RGs 1.26 and 1.29. The building provides structural
 
support, shelter, and protection for the system components and radiation protection during plant
 
operating conditions. Some elements of the building (walls and slabs) are credited, in the CLB, for
 
retention of liquid radwaste during a safe shutdown earthquake. These elements are designed to
 
seismic Class I criteria and sealed watertight. The seismic Class I boundary is based on the
 
volume required to contain the entire liquid inventory of the radwaste system inside the building, taking into account the effects of non-seismic elements of the building collapsing and displacing
 
some of this liquid. This basis provides assurance that postulated failures of the nonseismic liquid
 
radwaste components within the building will not cause uncontrolled releases of radioactivity in
 
liquid form to the environment. The rest of t he building is nonseismic, conventionally designed.
The building is rectangular in plan, constructed on a reinforced concrete foundation mat at grade
 
resting on compacted backfill. Steel framing and metal decking support the reinforced concrete
 
floor slabs. Walls required to contain liquid radwaste within the building, in the event of liquid
 
radwaste system components failure, are reinforced concrete. Other walls consist of insulated
 
metal siding or solid concrete block construction.
The failure of nonsafety-related SSCs in the new radwaste building potentially could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function
* provides an essentially water leak-tight boundary In LRA Table 2.4.13, the applicant identified the following new radwaste building component types within the scope of license renewal and subject to an AMR:
* penetration seals
* reinforced concrete foundation
* reinforced concrete walls (above and below grade) 2.4.13.2  Staff Evaluation The staff reviewed LRA Section 2.4.13 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those 2-170 components that the applicant had identified as within the scope of license renewal to verify that it had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.13.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the new
 
radwaste building components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.14  Office Building 2.4.14.1  Summary of Technical Information in the Application In LRA Section 2.4.14, the applicant described the office building as a three-story concrete structure between the reactor and turbine buildings. The purpose of the office building is to house
 
and support recirculation pump motor generator sets, emergency switchgear, main station
 
batteries, and their electrical and mechanical s upporting systems, including ventilation systems.
The building also provides offices for site management and plant support personnel, chemistry
 
laboratory testing equipment, showers, locker rooms, and a secondary access to controlled areas.
 
The building is erected partly on the reactor building and partly on a separate mat foundation slab
 
on grade separated from the reactor building by 1-1/2 inch gap to allow for differential settlement.
 
The reactor building west wall and the torus area roof slab form the east wall of the office building
 
and its first floor slab, respectively. The building was designed as a seismic Class II as specified
 
in UFSAR Section 3.8.4.
The office building contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the office building potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the office
 
building performs functions that support fire protection.
The intended functions within the scope of license renewal include:
* provides spray shield or curbs for directing flow
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.14, the applicant identified the following office building component types within the scope of license renewal and subject to an AMR:
* cable tray
* concrete embedments
* conduits
* curb 2-171
* masonry block walls
* panels and enclosures
* reinforced concrete foundation
* reinforced concrete walls, slabs, beams 2.4.14.2  Staff Evaluation The staff reviewed LRA Section 2.4.14 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.14.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
office building components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.15  Oyster Creek Substation 2.4.15.1  Summary of Technical Information in the Application In LRA Section 2.4.15, the applicant described the OCGS substation located west of the reactor building adjacent to the intake and discharge canals. The purpose of the substation is to provide
 
structural support, shelter, and protection to nonsafety-related electrical components and
 
commodities. The substation consists of a reinforced concrete slab on grade, the breaker switch
 
control room, transmission towers, and the foundation for OCGS output power to the grid and for
 
incoming offsite power system components. The br eaker switch control room is a commercial grade steel enclosure with metal siding and metal deck supported on the substation concrete
 
slab. The substation is classified as nonsafety-related, seismic Class II.
The OCGS substation performs functions that support SBO.
 
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.15, the applicant identified the following OCGS substation component types within the scope of license renewal and subject to an AMR:
2-172
* conduits
* door
* equipment foundation
* metal deck
* metal siding
* reinforced concrete foundation
* seals
* structural bolts
* structural steel
* transmission towers 2.4.15.2  Staff Evaluation The staff reviewed LRA Section 2.4.15 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.15.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
OCGS substation components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.16  Turbine Building 2.4.16.1  Summary of Technical Information in the Application In LRA Section 2.4.16, the applicant described the turbine building as a reinforced concrete and steel structure directly west of the reactor building and adjacent to the office building. The purpose
 
of the building is to provide structural support, shelter, and protection for safety-related and
 
nonsafety-related SSCs housed within. The building contains the plant control room, two cable
 
spreading rooms, the 4160V switchgear room, t he "C" battery room, and a mechanical equipment room (HVAC) for the control room. The control room, the two cable spreading rooms, and the mechanical equipment room on the northeast corner of the building are enclosed in reinforced
 
concrete walls and slabs to protect safety-related components and control room personnel from
 
extreme environmental conditions and DBEs. The re st of the building encloses the steam and power conversion system, the TBCCW system, r eactor protection system components, turbine building ventilation, the hydrogen injection sy stem, and supporting systems. Major components within the building include turbine generators, main condensers, moisture separators, reheaters, reactor feedwater pumps, main steam control and stop valves, condensate pumps, TBCCW heat 2-173 exchangers, and their piping. Highly radioactive components are enclosed within heavy concrete walls with labyrinthine entrances for shielding purposes. Equipment in the building is serviced by
 
two cranes, the turbine building overhead bri dge crane and the heater bay overhead bridge crane.
The building foundation is a reinforced concrete mat founded on dense Cohansey sand 31 feet
 
below grade level. Reinforced concrete walls extend from the top of the base mat level to the
 
turbine generator operating floor 23 feet above grade level. Steel framework and insulated metal
 
siding and built-up roofing enclose the turbine generator operating floor.
The turbine building contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the turbine building potentially could
 
prevent the satisfactory accomplishment of a safety-related function. In addition, the turbine
 
building performs functions that support fire protection, ATWS, SBO, and EQ.
The intended functions within the scope of license renewal include:
* provides enclosure, shelter, or protection for in-scope equipment (including shielding)
* provides flood protection barrier (internal and external flood event)
* provides HELB shielding
* provides missile barrier (internal or external)
* provides shielding against radiation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.16, the applicant identified the following turbine building component types within the scope of license renewal and subject to an AMR:
* bird screen
* cable tray
* concrete embedments
* conduits
* equipment foundation
* hatch plugs
* masonry block walls
* metal deck
* metal siding
* miscellaneous steel (catwalks, handrails, ladders, platforms, grating, and associated supports)
* panels and enclosures
* penetration seals
* reinforced concrete foundation
* reinforced concrete walls (above and below grade) 2-174
* reinforced concrete walls, slabs, beams
* roofing
* seals
* structural bolts
* structural steel: beams, columns, girders, plate 2.4.16.2  Staff Evaluation The staff reviewed LRA Section 2.4.16 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.16.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
turbine building components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
2.4.17  Ventilation Stack 2.4.17.1  Summary of Technical Information in the Application In LRA Section 2.4.17, the applicant described the ventilation stack as a 394-foot high, tapered, reinforced concrete structure southeast of the reactor building and adjacent to the SGTS and the
 
heating boiler house. The purpose of the ventilation stack is to provide an elevated discharge
 
point for gaseous effluents collected from the SGTS, RBVS, radwaste area heating and
 
ventilation system, main condenser air extraction sy stem (includes turbine steam seal effluents), augmented offgas system, and turbine building v entilation system. In addition, the stack in conjunction with the hardened vent system provides a secondary pressure vent path for primary containment if the torus vent path is unavail able. Effluents through the ventilation stack are monitored to ensure that the 10 CFR Part 20 limits, which apply to releases during normal
 
operation, and the 10 CFR Part 100 limits, which apply to accidental releases, are not exceeded.
 
The stack also provides structural support to the piping, tubing, and air ducts penetrating it and to
 
components inside it, including valves, absolute filter, and radiation monitors. Its base is a
 
7-foot thick reinforced concrete slab founded on very dense sand and buried 26 feet below grade.
 
Internally, the structure is divided into three levels formed by the base slab, an intermediate slab
 
at ground level, and an upper slab located 11' 6" above ground level . Access into the stack is
 
from the old heating boiler house and from the exhaust tunnel. The stack is classified as seismic 2-175 Class I and relied upon to elevate gaseous effluents during normal plant operation and during accident conditions.
The ventilation stack contains safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the ventilation stack potentially
 
could prevent the satisfactory accomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides path for release of filtered and unfiltered gaseous discharge
* maintains mechanical and structural integrity to prevent spatial interactions that could cause failure of safety-related SSCs (includes the required structural support when the
 
nonsafety-related leakage boundary piping is also attached to safety-related piping)
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.4.17, the applicant identified the following ventilation stack component types within the scope of license renewal and subject to an AMR:
* concrete embedments
* hatch cover
* miscellaneous steel (catwalks, handrails, ladders, platforms, grating, and associated supports)
* penetration seals
* penetration sleeve, cap plates, capped auxiliary boiler exhaust pipe
* reinforced concrete foundation
* reinforced concrete slabs
* reinforced concrete stack (above and below grade)
* structural bolts 2.4.17.2  Staff Evaluation The staff reviewed LRA Section 2.4.17 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2-176 2.4.17.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
ventilation stack components within the scope of license renewal, as required by 10 CFR 54.4(a),
and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.18  Component Supports Commodity Group 2.4.18.1  Summary of Technical Information in the Application In LRA Section 2.4.18, the applicant described the component supports commodity group consisting of structural elements and specialty components designed to transfer the load applied
 
from an SSC to building structural elements or directly to building foundations. 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 isolators. Sliding surfaces, when incorporated
 
into the support design, permit release of lateral forces but are relied upon to carry vertical load.
 
Specialty supports like snubbers only resist seismic forces. Vibration isolators are incorporated in
 
the design of some vibrating equipment to minimize the impact of vibration. Other support types
 
like guides and position stops allow displacement in a specified direction or preclude
 
unacceptable movements and interactions.
The commodity group is comprised of the following supports:
* supports for ASME Class 1, 2 and 3 piping and components including reactor vessel stabilizer, reactor vessel skirt support, and CRD housing supports
* supports for ASME Class MC components including suppression chamber seismic restraints, suppression chamber support saddles and columns, and vent system supports
* supports for cable trays, conduit, HVAC ducts, tube track, and instrument tubing
* supports for non-ASME piping and components including EDG supports
* supports for racks, panels, and enclosures
* supports for spray shields and masonry walls The component supports commodity group contai ns safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the
 
component supports commodity group potentially c ould prevent the satisfactory accomplishment of a safety-related function. In addition, the component supports commodity group performs functions that support fire protection, ATWS, SBO, and EQ.
The intended functions within the scope of license renewal include:
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function 2-177
* provides flexible support for HVAC fan units In LRA Table 2.4.18, the applicant identified the following component supports commodity group component types within the scope of license renewal and subject to an AMR:
* building concrete at locations of expansion and grouted anchors, grouted pads for support base plates
* supports for ASME Class 1 piping and components (constant and variable load spring hangers, guides, stops, sliding surfaces, design clearances)
* supports for ASME Class 1 piping and components (support members, welds, bolted connections, support anchorage to building structure)
* supports for ASME Class 2 and 3 piping and components (constant and variable load spring hangers, guides, stops, sliding surfaces, design clearances)
* supports for ASME Class 2 and 3 piping and components (support members, welds, bolted connections, support anchorage to building structure)
* supports for ASME Class MC components (guides, stops, sliding surfaces, design clearances)
* supports for ASME Class MC components (support members, welds, bolted connections, support anchorage to building structure)
* supports for cable trays (support members, welds, bolted connections, support anchorage to building structure)
* supports for conduits (support members, welds, bolted connections, support anchorage to building structure)
* supports for HVAC components (vibration isolation elements)
* supports for HVAC components and other miscellaneous mechanical equipment (support members, welds, bolted connections, support anchorage to building structure)
* supports for HVAC ducts (support members, welds, bolted connections, support anchorage to building structure)
* supports for masonry walls (support members, welds, bolted connections, support anchorage to building structure)
* supports for non-ASME piping and components (support members, welds, bolted connections, support anchorage to building structure)
* supports for panels and enclosures, racks (support members, welds, bolted connections, support anchorage to building structure)
* supports for platforms, pipe whip restraints, jet impingement and spray shields, and other miscellaneous structures (support members, welds, bolted connections, support
 
anchorage to building structure)
* supports for tube track and instrument tubing (support members, welds, bolted connections, support anchorage to building structure) 2-178 2.4.18.2  Staff Evaluation The staff reviewed LRA Section 2.4.18 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.18.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
component supports commodity group components within the scope of license renewal, as
 
required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.19  Piping and Component Insulation Commodity Group 2.4.19.1  Summary of Technical Information in the Application In LRA Section 2.4.19, the applicant described the piping and component insulation commodity group 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 originally installed and replacement metallic and nonmetallic materials.
 
The purpose of insulation is to improve thermal efficiency, minimize heat loads on the HVAC
 
systems, provide protection for personnel, or prevent sweating of cold piping and components.
Metallic insulation consists of stainless steel mirror insulation. Nonmetallic insulation consists of
 
calcium silicate, asbestos, and light-density, semi-rigid fibrous glass quilted between two layers of
 
glass scrim and encapsulated in a fiberglass cloth forming a composite blanket or of pre-molded
 
fiberglass modules and panels encased in fiberglass jackets. Anti-sweat insulation consists of
 
closed cell, foamed plastic (inside primary cont ainment drywell) and fiberglass dual-temperature or glass wool blanketing (outside primary containm ent drywell). Metal protective jackets are made from rolled aluminum or stainless steel. The insulation is a nonsafety-related commodity.
The failure of nonsafety-related SSCs in the piping and component insulation commodity group potentially could prevent the satisfactory a ccomplishment of a safety-related function.
The intended functions within the scope of license renewal include:
* provides physical support of thermal insulation and prevents moisture absorption
* provides heat loss control to preclude overheating of nearby safety-related SSCs In LRA Table 2.4.19, the applicant identified the following piping and component insulation commodity group component types within the sc ope of license renewal and subject to an AMR:
2-179
* insulation
* insulation jacketing 2.4.19.2  Staff Evaluation The staff reviewed LRA Section 2.4.19 using the evaluation methodology of SER Section 2.4. The staff conducted its review in accordance with the guidance of SRP-LR Section 2.4.
In conducting its review, the staff evaluated the structural component functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal
 
any components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that it
 
had not omitted any passive and long-lived components subject to an AMR in accordance with
 
the requirements of 10 CFR 54.21(a)(1).
2.4.19.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCs that should be within the scope of license renewal had not been identified by the applicant. No
 
omissions were identified. In addition, the staff determined whether any components subject to an
 
AMR had not been identified by the applicant. No omissions were identified. The staff's review
 
concludes that there is reasonable assurance that the applicant has adequately identified the
 
piping and component insulation commodity group components within the scope of license
 
renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by
 
10 CFR 54.21(a)(1).
 
===2.5 Scoping===
and Screening R esults: Electrical Components This section documents the staff's review of the applicant's scoping and screening results for electrical and instrumentation and control (I&C) sy stems. Specifically, this section discusses the electrical and I&C systems and the electrical commodity groups.
In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and 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 focused its review on the
 
implementation results. This focus allowed the staff to confirm that there were no omissions of
 
electrical and I&C system components meeting the scoping criteria and subject to an AMR.
Staff Evaluation Methodology. The staff's evaluation of the information provided in the LRA was the same for all electrical and I&C systems. The objective was to determine whether the
 
components and supporting structures for a specific system or commodity group, that appeared to meet the scoping criteria specified in the Rule, had been identified by the applicant as within the
 
scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the
 
applicant's screening results to verify that all long-lived, passive components were subject to an
 
AMR in accordance with 10 CFR 54.21(a)(1).
Scoping. For its evaluation, the staff reviewed the applicable LRA sections and associated component drawings, focusing its review on components that had not been identified as within the
 
scope of license renewal. The staff reviewed relevant licensing basis documents, including the
 
UFSAR, for each system and commodity group to determine whether the applicant had omitted 2-180 components with intended functions under 10 CFR 54.4(a) from the scope of license renewal.
The staff also reviewed the licensing basis documents to determine whether all intended functions
 
under 10 CFR 54.4(a) were specified in the LRA. If omissions were identified, the staff requested
 
additional information to resolve them.
Screening. After completing its review of the scoping results, the staff evaluated the applicant's screening results. For those SCs with intended functions, the staff sought to determine whether
 
(1) the functions are performed with moving parts or a change in configuration or properties, or (2)
 
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 SCs 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.2.5.1  Summary of Technical Information in the Application 2.5.1.1  Electrical Systems In LRA Section 2.5.1, the applicant described the electrical and I&C systems. The electrical systems include the following:
* 120/208V non-essential distribution system
* 120V AC vital power system
* 125V station DC system
* 24/48V instrument power DC system
* 4160V AC system
* 480/208/120V utility (JCP&L) non-vital power
* 480V AC system
* alternate rod injection system
* grounding and lightning protection system
* intermediate range monitoring system
* lighting system
* local power range monitoring syst em and average power range monitoring system
* offsite power system
* post-accident monitoring system
* radio communications system
* reactor overfill protection system
* reactor protection system
* remote shutdown system
* SBO system The electrical systems contain safety-related components relied upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in the electrical systems potentially
 
could prevent the satisfactory accomplishment of a safety-related function. In addition, the
 
electrical systems perform functions that support fire protection, ATWS, SBO, and EQ.
120/208V Non-Essential Distribution System. The 120/208V non-essential electrical distribution system receives power from 460V motor cont rol centers and 460V distribution panels through dry-type transformers. The system is designed to provide nonessential power to the various nonsafety-related and auxiliary plant loads. Addi tional detail of the system is in UFSAR Section 8.3.1.1.3.
2-181 This system is within the scope of license renewal because it (a) resists nonsafety-related SSC failures that could prevent satisfactory accomp lishment of a safety-related function (this system provides electrical power to a control room ventilation fan) and (b) is relied upon in safety
 
analyses or plant evaluations to perform a function for compliance with fire protection and SBO
 
regulations.
120V AC Vital Power System. The 120V AC vital power system is a Class 1E safety-related electrical distribution system that supplies 120V AC power to various loads essential for
 
operation, protection, and safe shutdown of the plant. The system design incorporates redundant
 
power sources and automatic bus transfer switches so that critical loads remain energized at all
 
times. Additional detail of the system is in UFSAR Section 8.3.1.1.4.
This system is within the scope of license renewal because it (a) provides motive power to safety-related components and (b) is relied upon in safety analyses or plant evaluations to
 
perform a function for compliance with fire protection, EQ, and SBO regulations.
125V Station DC System. Three complete 125V DC distribution systems make up the station DC power system at OCGS. Two of these, designat ed as DC Distribution Systems A and B, are the originally installed systems. The third system , designated as DC Distribution System C, was designed and installed as a modification.
The function of the station DC system is to provide a continuous source of 125V DC power.
Safety loads are supplied from DC Distribution Systems B and C with DC Distribution System B supplying Division B safety-related loads and DC Distribution System C supplying Division A safety-related loads. DC Distribution System A supplies nonsafety loads. Additional detail of the
 
system is in UFSAR Section 8.3.2.1.
This system is within the scope of license renewal because it (a) provides motive power to safety-related components and (b) is relied upon in safety analyses or plant evaluations to
 
perform a function for compliance with fire protection, EQ, and SBO regulations.
24/48V Instrumentation Power DC System. The 24/48V DC power electrical distribution system is designed to supply power to the reactor nuclear instrumentation and radiation monitoring
 
systems. Additional detail of the system is in UFSAR Section 8.3.2.2.
This system is within the scope of license renewal because provides motive power to safety-related components.
4160V System. The 4160V electrical distribution system is designed to provide continuous electrical power necessary for plant operation, startup, and shutdown. The 4160V switchgear is
 
comprised of four separate bus sections or lineups of switchgear. The four bus sections are
 
identified as Bus Sections 1A, 1B, 1C, and 1D with Bus Sections 1C and 1D the essential or
 
emergency switchgear lineups.
The 4160V AC system also can be powered from the FRCT, which is the OCGS alternate AC (AAC) power source during an SBO event. The AAC source utilizes a connection independent
 
from the normal connection to the regional transmission grid. The routing is through a dedicated
 
underground ductbank to the load break switches and SBO transformer located on site and then
 
through a cable trench to the switchgear breaker connection to the 4160V AC Bus 1B. Additional
 
detail of the system is in UFSAR Section 8.3.1.1.1.
2-182 This system is within the scope of license renewal because it (a) provides motive power to safety-related components and (b) is relied upon in safety analyses or plant evaluations to
 
perform a function for compliance with fire protection and SBO regulations.
480/208/120V Utility (JCP&L) Non-Vital Power System. The 480/208/120V utility (JCP&L) nonvital power electrical distribution system is des igned to provide nonessential electrical power necessary for balance of plant equipment located throughout the site. Additional detail of the
 
system is in UFSAR Section 8.2.1.2.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with fire protection regulations.
480V AC System. The 480V AC electrical distribution system is designed to provide continuous electrical power necessary for plant operation, startup, and shutdown. Additional detail of the
 
system is in UFSAR Section 8.3.1.1.2.
This system is within the scope of license renewal because it (a) provides motive power to safety-related components and (b) is relied upon in safety analyses or plant evaluations to
 
perform a function for compliance with fire protection, EQ, and SBO regulations.
Alternate Rod Injection System. The alternate rod injection electrical system provides a method diverse from the reactor protection system (RPS) for depressurizing the instrument (control) air system scram air header in the unlikely event the RPS does not cause a reactor scram in response to an operational transient. Additional detail of the system is in UFSAR Section 3.9.4.4.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with ATWS regulations.
Grounding and Lightning Protection System. The plant grounding and lightning protection electrical system is designed to provide a low-impedance path to ground for fault currents and
 
lightning strokes.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with fire protection regulations.
Intermediate Range Monitoring System. The intermediate range monitoring electrical instrumentation and logic system is designed to m onitor the neutron flux and power in the reactor core and to provide automatic core protec tion. The intermediate range monitoring system generates annunciator alarms, rod blocks, and scram signals for nuclear instrumentation
 
degraded operation and downscale or upscale conditions. Additional detail of the system is in
 
UFSAR Section 7.5.1.8.4.
This system is within the scope of license renewal because it senses process conditions and generates signals for a reactor trip or an ESF actuation.
Lighting System. The lighting system is comprised of the normal lighting and convenience system (outdoor area lighting, general plant lighting, office building lighting), emergency lighting, and
 
security lighting. Additional detail of the system is in UFSAR Section 9.5.3.
2-183 This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with fire protection and SBO regulations.
Local Power Range Monitoring System and Average Power Range Monitoring System. The local power range and average power range monitoring elec trical instrumentation and logic systems are designed to monitor the neutron flux and power in the reactor core and to provide automatic core protection. Additional detail of the system is in UFSAR Section 7.5.1.8.6.
This system is within the scope of license renewal because it senses process conditions and generates signals for a reactor trip or an ESF actuation.
Offsite Power System. The offsite power electrical distribution system is designed to connect OCGS to the offsite electrical transmission syst em. The purpose of the offsite power system is to connect to the output of the generator and to provide redundant sources of power to the plant
 
when the main generator is offline. It accomplishes this purpose with a 230 kV substation and a
 
connected 34.5 kV substation in a switchyard adjacent to the plant. Additional detail of the system
 
is in UFSAR Section 8.2.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with fire protection and SBO regulations.
Post-Accident Monitoring System. The purpose of the post-accident electrical monitoring system is to display and record plant parameters of drywell radiation and pressure levels, torus level, and
 
temperature and safety/relief valve flow det ection during and following a LOCA. The system is comprised of containment high-range radiation monitors, safety valve and relief valve accident
 
monitoring instrumentation, suppression pool temperature and water level monitors, and
 
containment pressure indicators. Additional detail of the system is in UFSAR Sections 5.2.2.4.2.2, 7.6.1.4, and 11.5.2.13.
This system is within the scope of license renewal because it (a) senses process conditions and generates signals for a reactor trip or an ESF actuation and (b) is relied upon in safety analyses
 
or plant evaluations to perform a function for compliance with fire protection and EQ regulations.
Radio Communications System. The radio communications electrical system is designed to provide two-way voice communication between personnel operating safe shutdown equipment
 
during a fire emergency and SBO. The radio communica tions system is comprised of primary and installed spare base station transmitter-repeaters in the upper cable spreading room, portable
 
radio units with batteries and chargers in the control room, and antennae with associated cabling
 
at selected locations in the reactor building and turbine building. Electrical power for the primary
 
base station transmitter and repeater is supplied from the 120V AC vital power system.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with fire protection and SBO regulations.
Reactor Overfill Protection System. The reactor overfill protection electrical instrumentation and logic system minimizes the potential for overfilling the reactor to the elevation of the main steam
 
lines. Additional detail of the system is in UFSAR Section 7.7.1.6.
This system is within the scope of license renewal because failure of its components could adversely affect the safety-related RPS.
2-184 Reactor Protection System. The RPS is an electrical logic system designed to furnish signals to trip the reactor and to initiate certain ESF systems. Additional detail of the system is in UFSAR
 
Section 7.2.
This system is within the scope of license renewal because it (a) senses process conditions and generates signals for a reactor trip or an ESF actuation and (b) is relied upon in safety analyses
 
or plant evaluations to perform a function for compliance with fire protection regulations.
Remote Shutdown System. The remote shutdown system enables operators to achieve and maintain hot and cold shutdown whenever necessa ry to evacuate the control room. The remote shutdown system is comprised of a remote shutdown panel and several local shutdown panels
 
outside the control room. Additional detail of the system is in UFSAR Sections 9.5.1 and 3.1.15.
This system is within the scope of license renewal because it (a) senses process conditions and generates signals for a reactor trip or an ESF actuation and (b) is relied upon in safety analyses
 
or plant evaluations to perform a function for compliance with fire protection, EQ, and SBO
 
regulations.
Station Blackout System. The SBO electrical supply system provides AAC power for the regulated event of loss of all AC power. The source of el ectrical power to the SBO system is the FRCT station, an electrical power plant owned, operated, and maintained by FirstEnergy and designed
 
for peak loading to the grid. Additional detail of the system is in UFSAR Section 8.3.4.
This system is within the scope of license renewal because it is relied upon in safety analyses or plant evaluations to perform a function for compliance with SBO regulations.
2.5.1.2  Electrical Commodity Groups In LRA Section 2.5.2.5, the applicant described the electrical commodity groups subject to an AMR. The screening process for electrical components used plant documentation to identify the
 
electrical component types within the electrical, mechanical, and civil or structural systems based on plant design documentation, drawings, the CRL, and interface with the parallel mechanical and
 
civil screening efforts. These component types were grouped into a smaller set of electrical
 
commodity groups identified from a review of NEI 95-10 Appendix B, the GALL Report, and
 
information from previous LRAs.
The intended functions within the scope of license renewal include:
* provides electrical connections to s pecified sections of an electrical circuit
* provides insulation and support for an electric conductor
* provides pressure-retaining boundary; fission product barrier; containment isolation
* provides structural support or structural integrity to preclude nonsafety-related component interactions that could prevent satisfactory accomplishment of a safety-related function In LRA Table 2.5.2, the applicant identified the following electrical commodity group component types within the scope of license renewal and subject to an AMR:
* cable connections (metallic parts)
* electrical penetrations 2-185
* fuse holders
* high-voltage insulators
* insulated cables and connections
* insulated cables and connections in instrumentation circuits
* insulated inaccessible medium-voltage cables
* transmission conductors and connections
* uninsulated ground conductors
* wooden utility poles The phase bus in the main generator and auxiliaries system and the switchyard bus were not included within the AMRs because they perform no license renewal intended function. The phase
 
bus is further discussed in SER Section 2.5.3.
The commodity groups were screened by 10 CFR 54.21(a)(1)(ii) criteria that allow the exclusion of component commodity groups subject to replacement based on a qualified life or specified time
 
period. The only electrical components excluded by the 10 CFR 54.21(a)(1)(ii) criteria are
 
included in the Environmental Qualification Program because they are replaced prior to the
 
expiration of their defined qualified lives. No electrical components within the Environmental
 
Qualification Program are subject to an AMR by 10 CFR 54.21(a)(1)(ii) screening criteria.
 
Therefore, the electrical components in the Environmental Qualification Program were screened
 
out.The remaining commodity groups, some or all of which are not in the Environmental Qualification Program, are within the scope of license renewal and require an AMR. In the LRA, the following
 
commodity groups are discussed:  (1)Insulated Cables and Connections - The insulated cables and connections commodity group was broken down for an AMR of insulation into subcategories based on their
 
treatment in the GALL Report:
* insulated cables and connections
* insulated cables and connections in instrumentation circuits
* insulated inaccessible medium-voltage cables The types of insulated connections included in this review are splices, connectors, and terminal blocks. Fuse holders were reviewed separately.    (2)Electrical Penetrations - The electrical portions of those electrical penetrations not included in the Environmental Qualification Program meet the 10 CFR 54.21(a)(1)(ii)
 
screening criterion and are subject to an AMR. The electrical insulation within the
 
penetration assembly and the epoxy potting compound that provides the sealing function
 
were reviewed. Insulated cable pigtails are considered part of the insulated cables and
 
connectors commodity group. Metallic portions of the electrical penetrations are
 
considered part of the primary containment structure.  (3)High Voltage Insulators - High-voltage insulators are on the circuits supplying power from the switchyard to plant buses during recovery from an SBO or fire protection event. The
 
high-voltage insulators meet the 10 CFR 54.21(a)(1)(ii) screening criterion and are subject
 
to an AMR.
2-186  (4)Transmission Conductors and Connections - Transmission conductors that provide a portion of the circuits supplying power from the switchyard to plant buses during recovery
 
from an SBO or fire protection event meet the 10 CFR 54.21(a)(1)(ii) screening criterion
 
and are subject to an aging management review.  (5)Fuse Holders - Both the metallic and nonmetallic portions of fuse holders not included in the Environmental Qualification Program meet the 10 CFR 54.21(a)(1)(ii) screening
 
criterion and are subject to an AMR.    (6)Wooden Utility Poles - Wooden utility poles did not fit within an existing electrical commodity group; therefore, a separate commodity group was created. Utility poles
 
provide structural support for transmission conductors, high-voltage insulators, and other
 
active electrical components supplying power from the switchyard to plant buses during
 
recovery from an SBO or fire protection event. The wooden utility poles meet the
 
10 CFR 54.21(a)(1)(ii) screening criterion and are subject to an AMR.  (7)Cable Connections (Metallic Parts) - The cable connections commodity group includes the metallic portions of cable connections not included in the Environmental Qualification
 
Program. The metallic connections evaluated include splices, threaded connectors, compression type termination lugs, and terminal blocks.  (8)Uninsulated Ground Conductors - The uninsulated ground conductors commodity group is comprised of grounding cable and connectors.
The components which support or interface with electrical components (e.g., cable trays, conduits, instrument racks, panels, and enclosures) are assessed as part of the structural
 
component support commodity group in LRA Section 2.4.18.
 
====2.5.2 Staff====
Evaluation The staff reviewed LRA Section 2.5 and the UFSAR using the evaluation methodology of SER Section 2.5. The staff conducted its review in accordance with the guidance of SRP-LR
 
Section 2.5.
In conducting its review, the staff evaluated the system functions described in the LRA and UFSAR to verify that the applicant had not omitted from the scope of license renewal any
 
components with intended functions under 10 CFR 54.4(a). The staff then reviewed those
 
components that the applicant had identified as within the scope of license renewal to verify that
 
the applicant had not omitted any passive and long-lived components subject to an AMR in
 
accordance with 10 CFR 54.21(a)(1).
The staff's review of LRA Section 2.5 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 2.5.1.19-1 dated September 28 2005, the staff stated that the combustion turbine power plant was determined to be within the scope of license renewal. The staff requested that the
 
applicant evaluate the long-lived passive components of the combustion turbine power plant and
 
any AMPs and AMRs related to those components in the same format and depth as used in the
 
diesel generator section of the LRA.
2-187 In its response dated October 12, 2005, the applicant stated:
AmerGen has taken a more detailed approach to scoping, screening, aging management reviews and aging management programs, for long-lived passive components, than was previously presented in the Oyster Creek License Renewal Application submittal for the Oyster Creek Station Blackout System, Combustion
 
Turbine Power Plant.
In addition, the applicant revised Commitment Nos. 31 and 36. Furthermore, Commitment No. 43,"Periodic Monitoring of Combustion Turbine - Electrical," was completely modified as follows:
A new plant specific program, 'Periodic Monitoring of Combustion Turbine Power Plant - Electrical' is credited. The program will be used in conjunction with the
 
existing 'Structures Monitoring Progr am' and the new 'Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.59 Environmental Qualification
 
Requirements Program', to manage the aging effects for the electrical commodities
 
that support Forked River Combustion Turbine (FRCT) operation. The Program
 
consists of visual inspections of a ccessible electrical cables and connections exposed in enclosures, pits, manholes and pipe trench; visual inspection for water
 
collection in manholes, pits, and trenches, located on the FRCT site, for
 
inaccessible medium voltage cables; and visual inspection of accessible phase bus
 
and connections and phase bus insulators/supports. The new program will be
 
performed on a 2-year interval for manhol e, pit and trench inspections, on a 5-year interval for phase bus inspections, and on a 10-year interval for cable and
 
connection inspections.
In Appendix B of this letter, the applicant described the scoping system in more detail, correlating to LRA Section 2.5.1.19, "Station Blackout," for scoping and screening results. Sixteen subsystem
 
descriptions (e.g., fuel oil system, combustion turbine inlet and exhaust system, cooling water system), combustion turbine structure and elec trical commodity descriptions, and associated system boundary details have been added to the scoping information. The applicant stated that
 
the expanded information is consistent with such other LRA system information as the EDGs.
The applicant identified and described the followi ng SBO system electrical commodity groups subject to AMR in Section 2.5.2A.5 of its letter:*cable connections (metallic parts)(Section 2.5.2A.5.1)*high-voltage insulators (Section 2.5.2A.5.2)
*insulated cables and connections(Section 2.5.2A.5.3)
*phase bus(Section 2.5.2A.5.4)
*transmission conductors and connections(Section 2.5.2A.5.4)
*uninsulated ground conductors(Section 2.5.2A.5.5)
The staff reviewed the applicant's response following the guidance of SRP-LR, Section 2.5. The staff agreed that the electrical commodities groups in the SBO recovery path consisting of passive
 
long-lived components subject to AMR are in accordance with 10 CFR 54.21(a)(1).
In RAI 2.5.2-1 dated March 20, 2006, the staff noted that LRA Section 2.5.2.5 describes electrical commodity groups subject to an AMR. The staff requested that the applicant confirm that, in
 
addition to power circuits in the electrical systems, the control circuits also had been considered in 2-188 the scoping and screening review and included in the electrical commodity groups subject to AMR.In its response dated April 18, 2006, the applicant clarified that both power and control circuits had been considered in the scoping, screening, AMR, and AMP processes for the electrical
 
commodity groups.
In RAI 2.5.2.3-1 dated March 20, 2006, the staff noted that in LRA Section 2.5.2.3 the first bullet states: "Phase Bus exist only in the Main Gener ator and Auxiliaries System. The system has no electrical intended functions and is within the scope for 10 CFR 54.4(a)(2) systems interaction
 
only. Because the phase bus contains no fluid, it has no license renewal intended functions."
The staff requested that the applicant address the following as to that statement:
* Provide a cross-reference to the phase bus in the SBO path.
* Confirm whether the phase bus (in the main generator and auxiliaries system) provides interactions for 10 CFR 54.4(a)(2) systems. If yes, list the 10 CFR 54.4(a)(2) systems. If
 
10 CFR 54.4(a)(2) applies to this phase bus, explain why it is not included as an electrical
 
commodity group subject to an AMR.
* Explain the statement: "Because the phase bus contains no fluid,it has no license renewal intended functions."
In its response dated April 18, 2006, the applicant stated that as part of the October 12, 2005, response to RAI 2.5.1.19-1 the phase bus was determined to be within the scope of license
 
renewal as an electrical commodity group for the FRCT station. Drawing LR-BR-3000 shows the
 
FRCT station phase bus circuits from the FRCT generators to breakers 52G-1 and 52G-2 and
 
subsequently to breakers 52G-1N and 52G-2N.
The applicant also clarified that the phase bus (in the main generator and auxiliaries system) provides no interactions for 10 CFR 54.4(a
)(2) systems. Nonsafety-related systems and components containing water, oil, or steam located in the vicinity of safety-related SSCs are
 
included within the scope of license renewal for potential spatial interaction under
 
10 CFR 54.4(a)(2). The phase bus in the main generator and auxiliary systems has no water, steam, or oil pressure boundary and therefore is not within the scope of license renewal for
 
potential spatial interaction.
In RAI 2.5.2.3-2, dated March 20, 2006, the staff noted that in LRA Section 2.5.2.3 the second bullet states: "Switchyard Bus was eliminated because none perform a license renewal intended
 
function. Rather, transmission conductors, high voltage insulators and insulated cables and
 
connectors perform the functions of providing offsite power to cope with and recover from
 
regulated events."
The staff requested that the applicant address the following as to that statement:
* List (with reference to drawing LR-BR-3000) the circuits that may contain transmission conductors, high-voltage insulators, and insulated cables and connectors that provide
 
offsite power to cope with and recover from regulated events.
* List the regulated events.
 
2-189 In its response dated April 18, 2006, the applicant clarified that the transmission conductors, high-voltage insulators, and insulated cables and connectors are parts of the following circuits shown
 
on drawing LR-BR-3000:
* 34.5 kV feeds from the "B" bus of the 34.5 kV substation to transformers XMR-732-16 andXMR-732-15 via circuit breakers R144 and J69361, respectively.
* 34.5 kV feed from the 34.5 kV substation to start-up transformer SA via circuit breaker BK5.
* 34.5 kV feed from the 34.5 kV substation to startup transformer SB via circuit breaker BK6.
* 230 kV feeds from the 230 kV substation bank 9 and bank 10 circuit disconnect switches to bank 9 and bank 10 transformers, respectively. These feeds are in support of the AAC
 
power supply credited for SBO.
The applicant stated that the transmission conductors, high-voltage insulators, and insulated cables and connectors meet 10 CFR 54.4(a)(3) because they are relied upon in safety analyses
 
and plant evaluations to perform a function for compliance with fire protection and SBO
 
regulations. In this discussion, "transmission conductors" refers to uninsulated high-voltage
 
transmission cables, not the bus bar.
In RAIs 2.5.2.5-1 and 2.5.2.5-2 dated March 20, 2006, the staff noted that LRA Section 2.5.2.5.3 states that high-voltage insulators are on the circuits supplying power from the switchyard to plant
 
buses during recovery from a SBO or fire protection event. The staff requested that the applicant
 
describe the circuit path (which may contain the high-voltage insulators) relied upon to supply
 
power from the switchyard to plant buses in fire protection events.
In addition, the staff noted that LRA Section 2.5.2.5.4 states that the transmission conductors are a portion of the circuits supplying power from the switchyard to plant buses during recovery from
 
an SBO or fire protection event. The staff requested that the applicant describe the circuit path (which may contain transmission conductors) relied upon to supply power from the switchyard to
 
plant buses in fire protection events.
In its response dated April 18, 2006, the applicant stated:
Offsite power from the 34.5 kV switchyard that feeds Oyster Creek station 4160V buses 1 A and 1 B, via the start-up transformers SA and SB, respectively, is
 
credited in support of post-fire safe shutdown at Oyster Creek. Offsite power from the 34.5 kV switchyard to transformers XMR-732-15 and XMR-732-16 is credited in
 
support of power to the redundant fire pump house. These circuits are shown on
 
License Renewal Drawing LR-BR-3000, and are detailed as follows:
* 34.5 kV feeds from the "B" bus of the 34.5 kV substation to transformersXMR-732-16 and XMR-732-15 via circuit breakers R144 and J69361, respectively.
* 34.5 kV feed from the 34.5 kV substation to start-up transformer SA via circuit breaker BK5.
* 34.5 kV feed from the 34.5 kV substation to startup transformer SB via circuit breaker BK6.
2-190 The staff agrees that the applicant responses dated October 12, 2005, and April 18, 2006, has adequately addressed the staff concerns and had not omitted any passive, long-lived components
 
subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff's concerns described in RAIs
 
2.5.1.19-1, 2.5.2-1, 2.5.3-1, 2.5.3-2, 2.5.2.5-1, and 2.5.2.5-2 are resolved.
 
====2.5.3 Conclusion====
 
The staff reviewed the LRA, the UFSAR, and RAI responses to determine whether any SSCs within the scope of license renewal had not been identified by the applicant. No omissions were
 
identified. In addition, the staff determined whether any components subject to an AMR had not
 
been identified by the applicant. No omissions were identified. The staff's review concluded that
 
there is reasonable assurance that the applicant has adequately identified the electrical
 
commodity group components within the scope of license renewal, as required by
 
10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
 
===2.6 Conclusion===
for Scoping and Screening The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for
 
Identifying Structures and Components Subject to Aging Management Review, and
 
Implementation Results." The staff determined that the applicant's scoping and screening
 
methodology is consistent with 10 CFR 54.21(a)(1) requirements and the staff's position on the
 
treatment of safety-related and nonsafety-related SSCs within the scope of license renewal and
 
that the SCs requiring an AMR is 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 systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), and those
 
subject to an AMR, as required by 10 CFR 54.21(a)(1).
The staff's review concludes that there is reasonable assurance 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, in order to comply with 10 CFR 54.29(a), with the Atomic Energy Act of 1954, as amended, and with NRC regulations.
THIS PAGE IS INTENTIONALLY LEFT BLANK.
3-1 SECTION 3 AGING MANAGEMENT REVIEW RESULTS This section of the safety evaluation report (SER) contains the evaluation of aging management programs (AMPs) and aging management reviews (AMR s) for Oyster Creek Generating Station (OCGS) by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff).
 
In Appendix B of its license renewal applicat ion (LRA), AmerGen Energy Company, LLC, (AmerGen or the applicant) described the 56 AMPs that it relies on to manage or monitor the
 
aging of long-lived, passive 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 draft NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," dated January 2005. The use of the draft January 2005 GALL Report (draft GALL
 
Report) is in accordance with the January 13, 2005, meeting between the NRC and Nuclear
 
Energy Institute (NEI) on updating license renewal guidance documents, as summarized and
 
documented in a meeting summary dated February 17, 2005 (ADAMS Accession Number
 
ML050490142). 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 they should be augmented for the period of extended
 
operation. The evaluation results documented in the GALL Report indicate that many of the
 
existing programs are adequate to manage the aging effects for particular license renewal SCs
 
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 Report.
In AmerGen letter dated March 30, 2006, (ML060950408), the applicant summarized the results of its reconciliation of the LRA with the guidance in NUREG-1800, "Standard Review Plan for
 
Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR), Revision 1, and
 
GALL Report, Revision 1, both dated September 2005. The applicant provided details of this
 
reconciliation in its document, "Reconciliation of Program and Line Item Differences Between
 
January 2005 Draft NUREG-1801 and September 2005 Revision 1 NUREG-1801, Revision 1,"
 
dated March 24, 2006. In its reconciliation document, the applicant identified differences between
 
the draft GALL Report AMPs and AMR line items used in the LRA with those in the GALL Report
 
Revision 1. This reconciliation document was reviewed by the staff and treated as a supplement
 
to the LRA.
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 the 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 3-2 identify AMPs and activities that the staff has determined will adequately manage or monitor aging during the period of extended operation.
The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects associated with the
 
materials and environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain
 
component types.
To determine whether using the GALL Report would improve the efficiency of the license renewal review, the staff conducted a demonstration project to test the GALL Report process and to
 
determine the format and content of a safety evaluation based on it. The results of the
 
demonstration project confirmed that the GALL Report process will improve the efficiency and effectiveness of the LRA review and maintain the staff's focus on public health and safety.
 
SRP-LR Revision 1 dated September 2005 was prepared based on both the GALL Report model
 
and lessons learned from the demonstration project.
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 of the SRP-LR, and the guidance of 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 October 3-7, 2005, January 23-27, 2006, February 13-17, 2006, and April 19-20, 2006. The staff documented the results of its audit and
 
review in "Audit and Review Report for Plant Aging Management Reviews and Programs, Oyster Creek Generating Station (OCGS)" (Audit and Review Report) dated May 9, 2006 (ADAMS
 
Accession Number ML062280051). The onsite audits and reviews are designed to maximize the
 
efficiency of the staff's review of the LRA. The applicant can respond to questions and the staff
 
can readily evaluate the applicant's responses. As a result, the need for formal correspondence
 
between the staff and the applicant is reduced, and the result is an improvement in the review's
 
efficiency.3.0.1  Format of the License Renewal Application The applicant submitted an application that follows the standard LRA format, as agreed to between the staff and the NEI, by letter dated April 7, 2003 (ML030990052). This revised LRA
 
format incorporates lessons learned from t he staff's reviews of the previous LRAs.
The organization of LRA Section 3 parallels SRP-LR Chapter 3. The AMR results in LRA Section 3 are presented in the following two table types:
* Table 1s: Table 3.x.1 - where "3" indicates the LRA section number, "x" indicates the subsection number from the GALL Report, and "1" indicates the first table type in LRA
 
Section 3.
* Table 2s: Table 3.x.2.1.y - where "3" indicates the LRA section number; "x" indicates the subsection number from the GALL Report; "2" indicates the second table type in LRA
 
Section 3; "1" indicates the summary subsection for materials, environments, aging
 
effects, and AMPs; and "y" indicates the system table number.
3-3 In its Table 1s the applicant summarized the portions of the application that it considered to be consistent with the GALL Report. In its Table 2s the applicant identified the linkage between the
 
scoping and screening results in LRA Section 2 and the AMRs in LRA Section 3.
3.0.1.1  Overview of Table 1 Each Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the corresponding tables in the GALL Report. The tables are essentially the same as Tables 1
 
through 6 in the GALL Report, except that the "ID" column has been deleted, 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 "Item Number" column provides
 
the staff reviewer with a means to cross-reference Table 2s with Table 1s. The "Discussion"
 
column is used by the applicant to provide clar ifying information. The following are examples of information that might be in this column:
* further evaluation recommended - information or reference to where that information is located
* the name of a plant-specific program used
* exceptions to GALL Report assumptions
* a discussion of how the line is consistent with the corresponding line item in the GALL Report when it may not be intuitively obvious
* a discussion of how the item is different from the corresponding line item in the GALL Report (e.g., when there is exception taken to a GALL AMP)
The format of each Table 1 allows the staff to align a specific row in the table with the corresponding GALL Report table row so that the consistency can be easily checked. It should be
 
noted that, since the LRA was prepared based on the draft January 2005 version of the GALL
 
Report, there is not always a one-to-one correspondence between the LRA Table 1 line items and
 
the line items in the September 2005 Revision 1 of the GALL Report, which was used as the
 
basis for this safety evaluation.
3.0.1.2  Overview of Table 2 Each Table 3.x.2.1.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 structures within a specific system grouping (e.g., reactor coolant systems, engineered safety features, auxiliary systems, etc.). For example, the engineered safety features group contains tables specific to the core spray system, high pressure coolant injection system, and residual heat removal system. Each Table 2 consists of the following nine columns:  (1)Component Type - The first column identifies the component types from LRA Section 2 that are subject to an AMR. The component types are listed in alphabetical order.  (2)Intended Function - The second column identifies the license renewal intended functions for the listed component types. Definitions of intended functions are contained within LRA
 
Table 2.1-1.  (3)Material - The third column lists the particular construction materials for the component type.
3-4  (4)Environment - The fourth column lists the environment to which the component types are exposed. Internal and external service env ironments are indicated and a list of these environments is provided in LRA Tables 3.0-1 and 3.0-2, respectively.  (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 uses to manage the identified aging effects.  (7)NUREG-1801 Vol. 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 LRA
 
Table 2 with the items in the GALL Report. If there were no corresponding items in the
 
GALL Report, the applicant left the column blank. In this way, the applicant identified in the
 
LRA tables AMR results that correspond to the items in the GALL Report tables.  (8)Table 1 Item - The eighth column lists the corresponding summary item number from LRA Table 1. If the applicant identified in each LRA Table 2 AMR results consistent with the
 
GALL Report, then the associated Table 1 line item summary number should be listed in
 
LRA Table 2. If there is no corresponding item in the GALL Report, column eight is left
 
blank. In this manner, the information from the two tables can be correlated.  (9)Notes - The ninth column lists the corresponding notes that the applicant used to identify how the information in each Table 2 aligns with the information in the GALL Report. The
 
notes are identified by letters and were developed by an NEI work group. These notes 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 with the GALL
 
Report.  (2)For items that the applicant stated were consistent with the GALL Report with exception(s) and/or enhancement(s), 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 justifications for the exceptions
 
and of the adequacy of the enhancements.
The SRP-LR states that an applicant may take one or more exceptions to specific GALL AMPs program elements. However, any devia tion or exception to the GALL AMP should be described and justified. Therefore, the staff considers exceptions as portions of the
 
GALL AMP that the applicant does not intend to implement.
In some cases, an applicant may choose an existing plant program that does not meet all the program elements defined in the GALL AMP. However, the applicant may make a
 
commitment to augment the existing program to satisfy the GALL AMP prior to the period
 
of extended operation. Therefore, the staff considers these revisions or additions to be
 
enhancements. Enhancements include, but are not limited to, those activities needed to 3-5 ensure consistency with the GALL Report recommendations. Enhancements may expand, but not reduce, the scope of an AMP.  (3)For other items, the staff conducted a technical review to determine whether the applicant conforms with the requirements in 10 CFR 54.21(a)(3).
The staff performed audits and technical reviews of the applicant's AMPs and AMRs. These audits and technical reviews determined whether the aging effects on SCs can be adequately
 
managed so that their intended function(s) 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.
 
Detailed results of the staff's onsite audit and review are documented in the Audit and Review
 
Report.3.0.2.1  Review of AMPs For those AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conducted either an audit or a technical review to verify consistency of the applicant's AMPs with the GALL AMPs. For each AMP with one or more deviations, the staff evaluated each deviation to
 
determine whether it was acceptable and whether the AMP, as modified, would adequately
 
manage the aging effect(s) for which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs
 
against the following 10 program elements defined in SRP-LR, Appendix A.  (1)Scope of the Program - Scope of the program should include the specific SCs subject to an AMR for license renewal.  (2)Preventive Actions - Preventive acti ons should prevent or mitigate aging degradation.  (3)Parameters Monitored or Inspected - Parameters monitored or inspected should be linked to the degradation of the particular structure or component intended function(s).  (4)Detection of Aging Effects - Detection of aging effects should occur before there is a loss of structure or component intended function(s). Such detection includes method or
 
technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data
 
collection, and timing of new/one-time inspections to ensure timely detection of aging
 
effects.  (5)Monitoring and Trending - Monitoring and trending should provide predictability of the extent of degradation as well as timely corrective or mitigative actions.  (6)Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended 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 corrective actions have been completed and are effective.  (9)Administrative Controls - Administrative controls should provide a formal review and approval process.  (10)Operating Experience - Operating ex perience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide 3-6 objective evidence for the conclusion that the effects of aging will be adequately managed so that the SC intended function will be maintained during the period of extended
 
operation.
Details of the staff's audit evaluation of program elements (1) through (6) are documented in the Audit and Review Report and summarized in SER Section 3.0.3.
The staff reviewed the applicant's Quality Assurance Program and documented its evaluations in SER Section 3.0.4. The staff's evaluation of the Quality Assurance Program included assessment of the following program elements: (7) corrective actions, (8) confirmation process, and
 
(9) administrative controls.
The staff reviewed the information concerning the operating experience program element (10) and documented its evaluation in the Audit and Review Report. The staff also included a
 
summary of the program in SER Section 3.0.3.3.0.2.2  Review of AMR Results Each LRA Table 2 contains information on whether the AMRs correlate with the AMRs of the GALL Report. For AMRs in a Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a par ticular component type within a system. The AMRs that correlate between a combination in a Table 2 and a combination in the GALL Report
 
were identified by a referenced item number in column seven, "NUREG-1801 Vol. 2 Item." The
 
staff also conducted onsite audits to verify the correlations. A blank column seven indicates that
 
the applicant was unable to locate an appropriate correlating combination in the GALL Report.
 
The staff conducted a technical review of these combinations inconsistent with the GALL Report.
 
The next column, "Table 1 Item," provides a reference number indicating the correlating 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, which summarizes the applicant's programs and activities for
 
managing aging effects for the period of extended operation as required by 10 CFR 54.21(d).
3.0.2.4  Documentation and Documents Reviewed In its review the staff used the LRA, LRA supplements, OCGS reconciliation document, SRP-LR, and the GALL Report.
During the onsite audit, the staff examined the applicant's justifications, as documented in the Audit and Review Report, to verify that the applicant's activities and programs will adequately
 
manage aging effects 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, provided below, presents the AMPs that the applicant takes credit for to manage aging in the listed SCCs and whether they are consistent with the GALL Report. The 3-7 table also indicates the SER section in which the staff's evaluation is documented.
Table 3.0.3-1  OCGS Aging Management ProgramsOCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER SectionExisting AMPsASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)Consistent with exceptions and
 
enhancementsXI.M1reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems; steam and power conversion system 3.0.3.2.1 Water Chemistry (B.1.2)Consistent with exceptionsXI.M2reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems; steam and power conversion system; containment, structures, component
 
supports, and piping and
 
component insulation 3.0.3.2.2 Reactor Head Closure Studs (B.1.3)Consistent with exceptionXI.M3reactor vessel, internals, andreactor coolant systems 3.0.3.2.3 BWR Vessel ID Attachment Welds (B.1.4)Consistent with exceptionsXI.M4reactor vessel, internals, andreactor coolant systems 3.0.3.2.4BWR Feedwater Nozzle (B.1.5)Consistent with exception and
 
enhancementXI.M5reactor vessel, internals, andreactor coolant systems 3.0.3.2.5 BWR Control Rod Drive Return Line Nozzle (B.1.6)Consistent with exceptionsXI.M6reactor vessel, internals, andreactor coolant systems 3.0.3.2.6 BWR Stress Corrosion Cracking (B.1.7)Consistent with exceptionXI.M7reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems 3.0.3.2.7BWR Penetrations (B.1.8)Consistent with exceptionsXI.M8reactor vessel, internals, andreactor coolant systems 3.0.3.2.8 BWR Vessel Internals (B.1.9)Consistent with exceptions and
 
enhancementsXI.M9reactor vessel, internals, andreactor coolant systems 3.0.3.2.9Flow-Accelerated Corrosion (B.1.11)ConsistentXI.M17steam and power conversionsystem 3.0.3.1.2 Bolting Integrity (B.1.12)Consistent with exceptionXI.M18reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems; steam and power conversion system 3.0.3.2.10 OCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-8Open-Cycle CoolingWater System (B.1.13)Consistent with enhancementsXI.M20auxiliary systems 3.0.3.2.11Closed-Cycle CoolingWater System (B.1.14)Consistent with exceptionXI.M21auxiliary systems, steam andpower conversion system 3.0.3.2.12Boraflex Rack Management Program (B.1.15)Consistent with exceptionXI.M22auxiliary systems 3.0.3.2.13 Inspection of OverheadHeavy Load and Light
 
Load (Related to
 
Refueling) Handling Systems (B.1.16)Consistent with exception and
 
enhancementsXI.M23auxiliary systems 3.0.3.2.14 Compressed Air Monitoring (B.1.17)ConsistentXI.M24auxiliary systems 3.0.3.1.3 BWR Reactor WaterCleanup System (B.1.18)Consistent with exceptionXI.M25auxiliary systems 3.0.3.2.15Fire Protection (B.1.19)Consistent with exception and
 
enhancementsXI.M26auxiliary systems 3.0.3.2.16Fire Water System (B.1.20)Consistent with enhancementsXI.M27auxiliary systems 3.0.3.2.17Fuel Oil Chemistry (B.1.22)Consistent with exceptions and
 
enhancementsXI.M30auxiliary systems 3.0.3.2.19 Reactor Vessel Surveillance (B.1.23)Consistent with enhancementXI.M31reactor vessel, internals, andreactor coolant systems 3.0.3.2.20 Buried Piping Inspection (B.1.26)Consistent with exception and
 
enhancementXI.M34ESFs; auxiliary systems;steam and power conversion system 3.0.3.2.21ASME Section XI,Subsection IWE (B.1.27)Consistent with exceptionXI.S1auxiliary systems; containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.2.22ASME Section XI,Subsection IWF (B.1.28)Consistent with exception and
 
enhancementsXI.S3containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.2.23 OCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-910 CFR Part 50, Appendix J (B.1.29)ConsistentXI.S4auxiliary systems; containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.1.6Masonry Wall Program (B.1.30)ConsistentXI.S5containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.1.7 Structures Monitoring Program (B.1.31)Consistent with enhancementsXI.S6reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems; steam and power conversion system; containment, structures, component
 
supports, and piping and
 
component insulation FRCT Mechanical Systems FRCT Electrical Systems FRCT Structural Systems Met Tower Structural Systems Radio Com. System 3.0.3.2.24 RG 1.127, Inspection of Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent with enhancementsXI.S7containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.2.25 Protective Coating Monitoring and
 
Maintenance Program (B.1.33)ConsistentXI.S8containment, structures, component supports, and
 
piping and component
 
insulation 3.0.3.1.8 Electircal Cables and Connections Not
 
Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Used in
 
Instrument Circuits (B.1.35)Consistent with enhancementsXI.E2electrical co mponents 3.0.3.2.26Periodic Testing of Containment Spray
 
Nozzles (B.2.1)Plant-specificNAESFs 3.0.3.3.1 Lubricating Oil Monitoring Activities (B.2.2)Plant-specificNAreactor vessel, internals, andreactor coolant systems; auxiliary systems; steam and power conversion system 3.0.3.3.2 OCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-10Generator Stator WaterChemistry Activities (B.2.3)Plant-specificNAsteam and power conversionsystem 3.0.3.3.3 Periodic Inspection ofVentilation Systems (B.2.4)Plant-specificNAESFs; auxiliary systems 3.0.3.3.4 Periodic Monitoring ofCombustion Turbine Power Plant (B.2.7)Plant-specificNAThis AMP was deleted.3.0.3.3.7Metal Fatigue of Reactor Coolant
 
Pressure Boundary (B.3.1)Consistent with enhancementX.M1reactor vessel, internals, andreactor coolant systems 3.0.3.2.27 Environmental Qualification (EQ)
 
Program (B.3.2)ConsistentX.E1electrical components 3.0.3.1.11New AMPsThermal Aging and Neutron Irradiation
 
Embrittlement of Cast
 
Austenitic Stainless
 
Steel (CASS)
(B.1.10)ConsistentXI.M13reactor vessel, internals, andreactor coolant systems 3.0.3.1.1 Aboveground OutdoorTanks (B.1.21)Consistent with exceptionXI.M29auxiliary systems; steam andpower conversion system 3.0.3.2.18One-Time Inspection (B.1.24)ConsistentXI.M32reactor vessel, internals, andreactor coolant systems; ESFs; auxiliary systems; steam and power conversion system; containment, structures, component
 
supports, and piping and
 
component insulation 3.0.3.1.4 Selective Leaching of Materials (B.1.25)ConsistentXI.M33ESFs; auxiliary systems;steam and power conversion system 3.0.3.1.5 Electrical Cables and Connections Not
 
Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements (B.1.34)ConsistentXI.E1electrical components 3.0.3.1.9 OCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-11 Inaccessible Medium-Voltage Cables
 
Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements (B.1.36)ConsistentXI.E3electrical components FRCT Electrical Systems 3.0.3.1.10 Electrical Cable Connections - Metallic
 
Parts - Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements (B.1.40)ConsistentXI.E6electrical components, metallic parts 3.0.3.1.12 Periodic Inspection Program (B.2.5)Plant-specificNAauxiliary systems; steam andpower conversion system 3.0.3.3.5Wooden Utility Pole Program (B.2.6)Plant-specificNAelectrical components 3.0.3.3.6New AMPs for Forked River Combustion Turbines (FRCT), Radio Communications System, andMeteorological TowerBolting Integrity - FRCT (B.1.12A)Consistent with exceptionsXI.M18FRCT Mechanical Systems3.0.3.2.28Closed-Cycle CoolingWater System - FRCT (B.1.14A)Consistent with exceptionXI.M21FRCT Mechanical Systems3.0.3.2.29 Aboveground OutdoorTanks - FRCT (B.1.21A)Consistent with exceptionXI.M29FRCT Mechanical Systems3.0.3.2.30Fuel Oil Chemistry -FRCT (B.1.22A)Consistent with exceptionsXI.M30FRCT Mechanical Systems3.0.3.2.31One-Time Inspection -FRCT (B.1.24A)Consistent with exceptionsXI.M32FRCT Mechanical Systems3.0.3.2.32 Selective Leaching of Materials -
FRCT(B.1.25A)Consistent with exceptionXI.M33FRCT Mechanical Systems3.0.3.2.33 Buried Piping Inspection- FRCT (B.1.26A)Consistent with exceptionXI.M34FRCT Mechanical SystemsRadio Com. System 3.0.3.2.34 Inspection of Internal Surfaces in
 
Miscellaneous Piping
 
and Ducting Components - FRCTConsistent with exceptionXI.M38 FRCT Mechanical Systems3.0.3.2.35 OCGS AMP(LRA Section)GALL ComparisonGALLAMP(s)LRA Systems or StructuresThat Credit the AMP Staff's SER Section 3-12 (B.1.38)Lubricating Oil Analysis- FRCT (B.1.39)Consistent with exceptionsXI.M39 FRCT Mechanical Systems3.0.3.2.36 Periodic Monitoring ofCombustion Turbine Power Plant Electrical (B.1.37)N/AOCGS plant-specific
 
programFRCT Electrical Systems3.0.3.3.8 Periodic InspectionProgram - FRCT (B.2.5A)N/AOCGS plant-specific
 
programFRCT Mechanical Systems3.0.3.3.9 Buried PipingInspection-Met Tower (B.1.26B)Consistent with exceptionsXI.M34Met Tower MechanicalSystems 3.0.3.2.373.0.3.1  AMPs That Are Consistent with the GALL Report In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL Report:
* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) (B.1.10)
* Flow-Accelerated Corrosion (B.1.11)
* Compressed Air Monitoring (B.1.17)
* One-Time Inspection (B.1.24)
* Selective Leaching of Materials (B.1.25)
* 10 CFR Part 50, Appendix J (B.1.29)
* Masonry Wall Program (B.1.30)
* Protective Coating Monitoring and Maintenance Program (B.1.33)
* Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.34)
* Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.36)
* Environmental Qualification (EQ) Program (B.3.2)
* Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.40) 3.0.3.1.1  Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) 3-13 Summary of Technical Information in the Application. In LRA Section B.1.10, the applicant described the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program as a new program consistent with GALL AMP XI.M13, "Thermal Aging and
 
Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)."
The Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program provides for aging management of CASS reactor internal components within the scope of license renewal. The program will be implement ed prior to the period of extended operation.
The program will include a component-specific evaluation of the loss of fracture toughness. A
 
supplemental inspection of components where loss of fracture toughness may affect function of
 
the component will use the criteria provided in GALL AMP XI.M13. This inspection will ensure the integrity of the CASS components exposed to the high temperature and neutron fluence present
 
in the reactor environment.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. In SER Section 3.0.2.1, the staff reviewed the program
 
elements of the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program and basis documents for consistency with GALL AMP XI.M13. Details of the staff's
 
evaluation of this AMP are documented in the Audit and Review Report Section 3.0.3.1.1. The
 
staff found the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program consistent with GALL AMP XI.M13, including the associated operating experience
 
attribute.
Operating Experience. In LRA Section B.1.10, the applicant explained that the Thermal Aging and Neutron Irradiation Embrittlement of Cast Aust enitic Stainless Steel Program is a new program, and therefore, no operating experience exists.
In Program Basis Document (PBD)-AMP-B.1.10, the applicant stated that research data on both laboratory-aged and service-aged materials have confirmed that loss of fracture toughness could
 
occur in some reactor vessel CASS internal components. Internal reactor vessel CASS
 
components are periodically examined, but no degradation has been identified to date. Because
 
the thermal aging and neutron irradiation embrittlement of the Thermal Aging and Neutron
 
Irradiation Embrittlement of Cast Austenitic Stainless Steel Program is new, a review of plant
 
operating experience cannot confirm at this time that loss of fracture toughness of CASS is a
 
factor.The Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program will include a component-specific evaluation to assess susceptibility to loss of fracture
 
toughness. This evaluation will be performed prior to the period of extended operation. A
 
supplemental inspection will be performed for those components where loss of fracture toughness may affect function using the criteria provided in GALL AMP XI.M13, "Thermal Aging and Neutron
 
Irradiation Embrittlement of Cast Austenitic Stainless Steel." This inspection will ensure the
 
integrity of the CASS components exposed to the high temperature and neutron fluence present
 
in the reactor environment.
The staff also reviewed the operating experience provided in the basis document, and interviewed the applicant's technical personnel to conclude that no industry operating experience with thermal
 
aging and embrittlement of CASS has emerged.
3-14 The staff believes that the corrective action process will capture internal and external plant operating issues to ensure that aging effects are adequately managed.
UFSAR Supplement. In LRA Section A.1.10, the applicant provided the UFSAR supplement for the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel
 
Program. The staff reviewed this section and determined that the information in the UFSAR
 
supplement provides 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 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel Program, the staff determined that all
 
the program elements are consistent with the GALL Report. The staff concludes that the applicant
 
has demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.1.2  Flow-Accelerated Corrosion
 
Summary of Technical Information in the Application. In LRA Section B.1.11, the applicant described the existing Flow-Accelerated Corrosion (FAC) Program as consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion."
The Flow-Accelerated Corrosion Program is based on Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R2, "Recommendations for an Effective Flow Accelerated Corrosion
 
Program." The program predicts, detects, and monitors wall thinning in piping, fittings, valve
 
bodies, and feedwater heaters due to FAC. Analytical evaluations and periodic examinations of
 
locations most susceptible to wall thinning due to FAC are used to predict the amount of wall
 
thinning in pipes, fittings, and feedwater heater shells. Program activities include analyses to
 
determine critical locations, baseline inspections to determine the extent of thinning at these
 
critical locations, and followup inspections to confirm the predictions. Inspections use ultrasonic, radiographic, visual, or other approved testing techniques capable of detecting wall thinning.
 
Repairs and replacements are performed as necessary.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with GALL AMP XI.M17. Details of the staff's evaluation of this AMP are documented
 
in the Audit and Review Report Section 3.0.3.1.2. The staff determined that this AMP is consistent with GALL AMP XI.M17, including the associated operating experience attribute.
Operating Experience. Operating experience of the Flow-Accelerated Corrosion Program activities shows that the program can determine susceptible locations for FAC, predict the
 
component degradation, and detect the wall thinning in piping, valves, and feedwater heater
 
shells due to FAC. In addition, the program provi des for reevaluation, repair, or replacement for locations where calculations indicate an area will reach minimum allowable thickness before the
 
next inspection. Periodic self-assessments of the program have been performed which have identified opportunities for program improvements.
In 2000, inspections of the "C" feed pump minimum recirculation line showed that several 90-degree elbows experienced significant wear. Similar wear was found on several 45-degree 3-15 elbows. As a result of these inspections, approximately 25 feet of 4-inch pipe, one 90-degree elbow, and three 45-degree elbows were replaced with chrome-moly material.
During cycle 17, ultrasonic (UT) inspections were performed on the high pressure (HP) feedwater heater (FWH) shells. These inspections were driven by the Point Beach Nuclear Power Plant
 
FWH shell rupture event and other industry experience, as described in Significant Event
 
Notification (SEN) 199 and information notice (IN) 99-19. Results of the inspections showed wall
 
thinning on all three HP FWH shells. Two areas on the "A" HP FWH required immediate repair.
 
Other identified degradation was evaluated and determined to be acceptable through the
 
remainder of the operating cycle, at which time further inspections and repairs were performed.
A number of steam leaks has been associated with flash tank and drain tank piping and attached piping. A condition report was initiated to determine why the FAC scope and inspection frequency
 
did not prevent these failures from occurring. As documented in the condition report response, the
 
Corporate FAC Program Manager performed an oversight self-assessment of the Flow-Accelerated Corrosion Program at OCGS in February 2003. Two deficiencies in the program
 
were identified: (1) the system susceptibility evaluation did not meet EPRI or procedural
 
requirements and (2) plant model input to the Flow-Accelerated Corrosion Program software tool, CHECWORKS, contained a number of errors and omissions. These deficiencies were identified
 
as the primary reasons the Flow-Accelerated Corrosion Program has missed identifying
 
components that developed leaks due to FAC. A Flow-Accelerated Corrosion Program
 
improvement project was implemented to correct the deficiencies. The project was completed in August 2003. As a result of the improvement project, the risk of a FAC failure in unidentified
 
susceptible lines has been reduced, and FAC inspections and outage inspection costs and time
 
have been optimized since the tools are now available to assist in selecting the right outage
 
inspection scope.
UFSAR Supplement. In LRA Section A.1.11, the applicant provided the UFSAR supplement for the Flow-Accelerated Corrosion Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides 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 determined that all the program elements are consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the period
 
of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3.0.3.1.3  Compressed Air Monitoring
 
Summary of Technical Information in the Application. In LRA Section B.1.17, the applicantdescribed the existing Compressed Air Monitoring Program as consistent with GALL AMP XI.M24, "Compressed Air Monitoring."
The Compressed Air Monitoring Program ensures dewpoint, particulates, and suspended hydrocarbons are kept within the specified limits for the portions of the instrument air system
 
within the scope of license renewal. Activities consist of yearly air quality monitoring, pressure
 
decay testing at intervals not exceeding 5 years and visual inspections. The activities are 3-16 consistent with the OCGS response to Generic Letter (GL) 88-14, "Instrument Air Supply Problems," and utilize guidance and standards provided by the Institute of Nuclear Power
 
Operations (INPO) Significant Operating Experience Report (SOER) 88-01, EPRI TR-108147, and American Society of Mechanical Engineers (ASME) OM-S/G-1998, Part 17. Testing and
 
monitoring activities are implemented through station procedures.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.3. The staff found the Compressed Air Monitoring Program consistent with GALL AMP XI.M24, including the associated operating experience
 
attribute.
Operating Experience. In LRA Section B.1.17, the applicant stated that the reliability of the instrument air system has improved since the im plementation of GL 88-14 activities and industry guidance. The Compressed Air Monitoring Program has implemented new industry air quality
 
standard, ISA-S7.0.01-1996, consistent with the GALL Report, and replacement dryers have
 
increased air quality as indicated by air quality test results and dewpoint monitoring.
UFSAR Supplement. In LRA Section A.1.17, the applicant provided the UFSAR supplement for the Compressed Air Monitoring Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Compressed Air Monitoring Program, the staff determined that all the program elements are consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that 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  One-Time Inspection
 
Summary of Technical Information in the Application. In LRA Section B.1.24, the applicantdescribed the new One-Time Inspection Program as consistent with GALL AMP XI.M32, "One-Time Inspection."
The applicant stated that the One-Time Inspection Program provides reasonable assurance that an aging effect does not occur or occurs so slowly as not to affect the component or structure
 
intended function during the period of extended operation and therefore requires no additional
 
aging management. The program will be credited for cases where either (a) an aging effect is not
 
expected to occur but there is insufficient data to rule it out completely, (b) an aging effect is
 
expected to progress very slowly in the spec ified environment, but the local environment may be more adverse than generally expected; or (c) the characteristics of the aging effect include a long
 
incubation period. This program will be used for the following:
* To confirm that crack initiation and growth due to stress corrosion cracking (SCC), intergranular stress corrosion cracking (IGSCC), or thermal and mechanical loading does
 
not occur in Class 1 piping less than 4-inch nominal pipe size (NPS) exposed to reactor
 
coolant.
3-17
* To confirm the effectiveness of the Water Chemistry Program to manage the loss of material and crack initiation and growth aging effects.
* To confirm the effectiveness of the Cl osed Cycle Cooling Water System Program to manage the loss of material aging effect.
* To confirm the effectiveness of the Fuel Oil Chemistry Program and Lubricating Oil Monitoring Activities Program to manage the loss of material aging effect.
* To confirm that loss of material in stainless steel piping, piping components, and piping elements is insignificant in an intermittent condensation (internal) environment.
* To confirm that loss of material in steel piping, piping components, and piping elements is insignificant in an indoor air (internal) environment.
* To confirm that loss of material is insignificant for nonsafety-related piping, piping components, and piping elements of vents and drains, floor and equipment drains, and
 
other systems and components that could contain a fluid and are in scope for
 
10 CFR 54.4(a)(2) for spatial interaction. The scope of the program consists of only those
 
systems not covered by other aging management activities.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. The staff noted that the LRA does not show any exceptions to
 
the GALL AMP. However, in their reconciliation document, the applicant identified three
 
exceptions to the GALL Report. Details of the staff's evaluation of this AMP are documented in the Audit and Review Report Section 3.0.3.1.4. The staff reviewed the exceptions and their
 
justifications to determine whether the AMP, with the exceptions, remained adequate to manage
 
the aging effects for which it is credited.
The staff noted that LRA Table 3.3.1, item 43, states that the One-Time Inspection Program will be used to verify the effectiveness of the Sele ctive Leaching of Materials Program; however, this intended use is not discussed in the program description. The applicant was asked to clarify this
 
intended use of the One-Time Inspection Program.
The applicant stated that the One-Time Inspection Program does not verify the effectiveness of the Selective Leaching of Materials Program. As described in the Selective Leaching of Materials
 
Program, the program is itself a one-time inspection to confirm that loss of material due to the
 
selective leaching aging mechanism does not occur.
In its letter dated April 17, 2006, the applicant stated that item 43 in LRA Table 3.3.1 will be modified to delete reference to use of the One-Time Inspection Program to verify the
 
effectiveness of the Selective Leaching of Materials Program. The staff agreed that item 43 in
 
LRA Table 3.3.1 should be modified as such verification is not one of the intended uses of the
 
One-Time Inspection Program.
The staff also noted in the LRA description of the One-Time Inspection Program that this new program will include program elements to determine the sample size and location as well as
 
inspection techniques. The applicant was asked for additional information on the rationale to be
 
used in selecting the size and location as well as the inspection techniques.
In its response the applicant stated that an inspection sample basis document had been prepared for one-time inspections. This document provides information on component population, sample
 
population, and expansion criteria for the various applications of the One-Time Inspection 3-18 Program. Implementation of one-time inspections will be through the normal maintenance planning process.
The staff reviewed the inspection sample basis document, an OCGS report titled "Inspection Sample Basis, Oyster Creek License Renewal Project" dated August 16, 2005, and determined
 
that it provides an adequate rationale for selecting one-time inspection samples to manage the
 
aging effects for which it is credited.
The staff also reviewed the following exceptions to the GALL Report program elements identified by the applicant.
Exception 1. In its reconciliation document, the applicant identified an exception to the GALL Report program elements "scope of program," "p reventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria."
 
Specifically, the exception stated that:NUREG-1801 states in XI.M32 that one-time inspection of Class 1 piping less thanor equal to NPS 4 is addressed in Chapter XI.M35, One Time Inspection of ASME
 
Code Class 1 Small Bore-Piping. NUREG-1801 aging management program XI.M35, One Time Inspection of ASME Code Class 1 Small Bore-Piping will not be
 
used at Oyster Creek. The new Oyster Creek One-Time Inspection aging
 
management program will include the one-time inspection of Class 1 piping less
 
than or equal to NPS 4.
In its letter dated March 30, 2006, the applicant committed (Commitment No. 24) to revise the One-Time Inspection Program in the LRA to include the exception identified in the reconciliation
 
document, which states that the new One-Time Inspection Program will include the one-time inspection of Class 1 piping less than or equal to NPS 4, and that GALL AMP XI.M35, "One-Time
 
Inspection of ASME Code Class 1 Small Bore Piping," will not be used.
The staff compared the program elements for the One-Time Inspection Program to those forGALL AMP XI.M35 to determine whether they were consistent for the inspection of piping less
 
than 4-inch NPS. Specifically, because the selection of the one-time inspection sample for the
 
One-Time Inspection Program is described in the OCGS inspection sample basis document, an
 
OCGS report titled "Inspection Sample Basis, Oyster Creek License Renewal Project" dated
 
August 16, 2005, the staff reviewed this document to determine how the small bore piping inspection sample will be determined. GALL AMP XI.M35 recommends for ASME Code Class 1
 
small bore piping a one-time inspection with volumetric examination on selected weld locations to
 
detect cracking. The sample size should be based on susceptibility, accessibility for inspection, dose considerations, operating experience, and limiting locations of the total population of ASME
 
Code Class 1 smallbore piping locations.
The staff noted that the inspection sample basis document stated that sample size for Class 1 piping less than 4-inch NPS will include 10 percent of the total butt welds, and inspection
 
locations will be based on physical accessibility, exposure levels, non-destructive examination (NDE) techniques, and will be determined by the site. The applicant was asked to clarify the
 
process for selecting pipe inspection samples to ensure that different piping sizes, including
 
socket-welded piping, are included in the sample selection for Class 1 piping less than 4-inch
 
NPS.
3-19 In its response to the staff's questions on this issue, the applicant committed to the following:
The one-time inspection program will also include destructive or non-destructive examination of one socket welded connection using techniques proven by past
 
industry experience to be effective for the identification of cracking in small bore
 
socket welds. This examination will be an examination of opportunity (e.g., socket weld failure or socket weld replacement). Should an inspection of opportunity not
 
occur prior to entering the period of extended operation, a susceptible small bore
 
socket weld will be examined either destructively or non-destructively prior to
 
entering the period of extended operation. The current plan is to examine a
 
susceptible small bore Class 1 elbow off of an isolation condenser system drain
 
line. Results of the inspection will be evaluated in accordance with the Oyster
 
Creek 10 CFR Part 50, Appendix B Corrective Action process.
In its letter dated May 1, 2006, the applicant committed (Commitment No. 24) to such inspections of small-bore piping as part of the One-Time Inspection Program.
The staff determined that the applicant had committed to do a non-destructive or destructive examination of one socket weld prior to the period of extended operation in response to the staff's
 
concern in this area. As this is a sampling process, the staff determined that one socket weld will
 
represent the population for Class 1 piping less than 4-inch NPS. With this new commitment and
 
the examination of 10 percent of the butt-welded small bore piping, there is reasonable assurance
 
that the aging of small bore piping will be adequately managed during the period of extended
 
operation.
Exception 2. In its reconciliation document the applicant identified an exception to the GALL Report program elements "scope of program," "par ameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the exception
 
stated that:NUREG-1801 references, in XI.M32 and XI.M35, the 2001 ASME Section XI B&PV Code, including the 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD.
 
The current Oyster Creek ISI Program Plan for the fourth ten-year inspection
 
interval effective from October 15, 2002 through October 14, 2012, approved per 10CFR50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996
 
addenda. The next 120-month inspection interval for Oyster Creek will incorporate the requirements specified in the version of the ASME Code incorporated into
 
10 CFR 50.55a twelve months before the start of the inspection interval.
In its letter dated March 30, 2006, the applicant stated that the One-Time Inspection Program will be revised to include this exception.
The staff evaluated this exception as part of its review of AMP B.1.1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD," and found it acceptable as consistent with the
 
requirements of 10 CFR 50.55a. The staff's evaluation is discussed in SER Section 3.0.3.2.1.
3-20 Exception 3. In its reconciliation document, the applicant identified an exception to the GALL Report program elements "scope of program" and
" "monitoring and trending." Specifically, the exception stated that:NUREG-1801 states in XI.M35, One Time Inspection of ASME Code Class 1 Small Bore-Piping, that the guidelines of EPRI Report 1000701, "Interim Thermal Fatigue
 
Management Guideline (MRP-24)," January 2001 should be used for identifying
 
piping susceptible to potential effects of thermal fatigue. EPRI Report 1000701
 
recommends specific locations for assessment and/or inspection where cracking
 
and leakage has been identified in nominally stagnant non-isolable piping attached
 
to reactor coolant systems in domestic and similar foreign PWRs. As Oyster Creek
 
is a BWR, these inspection guidelines are not applicable.
In its letter dated March 30, 2006, the applicant stated that the One-Time Inspection Program will be revised to include this exception.
In reviewing this exception the staff noted that EPRI Report 1000701 focuses on PWR plant locations susceptible to thermal fatigue but also includes generic guidance that may be useful for
 
boiling water reactor (BWR) plants. The applicant was asked to clarify whether the generic
 
guidance in EPRI Report 1000701 had been considered in the development of the One-Time
 
Inspection Program.
In its response the applicant stated that the evaluation to identify piping susceptible to the effects of thermal fatigue is in PBD-AMP-B.1.24, Section 3.1. This evaluation addresses the generic
 
guidance of the EPRI document for identification of locations. No locations were identified as
 
requiring inspection. The staff reviewed Section 3.1 of the program basis document (PBD) for the
 
One-Time Inspection Program and confirmed that the evaluation used the generic guidance in the
 
EPRI report. The evaluation identified no locations that would be subject to thermal fatigue. On
 
this basis, the staff finds this exception acceptable.
Operating Experience. In LRA Section B.1.24, the applicant stated that there is no programmatic operating experience specifically applicable to the new One-Time Inspection Program but that plant and industry operating experience will be considered in the selection of the component sample set.
Because this program is new there was no plant-specific operating experience for the staff to review. However, the staff expects the One-Time Inspection Program to adequately manage the aging effects for which it is credited on the basis of its consistency with GALL AMP XI.M32, with
 
exceptions.
The staff concludes that the corrective action process, which captures internal and external plant operating experience issues, will ensure that operating experience is reviewed and incorporated
 
to provide objective evidence for the conclusion that the effects of aging are adequately managed.
UFSAR Supplement. In LRA Section A.1.24 and letters dated March 30, April 17, and May 1, 2006, the applicant provided the UFSAR supplement for the One-Time Inspection
 
Program. The staff determined that the information in the UFSAR supplement provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3-21 Conclusion. On the basis of its audit and review of the applicant's One-Time Inspection Program, the staff determined that all the program elements are consistent with the GALL Report. In
 
addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with exceptions, is adequate to manage the aging effects for which is credited. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the period
 
of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3.0.3.1.5  Selective Leaching of Materials
 
Summary of Technical Information in the Application. In LRA Section B.1.25, the applicant described the new Selective Leaching of Materials Program as consistent with GALL AMP XI.M33, "Selective Leaching of Materials."
The Selective Leaching of Materials Program will consist of one-time inspections to determine whether loss of material due to selective leaching occurs. The scope of the program includes
 
such susceptible components as piping, pumps, and valves within the scope of license renewal
 
exposed to raw water, closed cooling water, treated water, auxiliary steam, condensation, or soil.
 
Susceptible component materials are gray cast iron, brass, and bronze with greater than 15
 
percent zinc, and aluminum bronze with greater than 8 percent aluminum. The One-Time
 
Inspection Program includes visual inspections consistent with ASME Code Section XI visual examination (VT)-1 requirements, hardness test s, and other appropriate examination methods as may be required to confirm or rule out selective leaching and to evaluate the remaining
 
component wall thickness. Components of the susceptible materials are selected from potentially
 
aggressive environments. The purpose of the program is to determine whether loss of material
 
due to selective leaching occurs. If selective leaching is found, the program evaluates the effect
 
on the ability of the affected components to perform intended function(s) for the period of
 
extended operation and the need to expand the sample of components to be tested. The program
 
will be implemented prior to the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.5. The staff found the Selective Leaching of Materials Program consistent with GALL AMP XI.M33, including the associated operating
 
experience attribute.
Operating Experience. In LRA Section B.1.25, the applicant explained that the Selective Leaching of Materials Program is new and, therefore, no programmatic operating experience is available.
 
Industry operating experience identifies graphitization of pump components from long-term
 
submersion in saltwater environments. Any degr adation of components due to selective leaching at OCGS may have been classified with different aging mechanisms and the component
 
deficiency corrected by repair or replacement, including the cast iron circulating water and service
 
water (SW) pump subcomponents that have been replaced with stainless steel. Sample
 
inspections at OCGS will include cast iron components in a saltwater environment.
The staff believes that the corrective action process will capture internal and external plant operating issues to ensure that aging effects are adequately managed.
3-22 On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Selective Leaching of Materials Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.25, the applicant provided the UFSAR supplement for the Selective Leaching of Materials Program. The staff reviewed this section and determined that
 
the information in the UFSAR supplement provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Selective Leaching of Materials Program, the staff determined that all the program elements are consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended 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  10 CFR Part 50, Appendix J
 
Summary of Technical Information in the Application. In LRA Section B.1.29, the applicantdescribed the existing 10 CFR Part 50, Appendix J Program as consistent with GALL AMP XI.S4, "10 CFR 50, Appendix J."
The 10 CFR Part 50, Appendix J Program provides for detection of age-related pressure boundary degradation and loss of leak tightness due to such aging effects as loss of material, cracking, or loss of preload in the primary containment and various systems penetrating the
 
primary containment. The program also detects age-related degradation in material properties of
 
gaskets, o-rings, and packing materials for the primary containment pressure boundary access
 
points. The program consists of tests performed in accordance with the regulations and guidance
 
provided in 10 CFR 50 Appendix J, "Primary Reactor Containment Leakage Testing for
 
Water-Cooled Power Reactors," Option B, Regulatory Guide (RG) 1.163, "Performance-Based
 
Containment Leak-Testing Program," NEI 94-01, "Industry Guideline for Implementing
 
Performance-Based Options of 10 CFR Part 50, Appendix J," ANSI/ANS 56.8, "Containment
 
System Leakage Testing Requirements," and station procedures. Containment leak rate tests
 
assure that leakage through the primary c ontainment and systems and components penetrating the primary containment does not exceed allowable lim its specified in the technical specifications.
An integrated leak rate test (ILRT) is performed during a period of reactor shutdown at the
 
frequency specified in 10 CFR Part 50, Appendix J, Option B. Local leak rate tests (LLRT) on
 
isolation valves and containment access penetrations comply with frequency requirements of
 
10 CFR 50 Appendix J, Option B.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.6. The staff determined that the 10 CFR Part 50, Appendix J Program is consistent with GALL AMP XI.S4, including the associated operating
 
experience attribute.
Operating Experience. In LRA Section B.1.29, the applicant explained that the industry has found the 10 CFR Part 50, Appendix J Program effective in maintaining the pressure integrity of the 3-23 containment boundaries, including identification of leakage within the various system pressure boundaries.
The OCGS facility has demonstrated experience in effectively maintaining the integrity of the containment boundaries as evidenced by the selection of Option B of 10 CFR 50 Appendix J
 
leakage testing requirements. The station has ex perienced "as found" LLRT results in excess of individual containment penetration administrat ive limits. Evaluations were performed and corrective actions were taken to restore the individual penetration leakage rates to within the
 
established administrative leakage limits in accordance with the Appendix J testing program.
 
Some site-specific examples include the following:
* In 2000, an LLRT of V-26-8 determined that the leakage rate was above the alert limit for that valve. The rate was evaluated to be acceptable as-found. The valve was
 
subsequently rebuilt and retested satisfactorily in the next refueling outage.
* In 2002, an LLRT of V-19-20 determined that the leakage rate exceeded the action limit.
The valve was repaired and the post-maintenance test LLRT was acceptable.
* In 2004, an LLRT of MSIV NS04A determined that the leakage rate failed to meet acceptance criteria. The main seating surface was lapped and a successful LLRT was
 
performed. As a result of this occurrence, the MSIV overhaul procedure was revised to
 
include a documented management review prior to eliminating seat lapping after poppet
 
replacement even if a successful blue check has been obtained.
The staff reviewed the operating experience provided in the LRA and PBD, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
10 CFR Part 50, Appendix J Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.29, the applicant provided the UFSAR supplement for the 10 CFR Part 50, Appendix J Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides 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 10 CFR Part 50, Appendix J Program, the staff determined that all the program elements are consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed
 
the UFSAR supplement for this AMP and concludes that it provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.7  Masonry Wall Program
 
Summary of Technical Information in the Application. In LRA Section B.1.30, the applicantdescribed the existing Masonry Wall Program as consistent with GALL AMP XI.S5, "Masonry Wall
 
Program."
3-24 The Masonry Wall Program is part of the Structures Monitoring Program. It is based on the guidance provided in Bulletin 80-11, "Masonry Wall Design," and IN 87-67, "Lessons Learned
 
from Regional Inspections of Licensee Actions in Response to Bulletin 80-11," and is
 
implemented through station procedures. The "scope of program" includes all masonry walls with
 
intended function(s) in accordance with 10 CFR 54.4. The program requires inspection of
 
masonry walls for cracking on a frequency of four years, so that the established evaluation basis
 
for each masonry wall remains valid during the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.7. The staff determined that the Masonry Wall Program is consistent with GALL AMP XI.S5, including the associated operating experience
 
attribute.
Operating Experience. In LRA Section B.1.30, the applicant explained that the Masonry Wall Program indentified cracks and other minor aging effects in masonry walls. Maintenance history
 
revealed minor degradation of masonry block walls but none that could impact their intended
 
function. In response to Bulletin 80-11 and IN 87-67 various actions were taken, including
 
program enhancements, followup inspections to substantiate masonry wall analyses and
 
classifications, and development of procedures for tracking and recording changes to the walls.
 
These actions addressed all concerns raised by Bulletin 80-11 and IN 87-67, namely unanalyzed
 
conditions, improper assumptions, improper classification, and lack of procedural controls.
 
Operating experience review concluded that the program is effective for managing aging effects of masonry walls.
The staff reviewed the operating experience provided in the LRA and the PBD and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience
 
revealed no degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Masonry Wall Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.30, the applicant provided the UFSAR supplement for the Masonry Wall Program. The staff reviewed this section and determined that the information in
 
the UFSAR supplement provides 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 determined that all the program elements are consistent with the GALL Report. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended 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).
3-25 3.0.3.1.8  Protective Coating Monitoring and Maintenance Program Summary of Technical Information in the Application. In LRA Section B.1.33, the applicant described the existing Protective Coating Monitoring and Maintenance Program as consistent with GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program."
The Protective Coating Monitoring and Maint enance Program provides for aging management of Service Level I coatings inside the primary c ontainment and Service Level II coatings for the external drywell shell in the sandbed region. Serv ice Level I coatings are used in areas where coating failure could affect the operation of post-accident fluid systems adversely and thereby impair safe shutdown. OCGS was not originally committed to Regulatory Guide (RG) 1.54 for
 
Service Level I coatings because the plant was licensed prior to the issuance of this RG in 1974.
 
Currently, OCGS is committed to a modified version of this RG as described in the response to
 
GL 98-04 and as detailed in the Exelon Quality Assurance Topical Report (QATR) NO-AA-10.
 
Service Level II coatings provide corrosion protection and decontamination ability in areas outside
 
of the primary containment subject to radiation exposure and radionuclide contamination. The
 
Protective Coating Monitoring and Maintenance Program provides for visual inspections, assessment, and repairs for any condition that adver sely affects the ability of Service Level I coatings or sandbed region Service Level II coatings to function as intended.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.8.
During the audit the staff requested that the applicant clarify which coatings are credited for corrosion protection of metal surfaces. In its response, the applicant clarified that Service Level 2
 
coatings are used only for corrosion protection in the external drywell shell sand bed region.
 
Similarly, while some service Level 1 coatings are used to provide corrosion protection, the
 
applicant does not credit them for corrosion protection for the drywell shell above the sand bed
 
region for license renewal purposes. An analysis has been performed which demonstrates that
 
the upper portion of the drywell vessel will meet ASME Code requirements for the remaining life of
 
the plant based on corrosion rates. The corrosion of the drywell shell above the sand bed region
 
is considered a time-limited aging analysis (TLAA) and is further described in LRA Section 4.7.2.
 
However, Service Level 1 coatings are credited for corrosion protection for the vent header and
 
torus.The applicant further stated that for loss of coolant accident debris generation and transport, the drywell coating is qualified for such an environment. The mass of coating released following a
 
loss of coolant accident jet impingement was conservatively estimated at 47 pounds. No
 
additional coating flaking was assumed due to the harsh environment because the coating is
 
qualified. Coating within the vent system and torus is expected to contribute 0 pounds of debris to
 
the suction strainer load following a loss of coolant accident. However, the analysis conservatively
 
assumed 10 pounds of debris attributed to the vent system and torus coating.
The staff also requested that the applicant clarify whether any Service Level III coatings are credited for corrosion protection for license renewal. In its response, the applicant stated that
 
Exelon Corporate Procedure ER-AA-330-008 in paragraph 2.7.3 defines Service Level III coatings
 
as coatings used on any exposed surface area located outside containment whose failure could
 
affect normal plant operation or orderly and sa fe plant shutdown adversely. Service Level III coatings are also used in areas outside the reactor containment where failure could affect the 3-26 safety function of a safety-related structure, system, or component adversely. Specification SP-9000-06-004 in paragraph 3.2.1.c specifies the use of Service Level III coatings on
 
structures/components subjected to a corrosive environment (e.g., liquid immersion, saltwater
 
contact, underground burial, outdoor exposure, etc.). For license renewal Service Level III
 
coatings are credited only for corrosion protection for the external surfaces of piping and fittings
 
exposed to a soil (external) environment in t he emergency service water (ESW) system, SW system, and roof drain and overboard discharge system. These coatings are managed under the Buried Piping Inspection Program. Other than the Service Levels I and II coatings discussed in
 
PBD-AMP-B.1.33, and the Service Level III coatings described in response to this question no
 
other protective coatings are credited for corrosion protection for license renewal.
The staff also noted that the discussion in LRA Table 3.5.1, item 3.5.1-15, appears to identify a scope larger than that identified in the AMP description. The staff requested that the applicant
 
clarify the scope of this program. In its response, the applicant stated that the structures or
 
components and environments "rolled-up" into LR A Table 3.5.1 item 3.5.1-15 (reference LRA Table 3.5.2.1.1 for primary containment) include the following:
* access hatch covers - containment atmosphere (internal)
* downcomers - containment atmosphere
* drywell penetration sleeves - containment atmosphere (internal)
* drywell shell - containment atmosphere (internal) and indoor air (external)
* personnel airlock/equipment hatch - containment atmosphere (internal)
* suppression chamber penetrations - containment atmosphere (internal)
* suppression chamber ring girders - containment atmosphere (external)
* suppression chamber shell - containment atmosphere (internal)
* vent line, and vent header - containment atmosphere (internal) and indoor air (external)
* downcomers - immersed
* suppression chamber ring girders - immersed
* suppression chamber penetrations - immersed
* suppression chamber shell - immersed The applicant stated that for Service Level I coatings the Protective Coating Monitoring and Maintenance Program is not used to manage loss of material for access hatch covers, drywell
 
penetration sleeves, and personnel airlock/equipment hatches exposed to a containment
 
atmosphere (internal) environment. Accordingly, LRA Table 3.5.2.1.1 for the primary containment
 
will be revised to delete the Protective Coating Monitoring and Maintenance Program from these
 
component types exposed to a containment at mosphere environment. For Service Level II coatings, the Protective Coating Monitoring and Maintenance Program is not used to manage
 
corrosion for the vent line and vent header ex posed to an indoor air (external) environment.
Accordingly, LRA Table 3.5.2.1.1 and Table 3.5.1, item 3.5.1-15, will be revised to delete the
 
Protective Coating Monitoring and Maintenance Pr ogram from this component type exposed to an indoor air environment.
In its letter dated April 17, 2006, the applicant stated that LRA Tables 3.5.2.1.1 and 3.5.1 will be revised to delete the Protective Coating Monitoring and Maintenance Program from line items to
 
manage loss of material for access hatch covers, drywell penetration sleeves, and personnel
 
airlock/equipment hatches exposed to a contai nment atmosphere (internal) environment and line items to manage corrosion for the vent line and vent header exposed to an indoor air (external)
 
environment.
3-27 The staff finds the applicant's clarifications acceptable because they defined the scope of coatings credited for corrosion protection and also defined the coatings specifically monitored and
 
maintained by the Protective Coating Monitoring and Maintenance Program for license renewal.
During its review of plant-specific operating experience related to containment degradation, the staff asked a number of questions about the implementation of the Protective Coating Monitoring
 
and Maintenance Program for the exterior surface of the sand bed region and for the submersed
 
interior surface of the torus. The staff's inquiries and assessments of the applicant's responses are documented in the evaluation of the applicant's ASME Section XI, Subsection IWE Program
 
summarized in SER Section 3.0.3.2.22. The applicant made new commitments related to monitoring of the primary containment coatings in accordance with ASME Section XI, Subsection IWE (Commitment No. 33).
Subsequent to the audit, in response to RAI 4.7.2-1, by letter dated June 20, 2006, the applicant provided additional information regarding the coatings credited for corrosion mitigation for primary
 
containment and activities associated with drywell shell corrosion. The staff's evaluation of the
 
applicant's information and commitments is documented in SER Section 4.7.2.
Although the LRA did not identify any enhancements for the Protective Coating Monitoring and Maintenance Program, the applicant's program basis document, (PBD)-AMP-B.1.33, "OCGS Program Basis Document: Protective Coating Monitoring and Maintenance Program," Revision 0, identified the following enhancement to meet the GALL Report program elements:
Enhancement. The applicant identified an enhancement to its program elements "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria." Specifically, the
 
enhancement stated that:
The inspection of Service Level I and Service Level II protective coatings that are credited for mitigating corrosion on interior surfaces of the Torus shell and vent
 
system, and, on exterior surfaces of the Drywell shell in the area of the sand bed region, will be consistent with ASME Section XI, Subsection IWE requirements.
The staff requested that the applicant clarify what changes were necessary to make theProtective Coating Monitoring and Maintenance Program consistent with ASME Code Section XI, Subsection IWE requirements. In its response, the applicant stated that the requirements for
 
coating inspections are included in OCGS specifications SP-1302-52-120, "Specification for
 
Inspection and Localized Repair of the Torus and Vent System Coating," and IS-328227-004, "Functional Requirements for Drywell Contai nment Vessel Thickness Examination." Thesespecifications do not invoke all of the requirements of ASME Code Section XI, Subsection IWE.
 
The following requirements will be included in these inspection specifications:    (1)Torus and vent system internal coati ng inspections will be per Examination Category E-A and will require VT-3 visual examinations per IWE-3510.2. The inspected area shall be
 
examined (as a minimum) for evidence of flaking, blistering, peeling, discoloration, and
 
other signs of distress. Disposition of suspect areas shall be by engineering evaluation or
 
correction by repair or replacement in accordance with IWE-3122. Supplemental
 
examinations in accordance with IWE-3200 shall be performed when specified as a result
 
of engineering evaluation.
3-28  (2)Sand bed region external coating inspections will be per Examination Category E-C (augmented examination) and will require VT-1 visual examinations per IWE-3412.1. The inspected area shall be examined (as a minimum) for evidence of flaking, blistering, peeling, discoloration, and other signs of distress. Disposition of suspect areas shall be by
 
engineering evaluation or correction by repair or replacement in accordance with
 
IWE-3122. Supplemental examinations in accordance with IWE-3200 shall be performed
 
when specified as a result of engineering evaluation.
In its letter dated April 4, 2006, the applicant committed (Commitment No. 27) to the following:
The coating inside the torus will be visually inspected in accordance with ASMESection XI, Subsection IWE, per the protective coatings program. This commitment
 
will be performed every other refueling outage prior to and during the period of
 
extended operation.
On this basis, the staff finds this enhancement to the protective coating monitoring and maintenance program acceptable because it ensures that the requirements of ASME Code IWE
 
related to coatings inspection will be implemented during the period of extended operation.
Operating Experience. In LRA Section B.1.33, the applicant explained that it has successfully identified indications of age-related degradation in Service Level I coatings prior to the loss of
 
intended function(s) and has taken appropriate corrective actions through evaluation or repair in
 
accordance with the Service Level I coatings procedures and specifications. Torus and vent
 
header vapor space Service Level I coating inspections performed in 2002 found the coating in
 
these areas in good condition. Inspection of the immersed coating in the torus identified blistering
 
that occurred primarily in the shell invert but was also noted on the upper shell near the water line.
 
The majority of the blisters remained intact and continued to protect the base metal. However, several blistered areas included pitting damage where the blisters were fractured. A qualitative
 
assessment of the identified pits concluded that the measured pit depths were significantly less
 
than the established acceptance criteria. The fractured blisters were repaired to reestablish the
 
protective coating barrier.
The Service Level II coating effort completed in the 14R refueling outage has been effective in mitigating corrosion in the sand bed area. This effort was accomplished while the vessel thickness
 
was sufficient to satisfy ASME Code requirements, so drywell vessel corrosion in the sand bed
 
region is no longer a limiting factor in plant operation; however, inspections are conducted to
 
ensure that the coating remains effective. To date, no age-related degradation has been detected
 
in the sandbed region Service Level II coating.
In 2003, the replacement motor for the "A" recirculation motor was found to be top-coated with a non-design basis accident qualified coating on the motor housing, end bells, and stator.
 
Engineering analysis concluded that negligible additional suction strainer debris loading will be
 
created by the failure of this additional unqualified coating.
The staff reviewed the operating experience provided in the LRA and PBD and also interviewed the applicant's technical personnel. The staff concluded that the plant-specific operating
 
experience with containment degradation is unique and not bounded by industry experience. The
 
staff's review of operating experience led to a number of questions about the implementation of
 
the Protective Coating Monitoring and Maintenance Program. As a result, the staff identified 3-29 OI 4.7.2-3, regarding the extent of drywell shell coated surfaces examined during each inspection.
The staff's evaluation of this OI is documented in SER Section 4.7.2.
UFSAR Supplement. In LRA Section A.1.33 and letters dated April 4, April 17, May 1, and June 23, 2006, the applicant provided the UFSAR supplement for the Protective Coating
 
Monitoring and Maintenance Program. The staff determined that the UFSAR supplement must be
 
revised to reflect the resolution of OI 4.7.2-3 to provide an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review, as discussed above, the staff concludes, contingen upon resolution of OI 4.7.2-3, that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) of primary containment will be maintained
 
during the period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff also concludes that the UFSAR must be revised to reflect the resolution of the OI to provide an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.1.9  Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. In LRA Section B.1.34, the applicant described the new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ
 
Requirements Program as consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."
The Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program will be used to manage non-EQ cables and connections within the scope of license renewal that
 
are subject to adverse localized environments. An adverse localized environment is a condition in a limited plant area significantly more severe t han the specified service environment for a subject cable or connection. An adverse variation in environment is significant if it could appreciably
 
increase the rate of aging of a component or have an immediate adverse effect on its operation.
 
Cables and connections subject to an adverse environment are managed by inspection of these components. A sample of accessible electrical cables and connections installed in adverse
 
localized environments is inspected visually for signs of accelerated age-related degradation like
 
embrittlement, discoloration, cracking, or surface contamination. Additional inspections, repair, or
 
replacement are initiated as appropriate. Accessible cables and connections in adverse areas are
 
inspected prior to the period of extended operation with an inspection frequency of at least once
 
every 10 years. The scope of this program includes inspections of power, control, and
 
instrumentation cables and connections located in adverse areas.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.9. The staff finds the Electrical Cables and
 
Connections Not Subject to 10 CFR 50.49 EQ Requirements Program consistent with GALL AMP XI.E1, including the associated operating experience attribute.
Operating Experience. In LRA Section B.1.34, the applicant explained that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program is new and, therefore, no programmatic operating experience is available. Disposition of instances of potentially
 
age-related degradation of cables identified during routine maintenance activities has been by the 3-30 corrective action process. In each instance engineering evaluations determined the cause of the apparent degradation, the effect on operation, and appropriate corrective action. OCGS also has
 
a history of age-related cable failures of inaccessible medium-voltage cables in a wetted
 
environment. Operating experience for these cabl es is addressed in the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Program. As noted in the GALL
 
Report, industry operating experience shows that adverse localized environments have been found to produce visible degradation of insulating materials for electrical cables and connections.
The staff also reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
The staff believes that the corrective action process will capture internal and external plant operating issues to ensure that aging effects are adequately managed.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.34, the applicant provided the UFSAR supplement for the Electircal Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.
 
The staff reviewed this section and determined that the information in the UFSAR supplement
 
provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that
 
all the program elements are consistent with the GALL Report. The staff concludes that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended 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  Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. In LRA Section B.1.36, the applicant described 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 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program manages i naccessible medium-voltage cables exposed to significant moisture simultaneously with significant voltage. Significant moisture is defined as
 
lasting more than a few days (e.g., cable in standing water). Periodic exposures to moisture
 
lasting less than a few days (i.e., normal rain and drain) are not significant. Significant voltage is
 
defined as subject to system voltage more than 25 percent of the time. OCGS has a total of
 
47 medium-voltage cable installations. Because of OCGS's history of medium voltage cable 3-31 failures all 47 cable circuits are conservatively assumed to have potential exposure to significant moisture conditions. This program will inspect manholes, conduits, and sumps of the 47 cable
 
circuits for water collection so draining or other corrective actions can be taken. In addition, these
 
medium-voltage cable circuits will be tested fo r deterioration of the insulation system due to wetting by a proven test like power factor, partial discharge, or polarization index as described in EPRI TR-103834-P1-2, or other state-of-the-art testing at the time. Cable testing will be performed
 
at least once every10 years testing frequency will be adjusted in accordance with the results
 
obtained. The first tests will be completed prior to the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.10. The staff determined that, with Commitment No.
 
36, the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental
 
Qualification Requirements Program is consistent with GALL AMP XI.E3, including the associated operating experience attribute.
The staff requested that the applicant to clarify its use of polarization index testing. In its response, the applicant stated that current methodologies at OCGS implement a polarization
 
index test as part of step voltage and Megger testing, and the applicant does not currently use, nor does it plan to use in the future, polarization index testing as the sole condition monitoring test
 
in its Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental
 
Qualification Requirements Program.
In its letter dated April 17, 2006, the applicant stated that the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environment al Qualification Requirements Program will be revised to clarify that polarization index testing is not used as the sole condition monitoring test for
 
medium-voltage cable circuits.
The staff's review of LRA Section B.1.36 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's request for additional information (RAI) as discussed below.
As stated in SER Section 2.5, in RAI 2.5.1.19-1 dated September 28, 2005, the staff expressed the need for additional information to continue its review of long-lived passive components of the
 
Forked River combustion turbines (FRCTs). By letters dated October 12, 2005, and
 
November 11, 2005, the applicant responded. The Inaccessible Medium-Voltage Cables Not
 
Subject to 10 CFR 50.49 Environmental Qualification Requirements Program scope has been
 
revised to include 13.8 kV inaccessible medium-voltage cables associated with the FRCTs. The staff noted that OCGS has included 2.3 kV, 4.1 kV, and 13.8 kV system circuits in the scope of the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental
 
Qualification Requirements Program. In addition, as a result of the applicant's reconciliation of the
 
September 2005 revision of the GALL Report with the January 2005 draft revision, 34.5 kV
 
system cables will be added to this program.
In its letter dated March 30, 2006, the applicant committed (Commitment No. 36) to revise the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements Program in the LRA to include 34.5 kV system cables in the program.
Operating Experience. In LRA Section B.1.36, the applicant explained that OCGS has experienced eleven in-service medium voltage circuit failures to date, five from water intrusion, 3-32 four from manufacturing defects, and two from a single lightning strike. The majority of those failures occurred in EPR-insulated "UniShield" cables manufactured by Anaconda before 1985. In
 
1991, OCGS implemented a medium voltage cable te sting program covering all 47 of its medium voltage circuits in an attempt to identify cable degradation so that appropriate corrective action
 
could be taken prior to failure. The results of that inspection program have successfully identified degradation in cross-linked polyethylene (XLPE)-insulated cables prior to failure. The results
 
failed to identify degradation in EPR-insulated cables.
The applicant stated that testing under the current cable testing program has successfullyidentified degradation in XLPE-insulated cables (e.g., General Electric (GE) Vulkene) so that replacements could be made prior to in-service failures. Eleven XLPE-insulated cable circuit
 
replacements have been made based on test results since the testing program was implementedin 1991. No in-service failures of XLPE-insulated cable have occurred since the testing program
 
was implemented in 1991.
The applicant also stated that the current cable testing program has not been successful at identifying degradation in EPR-insulated UniShield type cables (for example, Anaconda
 
UniShield) so that replacements could be made prior to in-service failures. Five in-service failures
 
of UniShield cable circuits exposed to moisture have occurred since the testing program was
 
implemented in 1991. Four of the five failed cables were manufactured before UniShield
 
manufacturing process improvements to addre ss manufacturing defects were implemented in mid-1984. OCGS has experienced no failures in UniShield cables manufactured since that date.
The fifth and most recent in-service cable failure occurred in 2003. Corrective actions were completed to (1) test failed cables to confirm the failure mechanisms, (2) confirm the accuracy of
 
configuration information for 4160V circuits, (3) evaluate all remaining UniShield cables and
 
replace or schedule for replacement of any manufactured before 1985 which might be exposed to
 
significant moisture, and (4) eliminate the future use of UniShield cables.
The applicant tested 18 of its medium voltage cable circuits in 2004 in a trial use of a new,state-of-the-art testing method based on partial discharge. As a result, one XLPE-insulated cable
 
was replaced. Additional medium voltage cables were tested in 2005. The current inspection
 
program will remain in effect until replaced by the Inaccessible Medium Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program before entering the
 
period of extended operation.
The Inaccessible Medium Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program is new; t herefore, no programmatic operating experience is available. The staff reviewed the operating exper ience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
The staff noted that the new Inaccessible Medium Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Progr am now includes the underground circuits in the 2.4 kV, 4.16 kV, 13.8 kV, and 34.5 kV systems.
This program will test in-scope medium-voltage cables at OCGS for an indication of the condition of the conductor insulation. The specific type of
 
test performed will be an industry-endorsed, proven test for detecting deterioration of the
 
insulation system resulting from wetting like power factor, partial discharge, or polarization index as described in EPRI TR-103834-P1-2, or other state-of-the-art testing at the time. Additionally, inspections for water collection in the manholes, conduits, and sumps containing medium-voltage 3-33 cables within the scope of this program w ill be performed as preventive measures. The applicant stated that underground 13.8 kV circuits at the FRCT power plant as well as 34.5 kV circuits that
 
provide offsite feeds to OCGS are included in the AMP. These circuits date back to the 1989
 
installation of alternate alternating current (AC) capabilities for station blackout (SBO) at OCGS.
 
There have been no failures reported on these cables.
The staff asked the applicant whether it has any plans to trend the cable test data during the period of extended operation. The applicant stated that ongoing test results from the current
 
OCGS medium-voltage cable testing program are being trended. Trending of test results will continue through the period of extended operation.
In its letter dated April 17, 2006, the applicant committed (Commitment No.36) to revise the LRA to state that cable test/monitoring frequency will be at least once every 10 years, that it will be
 
adjusted based on test/monitoring results, and that the test results will be trended.
The staff also noted that the recent industry concern with direct current (DC) high-potential testing and its impact on the life of cables is not a concern at OCGS because the majority of the
 
medium-voltage cables at OCGS are tested by partial discharge or power factor testing methodologies. The applicant stated that it is not implementing hi-pot testing at OCGS as part of
 
its medium-voltage cable testing program except fo r five circuits feeding the 2.4 kV recirculation pump motors. These cables are DC step-voltage tested to only a maximum of 4 kV. The industry
 
has concerns about hi-pot testing at very high DC voltages.
The staff believes that the corrective action process will capture internal and external plant operating issues to ensure that aging effects are adequately managed.
On the basis of its review of the above industry and plant-specific operating experience as well as discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification
 
Requirements Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
UFSAR Supplement. In LRA Section A.1.36 and letters dated March 30, and April 17, 2006, the applicant provided the UFSAR supplement for the Inaccessible Medium Voltage Cables Not
 
Subject To 10 CFR 50.49 Environmental Qualification Requirements Program. The staff
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Inaccessible Medium Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Program, the
 
staff determined 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).
3-34 3.0.3.1.11  Environmental Qualification (EQ) Program Summary of Technical Information in the Application. In LRA Section B.3.2, the applicantdescribed the existing Environmental Qualification Program as consistent with GALL AMP X.E1, "Environmental Qualification (EQ) of Electric Components."
The Environmental Qualification Program is implemented through station procedures and preventive maintenance tasks. The Environmental Qualification Program complies with
 
10 CFR 50.49, "Environmental Qualification of El ectrical Equipment Important to Safety for Nuclear Power Plants." All EQ equipment is included within the scope of license renewal. The
 
program provides for maintenance of the qualified life for electrical equipment important to safety
 
within the scope of 10 CFR 50.49. Program activities establish, demonstrate, and document the
 
level of qualification, qualified configuration, maintenance, surveillance, and replacement
 
requirements necessary to meet 10 CFR 50.49. Reanalysis addresses attributes of analytical
 
methods, data collection and reduction methods, underlying assumptions, acceptance criteria, corrective actions if acceptance criteria are not met, and the period of time prior to the end of
 
qualified life when the reanalysis will be completed. Qualified life is determined for equipment
 
within the scope of the Environmental Qualification Program and such appropriate actions as
 
replacement or refurbishment are taken prior to or at the end of the qualified life of the equipment
 
so that the aging limit is not exceeded. The Envi ronmental Qualification Program addresses the low voltage instrument and control cable issues consistent with those described in the closure of
 
generic safety issue (GSI)-168, "Environmental Qualification of Electrical Equipment."
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's evaluation of this AMP are documented in
 
the Audit and Review Report Section 3.0.3.1.11.
The staff reviewed those portions of the applicant's Environmental Qualification Program forwhich the applicant claimed consistency with GALL AMP X.E1 and found them consistent with
 
this GALL AMP, including the associated operating experience attribute. The staff's review
 
concluded that the applicant's Environmental Qualification Program provided reasonable
 
assurance that electrical components import ant to safety in harsh environments will be adequately managed. The staff found that the applicant's Environmental Qualification Program conforms to the recommended GALL AMP X.E1.
Operating Experience. In LRA Section B.3.2, the applicant explained that the Environmental Qualification Program provides for consideration of operating experience to reconcile qualification bases and conclusions, including the equipment qua lified life. Operating experience and system, equipment, or component related information as reported through NRC bulletins, notices, circulars, GLs and Part 21 notifications are evaluated for applicability. The evaluations are
 
documented and corrective actions are identified. Operating experience is reviewed to determine
 
whether it is applicable to EQ equipment. When problems have been identified through industry or
 
plant-specific experience, corrective actions have been taken to prevent recurrence.
The staff's review of the applicable corrective action process database and sample EQ binders revealed no occurrence where the qualified life of a component had been exceeded. This review
 
indicated no adverse trend in the Environmental Qualification Program.
3-35 The staff also reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Environmental Qualification Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.3.2, the applicant provided the UFSAR supplement for the Environmental Qualification Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides 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 Environmental Qualification Program, the staff determined that all the program elements are consistent with the GALL Report.
 
The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended 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).
3.0.3.1.12 Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Summary of Technical Information in the Application. Originally, this AMP was not included within the scope of this LRA. However, in response to RAI 3.6.2.3.3 (documented in SER Section 3.6),
by letter dated May 9, 2006, the applicant committed (Commitment No. 64) to develop and
 
implement this AMP to manage the aging effects of electrical connections.
In the May 9, 2006, letter the applicant stated that the new Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requirement Program is consistent with GALL AMP XI.E6, "Electrical Cable Connections - Metallic Parts - Not Subject to
 
10 CFR 50.49 Environmental Qualification Requirements."
The Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requirement Program is a new program that will be used to manage the aging effects of metallic parts of non-EQ electrical cable connections within the scope of license
 
renewal. The program will address cable connections for cable conductors to other cables or
 
electrical devices. The most common types of connections in nuclear power plants are splices (butt or bolted), crimp-type ring lugs, connectors, and terminal blocks. Most connections have
 
insulating material and metallic parts. The applicant stated that this AMP will account for the aging
 
stressors of thermal cycling, ohmic heating, electrical transients, vibration, chemical
 
contamination, corrosion, and oxidation of the metallic parts.
Electrical cable connections, metallic parts not subject to 10 CFR 50.49 environmental qualification requirements subject to aging stressors, will be managed by testing for an indication
 
of the integrity of the cable connections. The type of test to be performed, (i.e., thermography), is
 
proven for detecting loose connections. A represent ative sample of electrical cable connections will be tested.
3-36 This program as described can be thought of as a sampling program. The following factors are considered for sampling: application (high, medium, and low voltage), circuit loading, and location (high temperature, high humidity, vibration, etc.) with respect to connection stressors. If an
 
unacceptable condition or situation is identified in the selected sample, a determination is made
 
whether the same condition or situation is applicable to other connections not tested.
A sample of non-EQ electrical cable connections metallic parts will be tested prior to the period of extended operation with an inspection frequency of at least once every 10 years.
Staff Evaluation. The staff review of LRA Section 3.6.2.3.3 identified an area in which additional information was necessary to complete the review of the applicant's program elements. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 3.6.2.3.3 dated April 20, 2006, the staff requested that the applicant provide an AMP with the 10 elements to manage the aging effects of electrical components, metallic parts, or for
 
justification for not requiring an AMP. In its response dated May 9, 2006, the applicant committed (Commitment No. 64) to develop and implement the Electrical Cable Connections - Metallic Parts- Not Subject to 10 CFR 50.49 Environmental Qualification Requirement Program to manage
 
aging effects of electrical connections.
To determine whether the applicant's AMP is adequate to manage the effect of aging so that intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation the staff evaluated seven elements. The staff reviewed those portions of the applicant's program for which the applicant claimed consistency with GALL AMP XI.E6 and found them
 
consistent with this GALL AMP. the staff's review concluded that the applicant's program provided
 
reasonable assurance that electrical components, metallic parts, will be adequately managed.
The staff finds that the applicant's program conforms to the recommended GALL AMP XI.E6.
The staff reviewed the Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requi rement Program against the AMP elements in the GALL Report, SRP-LR Section A.1.2.3, and Table A.1-1 and focused on how the program
 
manages aging effects through the effective incor poration of 10 program elements (i.e., "scope of program," "preventive actions," "
parameters monitored or inspected," "detection of aging effects,"
"monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process,"
 
"administrative controls," and "operating experience").
The applicant indicated that "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-controlled QA program. The staff's evaluation of the QA program is addressed in SER Section 3.0.4. The remaining seven elements are
 
discussed as follows.    (1) Scope of Program - In its letter, the applicant stated that the metallic parts of electrical cable connections not subject to 10 CFR 50.49 associated with cables within the scope of
 
license renewal are part of this program regardless of their association with active or
 
passive components The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.1 and concludes that this program attribute is
 
acceptable.
3-37  (2) Preventive Actions - In its letter, the applicant stated that no actions are taken as part of this program to prevent or mitigate aging degradation.
No actions are taken as part of this program to prevent or mitigate aging degradation, and the staff identified no need for such actions.
The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.2 and concludes that this program attribute is
 
acceptable.  (3) Parameters Monitored and Inspected - In its letter, the applicant stated that this program will focus on the metallic parts of electrical cable connections. The monitoring includes
 
loosening of bolted connections due to thermal cycling, ohmic heating, electrical
 
transients, vibration, chemical contamination, corrosion, and oxidation. A representative
 
sample of electrical cable connections is tested. The following factors are considered for
 
sampling: application (high, medium and low voltage), circuit loading, and location (high
 
temperature, high humidity, vibration, etc.) with respect to connection stressor. The
 
technical basis for the sample selected is documented.
The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3 and concludes that this program attribute is
 
acceptable.  (4) Detection of Aging Effects - In its letter, the applicant stated that electrical cable connections - metallic parts - not subject to 10 CFR 50.49 environmental qualification
 
requirements within the scope of license renewal will be tested at least once every 10
 
years. This period is adequate to preclude failures of the electrical connections since
 
experience shows that aging degradation is a slow process. Testing will utilize
 
thermography. A 10-year testing interval w ill provide during a 20-year period two data points which can be used to characterize the degradation rate. The first tests for license
 
renewal are to be completed before the period of extended operation.
The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.4 and concludes that this program attribute is
 
acceptable.  (5) Monitoring and Trending - In its letter, the applicant stated that trending actions are not included as part of this program.
The staff finds this statement acceptable because the ability to trend inspection results is limited.The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.5 and concludes that this program attribute is
 
acceptable.  (6) Acceptance Criteria - In its letter, the applicant stated that the acceptance criteria for each test are defined by the specific type of test performed and the specific type of cable
 
connections tested.
3-38 The staff finds this statement unacceptable because the applicant provided no acceptance criteria for the testing selected (thermography). On June 2, 2006, the applicant provided
 
supplemental information in which the "acceptance criteria" program element was revised.
 
In its supplemental letter, the applicant stated that, "Measured temperature by
 
thermography should be evaluated against baseline(s), if available, or similarly configured component(s). Consideration should be given to ambient temperature, electrical load, system operating parameters and visual indications when determining if measured
 
temperature is acceptable or requires further evaluation." The staff finds this statement
 
acceptable.
The staff confirmed that the this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.6 and concludes that this program attribute is
 
acceptable.  (10) Operating Experience - In its letter, the applicant stated that this AMP is new. As there is no adverse OCGS operating experience inform ation, this new AMP will be implemented inalignment with GALL AMP XI.E6 recommendations, including assessment of stressors, implementation of a sampling approach, and a frequency of every 10 years with the first
 
inspection prior to the period of extended operation.
The staff finds the applicant's statement unacceptable because the applicant did not include industry operating experience. On June 2, 2006, the applicant provided
 
supplemental information. In its supplemental letter, the applicant stated that operating
 
experience, both internal and external, will be used to enhance this program, prevent repeat events, and prevent events that have occurred at other plants from occurring at OCGS. This prevention will be implemented through the OCGS operating experience process. The process screens, evaluates, and acts on operating experience documents
 
and information to prevent or mitigate the consequences of similar events. Additionally, the process for managing programs requires the review of program-related operating
 
experience by the program owner. The staff finds this process acceptable.
The staff confirmed that this program element satisfies the criterion defined in the GALL Report and SRP-LR Section A.1.2.3.10 and concludes that this program attribute is
 
acceptable.
UFSAR Supplement. In its letter dated May 9, 2006, the applicant provided the UFSAR supplement for the Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirement s Program. The applicant committed (Commitment No. 64) to manage the aging effects of metallic parts during the period of extended operation. The
 
staff reviewed this section and determined that the information in the UFSAR 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 Electrical Cable Connections - Metallic Parts - Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program and RAI
 
response, the staff determined that all the program elements are consistent with the GALL
 
Report. The staff concludes that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-39 The staff also reviewed the UFSAR supplement for this AMP and concludes that, with the inclusion of Commitment No. 64, 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 that the following AMPs are, or will be, consistent with the GALL Report, with exceptions or enhancements:
* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)
* Water Chemistry (B.1.2)
* Reactor Head Closure Studs (B.1.3)
* BWR Vessel ID Attachment Welds (B.1.4)
* BWR Feedwater Nozzle (B.1.5)
* BWR Control Rod Drive Return Line Nozzle (B.1.6)
* BWR Stress Corrosion Cracking (B.1.7)
* BWR Penetrations (B.1.8)
* BWR Vessel Internals (B.1.9)
* Bolting Integrity (B.1.12)
* Open-Cycle Cooling Water System (B.1.13)
* Closed-Cycle Cooling Water System (B.1.14)
* Boraflex Rack Management Program (B.1.15)
* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.1.16)
* BWR Reactor Water Cleanup System (B.1.18)
* Fire Protection (B.1.19)
* Fire Water System (B.1.20)
* Aboveground Outdoor Tanks (B.1.21)
* Fuel Oil Chemistry (B.1.22)
* Reactor Vessel Surveillance (B.1.23)
* Buried Piping Inspection (B.1.26)
* ASME Section XI, Subsection IWE (B.1.27)
* ASME Section XI, Subsection IWF (B.1.28)
* Structures Monitoring Program (B.1.31)
* RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (B.1.32)
* Electircal Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrument Circuits (B.1.35) 3-40
* Metal Fatigue of Reactor Coolant Pressure Boundary (B.3.1)
* Bolting Integrity - FRCT (B.1.12A)
* Closed-cycle Cooling Water System - FRCT (B.1.14A)
* Aboveground Steel Tanks - FRCT (B.1.21A)
* Fuel Oil Chemistry - FRCT (B.1.22A)
* One-Time Inspection - FRCT (B.1.24A)
* Selective Leaching of Materials - FRCT (B.1.25A)
* Buried Piping Inspection - FRCT (B.1.26A)
* Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT (B.1.38)
* Lubricating Oil Analysis Program - FRCT (B.1.39)
* Buried Piping and Tank Inspection-Met Tower Repeater Engine Fuel Supply (B.1.26B)
For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) and/or enhancement(s), the staff performed an audit and review to confirm that those attributes or
 
features of the program, for which the applicant claimed consistency with the GALL Report, were
 
indeed consistent. The staff also reviewed the exception(s) and/or enhancement(s) to the GALL
 
Report to determine whether they were acceptable and adequate. The results of the staff's audits
 
and reviews are documented in the following sections.3.0.3.2.1  ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD
 
Summary of Technical Information in the Application. In LRA Section B.1.1, the applicantdescribed the existing ASME Section XI Inservice Inspection (ISI), Subsections IWB, IWC, and
 
IWD Program as consistent, with exceptions and enhancements, with GALL AMP XI.M1, "ASMESection XI Inservice Inspection, Subsections IWB, IWC, and IWD." The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is part of the ISI program and provides for monitoring the condition of reactor coolant pressure retaining
 
piping and components within the scope of license renewal. It also provides for condition
 
monitoring of reactor internal components within the scope of license renewal and of the isolation
 
condenser. The program is implemented through procedur es that require examinations consistentwith ASME Code Section XI, and through specific tasks that require the ASME Section XI
 
augmentation activities identified in the GALL Report. The program includes:
* Cracking monitoring for susceptible ISI components subject to a steam or treated water environment, through volumetric examinations of pressure-retaining welds and their
 
heat-affected zones in piping components.
* Cracking monitoring of the reactor vessel flange leak detection line.
* Cracking monitoring of the isolation condensers through surface and volumetric examinations of pressure-retaining nozzle welds and their heat-affected zones subject to a
 
steam or reactor water environment.
* Loss of material monitoring of portions of the isolation condensers subject to a steam or reactor water environment through system pressure tests.
3-41
* Cracking detection of the isolation condenser tube side components due to SCC and IGSCC or loss of material detection due to general and pitting and crevice corrosion
 
through temperature and radioactivity monitoring of the shell-side (cooling) water, eddy
 
current inspections of the tubes, and inspections (VT or UT) of the channel head and tube
 
sheets.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.1. The staff reviewed the exceptions
 
and enhancements and their justifications to determine whether the AMP, with the exceptions and
 
enhancements, remained adequate to manage the aging effects for which it was credited.The staff reviewed those portions of the ASME Section XI Inservice Inspection, Subsections IWB,IWC, and IWD Program for which the applicant claimed consistency with GALL AMP XI.M1 and
 
found them consistent. Furthermore, the staff concluded that the applicant's program provides
 
reasonable assurance that the aging effects for which this program was credited will be adequately managed. The staff found that the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program conforms to the recommended GALL AMP XI.M1, with
 
exceptions and an enhancement described below.
Exception 1. In LRA Section B.1.1, the applicant stated an exception to the GALL Report program elements "scope of program," "detection of aging effects," "monitoring and trending," "acceptance
 
criteria," and "corrective actions." Specifically, the exception stated that:
NUREG-1801 indicates that the aging of the isolation condenser is to be managedby ASME Section XI Inservice Inspection (ISI) Subsection IWB (for Class 1
 
components). However, the Oyster Creek isolation condensers are ISI Class 2 on
 
the tube side and ISI Class 3 on the shell side. Therefore, Subsections IWC and
 
IWD are used, as Class 1 requirements do not apply.
The staff reviewed the OCGS ISI program plan (OC-1) titled "OCGS ISI Program Plan Fourth Ten-Year Inspection Interval," Revision 1, dated September 30, 2004. Appendix B of that
 
document, "Class 1 Systems Summary," page 2-53, c onfirms that the isolation condenser system has Class 1, 2, and 3 components. A transition from Class 1 to Class 2 occurs at isolation valves
 
V-14-31, V-14-32, V-14-34, and V-14-35. With the information in this document, the staff was able
 
to verify that the isolation condenser tubes are Class 2 and the shell is Class 3, while piping
 
connected directly to the reactor vessel is Class 1. This arrangement is part of the CLB. On this
 
basis, the staff finds this exception acceptable.
Exception 2. In LRA Section B.1.1, the applicant stated an exception to the GALL Report program elements "detection of aging effects," "monitoring and trending," "acceptance criteria," and
 
"corrective actions." Specifically, the exception stated that:NUREG-1801 specifies the 2001 ASME Section XI B&PV Code, 2002 and 2003 Addenda for Subsections IWB, IWC, and IWD. The current Oyster Creek ISI
 
Program Plan for the fourth ten-year inspection interval effective from
 
October 15, 2002 through October 14, 2012, approved per 10CFR50.55a, is based on the 1995 ASME Section XI B&PV Code, 1996 addenda. The next 120-month
 
inspection interval for Oyster Creek will incorporate the requirements specified in 3-42 the version of the ASME Code incorporated into 10 CFR 50.55a 12 months before the start of the inspection interval.
In reviewing this exception the staff noted that, in accordance with 10 CFR 50.55a, the ASME Code edition to be used for ISI inspections is the latest edition available 12 months prior to the
 
start of the ten-year inspection interval. In the LRA, the applicant stated that it is currently in its
 
fourth ten-year inspection interval effective from October 15, 2002 through October 14, 2012. For this interval the 1995 ASME Section XI B&PV Code with 1996 addenda is the appropriate edition
 
to be used; therefore, the staff determined that this exception is justified and acceptable.
Enhancement. In LRA Section B.1.1, the applicant stated the following enhancement in meeting the GALL Report program elements "scope of progr am," "parameters monitored or inspected,"
and "monitoring and trending." Specifically, the enhancement stated:
Enhancement activities, which are in addition to the requirements of ASMESection XI, Subsections IWB, IWC, and IWD, consist of temperature and
 
radioactivity monitoring of the isolation condenser shell-side (cooling) water, eddy
 
current testing of the tubes, and inspections (VT or UT) of the channel head and
 
tube sheets, with verification of the effectiveness of the program through
 
monitoring and trending of results.
Since the Oyster Creek isolation condenser tube bundles were replaced in the "A" isolation condenser in 2000 and in the "B" isolation condenser in 1998, utilizing
 
upgraded materials that are more resistant to intergranular stress corrosion
 
cracking, these inspections will be performed during the first ten years of the
 
extended period of operation.
The staff noted that in Table IV.C1 of the GALL Report item IV.C1-4 for isolation condensercomponents states that GALL AMP XI.M1 is to be augmented to detect cracking due to SCC. In
 
addition, the GALL Report stated that verification of the program's effectiveness is necessary to
 
ensure that significant degradation does not occur and that the component's intended function will
 
be maintained during the period of extended operation. An acceptable verification program
 
includes temperature and radioactivity monitoring of the shell side water and eddy current testing
 
of the tubes. Therefore, the applicant's enhancement to add temperature and radioactivity
 
monitoring of the isolation condenser shell-side (cooling) water, eddy current testing of the tubes, and inspections (VT or UT) of the channel head and tube sheets with verification of the
 
effectiveness of the program through monitoring and trending of results will make the applicant's
 
AMP consistent with the recommendations of the GALL Report AMP. On this basis, the staff finds
 
this enhancement acceptable.
Operating Experience. In LRA Section B.1.1, the applicant explained that OCGS has successfully identified indications of age-related degradation prior to the loss of the intended function(s) of the
 
components and has taken appropriate corrective actions through evaluation, repair, or replacement of the components in accordance with ASME Code Section XI and station
 
implementing procedures. Some site-specific ex amples are provided. Periodic self-assessments of the ISI programs have been performed to ident ify areas that need improvement to maintain program quality.
An NDE examination of ESW piping for corrosion in 2002 identified an elbow with a measured wall thickness below the minimum. An evaluation provided an operability justification until the 3-43 following outage when the elbow was replaced. During a Class 1 pressure test of core spray piping following a refueling outage leakage was observed at a field weld and repaired via the
 
corrective action process. An expanded exami nation of similar type welds found no additional indications, supporting the conclusion that the observed defect was not a generic issue.
The staff reviewed the operating experience provided in the LRA and in the AMP basis document, interviewed the applicant's technical personnel, and confirmed that the plant-specific operating
 
experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's ASME Section XI Inservice Inspection, Subsection IWB, IWC and IWD Program will adequately
 
manage the aging effects for which this AMP is credited in the LRA.
UFSAR Supplement. In LRA Section A.1.1, the applicant provided the UFSAR supplement for theASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff
 
reviewed this section and determined that the information in the UFSAR supplement provides 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 Inservice Inspection, Subsections IWB, IWC, and IWD Program, the staff determined that those program
 
elements for which the applicant claimed consistency with the GALL Report are consistent. In
 
addition, the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. Also, the
 
staff reviewed the enhancements and confirmed that their implementation prior to the period of
 
extended operation will make the 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).
3.0.3.2.2  Water Chemistry
 
Summary of Technical Information in the Application. In LRA Section B.1.2, the applicant described the existing Water Chemistry Program as consistent, with exceptions, with GALLAMP XI.M2, "Water Chemistry."
The Water Chemistry Program's activities consis t of measures that are used to manage aging of piping, piping components, piping elements, and heat exchangers exposed to reactor water, condensate and feedwater, control rod drive (CRD) water, demineralized water storage tank water (DWST), condensate storage tank water, torus water, and spent fuel pool water, all classified as
 
treated water for aging management. The program activities monitor and control water chemistry
 
by station procedures and processes based on Boiling Water Reactor Vessel Internals Project (BWRVIP)-130, "BWR Vessel and Internals Project BWR Water Chemistry Guidelines,"
 
2004 Revision, for the prevention or mitigation of loss of material, reduction of heat transfer, and
 
cracking aging effects. The Water Chemistry Program is also credited for mitigating loss of
 
material and cracking for components exposed to sodium pentaborate and boiler-treated water
 
environments. As specified by the GALL Repor t, the Water Chemistry Program may not be effective in low-flow or stagnant areas. The O ne-Time Inspection Program includes provisions 3-44 specified by the GALL Report for verification of chemistry control and confirmation of the absence of loss of material and cracking in stagnant areas in piping systems and components.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.2. The staff reviewed the exceptions
 
and their justifications to determine whether the AMP remained adequate to manage the aging
 
effects for which it was credited.
The staff reviewed those portions of the Water Chemistry Program for which the applicant claimedconsistency with GALL AMP XI.M2 and found them consistent. Furthermore, the staff concluded
 
that the applicant's Water Chemistry Program provides reasonable assurance of mitigation of
 
degradation caused by corrosion and SCC in components exposed to reactor or treated water.
 
The staff found that the applicant's Water Chemistry Program conforms to the recommended GALL AMP XI.M2 with exceptions described below.
Exception 1. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "parameters monitored or inspected." Specifically, the exception stated:
NUREG-1801 indicates that water chemistry control is in accordance with BWRVIP-29 for water chemistry in BWRs. BWRVIP-29 references the 1996
 
revision of EPRI TR-103515, "BWR Water Chemistry Guidelines." The Oyster
 
Creek water chemistry program is based on BWRVIP-130, which is the 2004
 
Revision of "BWR Water Chemistry Guidelines." EPRI periodically updates the
 
water chemistry guidelines, as new information becomes available.
The staff recognized that the SER for the Dresden/Quad Cities LRA (NUREG-1769) has accepted BWRVIP-79, which is Revision 2 of the EPRI document EPRI-TR-103515, published in 2000.
 
Therefore, the staff reviewed the differences between the 2000 revision (BWRVIP-79) and 2004
 
revision (BWRVIP-130). The review demonstrated that the use of the 2004 revision of the EPRI
 
BWR water chemistry guidelines is an acceptable method of controlling water chemistry
 
consistent with the GALL Report recommendations. On this basis, the staff finds this exception
 
acceptable.
Exception 2. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "parameters monitored or inspected." Specifically, the exception stated:
In transitioning from TR-103515-R2 to BWRVIP-130, Oyster Creek has reviewed BWRVIP-130 and has determined that the most significant difference from
 
Revision 2 is that a recent policy of the U.S. nuclear industry commits each nuclear
 
utility to adopting the responsibilities and processes on the management of
 
materials aging issues described in "NEI 03-08: Guideline for the Management of
 
Materials Issues." Section 1 of the BWR Water Chemistry Guidelines specifies
 
which portions of the document are "Mandatory," "Needed," or "Good Practices,"
 
using the classification described in NEI 03-08. A new section (section 7) has been
 
added and contains recommended goals for water chemistry optimization. These
 
are "good practice" recommendations for targets that plants may use in optimizing
 
water chemistry that balances the conflicting requirements of materials, fuel and
 
radiation control. Significant time and expense may be required to meet these
 
targets; thus efforts to achieve these goals should be considered in the context of 3-45 the overall strategic plan for the plant. Therefore, Oyster Creek is not committing to obtaining these targets. All other changes do not change the original intent of
 
revision 2 implementation.
The staff reviewed the water chemistry guidelines of both BWRVIP-79 (EPRI TR-103515-R2) and BWRVIP-130 (EPRI TR-1008192) and noted that the new Section 7 in BWRVIP-130 contains
 
goals for water chemistry optimization. These are "good practice" recommended targets that
 
plants may use in optimizing water chemistry in order to balance the conflicting requirements of
 
materials, fuel, and radiation control. The staff also noted that BWRVIP-130 does not change the
 
original intent of the Revision 2 guidelines in BWRVIP-79. The applicant was asked to clarify the
 
details of this exception as it was not clear why it was needed. Based on the applicant's response, the staff determined that not all of the good practices recommended in BWRVIP-130 are
 
applicable to or achievable by OCGS. However, the applicant had implemented those practices
 
applicable to the plant and beneficial to the total water chemistry optimization program. For
 
example, an excess of feedwater zinc can be harmful to reactor fuel but beneficial for radiation
 
field control. At OCGS, the applicant establishes an optimum zinc program to protect the fuel as
 
well as manage radiation control.
The staff determined that the applicant had implemented those good practice recommendations applicable to the conditions of the reactor water and beneficial to the total water chemistry
 
optimization program. On this basis, the staff finds this exception acceptable.
Exception 3. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "parameters monitored or inspected." Specifically, the exception stated:
NUREG-1801 indicates that hydrogen peroxide is monitored to mitigate degradation of structural materials. The Oyster Creek program does not monitor for
 
hydrogen peroxide because the rapid decom position of hydrogen peroxide makes reliable data exceptionally difficult to obtain and BWRVIP-130 Section 6.3.3, "Water Chemistry Guidelines for Power Operation," does not address monitoring
 
for hydrogen peroxide. Hydrogen addition to feedwater has been applied in order
 
to mitigate occurrence of IGSCC of structural materials by suppressing the
 
formation of hydrogen peroxide. The hydrogen addition has accomplished an
 
Electrochemical Corrosion Potential (ECP) value less than -230mV, SHE (Standard Hydrogen Electrode). By maintaining a low ECP less than -230mV, SHE, the reactor water chemistry minimizes the effects from hydrogen peroxide
 
below the threshold that prompted the issue raised in NUREG 1801. Oyster Creek
 
uses the ISI program to investigate whether structural degradation in potentially
 
affected locations is ongoing. Oyster Creek's ISI program provides for condition
 
monitoring of the reactor vessel, reactor internal components and ASME Class 1 pressure retaining components in accordance with ASME Section XI, Subsection
 
IWB. Indications and relevant conditions detected during examinations are evaluated in accordance with ASME Section XI Articles IWB-3000, for Class 1.
As part of the audit, the staff interviewed the applicant's technical personnel to discuss issues related to this exception. During the interview, the applicant stated that hydrogen addition to
 
feedwater had been applied to mitigate IGSCC in structural materials by suppressing the
 
formation of hydrogen peroxide. The hydrogen addition has accomplished an ECP value less than
 
-230mV, SHE. By maintaining a low ECP less than -230mV, SHE, the reactor water chemistry
 
minimizes the effects from hydrogen peroxide.
3-46 The staff recognized that the ECP quantifies the oxidizing power of a solution in contact with a specific metal surface. ECPs of reactor internals component materials are very sensitive to the
 
concentration of oxygen, hydrogen, and hydrogen peroxide (which determine the ECP) and
 
therefore differ at locations within the BWR reactor system. BWRVIP-79 Section 5.3 discusses
 
locations suitable for measuring the ECP (Figure 5.5) and Section 5.4 provides alternate ECP
 
estimation techniques. Therefore, during the audit the staff requested that the applicant clarify
 
how the threshold ECP level is maintained within the reactor system without monitoring the
 
hydrogen peroxide level.
In its response, the applicant stated that the ECP is directly monitored with ECP probes in the B recirculation loop via the reactor water cleanup (RWCU) system (location E in Figure 5.5 of
 
BWRVIP-79). In addition, the dissolved oxygen is monitored in the reactor water as a secondary
 
parameter to ensure that mitigation is maintained in the recirculation loops. To assure that an
 
adequate excess of hydrogen relative to oxygen is present to reduce the ECP below -230 mV (SHE) at target locations during power operation, the measured reactor water hydrogen-to-oxygen
 
molar ratio (an alternative to ECP per Appendix E of BWRVIP-130) is maintained at greater than 3
 
during hydrogen injection. Thus, OCGS has chosen a strategy that uses ECP or the measured
 
molar ratio of hydrogen to oxygen as the primary indicator of IGSCC mitigation with proof of
 
sufficient catalyst loading. According to OCGS implementing procedure CY-AB-120-1000 (Revision 2), Section 4.6B, verification of mitigation can also be based on radiolysis modeling
 
using an EPRI model as an alternative to ECP measurement.
The staff determined that the Water Chemistry Program includes activities that are adequate to ensure that the reactor water contains an adequate excess of hydrogen relative to oxygen to
 
reduce the ECP below -230 mv (SHE) at target locations. On this basis, the staff finds this
 
exception acceptable.
Exception 4. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "parameters monitored or inspected." Specifically, the exception stated:
NUREG-1801 indicates that dissolved oxygen is monitored. Consistent with the guidance provided in BWRVIP-130, condensate storage tank, demineralized water
 
storage tank water, spent fuel pool water and torus water are not sampled for
 
dissolved oxygen. The Oyster Creek chemistry procedures require monitoring of
 
conductivity, chlorides, sulfates and total organic carbon (TOC) in accordance with
 
limits set by BWRVIP-130 as an alternate method for ensuring component integrity.
During the interview, the applicant stated that the water in the CST, DWST, spent fuel pool, and torus are exposed to atmospheric conditions (i.e., air-saturated) and hence measuring dissolved
 
oxygen in the water at these locations would not provide the actual oxygen content nor help
 
determine the quality of the water. The applicant was asked to explain what alternate parameters
 
are monitored for the water in these tanks exposed to the atmosphere and therefore containing
 
water saturated with oxygen. In its response, the applicant stated that dissolved oxygen is
 
monitored routinely for the feedwater, condensate, and CRD water systems as recommended in
 
BWRVIP-130 and is thus consistent with the GALL Report. However, the tanks or reservoirs of
 
these systems are monitored for conductivity, chlorides, sulfates, and TOC in accordance with limits set by BWRVIP-130, Appendix B, as an alternate method for ensuring component integrity.
3-47 The staff determined that the Water Chemistry Program monitors the water within both the subject systems and their tanks or reservoirs as recommended in BWRVIP-130. On this basis, the staff
 
finds this exception acceptable.
Exception 5. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "parameters monitored or inspected." Specifically, the exception stated:
NUREG-1801 indicates that water quality (pH and conductivity) is maintained in accordance with established guidance. However, per BWRVIP-130, "BWR Water
 
Chemistry Guidelines," Section 8.2.1.11, pH measurement accuracy in most BWR
 
streams is generally suspect because of the dependence of the instrument reading
 
on ionic strength of the sample solution. In addition, the monitoring of pH is not
 
discussed in BWRVIP-130, Appendix B for condensate storage tank, demineralized water storage tank, or torus water. pH is not monitored for torus
 
water, however pH is monitored in the CST & DWST. Alternate methods are
 
applied to monitor the water chemistry of the torus in lieu of direct pH
 
measurements. The Oyster Creek chemistry procedures require monitoring of
 
conductivity, chlorides and sulfates in accordance with limits set by BWRVIP-130.
In reviewing this exception, the staff noted that OCGS monitors conductivity, chlorides, sulfates, and TOC in the torus per BWRVIP-130, Table B-3, which does not include pH as one of the
 
parameters. The applicant was asked to explain the alternate method used to monitor pH in the
 
torus water. In its response, the applicant stated that a periodic pH analysis has found torus water
 
pH near neutral (i.e., 6.6 - 7.4) based on measurements during the last 5 years (July 2001 - 6.7;
 
March 2002 -7.0; July 2003 - 6.9; April 2005 - 7.4; and June 2005 - 6.6). The applicant also stated
 
that this pH analysis will continue during the period of extended operation.
The staff determined that the applicant had been routinely monitoring parameters suggested in the BWRVIP-130 and, in addition, performing pH analysis of the torus water periodically to ensure
 
its quality. On this basis, the staff finds this exception acceptable.
Exception 6. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "detection of aging effects." Specifically, the exception stated:
Aging of Standby Liquid Control (SBLC) system components not in the reactor coolant pressure boundary section of SBLC system relies on monitoring and
 
control of SBLC makeup water chemistry. The makeup water is monitored in lieu of
 
the storage tank, because the sodium pentaborate that is maintained in the storage
 
tank would mask most of the chemistry parameters monitored. The effectiveness of
 
the water chemistry program will be verified by a one-time inspection of the SBLC
 
system as discussed in the One-Time Inspection (B.1.24) aging management
 
program. As part of the audit the staff interviewed the applicant's technical personnel to discuss issues related to this exception. During the interview the applicant stated that aging of the SBLC system
 
components relies on monitoring and control of SBLC makeup water chemistry. The makeup
 
water is monitored in lieu of the storage tank because the sodium pentaborate maintained in the
 
storage tank would mask most of the chemistry parameters monitored. The applicant claimed that
 
the effectiveness of the Water Chemistry Program will be verified by a one-time inspection of the
 
SBLC system as discussed in the One-time Inspection Program. The applicant was asked to 3-48 confirm that the one-time inspection will consider the SBLC pump casing and associated tank discharge piping and valve bodies in addition to the tank. In its response, the applicant stated that
 
one stainless steel sample of the entire system (including the piping and fittings, tanks, thermowells, and valve bodies) will be selected for thickness measurements and crack detection
 
by a volumetric examination such as UT. Since the SBLC is a standby system, any section of pipe (with the smallest thickness compared to valve and pump bodies or other pipe fittings) containing
 
sodium pentaborate represents a "worst-case" location.
The staff determined that the applicant will select a "worst-case" sample from the SBLC system in the One-time Inspection Program, which will reasonably assure adequate management of the
 
aging effects for this system. On this basis, the staff finds this exception acceptable.
Operating Experience. In LRA Section B.1.2, the applicant explained that periodic self-assessments of water chemistry activities continue to identify areas that need improvement to
 
maintain the quality performance of the activity. The Water Chemistry Program has identified
 
parameters outside the established specifications. Increased sampling and actions to bring the
 
parameters back into specification were initiated. The chemistry excursion was then documented
 
in a condition report in accordance with plant administrative procedures. The corrective action
 
process ensures that adverse conditions are promptly corrected. If the deficiency is assessed to
 
be significantly adverse the cause of the condition is determined and a corrective action plan is
 
developed to prevent repetition. Some examples are as follows:
* The demineralized water system was contaminated due to a cross-connection with the fuel pool. The system was flushed and use of demineralized water required chemistry
 
sampling to ensure that the water was "clean." A plan was developed to sample the
 
demineralized water system from many loca tions. The completion of this plan enabled the demineralized water system to be declared "clean" again.
* There have been some instances of reactor water sulfate levels exceeding Action Level 1 limits of 5 ppb. Increased sampling and corrective actions (such as placing two RWCU
 
pumps inservice) were implemented.
* A resin ingress caused by failure of the underdrain system occurred in one of the condensate demineralizers. This event was entered into the corrective action process and
 
the apparent cause was determined to be incomplete work in the underdrain installation
 
four years prior.
In its PBDs the applicant stated that a review of industry operating experience has confirmed that IGSCC has occurred in small and large diameter BWR piping made of austenitic stainless steels
 
and nickel-based alloys. Significant cracking has occurred in recirculation, core spray, residual
 
heat removal, and RWCU systems piping welds. IGSCC has also occurred in a number of vessel
 
internal components, including core shroud, access hole cover, top guide, and core spray
 
spargers as referenced in NRC Bulletin 80-13, IN 95-17, GL 94-03, and NUREG-1544. No
 
occurrence of SCC in piping and other component s in standby liquid control systems exposed to sodium pentaborate solution has ever been reported as referenced in NUREG/CR-6001.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
3-49 On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel the staff concludes that the applicant's Water
 
Chemistry Program will adequately manage the aging effects identified in the LRA for which this
 
AMP is credited.
UFSAR Supplement. In LRA Section A.1.2, the applicant provided the UFSAR supplement for the Water Chemistry Program. The staff reviewed this section and determined that the information in
 
the UFSAR supplement provides 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 Water Chemistry Program, the staff determined that those program elements for which the applicant claimed consistency with
 
the GALL Report are consistent. In addition, the staff reviewed the exceptions and their
 
justifications and determined that the AMP, with the exceptions, is adequate to manage the aging
 
effects for which it is credited. The staff concludes that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.3  Reactor Head Closure Studs
 
Summary of Technical Information in the Application. In LRA Section B.1.3, the applicant described the existing Reactor Head Closure Studs Program as consistent, with an exception, with GALL AMP XI.M3, "Reactor Head Closure Studs."
The Reactor Head Closure Studs Program prov ides for condition monitoring and preventive activities to manage stud cracking. The program is implemented through station procedures based on the examination and inspection requirements specified in ASME Code Section XI, Table IWB-2500-1, and preventive measures described in RG 1.65, "Materials and Inspection for Reactor Vessel Closure Studs."
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.3. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it was credited.
The staff reviewed those portions of the Reactor Head Closure Studs Program for which theapplicant claimed consistency with GALL AMP XI.M3 and found them consistent. Furthermore, the staff concluded that the applicant's Reactor Head Closure Studs Program provides
 
reasonable assurance that the effects of cracking due to SCC/IGSCC and loss of material due to
 
wear will be adequately managed so that the intended functions of components within the scope
 
of license renewal will be maintained during the period of extended operation. The staff found that
 
the applicant's Reactor Head Closure Studs Program conforms to the recommendations in GALL AMP XI.M3, "Reactor Head Closure Studs," with an exception described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "parameters monitored/ inspected," "detection of aging effects," "monitoring and trending," and
 
"acceptance criteria." Specifically, the exception stated:
3-50 The current ASME code of record for ISI at Oyster Creek is the 1995 Edition through the 1996 Addenda.
The applicant stated in the LRA that for justification of exceptions to the ISI program see theASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff reviewed the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program
 
and documented its acceptability in SER Section 3.0.3.2.1. On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In LRA Section B.1.3, the applicant explained that OCGS is in its fourth ISI inspection interval. In the history of the ISI Program no evidence of head stud cracking has been
 
found. The reactor head closure studs, nuts, washers, and bushings have been coated with a
 
manganese phosphate surface treatment. The operating experience for these components
 
indicates that nicks, scratches, gouges, and thread damage have occurred due to maintenance
 
activities during refueling outages. This normal wear type of damage was determined to be
 
acceptable for continued service. There have been no deficiencies attributed to distortion/plastic
 
deformation from stress relaxation or loss of material due to mechanical wear, evidence that the
 
AMP is effective.
In its PBDs the applicant stated that a review of industry operating experience has confirmed that cracking due to SCC has occurred in reactor head studs. A review of plant operating experience
 
at OCGS shows that cracking of the head studs from SCC, IGSCC, and loss of material due to
 
wear has not occurred.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Reactor Head Closure Studs Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.3, the applicant provided the UFSAR supplement for the Reactor Head Closure Studs Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exception, is adequate to manage the
 
aging effects for which it is credited. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes
 
that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-51 3.0.3.2.4  BWR Vessel ID Attachment Welds Summary of Technical Information in the Application. In LRA Section B.1.4, the applicant described the existing BWR Vessel ID Attachment We lds Program as consistent, with exceptions,with GALL AMP XI.M4, "BWR Vessel ID Attachment Welds."
The BWR Vessel ID Attachment Welds Program incorporates the inspection and evaluation recommendations of BWRVIP-48 as well as the water chemistry recommendations of
 
BWRVIP-130. The program is implemented through station procedures that mitigate cracking
 
through water chemistry and monitor for cracking through in-vessel examinations. Reactor vessel attachment weld inspections are implemented through station procedures that are part of ISI and incorporate the requirements of ASME Code Section XI. Inspections are in accordance with
 
ASME Code requirements consistent with BWRVIP-48.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.4. The staff reviewed the exceptions
 
and their justifications to determine whether the AMP, with the exceptions, remained adequate to
 
manage the aging effects for which it is credited.
The inspection guidelines of BWRVIP-48 recommend enhanced visual VT-1 (EVT-1) examination of all safety-related attachments and those nonsaf ety-related attachments susceptible to IGSCC.
The applicant's examination plan applies EVT-1 for all of the ID attachment welds regardless of
 
whether the welds are known to be susceptible to IGSCC. The staff finds this plan acceptable as
 
more conservative than the GALL Report recommendation.
The staff reviewed those portions of the BWR Vessel ID Attachment Welds Program for which theapplicant claimed consistency with GALL AMP XI.M4 and found them consistent. Furthermore, the staff concluded that the applicant's BWR Vessel ID Attachment Welds Program provides
 
reasonable assurance that cracking will be adequately managed and that the intended function of
 
the vessel ID attachments will be maintained consistent with the CLB for the period of extended
 
operation. The staff found that the applicant's BWR Vessel ID Attachment Welds Program conforms to the recommended GALL AMP XI.M4 with exceptions described below.
Exception 1. In the LRA, the applicant identified an exception to the GALL Report program element "preventive actions." S pecifically, the exception stated:
NUREG-1801 indicates that water chemistry control is in accordance with BWRVIP-29 for water chemistry in BWRs. BWRVIP-29 references the 1993
 
revision of EPRI TR-103515, "BWR Water Chemistry Guidelines." The Oyster
 
Creek water chemistry programs are based on BWRVIP-130: "BWR Vessel and
 
Internals Project BWR Water Chemistry Guidelines", which is the 2004 revision of
 
"BWR Water Chemistry Guidelines". For justification of exceptions to the water
 
chemistry program see the Water C hemistry aging management program, B.1.2.
The applicant stated in the LRA that the water chemistry programs are based on BWRVIP-130:
"BWR Vessel and Internals Project BWR Water Chemistry Guidelines", which is the 2004 revision
 
of "BWR Water Chemistry Guidelines." For justification of exceptions to the water chemistry
 
program refer to the Water Chemistry Program in SER Section 3.0.3.2.2 where the staff
 
documents its acceptability. On this basis, the staff finds this exception acceptable.
3-52 Exception 2. In the LRA, the applicant stated an exception to the GALL Report program elements "parameters monitored/ inspected," "detection of aging effects," "monitoring and trending," and
 
"acceptance criteria." Specifically, the exception stated:NUREG-1801 program XI.M9 references ASME Section XI, Table IWB 2500-1 (2001 edition, including the 2002 and 2003 Addenda). Oyster Creek ISI program is based on the 1995 (including 1996 Addenda) version of ASME Section XI. For justification of exceptions to the ISI program see the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD aging management program, B1.1.The staff reviewed this exception as part of its review of the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program and finds it acceptable. The staff's finding is
 
documented in SER Section 3.0.3.2.1.
Operating Experience. In LRA Section B.1.4, the applicant explained that the inspection and testing methodologies have detected no cracking in the attachment welds in the history of the
 
plant. This history is evidence that the Water Chemistry Program has been effective in minimizing
 
the effects of SCC in the attachments welds. The same inspection and testing methodologies are
 
used for the attachments welds as for other reactor internals. These processes have detected
 
cracking in other vessel internals components as described in the operating experience of the
 
BWR Vessel Internals Program.
The staff also reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Vessel ID Attachment Welds Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.4, the applicant provided the UFSAR supplement for the BWR Vessel ID Attachment Welds Program. The staff reviewed this section and determined that
 
the information in the UFSAR supplement provides 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 BWR Vessel ID Attachment Welds Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions
 
and their justifications and determined that the AMP, with the exceptions, is adequate to manage
 
the aging effects for which it is credited. The staff concludes that the applicant has demonstrated
 
that the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes
 
that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-53 3.0.3.2.5  BWR Feedwater Nozzle Summary of Technical Information in the Application. In LRA Section B.1.5, the applicant described the existing BWR Feedwater Nozzle Program as consistent, with an exception and an enhancement, with GALL AMP XI.M5, "BWR Feedwater Nozzle."
The BWR Feedwater Nozzle Program provides for monitoring of feedwater nozzles for cracking through station procedures based on the 1995 Edition through 1996 Addendum of ASME Section XI, Subsection IWB, Table IWB 2500-1. The program specifies periodic UT inspections of
 
critical regions of the feedwater nozzle. Ins pections are at intervals not exceeding 10 years.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.5. The staff reviewed the exception
 
and enhancement and their justifications to determine whether the AMP, with the exception and
 
enhancement, remained adequate to manage the aging effects for which it is credited.
In the LRA, the applicant stated that the original feedwater spargers were replaced in 1977 to address industry-wide feedwater nozzle cracking issues in response to NUREG-0619, "BWR
 
Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking." Each replacement
 
feedwater sparger incorporated a piston ring seal at the single nozzle thermal sleeve to safe end
 
connection and included a flow baffle to better protect the low alloy steel nozzles. Also, the
 
removed stainless steel cladding was removed at the feedwater nozzle areas and all cracks found
 
there were repaired. The feedwater flow cont rol system was also changed to improve system performance and reduce temperature fluctuations at the nozzle bend areas during low power
 
operation. The RWCU system was not rerouted. In accordance with NUREG-0619, the applicant
 
performed liquid penetrant examination (PT) of t he originally cladded surfaces to ensure that no cracks remained in the nozzle area.
During the audit, the staff requested that the applicant discuss the results of the PT examinations performed in 1977. In its response, the applicant stated that the PT examination of the nozzle
 
area during the 1977 inspections detected 54 unacceptable flaws distributed among all four
 
nozzles. Following clad removal of the nozzle inside surface, the inspections were repeated and
 
revealed 12 smaller indications in three of the nozzles: 45-degree nozzle - 5 indications
 
(0.5-1.5 inches long), 135-degree nozzle - no indications, 225-degree nozzle - 4 indications (0.3
 
to 3 inches long), and 315-degree nozzle - 3 indications (0.25 to 1 inch long). These indications
 
were ground out with pencil grinders and surface-polished. Subsequent examinations have
 
identified no new indications.
In its response, the applicant also stated that OCGS continued to inspect the feedwater sparger visually during every subsequent refueling outage and found no sign of degradation. During the
 
1988-89 refueling outage (12R), the applicant performed UTs from outside of all nozzle safe ends, bores, and inside blend radius in accordance with NUREG-0619, Section 4.3.2.3 (i.e., UT
 
inspection and subsequent PT of recordable indications) and detected no reportable indications.
After submitting these results to the staff in 1992 (Appendix VIII UT qualification), the applicant submitted a relief request to eliminate routine PT examination of the feedwater and CRD return
 
line nozzles to which it had committed earlier in response to NUREG-0619 and utilize the
 
phased-array UT technique (most advanced method of UT at the time) as the primary method to
 
detect, characterize, and monitor flaws in these nozzles. On October 4, 1994, the staff approved 3-54 the applicant's request for relief and since then the applicant has performed UT examination of these nozzles in lieu of the PT examination recommended in NUREG-0619.
The staff recognized that relief requests typically apply only to the current inspection interval; therefore, they are not applicable to the period of extended operation and cannot be credited for
 
that period. The applicant was asked to confirm that the relief approved in 1994 has no time limit.
 
In its response, the applicant stated that this particular relief is from a commitment made to meet
 
the recommendations of NUREG-0619 at the time and has no time limit. Moreover, the applicant
 
is still committed to PT examination should any indications of cracking be found based on the UT
 
examination, as recommended in NUREG-0619.
After the relief request, the BWR Owner's Group (BWROG) submitted GE Topical Report GE-NE-523-A71-0594 to the staff. This report specifies a new advanced UT technique and
 
examination of specific regions of the nozzle blend radius and bore. In June 1998, the staff
 
approved this BWR feedwater nozzle inspection report as an alternate to the recommendations
 
set forth in NUREG-0619 subject to the conditions listed in the SER. In August 1999, the BWROG
 
issued Revision 1 of GE Topical Report GE-NE-523-A71-0594-A after incorporating all
 
recommendations listed in the SER. Chapter 4 of the GE report specifies UT requirements as the
 
primary means of inspection. OCGS has committed (Commitment No. 5) to implementing the UT
 
methodology recommended in the GE report to inspect the nozzle in future, including the
 
standard performance demonstration initiative (PDI) UT methodology that meets the requirementsof Appendix VIII of ASME Code Section XI. OCGS is planning to enhance its current augmented
 
inspection program to meet this UT methodology and other conditions set forth by the staff SER
 
prior to the period of extended operation.
The staff reviewed those portions of the BWR Feedwater Nozzle Program for which the applicantclaimed consistency with GALL AMP XI.M5 and found them consistent. Furthermore, the staff
 
concluded that the applicant's BWR Feedwater Nozzle Program provides reasonable assurance
 
of timely detection of cracking in the nozzle area by enhanced inspection of the feedwater nozzles
 
by GE-recommended periodic ultrasonic inspection of critical regions. The staff found that the applicant's BWR Feedwater Nozzle Program conforms to the recommended GALL AMP XI.M5, with an exception and an enhancement described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program," "parameters monitored or in spected," "detection of aging effects," "monitoring and trending," "acceptance criteria," and "corrective actions." Specifically, the exception stated:NUREG-1801 program XI.M5 references ASME Section XI, Table IWB 2500-1 (2001 edition, including the 2002 and 2003 Addenda). Oyster Creek ISI program is
 
based on the 1995 (including 1996 Addenda) version of ASME Section. For justification of exceptions to the ISI program see the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD aging management program, B1.1.The staff reviewed this exception as part of its review of the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program and finds it acceptable. The staff's review is
 
documented in SER Section 3.0.3.2.1.
Enhancement. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," and "monitoring and trending." Specifically, the enhancement stated:
3-55 The Oyster Creek Feedwater Nozzle aging management program will be enhanced to implement the recommendations of the BWR Owners Group Licensing Topical
 
Report General Electric (GE) NE-523-A71-0594. These enhancements will be
 
implemented prior to entering the period of extended operation.
In the LRA, the applicant stated that OCGS is committed to implementing the recommendations in NE-523-A71-0594, Revision 1, prior to the period of extended operation. The applicant's BWR
 
Feedwater Nozzle Program will be enhanced to include the recommendations of the BWROG
 
licensing topical report GE NE-523-A71-0594, Revision 1, which includes UT examination of
 
specific regions of the nozzle blend radius and bore region, UT methodology and personnel
 
qualifications, and fracture mechanics methodology.
The staff reviewed the ISI program plan, OC-1, and found that it had not been updated in the section for the feedwater nozzle inspections because the commitments had been made in
 
response to NUREG-0619. Therefore, the applicant was asked to confirm that the UT examination
 
specified in the GE topical report will be included in this ISI program plan. In its response, the
 
applicant stated that the ISI program plan, OC-1, will be revised at the time this AMP is enhanced
 
prior to the period of extended operation.
The staff finds this enhancement acceptable because, when implemented, the BWR Feedwater Nozzle Program will be consistent with GALL AMP XI.M5 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.5, the applicant explained that it had inspected the feedwater nozzles in 1977 in response to industry experience. Cracks found in the nozzles were
 
repaired. To minimize thermal cycling and fatigue-induced cracking the thermal sleeve was
 
modified with a piston-type design. Subsequent inspections, the most recent in 2000, have found
 
no indication of cracking in the feedwater nozzle, evidence that the thermal sleeve modification
 
has been effective in mitigating the effects of thermal fatigue on the feedwater nozzle.
The staff reviewed past inspection results of the feedwater nozzles since OCGS implemented NUREG-0619 recommendations and found that the UT examination of the nozzle area revealed
 
no new indications. Also, the applicant has been routinely performing inspections of the feedwater
 
spargers and no such degradation of the replacement spargers was noted. Although the applicant
 
claims that the VT-3 visual inspection of the sparger flow holes and welds in the sparger tees and
 
sparger arm are performed at a frequency of at least every fourth refueling outage, as
 
recommended in NUREG-0619, the staff finds no evidence for this claim. However, the applicant
 
will enhance the BWR Vessel Internals Program to include and document the conditions of the
 
feedwater nozzle as well as the CRD return line nozzle thermal sleeves (Commitment No. 9).
The staff reviewed the operating experience provided during the audit and interviewed the applicant's technical personnel to confirm that since the recommendations of NUREG-0619 were
 
implemented, including the installation of repl acement feedwater spargers, this program has detected no cracks in the feedwater nozzle regions at OCGS.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Feedwater Nozzle Program will adequately manage the aging effects identified in the LRA for
 
which this AMP is credited.
3-56 UFSAR Supplement. In LRA Section A.1.5, the applicant provided the UFSAR supplement for the BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides 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 BWR Feedwater Nozzle Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exception, is adequate to manage the
 
aging effects for which it is credited. Also, the staff reviewed the enhancement and confirmed that
 
the implementation of the enhancement prior to the period of extended operation will make the
 
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).
3.0.3.2.6  BWR Control Rod Drive Return Line Nozzle
 
Summary of Technical Information in the Application. In LRA Section B.1.6, the applicant described the existing BWR Control Rod Drive Return Line Nozzle Program as consistent, with exceptions, with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle."
The BWR Control Rod Drive Return Line Nozzle Program provides for monitoring the CRD returnline nozzle for cracking through station ISI procedures based on the ASME Code Section XI, augmented by inspections in accordance with recommendations of NUREG-0619. OCGS
 
requested and received relief from the NRC for the recommendation of NUREG-0619 to perform
 
UT testing in lieu of periodic dye PT. Inspec tions will be at intervals not exceeding 10 years.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.6. The staff reviewed the exceptions
 
and their justifications to determine whether the AMP, with the exceptions, remained adequate to
 
manage the aging effects for which it is credited.
During the audit, the staff requested that the applicant discuss activities performed in response to NUREG-0619. In its response, the applicant stated that OCGS had removed the original CRD
 
return line nozzle thermal sleeve and performed a dye PT on the inside diameter of the nozzle in
 
1977 (7R outage) to address industry-wide CRD return line nozzle-cracking issues in response to
 
NUREG-0619. No indication of cracking was observed at the time. The applicant also stated that, after finding no indications, it had replaced the CRD return line nozzle thermal sleeve with a
 
newly-designed thermal sleeve that directed the fl ow farther into the downcomer region and away from the nozzle area. The new thermal sleeve is a 1-inch schedule 40 pipe attached to the
 
remaining portion of the removed thermal sleeve by an interference fit. The 1-inch pipe increases
 
fluid velocity to minimize the possibility of reentry of hot reactor recirculation flow back into the thermal sleeve, which carries cold CRD water at 100 °F The staff noted that the applicant continued to inspect the CRD return line nozzle visually during every subsequent refueling outage and found no sign of degradation. During the 1991 refueling 3-57 outage (13R), the applicant performed UT from outside of the nozzle in accordance with NUREG-0619, Section 4.3.2.3 (i.e., UT inspection and subsequent PT of recordable indications)
 
and detected no reportable indications.
The staff reviewed those portions of the BWR Control Rod Drive Return Line Nozzle Program forwhich the applicant claimed consistency with GALL AMP XI.M6 and found them consistent with
 
the GALL Report AMP. Furthermore, the staff concluded that the applicant's program provides
 
reasonable assurance of timely detection of cracking in the nozzle area by enhanced inspection
 
of the CRD return line nozzles by NUREG-0619-recommended periodic inspection of critical
 
regions. The staff found that the applicant's BWR Control Rod Drive Return Line Nozzle Program conforms to the recommendations in GALL AMP XI.M6 with exceptions described below.
Exception 1. In the LRA, the applicant stated an exception to the GALL Report program elements "parameters monitored or inspected," "detection of aging effects," "monitoring and trending,"
 
"acceptance criteria," and "corrective actions." Specifically, the exception stated:NUREG-1801 program XI.M6 references ASME Section XI, Table IWB 2500-1 (2001 edition, including the 2002 and 2003 Addenda). Oyster Creek ISI program is based the 1995 (including 1996 Addenda) version of ASME Section XI. For justification of exceptions to the ISI program see the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD aging management program, B1.1.The staff reviewed this exception as part of its review of the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program and finds it acceptable. The staff's review is
 
documented in SER Section 3.0.3.2.1.
Exception 2. In the LRA, the applicant stated an exception to the GALL Report program elements "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending."
 
Specifically, the exception stated:
The Oyster Creek augmented ISI program for the CRD return line nozzle performs ultrasonic examination (UT) testing in lieu of dye penetrant testing (PT). Oyster Creek requested and received relief from the NRC to perform ultrasonic
 
examination (UT) testing in lieu of the periodic PT testing [recommendations]
 
specified in NUREG 0619.
As discussed in SER Section 3.0.3.2.5, in 1992 the applicant submitted a relief request to eliminate routine PT examination of the feedwater and CRD return line nozzles to which it had
 
committed in response to NUREG-0619 and to utilize the phased-array UT technique (most
 
advanced method of UT at the time) as the primary method to detect, characterize, and monitor
 
flaws in these nozzles. On October 4, 1994, the staff approved the applicant's request for relief
 
and since then the applicant has performed UT examination of these nozzles in lieu of the PT
 
examination recommended in NUREG-0619.
The staff recognized that relief requests typically apply only to the current inspection interval; therefore, they do not apply to the period of extended operation and cannot be credited for that
 
period. The applicant was asked to confirm that the relief approved in 1994 has no time limit. In its
 
response, the applicant stated that this particular relief is from a commitment made to meet the
 
recommendations of NUREG-0619 at the time and has no time limit. Moreover, periodic CRD
 
return line nozzle inspections are performed using qualified UT techniques at least once every 10 3-58 years (120 months). The inspection interval is based on fatigue crack growth analyses inaccordance with the methodology in ASME Code Section XI. If UT examination results indicate
 
the presence of a flaw exceeding the ASME Code allowable crack size, OCGS is committed to a
 
PT inspection in the vicinity of the indication to verify the results. Qualification testing by the
 
inspection vendor has demonstrated that the UT technique can reliably detect and size flaws in
 
the areas of interest. Modification to the CRD return line nozzle thermal sleeve has played a
 
major role in the prevention of CRD return line nozzle cracks.
The staff noted that the CRD return line nozzle is included in the ISI program plan under Category B-D, "Full Penetration Welds of Nozzles in Vessels," consistent with the requirements of
 
Table IWB 2500-1. Augmented inspections are performed in accordance with NUREG-0619
 
recommendations.
The staff reviewed the ISI program plan, OC-1, and found that it had not been updated in the section for the CRD return line nozzle inspections because the commitments had been made in
 
response to NUREG-0619. The applicant was asked to confirm that the UT examination
 
technique included in the relief request, or the most advanced technique (Appendix VIII UT
 
qualification), will be included in the ISI program plan. In its response, the applicant stated that the
 
ISI program plan, OC-1, will be revised to reflect the CRD return line nozzle inspections prior to
 
the period of extended operation.
The staff determined that although the applicant takes exceptions to some aspects of the ISI, the current ISI program includes the recommendations of NUREG-0619 and follows the guidelines of
 
the GALL Report. On this basis, the staff determined that this exception is acceptable.
Exception 3. In the LRA, the applicant stated an exception to the GALL Report program elements "acceptance criteria" and "corrective actions." Specifically, the exception stated:NUREG-1801, XI.M6, specifies any detected crack be ground out. Oyster Creek procedures allow a crack that is found unacceptable under IWB-3400 and IWB-3500 to be evaluated under ASME XI, IWB-3600 or repaired by an NRC
 
approved procedure.
During the audit, the staff requested that the applicant clarify the OCGS position stated in this exception. In its response, the applicant stated that all indications and relevant conditions
 
detected during past examinations at OCGS had been evaluated in accordance with ASME Section XI Subsection IWB-3100 for Class 1 components by the criteria of IWB-3512. When a flaw exceeded the applicable acceptance standards of IWB-3400 or IWB-3500, a plant condition report was initiated under applicable procedures. An analytical evaluation in accordance with
 
IWB-3600 or an approved repair in accordance with plant procedure ER-AA-330-002 had been
 
performed. In either case, staff's approval had been required prior to resumption of operation.
The applicant also stated that NUREG-0619 recommends that any cracks found during the initial NUREG-0619 inspection be grounded out unless clad removal is performed. However, the
 
NUREG does not provide guidance if flaws are found in subsequent inspections. OCGS
 
inspections during 1977 and subsequently have found no flaw indications in the CRD return line
 
nozzle. The applicant has followed the ISI guidelines for this nozzle inspection. According to these
 
guidelines, repairs are made if the flaw does not meet the requirements of IWB-3600, in which
 
case crack repairs may use the grind-out option.
3-59The staff noted that the 1995 or later version of the ASME Code Section XI does not contain Sections IWB-4000 for repair and IWB-7000 for replacement as stated in the GALL Report.
 
Instead, repair and replacement are performed in accordance with IWA-4000, as discussed in the
 
OCGS PBD for this AMP.
The staff determined that the current ISI program provides reasonable assurance that the intent of the NUREG-0619 acceptance criteria is met. On this basis, the staff determined that this
 
exception is acceptable.
Operating Experience. In LRA Section B.1.6, the applicant explained that OCGS had inspected the CRD nozzle in 1977 in response to industry experience at that time. No cracks were found in
 
the nozzle. To minimize thermal cycling and fatigue-induced cracking the thermal sleeve was
 
modified to divert the relatively cold CRD flow away from the nozzle. The most recent inspection
 
of the nozzle in 2002 confirms the lack of cracking in the nozzle area, good evidence that the
 
thermal sleeve modification has been effective in mitigating the effects of thermal fatigue on the
 
CRD nozzle.
The staff reviewed past inspection results of the CRD return line nozzle since OCGS implemented NUREG-0619 recommendations and found that the UT examination of the nozzle area revealed
 
no new indications. Also, the applicant has routinely inspected the nozzle thermal sleeve area
 
visually and no such degradation of the replacement thermal sleeve has been noted.
The staff reviewed the operating experience provided during the audit and interviewed the applicant's technical personnel to confirm that since the recommendations of NUREG-0619 were
 
implemented, including the installation of a repl acement nozzle thermal sleeve, this program has detected no cracks in the CRD return line nozzle regions.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Control Rod Drive Return Line Nozzle Program will adequately manage the aging effects
 
identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.6, the applicant provided the UFSAR supplement for the BWR Control Rod Drive Return Line Nozzle Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides 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 BWR Control Rod Drive Return Line Nozzle Program, the staff determined that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
exceptions and their justifications and determined that the AMP, with the exceptions, is adequate
 
to manage the aging effects for which it is credited. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-60 3.0.3.2.7  BWR Stress Corrosion Cracking Summary of Technical Information in the Application. In LRA Section B.1.7, the applicant described the existing BWR Stress Corrosion Cracking Program as consistent, with an exception, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking."
The BWR Stress Corrosion Cracking Program mitigates IGSCC in stainless steel reactor coolant pressure boundary piping components and piping 4 inches and greater NPS exposed to reactor coolant above 200 °F. Preventive measures include monitoring and controlling of water impurities by water chemistry activities and providing repl acement stainless steel components in the solution annealed condition with a maximum carbon content of 0.035 weight percent and a minimum
 
ferrite level of 7.5 weight percent. Inspection and flaw evaluation are in accordance with the ISI
 
program plan for the station. The program is implemented through station procedures based on NUREG-0313, "Technical Report on Material Selection and Processing Guidelines for BWR
 
Coolant Pressure Boundary Piping Revision 2," GL 88-01, "NRC Position on Intergranular Stress
 
Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping," and its Supplement 1, BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules,"
BWRVIP-130, "BWR Vessel and Internals Project BWR Water Chemistry Guidelines," and ASME Section XI.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.8. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it is credited.
The applicant was asked to provide details of all weld repairs and material replacement of components to implement the NUREG-0313 and GL 88-01 recommendations. In its response, the
 
applicant stated that the following piping was replaced with IGSCC-resistant material (low carbon
 
stainless steel):
* all isolation condenser large bore piping outside the drywell (from the drywell penetrations to the isolation condensers), including new stress-improved welds;
* all piping within the four isolation condenser drywell penetrations and the two RWCU system drywell penetrations, which contain welds that cannot be inspected;
* the isolation condenser piping at the isolation condensers at 95 feet elevation;
* the head cooling spray nozzle assembly; and
* the 4-inch tee and flange of the reactor vent line. Additionally, all welds accessible for inspection inside the drywell (except RWCU system) were stress-improved.
The applicant also stated that, of the 380 welds in the scope of GL 88-01, which includes 85 in the RWCU system outside the second containment isolation valves, 40 had IGSCC indications.
 
Following numerous piping replacements, 11 welds remained in service with indications of
 
IGSCC. Nine welds were repaired with full structural overlays (four in core spray, four in
 
recirculation and one in shutdown cooling systems). The remaining two welds were in service
 
without repair in the recirculation system, however, they were both stress-improved before inspections found IGSCC. The NRC-approved PDI inspections in 2002 and 2004 using the new
 
UT technique found no indications of IGSCC in either of the recirculation system welds.
3-61 The staff reviewed the OCGS program plan (OC-2: Program Plan - IGSCC Inspection Program, Revision 0, 07/31/2003) for implementing the GL 88-01 and BWRVIP-75 recommendations. The
 
program plan did not reference BWRVIP-14, 59, or 60 for guidance on the evaluation of crack
 
growth in stainless steel, nickel alloys, and low alloy steel components, respectively. The
 
applicant confirmed the use of these documents under the IGSCC program. Thus, the applicant
 
has inspected the relevant piping in accordance with NRC-approved BWRVIP-75 since the BWR
 
Stress Corrosion Cracking Program was first implemented.
As to the program element for "corrective actions," the GALL Report states that guidance for weld overlay repair and stress improvement or replacement is in GL 88-01; ASME Code Section XI, Subsections IWB-4000 and IWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively, for Classes 1, 2, or 3 components and ASME Code Case N504-1. These ASME Code Section XI subsections in earlier editions (1986 edition) have been replaced by subsections
 
IWA-4000 in later ASME Code editions. ISI program corrective action requirements are in
 
accordance with IWA-4000 of the 1995 edition of the ASME Code. The staff finds these requirements acceptable as consistent with the version of the ASME Code Section XI applicable
 
to OCGS.The staff reviewed those portions of the BWR Stress Corrosion Cracking Program for which theapplicant claimed consistency with GALL AMP XI.M7 and found them consistent with the GALL
 
Report AMP. Furthermore, the staff concluded that the applicant's BWR Stress Corrosion
 
Cracking Program provides reasonable assurance that IGSCC in reactor coolant pressure
 
boundary stainless steel and nickel-based alloy piping components (both base metal and welds)
 
will be adequately managed. The staff found that the applicant's BWR Stress Corrosion Cracking Program conforms to the recommended GALL AMP XI.M7 with an exception and an
 
enhancement described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program element "preventive actions." Specifically, the exception stated:
NUREG-1801 indicates that water chemistry control is in accordance with BWRVIP-29 for water chemistry in BWRs. BWRVIP-29 references the 1996
 
revision of EPRI TR- 103515, "BWR Water Chemistry Guidelines." The Oyster
 
Creek water chemistry program is based on BWRVIP-130, "BWR Vessel and
 
Internals Project BWR Water Chemistry Guidelines - 2004 Revision." For
 
justification of exceptions, see Water Chemistry Program, B.1.2.
In Attachment 1, item B.1.7 of its reconciliation document, the applicant stated that this exception is no longer required and will be withdrawn. The applicant was asked to clarify the reason for withdrawing this exception. In its response, the applicant stated that AMP XI.M7 in the
 
September 2005 GALL Report, to which the BWR Stress Corrosion Cracking Program was
 
compared, no longer makes reference to BWRVIP-29; therefore, this exception no longer applies
 
to the BWR Stress Corrosion Cracking Program.
The staff verified that the reactor coolant water chemistry at OCGS is monitored and maintained in accordance with the guidelines in BWRVIP-130, "BWR Vessel and Internals Project BWR
 
Water Chemistry Guidelines," to maintain high water purity to reduce susceptibility to SCC or
 
IGSCC. The staff reviewed the Water Chemistry Program and concludes that the use of
 
BWRVIP-130 is acceptable. The staff's evaluation of the Water Chemistry Program is discussed 3-62 in SER Section 3.0.3.2.2. On this basis, the staff concludes that the exception is not required and finds acceptable the applicant's decision to withdraw it.
Enhancement. In the LRA, the applicant stated that there are no enhancements for this AMP.
However, in PBD-AMP B.1.07, the applicant identified an enhancement not included in the LRA to
 
meet the GALL Report program element "prev entive actions,". Specifically, the enhancement stated: The program will be enhanced to require that, for those components within the scope of the BWR Stress Corrosion Cracking aging management program, all new
 
and replacement SS materials be low-carbon grades of SS with carbon content
 
limited to 0.035 wt. % maximum and ferrite content limited to 7.5% minimum.
In its letter dated April 17, 2006, the applicant committed (Commitment No. 7) to revise the BWR Stress Corrosion Cracking Program in the LRA to include the enhancement identified in
 
PBD-AMP-B.1.07, which states that for those components within the scope of the BWR Stress
 
Corrosion Cracking Program all new and replacement stainless steel materials will be low-carbon
 
grades of stainless steel with carbon content limited to 0.035 weight percent maximum and ferrite
 
content limited to 7.5 percent minimum.
In reviewing this enhancement, the staff noted that the carbon content and ferrite content screening criteria, as stated in GL 88-01, are applicable to both new and replacement
 
components while procuring and installing them during the life of a plant. Therefore, these criteria
 
already should have been implemented at OCGS. The applicant was asked to explain the reasons for this enhancement to an existing program, which should have included this screening
 
criterion as part of the CLB. In its response, the applicant stated that all replacements of piping
 
components susceptible to IGSCC during refueling outage 13R were in accordance with
 
GL 88-01. However, the current documentation does not include the GL 88-01 commitments in
 
the BWR Stress Corrosion Cracking Program; therefore, this enhancement to the program is
 
necessary to update the plant documentation to meet the recommendations of the
 
September 2005 GALL Report.
The staff finds the enhancement acceptable because when implemented the BWR Stress Corrosion Cracking Program will be consistent with GALL AMP XI.M7 and will provide additional assurance that the effects of aging for which this program is credited will be adequately managed.
Operating Experience. In LRA Section B.1.7, the applicant explained that of the welds included in the scope of GL 88-01, OCGS had 11 welds in service with indications of IGSCC. Nine were
 
repaired with full structural overlays (four in core spray, four in recirculation and one in shutdown
 
cooling). Two were inservice without repair in the recirculation system because they were both
 
stress-improved before the inspections found IGSCC. Both of these welds in the recirculation
 
system have recently been re-examined by t he PDI-qualified UT method and no IGSCC was identified. No new indications of IGSCC have been detected by inspection during the last
 
6 outages.
OCGS replaced the following piping material with IGSCC-resistant material:
  (1)All isolation condenser large bore piping outside the drywell (from the drywell penetrations to the isolation condensers). All new welds were stress-improved.
3-63  (2)All piping within the four isolation condenser drywell penetrations and the two RWCU system drywell penetrations containing welds not accessible for inspection.  (3)The head cooling spray nozzle assembly, the 4-inch tee, and flange of the reactor vent line were replaced.
Additionally, all accessible welds inside the drywell (except RWCU system) were stress-improved.Furthermore, as a result of the improved quality of water chemistry due to the execution of hydrogen water chemistry (HWC) and noble metal chemical addition (NMCA), inspection
 
frequency reductions permissible per BWRVIP-75 were implemented.
BWR Stress Corrosion Cracking Program activities have detected flaw indications in reactor coolant pressure boundary piping prior to loss of intended functions of the components. These indications were evaluated and repaired as necessary in accordance with ASME Section XI. As a
 
result OCGS has no indications of IGSCC at this time.
The staff reviewed the operating experience information given in the PBD and found that, since GL 88-01 was issued, OCGS has performed ISI examinations on piping subject to the GL
 
recommendations. During this period, OCGS has implemented HWC and performed stress
 
improvements as IGSCC mitigators. In additi on, examination procedures have been improved and examination personnel have received training on the latest techniques for IGSCC detection.
OCGS personnel have gained years of experience in the detection and sizing of IGSCC. No new
 
indications of IGSCC have been detected by inspection during the last 6 outages.
The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Stress Corrosion Cracking Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.7 and letter dated April 17, 2006, the applicant provided the UFSAR supplement for the BWR Stress Corrosion Cracking Program. The staff determined
 
that the information in the UFSAR supplement provides 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 BWR Stress Corrosion Cracking Program, the staff determined that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
exception and its justifications and determined that the AMP is adequate to manage the aging
 
effects for which it is credited. The staff concludes that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that 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).
3-64 3.0.3.2.8  BWR Penetrations Summary of Technical Information in the Application. In LRA Section B.1.8, the applicant described the existing BWR Penetrations Program as consistent, with exceptions, with GALLAMP XI.M8, "BWR Penetrations."
The BWR Penetrations Program activities incorporate the inspection and evaluation recommendations of BWRVIP-27-A, "BWR Standby Liquid Control System/Core Plate Delta-P Inspection and Flaw Evaluation Guidelines," and BWRVIP-49-A, "Instrument Penetration
 
Inspection and Flaw Evaluation Guidelines," as well as the water chemistry recommendations of BWRVIP-130, "BWR Vessel and Internals Project BWR Water Chemistry Guidelines," for the
 
standby liquid control nozzle and instrument penetrations. The program is implemented through station procedures that mitigate cracking through the water chemistry and monitor for cracking
 
through inservice inspection examinations. Penetration inspections through station procedures for reactor internals inspection incorporate the requirements of ASME Code Section XI.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.8. The staff reviewed the exceptions
 
and their justifications to determine whether the AMP, with the exceptions, remained adequate to
 
manage the aging effects for which it is credited.
The staff verified that the OCGS reactor internals program plan, OC-5, includes the instrument penetrations and the standby liquid control nozzle and implements the recommendations of
 
BWRVIP-27-A and BWRVIP-49-A. Inspections are in accordance with the station ISI program (OC-1). The staff also noted that repair and replacement activities, if needed, are in accordance
 
with the recommendations of the appropriate BWRVIP repair/replacement guidelines. These
 
activities are specified in implementation procedure ER-AB-331-1001 (Revision 0).
The staff reviewed those portions of the BWR Penetrations Program for which the applicantclaimed consistency with GALL AMP XI.M8 and found them consistent with the GALL Report
 
AMP. Furthermore, the staff concluded that the applicant's BWR Penetrations Program provides
 
reasonable assurance of effective management of cracking due to SCC or IGSCC in both
 
instrument and SLC/Delta-P penetrations in the vessel. The staff found that the applicant's BWR Penetrations Program conforms to the recommendations provided in GALL AMP XI.M8 with the
 
exceptions described below.
Exception 1. In the LRA, the applicant stated an exception to the GALL Report program element "preventive actions." Specifically, the exception stated:
NUREG-1801 indicates that water chemistry control is in accordance with BWRVIP-29 for water chemistry in BWRs. BWRVIP-29 references the 1996
 
revision of EPRI TR-103515, "BWR Water Chemistry Guidelines." The Oyster
 
Creek water chemistry programs are based on BWRVIP-130, which is the 2004
 
revision of "BWR Water Chemistry Guidelines. For justification of exceptions to the
 
water chemistry program see the Wa ter Chemistry aging management program, B.1.2.
3-65 The staff reviewed the Water Chemistry Program (AMP B.1.2) and concludes that the use of BWRVIP-130 is acceptable. The staff's evaluation of the Water Chemistry Program is discussed
 
in SER Section 3.0.3.2.2. On this basis, the staff concludes that the exception is acceptable.
Exception 2. In the LRA, the applicant stated an exception to the GALL Report program element "parameters monitored or inspected.
" Specifically, the exception stated:NUREG-1801 program XI.M9 references ASME Section XI, Table IWB 2500-1 (2001 edition, including the 2002 and 2003 Addenda). Oyster Creek ISI program is based on the 1995 (including 1996 Addenda) version of ASME Section XI. For justification of exceptions to the ISI program see the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD aging management program, B1.1.The staff reviewed this exception as part of its review of the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program and finds it acceptable. The staff's
 
evaluation is documented in SER Section 3.0.3.2.1.
Operating Experience. In LRA Section B.1.8, the applicant explained that OCGS is currently in its fourth ISI interval. In the history of the OCGS ISI program, no evidence of instrument penetration or standby liquid control nozzle cracking has been found, evidence that the Water Chemistry
 
Program has been effective in minimizing SCC effects in the instrument and standby liquid control
 
penetrations. The same inspection and testing methodologies are used for the BWR penetrations
 
as for other reactor internals. These processes have detected cracking in other vessel internals
 
components as described in the operating experience of the BWR Vessel Internals Program.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Penetrations Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
UFSAR Supplement. In LRA Section A.1.8, the applicant provided the UFSAR supplement for the BWR Penetrations Program. The staff reviewed this section and determined that the information
 
in the UFSAR supplement provides 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 BWR Penetrations Program, the staff determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their
 
justifications and determined that the AMP, with the exceptions, is adequate to manage the aging
 
effects for which it is credited. The staff concludes that the applicant has demonstrated that the
 
effects of aging will be adequately managed so that the intended function(s) will be maintained
 
consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
 
The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).
3-66 3.0.3.2.9  BWR Vessel Internals Summary of Technical Information in the Application. In LRA Section B.1.9, the applicant described the existing BWR Vessel Internals Program as consistent, with exceptions and enhancements, with GALL XI.M9, "BWR Vessels Internals."
In LRA Section B.1.9, the applicant stated that this program manages the effects of cracking initiation and growth of reactor vessel internals (RVI) components through condition monitoring
 
activities consisting of examinations by stat ion procedures consistent with the recommendationsof BWRVIP guidelines as well as the requirements of ASME Code Section XI. The program also
 
mitigates the effects of SCC, IGSCC, and irradiation-assisted stress corrosion cracking (IASCC)
 
in RVI components through water chemistry activities implemented through station procedures
 
which are consistent with the guidelines of BWRVIP-130: " BWR Vessel and Internals Project
 
BWR Water Chemistry Guidelines," 2004 Revi sion. Inspections and evaluations of RVI components are consistent with the guidelines in the following BWRVIP reports:
* BWRVIP-18-A, BWR Core Spray Inspection and Flaw Guidelines
* BWRVIP-25, BWR Core Plate Inspection and Flaw Evaluation Guidelines
* BWRVIP-26, BWR Top guide Inspection and Flaw Evaluation Guidelines
* BWRVIP-27-A, BWRVIP Standby Liquid Control System/Core Spray/ Core Plate P Inspection and Flaw Evaluation Guidelines
* BWRVIP-38, BWR Shroud Support Inspection and Flaw Evaluation Guidelines
* BWRVIP-47, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines
* BWRVIP-48, Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines
* BWRVIP-49-A, Instrument Penetration Inspection and Flaw Evaluation Guidelines
* BWRVIP-74-A, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines
* BWRVIP-76, BWR Core Shroud Inspection and Flaw Evaluation Guidelines
* BWRVIP-104, Evaluation and Recommendations to Address Shroud Support Cracking in BWRs The applicant stated that BWRVIP-41, "BWR Vessel and Internals Project, Jet Pump Assembly, Inspection and Flaw Evaluation Guidelines," and BWRVIP-42, "BWR Vessel and Internals Project, BWR LPCI Coupling Inspection and Flaw Evaluation Guidelines," are not applicable because
 
OCGS has no such components. The applicant also stated that OCGS has or will complete each
 
of the license renewal applicant action items described in the staff's safety evaluations (SEs) for
 
each BWRVIP report prior to the period of ex tended operation. In addition, OCGS will implement the guidelines of BWRVIP-139, "BWR RVI components Project, Steam Dryer Inspection and Flaw
 
Evaluation Guidelines," for the steam dryer when issued.
Staff Evaluation. In the LRA, the applicant stated that it will implement the BWR Vessel Internals Program to manage cracking in RVI components due to SCC, IGSCC, and IASCC consistent with the GALL AMP XI.M9. To monitor the aging effects, the applicant proposed to implement the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The applicant
 
stated that this program is consistent with GALL AMP XI.M1, "ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, IWD," with one exception. In SER Section 3.0.3.2.1 the staff 3-67evaluated the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Programand determined that it will comply with the recommendations of GALL AMP XI.M1.
The applicant stated that the Water Chemistry Program will be used at OCGS to manage the aging effects due to SCC, IGSCC, and IASCC. The applicant further stated that the Water Chemistry Program is consistent with GALL AMP XI.M2 with one exception. In SER
 
Section 3.0.3.2.2, the staff evaluated the Water Chemistry Program and determined that it will comply with the recommendations of GALL AMP XI.M2.
 
The applicant is required to comply with the license renewal action items specified in the staff's
 
SER as to the BWRVIP reports for the period of extended operation. The following list documents
 
the license renewal action items specified in the staff's SEs of the applicable BWRVIP reports, the
 
applicant's responses to these license renewal action items, and the corresponding staff's
 
evaluation.
 
  (1)The license renewal applicant is to verify that its plant is bounded by the applicable BWRVIP report. Further, the license renewal applicant is to commit to programs described
 
as necessary in the BWRVIP reports to manage the effects of aging during the period of
 
extended operation. License renewal applicants will be responsible for describing any
 
such commitments and how they will be controll ed. Any deviations from the AMPs within these BWRVIP reports described as necessary to manage the effects of aging during the
 
period of extended operation and to maintain component functions or from other
 
information presented in the report, like materials of construction, must be identified by the
 
license renewal applicant and evaluated on a plant-specific basis in accordance with
 
10 CFR 54.21(a)(3) and (c)(1).
The applicant verified that OCGS is bounded by applicable BWRVIP reports. Additionally, OCGS committed (Commitment No. 9) to programs described as necessary in the
 
BWRVIP reports to manage the effects of aging during the period of extended operations.
 
If, upon review of a BWRVIP-approved guideline, the applicant determines that exceptions
 
to full compliance are warranted the staff will be notified of the exception within 45 days of
 
the receipt of staff final approval of the guideline.
The staff finds this commitment acceptable as it complies with the staff's license renewal action items specified in the respective SERs on the BWRVIP reports.
Similarly, LRA Section A.1.9 references the BWRVIP-94 report, "BWR Vessels and Internals Project, Program Implementation Guideline." The staff's review of LRA
 
Section B.1.9 identified areas in which additional information was necessary to complete
 
the review of the applicant's program elements. The applicant responded to the staff's RAI
 
as discussed below.
In RAI 1.9-1(A) dated March 20, 2006, the staff requested that the applicant revise the BWR Vessel Internals Program to refer to the BWRVIP-94 report and include the following
 
issues related to the scope of implementation of the BWRVIP-94 guidelines.
* The applicant shall inform the staff within 45 days of the report of any decision not to implement fully a BWRVIP guideline approved by the staff.
* The applicant shall notify the staff if changes are made to the AMP related to the RVI components that affect the implementation of the BWRVIP guidelines.
3-68
* The applicant shall submit any devia tion from the existing flaw evaluation guidelines specified in the BWRVIP report.
In its response dated April 18, 2006, the applicant stated that it will create a new commitment to incorporate these issues. The staff reviewed the response and concluded
 
that the applicant's commitment (Commitment No. 9) to incorporate the program
 
implementation requirements specified in the BWRVIP-94 report in the LRA is acceptable.
 
Based on the review, the staff determined that its concern described in RAI B.1.9-1(A) is
 
resolved.    (2)Section 54.21(d) of 10 CFR requires a UFSAR supplement for the facility to contain a summary description of the programs and activities for managing the effects of aging and
 
the evaluation of TLAAs for the period of extended operation. License renewal applicants
 
shall describe summarily in the UFSAR supplement programs and activities specified as
 
necessary in applicable BWRVIP reports. One of the license renewal application action
 
items identified in the staff's corresponding SER on the applicable BWRVIP report
 
addresses the applicability of TLAA for evaluating the aging degradation of a specific RVI
 
component.The applicant stated that UFSAR supplements included as LRA Appendix A summarize programs and activities specified as necessary for the BWRVIP program. According to the
 
applicant there are no TLAA issues for OCGS related to the following BWRVIP reports:
* BWRVIP-18, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines."
* BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."
* BWRVIP-27-A, "BWR Standby Liquid Control System/Core Plate P Inspection and Flaw Evaluation Guidelines."
* BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines."
In RAI B.1.9-9 dated March 20, 2006, the staff requested that the applicant make a commitment to incorporate programs described as necessary in the BWRVIP reports to
 
manage the effects of aging during the period of extended operation at OCGS. The staff
 
also requested that the applicant include this commitment in the BWR Vessel Internals
 
Program and its UFSAR supplement.
In its response dated April 18, 2006, the applicant stated that it will include the following BWRVIP guidelines in the BWR Vessel Internals Program and its UFSAR supplement.
* BWRVIP-05, "Reactor Vessel Shell Weld Inspection Guidelines."
* BWRVIP-18-A, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines."
* BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."
* BWRVIP-26, "BWR Top Guide Inspection and Flaw Evaluation Guidelines."
* BWRVIP-27-A, "BWR Standby Liquid Control System/Core Plate P Inspection and Flaw Evaluation Guidelines."
3-69
* BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines."
* BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines."
* BWRVIP-48, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines."
* BWRVIP-49, "Instrument Penetration Inspection and Flaw Evaluation Guidelines."
* BWRVIP-74-A, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines."
* BWRVIP-75, "BWR Vessel and Internals Project (BWRVIP), Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedule."
* BWRVIP-76, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines."
* BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan."
* BWRVIP-86, "BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation."
* BWRVIP-104, "Evaluation and Recommendations to Address Shroud Support Cracking in BWRs."
* BWRVIP-116, "BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation for License Renewal."
* BWRVIP-130, "BWR Water Chemistry Guidelines."
The staff reviewed the response and concluded that the applicant's inclusion of these BWRVIP inspection guidelines in the UFSAR will ensure timely identification of aging
 
degradation of the RVI components so that their intended functions will not be
 
compromised during the period of extended operation.
By complying with the applicable BWRVIP recommendations, the applicant will identify
 
and evaluate any potential TLAA issues addressed in the BWRVIP reports. After reviewing
 
the SEs of the BWRVIP-18, 27-A and 47 reports, the staff determined that there are no
 
TLAA issues associated with these reports at OCGS. As to the potential TLAA issue of the
 
core plate hold-down bolts addressed in the BWRVIP-25 report, the applicant stated that it
 
had installed wedges and that there is no TLAA issue for this component. The applicant's
 
disposition of the TLAA issue with the core plate hold-down bolts is consistent with the
 
staff's SER of the BWRVIP-25 report and the staff finds it acceptable. Based on this review, the staff's concern described in RAI B.1.9-9 is resolved.
The license renewal action items specified in the staff's SER dated October 18, 2001, on the BWRVIP-74-A report, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation
 
Guidelines," address the aging effects of the RVI components and provide requirements to
 
effectively manage the aging effects during the period of extended operation. The BWRVIP-74-A
 
report also addresses the license renewal action items associated with TLAAs for the period of
 
extended operation. The following paragraphs address the TLAAs specified in the BWRVIP-74-A
 
report, the applicant's responses to these license renewal action items, and the corresponding
 
staff's evaluation of each TLAA.  (1)License renewal applicants should verify that the number of cycles assumed in the original fatigue design is conservative to assure that the estimated fatigue usage for 60 years of 3-70 plant operation is not underestimated. The use of alternate actions where the estimated fatigue usage is projected to exceed 1.0 will require case-by-case
 
staff review and approval. Further, a license renewal applicant must address
 
environmental fatigue for components listed in the BWRVIP-74-A report for the license
 
renewal period.
The applicant stated that thermal fatigue (including discussions of cycles, projected cumulative usage factors, environmental factors, etc.) is evaluated as a TLAA in LRA
 
Section 4. Environmental fatigue for those components described in NUREG-6260 is
 
addressed in the LRA Section 4.6.
The staff evaluated the TLAA of thermal fatigue in SER Section 4.6 and concludes that the applicant, as recommended by the BWRVIP-74-A report, has addressed the need to
 
include this TLAA in the LRA.    (2)Appendix A to the BWRVIP-74-A report indicates that a set of pressure-temperature (P-T) curves should be developed for the heat-up and cool-down operating conditions in the
 
plant at a given effective full power y ear (EFPY) in the license renewal period.
The applicant stated that the development of P-T curves for OCGS for the license renewal period is described as a TLAA in SER Section 4.2.
The staff evaluated the TLAA of P-T curves in SER Section 4.2 and concludes that the applicant, as required by the BWRVIP-74-A report, has addressed the need to include this
 
TLAA in the LRA.    (3)To demonstrate that the beltline materials meet the charpy upper shelf energy (USE) criteria specified in Appendix B of the BWRVIP-74-A report, the applicant shall
 
demonstrate that the percent reduction in charpy USE for their beltline materials is less
 
than that specified for the limiting BWR/3-6 plates or the non-Linde 80 submerged arc
 
welds and that the percent reduction in charpy USE for their surveillance weld and plate is
 
less than or equal to the values projected using the methodology in RG 1.99, "Radiation
 
Embrittlement of Reactor Vessel Materials," Revision 2.
The applicant stated that the discussion of charpy USE for OCGS for the license renewal period is described as a TLAA in LRA Section 4.2.
The staff evaluated the TLAA of USE criteria for the reactor pressure vessel (RPV) beltline materials in SER Section 4.2. The staff concludes that the applicant, as required by the
 
BWRVIP-74-A report, has addressed the need to include this TLAA in the LRA.    (4)To obtain relief from the ISI of the circumferential welds during the license renewal period, the BWRVIP-05 report, "Reactor Vessel Shell Weld Inspection Guidelines," requires each
 
licensee to demonstrate that: (1) at the end of the renewal period, the circumferential
 
welds will satisfy the limiting conditional failure frequency for circumferential welds in
 
Appendix E of the staff's July 28, 1998, SER on the BWRVIP-05 report, and (2) that they
 
have implemented operator training and established procedures that limit the frequency of
 
cold over-pressure events to that specified in the staff's July 28, 1998, SER on the
 
BWRVIP-05 report.
3-71 The applicant stated that relief from the ISI of the circumferential welds for OCGS for the license renewal period is described in LRA Section 4.2.
The staff's evaluation of the TLAA of the relief from the ISI of the RPV circumferential shell welds for OCGS is addressed in SER Section 4.2. The staff concludes that the applicant, as required by the BWRVIP-74-A report, has addressed the need to include this TLAA in
 
the LRA.    (5)A license renewal applicant shall monitor axial beltline weld embrittlement. One acceptable method is to determine that the mean reference nil-ductility transition
 
temperature (RT NDT) of the limiting axial beltline weld at the end of the period of extended operation is less than the values specified in Table 1 of the staff's October 18, 2001, SER
 
on the BWRVIP-74-A report.
The applicant stated that The RPV axial weld failure probability TLAA is addressed in LRA Section 4.2.
The staff evaluated the TLAA of the RPV axial weld failure probability for OCGS in SER Section 4.2. The staff concludes that the applicant, as required by the BWRVIP-74-A
 
report, has addressed the need to include this TLAA in the LRA.  (6)The Charpy USE, P-T limit, inspection relief for the RPV circumferential welds, and RPV axial weld integrity evaluations are all dependent upon the neutron fluence. The license
 
renewal applicant may perform neutron fluence calculations using staff-approved
 
methodology or may submit a methodology for staff review. If the applicant performs the
 
neutron fluence calculation using a methodology previously approved by the staff, the applicant should identify the NRC letter that approved the methodology
.The applicant stated that the neutron fluence calculation methodology for OCGS is consistent with RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure
 
Vessel Neutron Fluence."
The staff evaluated the TLAAs associated with the neutron fluence calculations in SER Section 4.2 and concludes that the applicant, as required by the BWRVIP-74-A report, has
 
addressed the need to include this TLAA in the LRA.  (7)Components with indications previous ly analytically evaluated in accordance withsubsection IWB-3600 of the ASME Code, Section XI until the end of the 40-year service
 
period shall be re-evaluated for the 60-year service period of the license renewal term.
The applicant stated that OCGS has evaluated flaws for previously identified indications
 
discussed in LRA Section 4.7.4.
The staff's evaluation of the TLAA of the flaw evaluations of previously identified indications in RPV and RVI components at OCGS is addressed in SER Section 4.7.4. The
 
staff concludes that the applicant, as required by the BWRVIP-74-A report, has addressed
 
the need to include this TLAA in the LRA.
3-72 The following paragraphs address additional license renewal action items specified in the BWRVIP-74-A report, the applicant's responses to these license renewal action items, and the
 
corresponding staff's evaluation.
 
  (1)Section 54.22 of 10 CFR requires each license renewal applicant to include any technical specification changes (and justification for the changes) or additions necessary to manage
 
the effects of aging during the period of extended operation as part of the LRA. The
 
applicable BWRVIP reports may state that there are no generic changes or additions to
 
technical specifications as a result of its AMR and that the applicant will justify
 
plant-specific changes or additions. License renewal applicants referring to applicable
 
BWRVIP reports shall ensure that the inspection strategy described in the reports does
 
not change or conflict with their technical specifications. If technical specification changes
 
or additions result, the applicant must include those changes in its LRA.
The applicant stated that there have been no OCGS technical specification changes based upon the BWRVIP reports.
The AMR indicated no changes in technical specifications based upon applicable BWRVIP reports and, therefore, the staff concludes that the applicant adequately addressed this
 
issue in LRA Section B.1.9.    (2)The staff is concerned that leakage around the reactor vessel seal rings could accumulate in the vessel flange leak detection (VFLD) lines, cause an increase in the concentration of
 
contaminants, and cause cracking in the VFLD line. The BWRVIP-74-A report does not
 
identify this component as within the scope of the report. However, since the VFLD line is
 
attached to the RPV and provides a pressure boundary function, license renewal
 
applicants should identify an AMP for the VFLD line.
The applicant stated that its VFLD line is a Class 1 line visually inspected (VT-3) duringreactor cavity flood up each refueling outage as part of the ASME Section XI programs.
The staff accepted the applicant's AMP for t he VFLD systems becaus e by implementing the inspection program during each refueling outage the applicant can effectively monitor
 
the aging effect in the VFLD components.    (3)License renewal applicants shall describe how each plant-specific AMP addresses the following elements: (1) "scope of program," (2) "preventative actions," (3) "parameters monitored and inspected," (4) "detection of aging effects," (5) "monitoring and trending,"
 
(6) "acceptance criteria," (7) "corrective actions," (8) "confirmation process,"
 
(9) "administrative controls," and (10) "operating experience."
The applicant stated that there is no plant-unique AMP credited for managing aging of the RVI components.
The only AMP for managing aging effects in the RVI components is the BWR VesselInternals Program. The staff concludes that this AMP is consistent with GALL AMP XI.M9
 
and is effective for managing the aging effects of the RVI components. Therefore, the staff
 
finds this AMP acceptable.
3-73  (4)The staff believes inspection by itself is not sufficient to manage cracking. Cracking can be managed by a program of inspection and water chemistry. The BWRVIP-29 report
 
describes a water chemistry program with monitoring and control guidelines for BWR
 
water acceptable to the staff. The BWRVIP-29 report is not discussed in the
 
BWRVIP-74-A report. Therefore, in addition to the BWRVIP reports, the LRA shall contain
 
water chemistry programs with monitoring and control guidelines for reactor water
 
chemistry contained in the BWRVIP-29 report.
The applicant stated that the BWR Stress Corrosion Cracking and BWR Vessel Internals Programs include water chemistry controls as preventive measures. The Water Chemistry Program meets the recommendations of the latest BWRVIP guidelines, BWRVIP-130, to
 
help ensure the long-term integrity of the RVI components.
The staff concludes that implementation of the Water Chemistry Program in conjunction with the BWR Stress Corrosion Cracking and BWR Vessel Internals Programs is
 
consistent with the license renewal action items specified in the staff's October 18, 2001, SER on the BWRVIP-74-A report. The staff believes that the guidelines included in
 
BWRVIP-130 takes into account the most recent industry experience and latest
 
information from EPRI, which has been proven effective in controlling water chemistry.
 
Therefore, the staff finds this implementation acceptable.  (5)One license renewal action item specified in the staff's October 18, 2001, SER on the BWRVIP-74-A report requires license renewal applicants to identify their vessel
 
surveillance program as either an integrated surveillance program (ISP) or plant-specific in-vessel surveillance program applicable to the license renewal period.
The applicant stated that the OCGS Reactor Vessel Surveillance Program will be the ISP for the license renewal term.
The staff determined that by implementing the BWR ISP the applicant complied with the license renewal action items specified in the staff's October 18, 2001, SER on the
 
BWRVIP-74-A report. Therefore, the staff finds this implementation acceptable. Details of
 
the staff's evaluation of the Reactor Vessel Surveillance Program are in SER
 
Section 3.0.3.2.20.In LRA Section B.1.9, the applicant stated that this program is consistent with GALL AMP XI.M9 with exceptions and enhancements.
The applicant stated that the BWR Vessel Internals Program will be enhanced to include inspections of the steam dryer in accordance with BWRVIP-139. The staff is currently reviewing
 
the BWRVIP-139 report relevant to the steam dryer component. The applicant has modified its
 
UFSAR and committed (Commitment No. 9) to inspect the steam dryer in accordance with this
 
Topical Report (TR). Because the staff's conditions and license renewal items to be specified in
 
the final SER of this TR will be incorporated in the BWRVIP-139, the staff concludes that this
 
commitment is adequate.
The applicant stated that the program will be enhanced to include the GALL Report recommendations related to IASCC in the top guide grid beam. The applicant stated that during
 
the 1991 refueling outage it had found a crack on the underside of a top guide grid beam.
 
Additional cracked beams were discovered in 1992 and 1994. The applicant stated that crack 3-74 growth in the top guide beam is monitored by visual inspection (VT-1) during every outage. The applicant claimed that under flaw evaluation guidelines the structural integrity of the top guide is
 
not challenged during the next cycle of operation. During the staff's audit, the applicant stated that
 
it will perform UT of the top guide grid beam during the next refueling outage. The applicant stated
 
that it will comply with all the recommendations of the BWRVIP-26 report and will conduct
 
additional inspections if significant crack growth is identified. The applicant has made a
 
commitment (Commitment No. 9) to inspect the top guide as recommended in the GALL Report.
 
Based on UT results, the applicant will develop inspection frequency and scope guidelines for the
 
top guide. The staff finds the applicant's commitment acceptable because it provides reasonable
 
assurance that the top guide will perform its intended functions during the period of extended
 
operation.
The staff's review of the enhancements for the top guide determined that the applicant's proposed augmented inspections of the top guide grid beams and slots are consistent with inspection
 
criteria specified in Table IV.B1, item IV.B1-17, of the GALL Report. Therefore, the staff
 
concludes that the proposed inspections of the top guide grid beams will adequately manage the
 
aging effect due to IASCC so that the intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation.
The applicant stated that during the 2000 refueling outage RPV pressure test leakage was observed from two CRD housing penetrations at the reactor bottom head interface. A roll
 
expansion repair design was completed on the two CRD housings to stop the leaks. This roll
 
expansion method was approved by the staff on November 16, 2000, for one operating cycle only.
 
Subsequent inspections in 2002 and 2004 found no evidence of any CRD housing penetration
 
leakage. The applicant further stated that this repair was submitted to the ASME Code in the form of draft ASME Section XI Code Case N-730, "Roll-Expansion of Class 1 Control Rod Drive Bottom
 
Head," for review and approval. The applicant intends to apply this repair permanently at the
 
OCGS when ASME Code Case N-730 is approved by the ASME Code and the staff. The staffdetermined that the applicant's proposal to use the ASME Section XI Code Case N-730 for
 
permanent repair of the CRD stub tubes will be acceptable provided the ASME Code Case is
 
approved by the staff.
In RAI B.1.9-3 dated March 20, 2006, the staff requested that the applicant provide details of the CRD repair. The staff requested that, if the ASME Code Case is not approved, the applicant
 
submit a permanent repair plan for review and approval 2 years prior to the beginning of the
 
period of extended operation. The staff requested that the applicant commit to immediate repair of
 
any leaking CRD stub tubes during the period of extended operation if there is a leak after the
 
implementation of an approved permanent roll repai r by implementing a permanent weld repairper the approved ASME Section XI Code Cases with staff conditions, if any. The staff also
 
requested that the applicant revise the BWR Vessel Internals Program and its UFSAR
 
supplement to indicate that it will implement the staff-approved permanent repair of the CRD stub tubes for no leakage during the period of extended operation.In its response dated April 18, 2006, the applicant stated that if the ASME Section XI Code Case N-730 is not approved it will develop a permanent repair plan that complies with the ASME Code Section XI requirements. This permanent repair could be in accordance with the
 
BWRVIP-58-A report, "BWRVIP Vessel And Internals Project, CRD Internal Access Weld Repair,"
 
which has been approved by the staff, or an alternate ASME Code repair plan which would be
 
submitted for prior staff approval. If the repair plan needs prior staff approval, the applicant will
 
submit the repair plan 2 years before the period of extended operation. After the implementation 3-75 of an approved permanent roll repair, if there is a leak in a CRD stub tube, the applicant will use the staff-approved weld repair method prior to restarting the plant. The applicant stated that the
 
UFSAR supplement and the commitment list will be updated to reflect such commitments (Commitment No. 9).
The staff finds the response acceptable because it committed to submit any repair plan not previously approved 2 years prior to the period of extended operation for NRC review and approval. The staff's concerns described in RAI B.1.9-3 are resolved.
In RAI B.1.9-2 dated March 20, 2006, the staff stated that the BWRVIP-76 report, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," and the BWRVIP-104 report, "Evaluation and
 
Recommendations to Address Shroud Support Cracking in BWRs," were under staff review. The
 
staff requested that the applicant make a commitment that it will comply with all requirements
 
specified in the staff's final SERs on these reports and that it will complete all license renewal
 
action items specified in the final SERs when issued.
In its response dated April 18, 2006, the applicant committed (Commitment No. 9) to comply with all applicable conditions specified in the staff's final SERs on the BWRVIP-76 and BWRVIP-104
 
reports and will complete all the license renewal action items specified in the final SERs on these
 
reports when issued. The staff finds this commitment acceptable. The staff's concern described in
 
RAI B.1.9-2 is resolved.
In RAI B.1.9-6 dated March 20, 2006, the staff requested that the applicant provide information about the type of core plate plugs used at OCGS. If spring-loaded core plate plugs are used at
 
OCGS, the applicant was asked for the type of AMP implemented to ensure their integrity.
In its response dated April 18, 2006, the applicant stated that the core plate at OCGS does not have drilled flow holes as in some BWR-3 and BWR-4 plants and, therefore, has neither
 
spring-loaded or welded core plate plugs. Based on this response, the staff's concern described
 
in RAI B.1.9-6 is resolved.
In the past, one of the aging degradation mechanisms in the RVI components was attributed to IGSCC, which is dependent on the oxygen content of the reactor coolant system (RCS) water.
 
High oxygen levels in the RCS water is one of the chief factors contributing to IGSCC in the RVI
 
components. Addition of hydrogen is considered effective in reducing the oxygen levels in the
 
RCS water and minimizing IGSCC. In addition, NMCA can increase the effectiveness of hydrogen
 
addition.
In RAI B.1.9-7 dated March 20, 2006, the staff requested that the applicant provide information as to whether any NMCA is applied at the OCGS. The staff further requested that the applicant
 
confirm the method of controlling HWC and any NMCA as a mitigative method to reduce IGSCC
 
susceptibility in the RVI components.
The staff also requested that the applicant provide details on the methods for determining the effectiveness of HWC and/or NMCA by the following parameters:
* electro chemical potential (ECP)
* feedwater hydrogen flow
* main steam oxygen content
* hydrogen/oxygen molar ratio 3-76 In its response dated April 18, 2006, the applicant stated that HWC and NMCA had been implemented at OCGS in 1992 and 2002, respectively. HWC control is established by monitoring and maintaining the hydrogen-oxygen molar ratio and the ECP of the RCS water. ECP of the RCS
 
water is determined and managed in accordance with requirements specified in the BWRVIP-130
 
report, "BWR Water Chemistry." For NMCA, noble metal concentrations are monitored and
 
re-application of noble metals is scheduled when the platinum (Pt)-Rhodium (Rh) concentration is
 
predicted to fall below established limits. The guidelines in the BWRVIP-130 report for BWR
 
reactor water recommend that the concentration of chlorides, sulfates, and dissolved oxygen be
 
monitored and kept below the recommended levels to mitigate corrosion. Two impurities, chlorides and sulfates, determine the RCS water conductivity; dissolved oxygen, hydrogen
 
peroxide, and hydrogen determine the ECP. The EPRI guidelines recommend that the RCS water
 
conductivity and ECP also be monitored and kept below the recommended levels to mitigate SCC
 
and corrosion in BWR plants. OCGS monitors ECP directly with probes in the B recirculation loop
 
via the RWCU system. OCGS uses reactor wate r dissolved oxygen as a secondary parameter to maintain mitigation in the recirculation loops. The hydrogen concentrations in the feedwater are
 
monitored daily. Calculated hydrogen flow rates are established to maintain hydrogen and oxygen levels in the vessel within guidelines developed from the BWRVIP-130 report. The
 
hydrogen-oxygen molar ratio is maintained greater than or equal to 3 to 1 to ensure proper ECP
 
levels and NMCA effectiveness. The oxygen levels in the main steam lines are not monitored
 
because oxygen levels are measured directly in the RCS water as a means of maintaining
 
chemistry control.
The staff reviewed the applicant's response and finds it acceptable for the following reasons:
* HWC/NMCA addition to the RCS water protects the majority of the RVI components from IGSCC except in areas exposed to high radiation levels (near the core region).
* The applicant's methodology of monitoring the effectiveness of HWC/NMCA includes measurement of the ECP of the RCS water and monitoring the feedwater hydrogen and
 
the RCS oxygen levels. These methods adequately protect the majority of the RVI
 
components from IGSCC.
* The applicant's methodology in maintaining a hydrogen-oxygen molar ratio of 3 to 1 ensures sufficient hydrogen coverage for the majority of the RVI components and reduces
 
the IGSCC crack growth rates in these components.
* Since the RCS water chemistry and conduc tivity are in compliance with the industry-accepted BWRVIP-130 report guidelines the staff determined that proper mitigation of
 
IGSCC can be achieved for the majority of the RVI components. The staff understands
 
that some RVI components will not be fully protected from IGSCC due to exposure to neutron radiation.
Based on the review, the staff's concern described in RAI B.1.9-7 is resolved.
 
Nonsafety-related RVI components (e.g., steam dryer, core shroud heads and separators, internal feedwater spargers, and RPV surveillance capsule holders) can be subject to aging degradation
 
due to pitting and crevice corrosion, SCC, and IGSCC. In RAI B.1.9-8 dated March 20, 2006, the
 
staff requested that the applicant address how it will use the BWR Vessel Internals Program to
 
monitor loss of material due to pitting and crevice corrosion, SCC, and IGSCC in
 
nonsafety-related RVI components.
3-77 In its response dated April 18, 2006, the applicant stated that it will monitor the aging degradation in the nonsafety-related RVI components by impl ementing the BWR Vessel Internals Program. In addition, the applicant committed (Commitment No. 9) to inspect the steam dryer in accordance
 
with the guidelines of the BWRVIP-139 report and that inspections will begin in 2008. The
 
feedwater spargers are inspected in accordance with the recommendations of NUREG-0619. The
 
applicant further stated that it conducts inspections of the steam separator, shroud head, and the
 
core inlet flow baffle (diffuser) in the lower head regions. The applicant has committed to enhance
 
the BWR Vessel Internals Program to include inspections to monitor corrosion in the feedwater
 
sparger, steam separator, RPV surveillance capsule holders, and baffle plates. The staff finds this
 
response acceptable because the applicant committed to monitor the aging degradation due to
 
pitting and crevice corrosion, SCC, and IGSCC in nonsafety-related RVI components.
 
Furthermore, conditions specified in the staff's SER on BWRVIP-139 would apply for OCGS. The
 
staff's concerns described in RAI B.1.9-8 are resolved.
Operating Experience. In LRA Section B.1.9, the applicant provided information about its capabilities in detecting the aging degradation of the RVI components and implementation of
 
appropriate corrective actions, including prompt repair of degraded components prior to failure, to
 
maintain system and component intended functions.
Some site-specific examples are provided.
The applicant stated that in 1978 it had identified crack indications in the core spray spargers.
Mechanical clamps were installed for structural support for identified cracks and indications in the
 
core spray sparger. Recent inspections in 1998, 2000, 2002, and 2004 have confirmed that the
 
repair clamps are in good condition.
In RAI B.1.9-4 dated March 20, 2006, the staff requested that the applicant provide further information on its future inspection plans for core spray spargers and core spray piping welds
 
including the type and frequency of inspections, inspection methods, sample size, for the repaired
 
and non-repaired core spray components during the period of extended operation.
In its response dated April 18, 2006, the applicant stated that it complied with all the recommendations of the BWRVIP-18 report, specifically as to the type and frequency of
 
inspections, re-inspection frequency, and flaw evaluation methods. The applicant also provided its
 
previous inspection results of the core spray piping brackets and sparger nozzle welds and the
 
repairs performed on core spray sparger tee box welds. As the AMP for the core spray system is
 
consistent with the guidelines specified in the staff-approved BWRVIP-18A report and GALL AMP XI.M9, the staff concludes that the applicant's response was acceptable and, therefore, the
 
staff's concern described in RAI B.1.9-4 is resolved.
The applicant stated that in 1994 it had installed shroud repair hardware (vertical tie rods) after cracks were discovered in the shroud horizontal welds. Subsequent inspections of the repair
 
hardware have confirmed that the tie rods are in good condition and continue to provide reliable
 
structural support for the shroud. Inspections of shroud vertical welds completed in 1998 and
 
2002 have confirmed that the Water Chemistry Program mitigation efforts have been successful as no new crack indications have been observed.
In RAI B.1.9-5 dated March 20, 2006, the staff requested that the applicant provide information on its future plans for type and frequency of inspections and percentage of the core shroud tie rods
 
currently inspected. If the inspection sample size was not consistent with the BWRVIP-76
 
guidelines the applicant was asked to explain the inconsistency. The staff also asked the 3-78 applicant for its inspection plans (i.e., inspection methods, sample size, and inspection frequency) of non-repaired core shroud welds during the period of extended operation.
In its response dated April 18, 2006, the applicant stated that thus far it had complied with the BWRVIP-76 guidelines for inspection of the core shroud. The program mandates 100 percent
 
inspection of the 10 shroud repair tie rods every 10 years with visual testing (VT-3) methods. In
 
addition, the BWRVIP-76 report specifies inspection of all of the tie rod repair anchorage points (lug-clevis assemblies) every 10 years by EVT-1. The BWRVIP-76 report does not require inspections for the shroud horizontal welds when they are repaired with the tie rods. The applicant
 
stated that the horizontal shroud welds are not inspected. However, it will continue to inspect all
 
accessible core shroud non-repaired (vertical) welds in accordance with the BWRVIP-76 report.
 
The staff finds this response acceptable because the applicant had made a commitment (Commitment No. 9) to monitor the aging degradation of the core shroud welds consistent with the recommendations of the BWRVIP-76 report and GALL AMP XI.M9.
The applicant stated that it had been inspecting the steam dryer every refueling outage for many years. Cracks were first identified on a lower bank brace in 1983 followed by weld repairs in 1983
 
and again in 1986. A different repair method, "stop drilling," was implemented in 1996 to mitigate
 
the cracks. Subsequent inspections indicate these measures have been successful in arresting
 
crack growth.
The staff is currently reviewing the BWRVIP-139 report relevant to the steam dryer component.
The applicant has modified its UFSAR and committed (Commitment No. 9) to inspect the steam
 
dryer in accordance with this Topical Report (TR). Because the staff's conditions and license
 
renewal items to be specified in the final SER of this TR will be incorporated in the BWRVIP-139, the staff concludes that this commitment is adequate.
The staff's review of OCGS operating experience concluded that by implementing the BWR Vessel Internals Program the applicant had adequately demonstrated its capability in identifying
 
the aging effects associated with the RVI components. The applicant also demonstrated that it
 
can adequately monitor the aging degradation of the RVI components by using proper corrective
 
actions to restore their structural integrity.
UFSAR Supplement. In LRA Section A.1.9 and letter dated April 18, 2006, the applicant provided the UFSAR supplement for the BWR Vessel Internals Program. The staff determined that the
 
information in the UFSAR 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 BWR Vessel Internals Program and RAI responses, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions
 
and their justifications and determined that the AMP, with the exceptions, is adequate to manage
 
the aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed
 
that implementation of the enhancements prior to the period of extended operation will make the
 
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
 
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).
3-79 3.0.3.2.10  Bolting Integrity Summary of Technical Information in the Application. In LRA Section B.1.12, the applicant described the existing Bolting Integrity Program as consistent, with an exception, with GALL AMP XI.M18, "Bolting Integrity."
The Bolting Integrity Program provides for condition monitoring of pressure-retaining bolted joints within the scope of license renewal. 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 &
 
Applications Guide," and EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power
 
Plants," as part of the comprehensive corporate component pressure retaining bolting program.
 
The program manages the loss of bolting function, including loss of material, cracking, and loss of
 
preload aging effects, by visual inspections for pressure-retaining bolted joint leakage. Inspection
 
of ASME Code Classes 1, 2, and 3 components is conducted in accordance with ASME Code Section XI. Non-Classes 1, 2, and 3 component inspections rely on detection of visible leakage
 
during routine observations and equipment maintenance activities. Procurement controls and
 
installation practices defined in plant procedures, ensure that only approved lubricants and torque
 
are applied. The activities are implemented through station procedures.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.10. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it is credited.
The staff reviewed those portions of the Bolting Integrity Program for which the applicant claimedconsistency with GALL AMP XI.M18 and found them consistent. Furthermore, the staff concluded
 
that the applicant's Bolting Integrity Program provides reasonable assurance that the aging
 
effects for bolting will be adequately managed for the period of extended operation. The staff
 
found that the applicant's Bolting Integrity Program conforms to the recommended GALL AMP XI.M18, with an exception described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "corrective actions
." Specifically, the exception stated:
NUREG-1801 indicates that the program covers all bolting within the scope of license renewal including component support and structural bolting. The Oyster
 
Creek Bolting Integrity program does not address structural or component support
 
bolting.In the LRA, the applicant stated that the Bolting Integrity Program does not address structural or component support bolting. For safety-related bolting, the GALL Report relies on the NRC
 
recommendations and guidelines delineated in NUREG-1339 and industry's technical basis for
 
the program and guidelines as to material selection and testing, bolting preload control, ISI, plant
 
operation and maintenance, and evaluation of structural integrity of bolted joints outlined in EPRI
 
NP-5769 with the exceptions noted in NUREG-1339.
The aging management of structural bolting is addressed by the Structures Monitoring Programand the ASME Section XI, Subsection IWE Program addresses primary containment pressure 3-80bolting. Aging management of ASME Code Section XI Classes 1, 2, and 3 and Class MC supportmembers is addressed by the ASME Section XI, Subsection IWF Program.
The staff reviewed this exception and found that structural or component support bolting agingeffects will be adequately managed by the Structures Monitoring, ASME Section XI, Subsection IWE, and the ASME Section XI, Subsection IWF Programs. The staff's review of these AMPs is
 
discussed in SER Sections 3.0.3.2.24, 3.0.3.2.22 and 3.0.3.2.26, respectively. On this basis, the
 
staff finds this exception acceptable.
Enhancement. In the LRA, the applicant stated that no enhancements were needed for this AMP.
However, in the PBD the applicant identified an enhancement to the GALL Report program
 
elements "scope of program," "preventive actions
," and "corrective actions." Specifically, the enhancement stated:
Enhance site procedure to include reference to EPRI TR-104213, "Bolted Joint Maintenance & Application Guide," December 1995.
The applicant stated, in the PBD, that the program addresses the guidance in EPRI TR-104213,"Bolted Joint Maintenance & Applications Guide;" however, the report is not specifically cited as a
 
reference in the Exelon corporate or station-specific bolted joint inspection/repair procedures. The
 
staff noted that this enhancement is not identified in LRA Section B1.12. The applicant was asked
 
to clarify this discrepancy.
In its letter dated April 17, 2006, the applicant committed (Commitment No. 12) to revise the Bolting Integrity Program in the LRA to include the enhancement identified in the PBD stating that
 
the site procedure will be enhanced to include reference to EPRI TR-104213, "Bolted Joint
 
Maintenance & Application Guide," December 1995.
The staff reviewed the EPRI TR-104213, 1995 Edition, and finds it an acceptable revision of the original EPRI TR-104213. The staff finds this enhancement acceptable as when implemented the program will be consistent with GALL AMP X I.M18 and provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.12, the applicant explained that it had experienced isolated cases of bolting function loss attributed to loss of material. Review of operating history
 
has identified no cracking of stainless steel bolting. RCPB leakage due to boric acid-induced
 
degradation is not applicable because the station is a BWR. In all cases the existing inspection
 
and testing methodologies have discovered the deficiencies and corrective actions have been
 
implemented prior to loss of syst em or component intended functions.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Bolting Integrity Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
3-81 UFSAR Supplement. In LRA Section A.1.12 and letter dated April 17, 2006, the applicant provided the UFSAR supplement for the Bolting Integrity Program. The staff determined that the
 
information in the UFSAR supplement provides 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 determined that those program elements for which the applicant claimed consistency with
 
the GALL Report are consistent. In addition, the staff reviewed the exception and the
 
enhancement and their justifications and determined that the AMP, with the exception and the
 
enhancement, is adequate to manage the aging effects for which it is credited. The staff
 
concludes that the applicant has demonstrated that the effects of aging will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the period
 
of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR
 
supplement for this AMP and concludes that it provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3.0.3.2.11  Open-Cycle Cooling Water System
 
Summary of Technical Information in the Application. In LRA Section B.1.13, the applicant described the existing Open-Cycle Cooling Water System (OCCWS) Program as consistent, withenhancements, with GALL AMP XI.M20, "O pen-Cycle Cooling Water System."
The Open-Cycle Cooling Water System Program manages aging of piping, piping components, piping elements, and heat exchangers included in the scope of license renewal for loss of material
 
and reduction of heat transfer and exposed to raw water-salt water. Program activities include: (1)
 
surveillance and control of biofouling (including biocide injection), (2) verification of heat transfer
 
capabilities for components cooled by the SW and ESW systems, (3) inspection and maintenance
 
activities, (4) walkdown inspections, and (5) review of maintenance, operating, and training
 
practices and procedures. Inspections may include visual, UT, and eddy current testing (ECT)
 
methods. The OCCWS Program is based on the recommendations of NRC GL 89-13.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.11. The staff reviewed the
 
enhancements and their justifications to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it was credited.
The staff reviewed those portions of the Open-Cycl e Cooling Water System Program for which theapplicant claimed consistency with GALL AMP XI.M20 and found them consistent. Furthermore, the staff concluded that the applicant's Open-Cy cle Cooling Water System Program provides reasonable assurance that aging effects attributable to open cycle cooling water will be
 
adequately managed during the period of extended operation. The staff found that the applicant's
 
Open-Cycle Cooling Water System Program conforms to the recommended GALL AMP XI.M20 with enhancements described below.
Enhancement 1. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," and "monitoring and trending." Specifically, the enhancement stated:
3-82 The open-cycle cooling water aging management program will be enhanced to include volumetric inspections, for piping that has been replaced, at a minimum of
 
4 aboveground locations every 4 years based on the observed and anticipated
 
performance of the new pipe.
In reviewing this enhancement, the staff noted that volumetric inspections of above-ground ESW and SW piping original to the plant design are at a minimum of 10 locations every 2 years based
 
on the maximum anticipated corrosion rates determined from past inspections and analyses. The
 
enhancement will add a minimum of 4 UT inspections every 4 years on above-ground piping
 
replaced with the same coatings and materials as new buried ESW and SW piping. As
 
above-ground and buried piping are subject to the same internal environments and failure
 
mechanisms, the volumetric inspections of above-ground piping bound the buried portions of
 
piping. During the audit, the applicant confirmed that the inspection locations for new piping are in
 
addition to the minimum of 10 locations for the original above-ground ESW and SW piping. The
 
applicant also stated that the frequency of the testing and inspections is based on previous
 
findings and, if testing and inspections need to be more frequent or the scope needs to be
 
increased, the program allows for such adjustments.
The staff determined that the enhancement will provide an adequate method of inspecting piping that has been replaced and is consistent with the recommendations in the GALL Report. The
 
inspection samples and frequencies are adequate because, based on previous findings, the
 
applicant's program allows for adjustment of the sample and frequency as needed. On this basis, the staff finds the enhancement acceptable because when implemented the program will beconsistent with GALL AMP XI.M20 and will provide additional assurance that the effects of aging
 
will be adequately managed.
Enhancement 2. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," and "monitoring and trending." Specifically, the enhancement stated:
The open-cycle cooling water aging management program will be enhanced to include specificity on inspection of heat exchangers for loss of material due to
 
general, pitting, crevice, galvanic and microbiologically influenced corrosion in the
 
RBCCW, TBCCW and Containment Spray preventative maintenance tasks.
In reviewing this enhancement the staff noted that the reactor building closed cooling water (RBCCW) and containment spray heat exchangers are included in the scope of license renewal
 
for the intended function of pressure boundary and heat transfer. The turbine building closed
 
cooling water (TBCCW) heat exchangers are included for a leakage boundary function only. The
 
current GL 89-13 program includes only the ESW system and containment spray heat
 
exchangers. Attributes of the GL 89-13 guidanc e will be implemented for the SW system, RBCCW system, and TBCCW system heat exchangers as par ts of the Open-Cycle Cooling Water System Program. Upon implementation of this enhancemen t, the program will be consistent with therecommendations in AMP XI.M20 in the GALL Report.
On this basis, the staff finds this enhancement acceptable because when implemented the Open-Cycle Cooling Water System Program will be consistent with GALL AMP XI.M20 and will provide additional assurance that the effects of aging will be adequately managed.
3-83 Operating Experience. In LRA Section B.1.13, the applicant explained that OCGS had reviewed both industry and plant-specific operating experience with the Open-Cycle Cooling Water System
 
Program. Inspections implementing the guidance of GL 89-13 have identified deterioration, degradation, and loss of material from inside the pipe.
OCGS evaluations have identified the buried pi ping with high risk of developing leaks and grave consequences should leaks occur. Piping replacements are scheduled based on the risk priority, and the monitoring and inspection program assures that the piping maintains adequate wall
 
thickness with margin prior to replacement.
The methodology for determining corrosion rates and projected service life was revised in 2002 based on analysis of station operating experience and previous inspection results. Additionally, in
 
2004, 50 percent of the buried ESW and 10 percent of the buried SW piping were replaced with
 
new pipe and an improved coating system. A plan is in place to replace the other 50 percent of the buried ESW piping prior to 2007.
After reviewing several ESW pipe leaks and wall thinning events, the applicant identified a common failure mechanism (local wall thinning due to salt-water corrosion). The results were
 
entered into the corrective action process and an operability evaluation was performed in 2003.
 
The operability evaluation included the effect of the failure mechanism on the SSC safety function
 
thresholds and methods for detection of leaks for each of the safety functions. Additionally, the
 
corrective action process problem resolution response developed an inspection plan, "Topical
 
Report 140 - ESW and Service Water System Plan." Some of the plan's goals are to prioritize
 
modifications and inspections based on risk and consequence of a leak, to modify piping
 
segments that pose high risks and cannot reasonably be inspected, to modify piping to allow
 
system flexibility for future repairs, and to inspect piping to ensure disposition/repair prior to
 
failure. The plan captures existing analysis, past action, and future action for ESW and SW pipe.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Open-Cycle Cooling Water System Program w ill adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.13, the applicant provided the UFSAR supplement for the Open-Cycle Cooling Water System Program. The staff reviewed this section and determined that the information in the UFSAR supplement provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Open-Cycle Cooling Water System Program, the staff determined that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. Also, the staff reviewed the
 
enhancements and confirmed that their implementat ion prior to the period of extended operation will make the 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 3-84 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  Closed-Cycle Cooling Water System
 
Summary of Technical Information in the Application. In LRA Section B.1.14, the applicant described the existing Closed-Cycle Cooling Wate r System (CCCWS) Program as consistent,with an exception, with GALL AMP XI.M21, "Closed-Cycle Cooling Water System" The Closed-Cycle Cooling Water System Progr am manages aging of piping, piping components, piping elements, and heat exchangers included in the scope of license renewal for loss of material
 
and reduction of heat transfer and exposed to a closed cooling water environment. The program
 
provides for preventive, performance monitoring, and condition monitoring activities implemented through station procedures. Preventive activities include measures to maintain water purity and
 
the addition of inhibitors to minimize corrosion based on EPRI 1007820, "Closed Cooling Water
 
Chemistry Guidelines." Performance monitoring indicates degradation in CCCWSs with plant
 
operating conditions indicating degradation in normally operating systems. In addition, station
 
maintenance inspections and NDE monitor the condition of heat exchangers exposed to
 
closed-cycle cooling water environments.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.12. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it is credited.
The staff reviewed those portions of the Closed-Cycle Cooling Water System Program for whichthe applicant claimed consistency with GALL AMP XI.M21 and found them consistent with the
 
GALL Report AMP. Furthermore, the staff concluded that the applicant's Closed-Cycle Cooling
 
Water System Program provides reasonable a ssurance that aging effects attributable to closed-cycle cooling water systems will be adequately managed during the period of extended operation. The staff found that the applicant's program conforms to the recommended GALL AMP XI.M21 with an exception described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "preventive actions," "parameters monitored or inspected," "detection of aging effects,"
"monitoring and trending," and "acceptance criteria." Specifically, the exception stated:
NUREG 1801 refers to EPRI TR-107396 Closed Cooling Water Chemistry Guidelines 1997 Revision. Oyster Creek implements the guidance provided in
 
EPRI 1007820 "Closed Cooling Water Chemistry Guideline, Revision 1" which is
 
the 2004 Revision to TR-107396. EPRI periodically updates industry water
 
chemistry guidelines, as new informati on becomes available. Oyster Creek has reviewed EPRI 1007820 and has determined that the most significant difference is
 
that the new revision provides more prescriptive guidance and has a more
 
conservative monitoring approach. EPRI 1007820 meets the same requirements of
 
EPRI TR-107396 for maintaining conditions to minimize corrosion and
 
microbiological growth in closed cooling water systems for effectively mitigating
 
many aging effects.
3-85 During the audit, the applicant described its review and evaluation of the differences between EPRI TR-107396, "Closed Cooling Water Chemistry Guidelines," the 1997 revision of the
 
guidelines referred to in the GALL Report, and EPRI TR-1007820, "Closed Cooling Water
 
Chemistry Guideline, Revision 1," which is the 2004 revision implemented by OCGS. In addition, the applicant stated that the most significant difference is that EPRI TR-1007820 provides more
 
prescriptive guidance and has a more conservative monitoring approach. The applicant further
 
stated that EPRI TR-1007820 meets the same recommendations of EPRI TR-107396 for
 
maintaining conditions to minimize corrosion and microbiological growth in closed cooling water
 
systems for effectively mitigating many aging effects. In addition, the applicant stated that it had
 
contacted the author of EPRI TR-107396 and EPRI TR-1007820, Anthony Selby, to confirm that
 
the new guidance provided in TR-1007820 was not contrary to that in TR-107396.
The staff reviewed EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline, Revision 1,"
and EPRI TR-107396, Revision 0, and confirmed the applicant's assessment that the new
 
revision provides more prescriptive guidance, has a more conservative monitoring approach, and
 
meets the same recommendations for maintaining conditions to minimize corrosion and
 
microbiological growth in closed cooling water systems for effectively mitigating many aging effects. On this basis, the staff finds this exception acceptable.
Operating Experience. In LRA Section B.1.14, the applicant explained that the OCGS has not experienced a loss of intended function failure of components due to corrosion product buildup or
 
through-wall loss of material for components within the scope of license renewal subject to
 
CCCWS activities. Additionally, industry operat ing experience demonstrates that corrosion inhibitors in CCCWSs monitored and maintained are effective in mitigating loss of material and
 
buildup of deposits. Buildup of deposits have degraded heat transfer in heat exchangers on the
 
tube side of the heat exchangers. The tube side of the heat exchangers is exposed to raw
 
water-salt water and managed by the Closed-Cycle Cooling Water System Program.
In 2002 OCGS increased its desired molybdate range in all of the CCCWSs from 50-125 ppm to 200-1000 ppm, enabling OCGS to align with industry best practices.
In 2004, the pH in the TBCCW system decreased outside the Action Level 1 range for pH. A caustic add returned pH back in spec within the acceptable time period for correcting an Action
 
Level 1 CCW limit.
In addition to mitigating loss of material and buildup of deposits by maintaining water chemistry, OCGS monitors the RBCCW, TBCCW and emergency diesel generator (EDG) cooling water (EDGCW) for microbiological growth (total bacteria colonies) in accordance with EPRI 1007820, "Closed Cooling Water Chemistry Guidelines." To date there have been no adverse trends in
 
microbiological growth in CCCWSs.
By improving the CCCW monitoring parameters, promptly returning out of range parameters within acceptable limits, and monitoring for microbiological growth OCGS has been effective in
 
managing loss of material and reduction of heat transfer for components in a closed cooling water
 
environment. Additionally, the Closed-Cycle C ooling Water System Program is adjusted continually to account for industry and station experience and research. With additional operating
 
experience lessons learned will be used to adjust this program as needed.
3-86 The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Closed-Cycle Cooling Water System Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.14, the applicant provided the UFSAR supplement for the Closed-Cycle Cooling Water System Program. The staff reviewed this section and determined
 
that the information in the UFSAR supplement provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Closed-Cycle Cooling Water System Program, the staff determined that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
exception and its justifications and determined that the AMP, with the exception, is adequate to
 
manage the aging effects for which it is credited. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.13  Boraflex Rack Management Program
 
Summary of Technical Information in the Application. In LRA Section B.1.15, the applicant described the existing Boraflex Rack Management Progr am as consistent, with an exception, withGALL AMP XI.M22, "Boraflex Monitoring."
The Boraflex Rack Management Program is bas ed on manufacturer recommendations, industry guidelines developed in response to GL 96-04, and plant-specific operating experience. The
 
program employs a defense in depth strategy to detect and take appropriate actions for degraded
 
Boraflex to ensure the 5 percent subcriticality margin is maintained. The program consists of
 
condition monitoring activities that include periodi c inspection of sample Boraflex coupons, in-situ testing of boron areal density using the BADGER device, monitoring dissolved silica in the spent
 
fuel storage pool, and trending the results with an EPRI RACKLIFE predictive code. The
 
RACKLIFE predictive model is updated periodically and validated through the BADGER boron
 
areal density tests. The BADGER test is conducted every 3 years.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.13. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it is credited.
The staff reviewed those portions of the Boraflex Rack Management Program for which theapplicant claimed consistency with GALL AMP XI.M22 and found them consistent. Furthermore, the staff concluded that the applicant's Borafl ex Rack Management Program provides reasonable 3-87 assurance that the effects of aging will be managed adequately during the period of extended operation. The staff found that the applicant's Boraflex Rack Management Program conforms to the recommended GALL AMP XI.M22 with an exception described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program element "preventive actions." Specifically, the exception stated:
Blackness test is not performed. The test is replaced with boron areal density measurements using the BADGER device, which gives a better indication of
 
Boraflex effectiveness to perform its intended function.
In the LRA, the applicant stated that blackness test is not performed. The test is replaced with boron areal density measurements using the BADGER device, which gives a better indication of
 
Boraflex effectiveness to perform its intended function. During the audit, the staff questioned why
 
area density measurement is equal to or better than Blackness tests. The applicant replied that
 
blackness testing provides only information on the presence of neutron absorber material.
 
Blackness testing provides information on gaps or missing sections in the Boraflex panel.
 
However, areal density testing using BADGER provides a direct measurement of in-rack
 
performance of Boraflex panels. The areal density test measures gaps, erosion, and general
 
thinning of the scanned Boraflex panel. Blackness testing gives only an indication whether
 
neutron absorber is present in a boraflex panel whereas a BADGER test quantitatively measures
 
the Boron-10 areal density of neutron absorber in the rack.
The staff reviewed this exception and concludes that because the areal density test is more quantitative than the blackness test this exception is acceptable.
Operating Experience. In LRA Section B.1.15, the applicant explained that the Boraflex Rack Management Program has been in effect since 1986 when the new high-density poison racks
 
were installed in the spent fuel storage pool. The program initially consisted of testing of sample
 
coupons maintained in the spent fuel pool and upgraded later to include in-situ testing of boron
 
areal density with the BADGER device. To date two BADGER tests have been conducted, the
 
first in 1997, the second in 2001. Both identified the presence of degradations similar to those
 
experienced in the industry, including some areas of local dissolution of boron carbide, and
 
formation of shrinkage-induced gaps. However, both tests show that the average areal density of
 
Boraflex is well in excess of the minimum areal density certified by the manufacturer. The in-situ
 
areal density test by the BADGER device has proved effective in identifying unacceptable
 
degradation prior to a loss of an intended function.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant
 
Boraflex Rack Management Program will adequately manage the aging effects identified in the
 
LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.15, the applicant provided the UFSAR supplement for the Boraflex Rack Management Program. The staff reviewed this section and determined that the 3-88 information in the UFSAR supplement provides 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 Boraflex Rack Management Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exception, is adequate to manage the
 
aging effects for which it is credited. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes
 
that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.14  Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Summary of Technical Information in the Application. In LRA Section B.1.16, the applicant described the existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
 
Handling Systems Program as consistent, with an exception and enhancements, with GALLAMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
 
Handling Systems."
This Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program provides for periodic visual inspections of overhead heavy load and light load (related to
 
refueling) handling systems through station procedures and is relied upon to manage loss of
 
material of cranes and hoists structural components, including the bridge, the trolley, bolting, lifting devices, and the rail system within the scope of 10 CFR 54.4. Bolting is monitored for loss
 
of material and loss of preload by inspections for missing, detached or loosened bolts. The
 
program relies on procurement controls and installation practices defined in plant procedures to
 
ensure that only approved lubricants and proper torque are applied consistent with the GALL
 
Report Bolting Integrity Program. Inspection frequency is annual for cranes and hoists accessible
 
during plant operation and every 2 years for cranes and hoists accessible only during refueling
 
outages.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.14. The staff reviewed the exception
 
and enhancements and their justifications to determine whether the AMP, with the exception and
 
enhancements, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program for which the applicant claimed consistencywith GALL AMP XI.M23 and found them consistent. Furthermore, the staff concluded that the
 
applicant's program provides reasonable assurance that the aging effects for which this program
 
is credited will be adequately managed. The staff found that the applicant's Inspection of
 
Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program conforms to the recommended GALL AMP XI.M23 with the exception and enhancements
 
described below.
3-89 Exception: In the LRA, the applicant stated an exception to the GALL Report program element "monitoring and trending." Specifically, the exception stated:
NUREG-1801 indicates that the number and magnitude of lifts made by the crane are reviewed. The Oyster Creek program does not require tracking of the number
 
and magnitude of lifts. Administrative controls are implemented to ensure that only
 
allowable loads are handled. As discussed in the Crane Load Cycle Limit
 
time-limited aging analysis (TLAA), the projected number of load cycles for 60
 
years for the reactor building crane is 2800 cycles. The projected number of load
 
cycles for 60 years for the turbine building and heater bay cranes are 2000 and
 
600 cycles respectively. The reactor building crane, the turbine building and the
 
heater bay cranes were designed for 20,000 to 100,000 load cycles. Thus tracking
 
the number of lifts, or load cycles, is not required because the projected number of
 
crane load cycles for 60 years is significantly lower than the design value.
In reviewing this exception, the staff noted that, while early versions of the GALL Report included a recommendation to monitor the number and m agnitude of lifts made by the cranes, the approved September 2005 Revision 1 version of the GALL Report no longer includes this
 
recommendation. Therefore, the applicant's program element is consistent with the GALL Report
 
as to monitoring the number of lifts and no excepti on is required. In Attachment 1, item B.1.16 of its reconciliation document, the applicant stated that this exception had been deleted.
On the basis that the GALL Report Revision 1 does not recommend monitoring the number of lifts made by each crane the staff determined that the applicant's program element is consistent with
 
the GALL Report and that this exception is not required.
Enhancement 1. In the LRA, the applicant stated an enhancement to the GALL Report program element "scope of program." specifically, the enhancement stated:
Increase the scope of the program to include additional hoists identified as potential Seismic II/I concern, in accordance with 10 CFR 54.4(a)(2).
The staff noted that LRA Section 2.3.3.11 stated that other cranes and hoists not in scope of NUREG-0612 but traveling in the vicinity of safety-related SSCs are also within the scope of
 
license renewal if their failure will impact a safety-related function. As a result, the reactor building
 
crane, the turbine building crane, turbine building heater bay crane, recirculation pumps monorail, spent fuel pool jib cranes, containment vacuum breakers jib cranes/hoists, equipment handling
 
monorail (elevation 95'), and the torus bay monorail are within the scope of license renewal. This
 
enhancement makes the AMP consistent with the recommendations of the GALL Report.
On this basis, the staff finds the enhancement acceptable because when implemented the Inspection of the Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M 23 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 2. In the LRA, the applicant stated an enhancement to the GALL Report program elements "parameters monitored or inspected" and "detection of aging effects." Specifically, the enhancement stated:
The program will provide for specific inspections for rail wear.
3-90 The staff reviewed the GALL Report recommendations for these program elements and determined that the addition of specific inspections for rail wear will make the applicant's AMP
 
consistent with the recommendations in the GALL Report; therefore, this enhancement is
 
acceptable.
On this basis, the staff finds the enhancement acceptable because when the enhancement is implemented the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
 
Handling Systems Program will be consistent with GALL AMP XI.M23 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 3. In the LRA, the applicant stated an enhancement to the GALL Report program elements "parameters monitored or inspected," "detection of aging effects," and "acceptance
 
criteria." Specifically, the enhancement stated:
The program will provide for specific inspections for corrosion of crane and hoist structural components, including the bridge, the trolley, bolting, lifting devices, and
 
the rail system.
The staff reviewed the GALL Report recommendations for these program elements and determined that the addition of specific inspections for corrosion of crane and hoist structural
 
components including the bridge, the trolley, bolti ng, lifting devices, and the rail system will make the applicant's AMP consistent with the recommendations in the GALL Report. On this basis, the
 
staff concludes that this enhancement is adequate.
On this basis, the staff finds the enhancement acceptable because when implemented the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent with GALL AMP XI.M 23 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.16, the applicant explained that the plant operating and maintenance experience review identified no incidents of failure of passive cranes and hoists
 
structural components due to age-related degradations. Minor nonage-related degradations have
 
been identified in nonload-bearing components during the inspections. The degradations were
 
repaired and documented in accordance with the corrective action process.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems
 
Program will adequately manage the aging effects identified in the LRA for which this AMP is
 
credited.UFSAR Supplement. In LRA Section A.1.16, the applicant provided the UFSAR supplement for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems
 
Program. The staff reviewed this section and determined that the information in the UFSAR
 
supplement provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-91 Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff determined that
 
those program elements for which the applicant claimed consistency with the GALL Report are
 
consistent. In addition, the staff reviewed the exception and its justifications, and determined that
 
the AMP, with the exception, is adequate to manage the aging effects for which it is credited.
 
Also, the staff reviewed the enhancements and confirmed that their implementation prior to the
 
period of extended operation will make the 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 intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also
 
reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.15  BWR Reactor Water Cleanup System
 
Summary of Technical Information in the Application. In LRA Section B.1.18, the applicant described the existing BWR Reactor Water Cleanup System Program as consistent, with an exception, with GALL AMP XI.M25, "BWR Reactor Water Cleanup System."
The BWR Reactor Water Cleanup System Program describes the requirements for augmented ISI for SCC or IGSCC on stainless steel RWCU system piping welds outboard of the second
 
containment isolation valves. The program includes inspection guidelines delineated in
 
NUREG-0313, Revision 2 and GL 88-01. The program also provides for water chemistry control in
 
accordance with BWRVIP-130, "BWR Vessel and Internals Project BWR Water Chemistry
 
Guidelines," to minimize the potential of crack initiation and growth due to SCC or IGSCC. In
 
accordance with GL 88-01, Supplement 1, upgrades and enhancements have been implemented to the RWCU isolation valves in accordance with GL 89-10 to ensure that the valves will produce
 
sufficient thrust to perform their design basis function, which is the isolation of containment in the
 
event of a pipe break downstream of the valves.
RCS chemistry activities that support the AMP for the RWCU system consist of preventive measures used to manage cracking in license renewal components exposed to reactor water and steam.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.15. The staff reviewed the exception
 
and its justifications to determine whether the AMP, with the exception, remained adequate to
 
manage the aging effects for which it is credited.
The staff reviewed those portions of the BWR Reactor Water Cleanup System Program for whichthe applicant claimed consistency with GALL AMP XI.M25 and found them consistent with the
 
GALL Report AMP. The staff found that the applicant's BWR Reactor Water Cleanup System
 
Program conforms with the recommended GAL AMP XI.M25 with an exception described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report AMP element "preventive actions." Specifically, the exception stated:
NUREG-1801 indicates that water chemistry control is in accordance with BWRVIP-29, "EPRI Report TR-103515-R1, BWR Water Chemistry Guidelines" dated 1996. The Oyster Creek water chemistry program is based on BWRVIP-130, "BWR Vessel and Internals Project BWR Water Chemistry Guidelines" dated 2004.
3-92 The staff reviewed the applicant's exception as part of the Water Chemistry Program and determined that it is acceptable. The evaluation of this exception is discussed in SER
 
Section 3.0.3.2.2.
Operating Experience. In LRA Section B.1.18, the applicant explained that no indications of IGSCC have been found in the RWCU, which is not stress-improved. The following mitigative
 
actions also have been implemented to reduce the susceptibility to IGSCC in the RWCU system:
improved water chemistry guidelines (BWR Water Chemistry Guidelines
 
2004 Revision (BWRVIP-130)), HWC, and NMCA.
The staff requested clarification on when the HWC and NMCA mitigative actions had been initiated. In its response, the applicant stated that the HWC had been implemented during
 
cycle 12 (1990) and NMCA implemented in refueling outage 1R19 (2002).
The staff reviewed the operating experience provided in the LRA and PBDs, interviewed the applicant's technical personnel, and confirmed that the plant-specific operating experience
 
revealed no degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's BWR
 
Reactor Water Cleanup System Program will adequately manage the aging effects identified in
 
the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.18, the applicant provided the UFSAR supplement for the BWR Reactor Water Cleanup System Program. The staff reviewed this section and
 
determined that the information in the UFSAR supplement provides 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 BWR Reactor Water Cleanup System Program, the staff determined that those program elements for which the applicant
 
claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the
 
exception and its justifications and determined that the AMP, with the exception, is adequate to
 
manage the aging effects for which it is credited. The staff concludes that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB for the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and
 
concludes that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.16  Fire Protection
 
Summary of Technical Information in the Application. In LRA Section B.1.19, the applicant described the existing Fire Protection Program as consistent, with an exception and enhancements, with GALL AMP XI.M26, "Fire Protection."
The Fire Protection Program provides for aging management of various fire protection-related components within the scope of license renewal. The program visually inspects fire barrier
 
penetration seals for such signs of degradation as change in material properties, cracking, and
 
loss of material, through periodic inspection, surveillance, and maintenance activities. The
 
program visually inspects fire barrier walls, ceilings, and floors in structures within the scope of 3-93 license renewal for the aging effects of cracking and loss of material. The program provides for periodic visual inspections of fire doors for holes in skin, wear, or missing parts. Fire door
 
clearances are checked during periodic inspections and whenever fire doors and components are
 
repaired or replaced. The program will manage loss of material aging effects for the fuel oil
 
systems for the diesel-driven fire pumps by periodic fuel oil system surveillance tests implemented through recurring task work orders and station procedures. The program will
 
manage aging of external surfaces of the carbon dioxide and halon fire suppression system
 
components by corrosion and mechanical damage through periodic operability tests based on the
 
National Fire Protection Association (NFPA) codes and visual inspections.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.16. The staff reviewed the exception
 
and enhancements and their justifications to determine whether the AMP, with the exception and
 
enhancements, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Fire Protection Program for which the applicant claimedconsistency with GALL AMP XI.M26 and found them consistent. The staff found that the applicant's Fire Protection Program conforms to the recommended GALL AMP XI.M26 with the
 
exception and enhancements described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "parameters monitored or inspected" and "detecti on of aging effects." Specifically, the exception stated: NUREG-1801 recommends visual inspection and functional testing of the halon and CO 2 fire suppression systems at least once every six months. The Oyster Creek halon and low-pressure carbon dioxide fire suppression systems undergo
 
operational testing and inspections every 18 months. Additionally, the halon fire
 
suppression system undergoes an inspection of the system charge (storage tank weight/level and pressure) every 6 months, and the low-pressure carbon dioxide
 
fire suppression system undergoes a weekly tank check and monthly valve position alignment verification. These test frequencies are considered sufficient to ensure
 
system availability and operability based on the station's operating history that
 
shows no aging related events that hav e adversely affected the systems' operation. The test procedures will be enhanced to include visual inspections of
 
the component external surfaces. Test and inspection frequency adequacy will be
 
evaluated as part of the corrective action process based on actual test and
 
inspection results.
In reviewing this exception, the staff noted that the Fire Protection Program directs halon fire suppression system surveillance that verifies halon storage tank weight, level, and pressure every
 
six months. Actuation of the system (autom atic and manual, including dampers) and flow are verified every 18 months. The program also directs performance of functional operability testing
 
and flow verification, including operation of associated ventilation dampers and manual and
 
automatic actuation. The low-pressure carbon dioxide fire suppression system undergoes a
 
weekly tank check and monthly valve position alignment verification. Visual aging degradation
 
inspections are performed during the operability tests. Existing operability testing requirements
 
are implemented through station procedures. The staff noted that the CLB for periodic inspection
 
and functional test frequency of the halon and CO 2 systems is every 18 months.
3-94 OCGS test procedures will be enhanced to include visual inspections of component external surfaces for signs of corrosion and mechanical damage. In LRA Section B.1.19, the applicant
 
stated that plant-specific operating experience shows no loss of material on the external surfaces
 
of components in the halon and carbon dioxide sy stems that have adversely affected system operation. The applicant's review of station operating experience identified no aging-related
 
degradation adversely affecting the operation of the halon or CO 2 systems. Although the frequency of functional testing exceeds that recommended in GALL AMP XI.M26, the staff determined that it is sufficient to ensure system availability and operability with the
 
enhancement to include visual inspections of component external surfaces for signs of corrosion
 
and mechanical damage. In addition, the station operating history indicates no aging-related
 
events adversely affecting system operation. Ba sed on its review of the applicant's program and plant-specific operating experience, the staff finds that the 18-month frequency is adequate for
 
aging management considerations. On this basis, the staff finds this exception acceptable.
Enhancement 1. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "parameters monitored or ins pected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement stated:
The fire protection aging management program will be enhanced to include inspection for corrosion and mechanical damage on external surfaces of piping
 
and components for the Oyster Creek halon and carbon dioxide fire suppression systems.In reviewing this enhancement, the staff noted that the applicant's Fire Protection Program includes periodic halon and low-pressure carbon dioxide fire suppression system inspections, including inspections for operation of the dampers. This enhancement will add visual inspections
 
of the piping and components for external surface corrosion degradation and mechanical damage
 
as recommended in the GALL Report. The addition of these visual inspections will provide
 
additional assurance that aging degradation of the fire protection system piping and components
 
will be adequately managed; therefore, this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire ProtectionProgram will be consistent with GALL AMP XI.M 26 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 2. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "parameters monitored or ins pected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement stated:
The fire protection aging management program will be enhanced to provide specific guidance for examining the fire pump diesel fuel supply systems for
 
corrosion during pump tests.
In reviewing this enhancement, the staff noted that the applicant's Fire Protection Program includes operational tests of the diesel-driven fire pumps to record flow and discharge, starting
 
capability, and controller function to be performed every 18 months. These operational tests
 
detect degradation of the fuel supply lines before the loss of the component intended function.
 
This enhancement will add a visual inspection for detecting any degradation of external surfaces
 
of the fuel supply line during engine operation as recommended in the GALL Report. Because the 3-95 inclusion of visual inspections will provide additional assurance of adequate management of aging degradation of the fuel supply lines this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire ProtectionProgram will be consistent with GALL AMP XI.M 26 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 3. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "parameters monitored or ins pected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement stated:
The fire protection aging management program will be enhanced to provide additional inspection guidance for degradation of fire barrier walls, ceilings, and floors such as
 
spalling and loss of material caused by freeze-thaw, chemical attack, and reaction with
 
aggregates. Enhancements will be implemented pr ior to the period of extended operation.
In reviewing this enhancement, the staff noted that, as part of the applicant's Fire Protection Program, the aging effects on the intended function of fire barrier walls, ceilings, and floors that
 
perform a fire barrier function are managed by specific inspection parameters in accordance with
 
industry codes, standards, and guidelines that detect and correct aging degradation prior to loss
 
of intended functions. This enhancement will add inspections of fire barrier walls, ceilings, and
 
floors for signs of degradation including but not limited to cracking, spalling, and loss of material
 
caused by freeze-thaw, aggressive chemical attack, reaction with aggregates, and corrosion of
 
embedded steel as recommended in the GALL Report. As these enhanced inspections will
 
provide additional assurance of adequate management of aging degradation of fire barrier walls, ceilings, and floors this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire ProtectionProgram will be consistent with GALL AMP XI.M 26 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 4 , In the PBD for this AMP, the applicant stated an additional enhancement in meeting the GALL Report program elements "param eters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria" not identified in the LRA.
 
Specifically, the enhancement stated:
The fire protection aging management program will be enhanced to require that surface integrity and clearances of fire doors in the scope of license renewal be
 
routinely inspected every two years. The program currently requires these doors be intact and verified functional, with fire doors identified as secondary containment
 
receiving routine clearance checks. Other fire doors in the scope of license
 
renewal currently receive clearanc e checks if they have been damaged or undergone maintenance such that the clearances may have been physically
 
altered. The enhancement of requiring routine surface integrity and clearance
 
checks for all fire doors in the scope of license renewal will provide assurance that
 
degradation of fire doors prior to loss of intended function will be detected.
In its letter dated April 17, 2006, the applicant committed (Commitment No. 19) to revise LRA Section B.1.19 to add the following enhancement to the Fire Protection Program for periodic 3-96 visual inspections of fire door surface integrity and clearance checks as described in PBD-AMP-B.1.19.
In reviewing this enhancement, the staff noted that the applicant's Fire Protection Program will direct that fire doors within the scope of license renewal be visually inspected by designated
 
qualified personnel for such signs of degradation as wear, missing parts, holes, and clearances.
 
Functional/operational condition tests of fire doors also will be conducted. In PBD-AMP-B.1.19, the applicant further stated that enhancements to the program will direct visual inspection of fire
 
doors for integrity of door surfaces and clearance checks every 2 years. This inspection frequency
 
ensures timely detection and correction of degraded door conditions prior to a loss of intended
 
function. The staff determined that visual inspection of fire doors for such signs of degradation as
 
wear, missing parts, holes, and clearances will provide additional assurance of adequate
 
management of aging effects as recommended in the GALL Report; therefore, this enhancement
 
is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire ProtectionProgram will be consistent with GALL AMP XI.M 26 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.19, the applicant explained that the Fire Protection Program had been effective in identifying aging effects and taking appropriate corrective action.
 
Minor degradation like minor cracks have been detected in concrete components in structures
 
within the scope of license renewal. Evaluation and disposition of observed degradation were
 
based on program acceptance criteria and in accordance with the corrective action process. The
 
OCGS experience with fire barrier penetration seal s is consistent with the industry experience.
Silicone foam fire barrier penetration seals are used. OCGS has experienced fire door component
 
degradation due to wear, loss of material due to corrosion, and physical damage. Mitigating
 
actions have been taken as appropriate. OCGS operating experience shows no loss of material
 
on the external surfaces of components in the halon and carbon dioxide systems adversely affecting system operation. The OCGS diesel-dri ven fire pump fuel oil systems have experienced minor system events promptly detected and co rrected. These events were detected and corrected prior to loss of intended function of the fire pumps. There have been no reports of loss of material
 
or flow blockage of the fuel oil subsystems.
The staff reviewed the operating experience prov ided in the LRA and Program Basis Document PDB-AMP-B.1.19 and interviewed the applicant's technical personnel to confirm that the
 
plant-specific operating experience revealed no degradation not bounded by industry experience.
 
The Fire Protection Program activities with enhancements will be effective in managing aging
 
degradation for the period of extended operation by timely detection of aging effects and
 
appropriate corrective actions prior to loss of system or component intended functions.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Fire
 
Protection Program will adequately manage the aging effects identified in the LRA for which this
 
AMP is credited.
UFSAR Supplement. In LRA Section A.1.19 and letter dated April 17, 2006, the applicant provided the UFSAR supplement for the Fire Protection Program. The staff determined that the
 
information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-97 Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, the staff determined that those program elements for which the applicant claimed consistency with
 
the GALL Report are consistent. In addition, the staff reviewed the exception and its justifications
 
and determined that the AMP, with the exception and enhancements, is adequate to manage the
 
aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed
 
that their implementation prior to the period of extended operation will make the 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).
3.0.3.2.17  Fire Water System
 
Summary of Technical Information in the Application. In LRA Section B.1.20, the applicant described the existing Fire Water System Program as consistent, with enhancements, with GALLAMP XI.M27, "Fire Water System."
The Fire Water System Program will manage identified aging effects for the water-based fire protection system and associated components through periodic inspections, monitoring, and
 
performance testing. The program includes prev entive measures and inspection activities to detect aging effects prior to loss of intended functions. System functional tests, flow tests, flushes, and inspections are in accordance with guidance from NFPA standards. Fire system main header
 
flow tests are conducted at least once every 3 years, hydrant flushing and inspections at least
 
once every 12 months. The condition of the fire pum ps is confirmed once every 18 months by a pump functional test. The redundant water storage tank is inspected once every 5 years. Sprinkler
 
system inspections are performed at least once every refueling outage. The fire water system is maintained at the required normal operating pressure and monitored so that a loss of system
 
pressure is immediately detected and corrective actions initiated. Periodic water samples will be
 
tested to detect microbiologically influenced corrosion (MIC). The program will be enhanced to
 
include volumetric inspections using appropriate techniques on system piping to monitor pipe wall
 
thickness and evaluate internal pipe conditions. The system flow testing, visual inspections, and
 
volumetric inspections assure that the aging effects of reduction of heat transfer and loss of
 
material due to corrosion, MIC, or biofouling are managed to maintain system intended functions.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.17. The staff reviewed the
 
enhancements and their justifications to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Fire Water System Program for which the applicantclaimed consistency with GALL AMP XI.M27 and found them consistent with the GALL Report
 
AMP. Furthermore, the staff concluded that the applicant's Fire Water System Program provides reasonable assurance that aging effects on fire protection components within the scope of license
 
renewal will be adequately managed during the period of extended operation. The staff found that
 
the applicant's Fire Water System Program conforms to the recommended GALL AMP XI.M27 with enhancements described below.
3-98 Enhancement 1. In the LRA, the applicant identified an enhancement to meet the GALL Report program elements "preventive actions," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement
 
stated: The fire water system aging management program will be enhanced to include periodic non-intrusive wall thickness measurements of selected portions of the fire
 
water system at intervals t hat do not exceed every 10 years.
In reviewing this enhancement, the staff noted that the applicant's Fire Water System Program will manage identified aging effects for the water-based fire protection system and associated
 
components through the use of periodic inspections, monitoring, and performance testing. The
 
program includes preventive measures and inspection activities to detect aging effects prior to
 
loss of intended functions. System functional tests, flow tests, flushes, and inspections are in
 
accordance with guidance from NFPA standards. This enhancement adds volumetric inspections
 
by appropriate techniques on system piping to monitor pipe wall thickness and evaluate internal pipe conditions as recommended in the GALL Report. Because the addition of non-intrusive wall
 
thickness measurements of selected portions of the fire water system will provide additional assurance that the effects of aging will be adequately managed, the staff determined that this
 
enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire Water SystemProgram will be consistent with GALL AMP XI.M 27 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 2. In the LRA, the applicant identified an enhancement to meet the GALL Report program element "preventive actions."
Specifically, the enhancement stated:
The fire water system aging management pr ogram will be enhanced to include periodic water sampling of the fire water system for the presence of MIC, at intervals not to exceed
 
every 5 years In reviewing this enhancement, the staff noted that the applicant's Fire Water System Program includes preventive actions to preclude buildup of significant corrosion, MIC, or biofouling by
 
periodic flushing, system performance testing, and inspections to identify these degraded
 
conditions prior to loss of system intended function. This enhancement will add water sampling for
 
the presence of MIC every 5 years as recommended in the GALL Report. Because the addition of
 
water sampling for the presence of MIC will provide additional assurance that the effects of aging
 
will be adequately managed, the staff determined that this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire Water SystemProgram will be consistent with GALL AMP XI.M 27 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 3. In the LRA, the applicant identified an enhancement to meet the GALL Report program element "detection of aging effe cts." Specifically, the enhancement stated:
The fire water system aging management pr ogram will be enhanced to include inspection of sprinkler heads before the end of the 50-year sprinkler head service life and at 10-year 3-99 intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.
In reviewing this enhancement, the staff noted that the applicant's Fire Water System Program will manage identified aging effects for the water-based fire protection system and associated
 
components through periodic inspections, monitoring, and performance testing. The program
 
includes preventive measures and inspection activities to detect aging effects prior to loss of
 
intended functions. System functional tests, flow tests, flushes, and inspections are in accordance
 
with guidance from NFPA standards. Sprinkler system inspections are performed at least once
 
every refueling outage. This enhancement will include 50-year sprinkler head inspections using
 
the guidance of NFPA 25 "Standard for the Inspection, Testing and Maintenance of Water-Based
 
Fire Protection Systems" (1998 Edition), Section 2-3.1.1. Representative samples will be
 
submitted to a testing laboratory prior to 50 years in service . Thereafter, this testing will be
 
repeated on a frequency of once every 10 years during the period of extended operation to
 
ensure that signs of degradation like corrosion are detected promptly. Initial inspections of the
 
sprinkler heads will be prior to 50 years in service . Because the addition of 50-year sprinkler
 
head inspections will provide additional assurance of adequate management of aging effects, the
 
staff determined that this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire Water SystemProgram will be consistent with GALL AMP XI.M 27 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 4. In the LRA, the applicant stated an enhancement in meeting the GALL Report program element "scope of program."
Specifically, the enhancement stated:
The fire water system aging management program will be enhanced to include visual inspection of the redundant fire water storage tank heater during tank internal inspections.
In reviewing this enhancement, the staff noted that the applicant's Fire Water System Program will manage identified aging effects for the water-based fire protection system and associated
 
components through periodic inspections, monitoring, and performance testing. The program
 
includes preventive measures and inspection activities to detect aging effects prior to loss of
 
intended functions. System functional tests, flow tests, flushes, and inspections are in accordance
 
with guidance from NFPA standards. The redundant water storage tank is inspected every 5
 
years. This enhancement will include visual inspection of the redundant fire water storage tank
 
heater during tank internal inspections as recommended in the GALL Report. Because visual
 
inspection of the redundant fire water storage tank heater will provide additional assurance of
 
adequate management of aging effects the staff determined that this enhancement is acceptable.
The staff finds this enhancement acceptable because when implemented the Fire Water SystemProgram will be consistent with GALL AMP XI.M 27 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.20, the applicant explained that in 2003 a leak was discovered in a small diameter cooling water line of the #2 diesel driven fire pump. The line
 
comes off of the 10-inch pump discharge line and provides cooling water to the diesel engine
 
when the engine-driven pump operates. Normally in standby, the pump is operated during pump testing. The leak was discovered during a pump performance test. The leak did not render the
 
system, pump, or engine inoperable, and the line was subsequently replaced. The cause of the 3-100 leak was attributed to MIC and a combination of highly turbulent flow in the line and the stagnant lay-up conditions when the pump is not operating. The cooling water line on the #1 diesel-driven
 
fire pump was subsequently inspected by NDE techniques and wall thinning was found. The
 
extent of wall thinning did not render the pump inoperable, and the line is scheduled for
 
replacement.
In 2002 a hydrant was identified with significant leakage below ground when operated. The problem was discovered during the hydrant flush surveillance activity. The hydrant was declared inoperable but did not affect the rest of the system and was considered available for use in an
 
emergency. It was replaced with a new hydrant.
The pump performance testing, hydrant inspection activities, and the corrective action process identified and corrected these degraded conditions prior to a loss of fire protection system
 
intended functions.
The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience. The Fire Water System Program activities with
 
enhancements will be effective in managing aging degradation for the period of extended
 
operation by timely detection of aging effects and appropriate corrective actions prior to loss of
 
system or component intended functions.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Fire Water System
 
Program will adequately manage the aging effects identified in the LRA for which this AMP is
 
credited.UFSAR Supplement. In LRA Section A.1.20, the applicant provided the UFSAR supplement for the Fire Water System Program. The staff reviewed this section and determined that the
 
information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program, the staff determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed
 
that their implementation prior to the period of extended operation will make the 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).
3.0.3.2.18  Aboveground Outdoor Tanks
 
Summary of Technical Information in the Application. In LRA Section B.1.21, the applicant described the new Aboveground Outdoor Tanks Program as consistent, with an exception, with GALL AMP XI.M29, "Aboveground Carbon Steel Tanks."
3-101 The Aboveground Outdoor Tanks Program provides for management of loss of material aging effects for outdoor carbon steel and aluminum storage tanks. The program credits the application
 
of paint as a corrosion preventive measure and per forms periodic visual inspections to monitor degradation of the paint and any resulting metal degradation for the carbon steel tanks. The
 
program will include periodic visual inspecti ons of the aboveground aluminum tank. Periodic internal UT inspections will be performed on the bottom of outdoor carbon steel tanks and the
 
outdoor aluminum storage tank supported by earthen/concrete foundations. The carbon steel
 
tanks not directly supported by earthen or concrete foundations undergo external visual
 
inspections without the necessity of bottom surface UT inspections. The program will require
 
removal of insulation to permit visual inspection of insulated tank surfaces. The program will be
 
implemented prior to the period of extended operation. Tanks will be inspected at an initial
 
frequency of every 5 years.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.18. The staff reviewed the
 
exceptions and their justifications to determine whether the AMP, with the exceptions, remained
 
adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Aboveground Outdoor Tanks Program for which theapplicant claimed consistency with GALL AMP XI.M29 and found them consistent with the GALL
 
Report AMP. Furthermore, the staff concluded that the applicant's Aboveground Outdoor Tanks
 
Program provides reasonable assurance that the effects of aging will be managed during the
 
period of extended operation. The staff found that the applicant's Aboveground Outdoor Tanks
 
Program conforms to the recommended GALL AMP XI.M29 with exceptions described below.
Exception 1. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "preventive actions
." Specifically, the exception stated:
The Oyster Creek program includes inspection of the outdoor aluminum storage tanks. Due to corrosion resistance properties of aluminum, these tanks are not
 
painted. The applicant stated in the LRA that the program includes the outdoor aluminum storage tanks in addition to the carbon steel tanks. Due to corrosion-resistant properties of aluminum the tanks are
 
not painted. For aluminum tanks, the AMP includes visual inspections, sealants/coating
 
examination at the tank foundation interfaces, and periodic UT inspections on the tank bottom.
 
The staff's review of operating experience for the Aboveground Outdoor Tanks Program found
 
this exception acceptable because it appropriately adds aluminum tanks to the scope of the AMP.
The staff reviewed this exception and concluded that it is acceptable to include aluminum tanks in this program because it adds aluminum tank within the scope of the AMP. The staff finds that it is
 
also acceptable not to paint aluminum tanks because experience shows that aluminum does not rust when exposed to atmospheric conditions.
Exception 2. In the PBD for this AMP the applicant stated an exception to the GALL Report program element "monitoring and trending" not stat ed in the LRA. Specifically, the exception stated:
3-102 The specified frequency by the Oyster Creek program is every 5 years in place of system walkdowns each outage.
In its letter dated April 17, 2006, the applicant committed (Commitment No. 21) to revise the Aboveground Outdoor Tanks Program in the LRA to include the exception identified in the PBD, which states that the specified frequency by the program is every 5 years in place of system walkdowns each outage.
The applicant stated in the PBD that the frequency of 5 years specified for monitoring of exterior surfaces of tanks is consistent with the frequenc y specified for exterior surfaces of supporting structures. The 5-year frequency consistent with industry guidelines has proven effective in
 
detecting loss of material due to corrosion and change in material properties of structural
 
elastomers on exterior surfaces of structures. Consequently this frequency will also be effective
 
for detecting loss of material and change in material properties on exterior tank surfaces before
 
an intended function is impacted.
The staff questioned the schedule for conducting the walkdowns and asked whether the schedule is consistent with the GALL Report recommendation. The applicant stated that it uses structured
 
inspections every 5 years rather than system walkdowns every outage and that this use is an exception to the GALL Report recommendation. The applicant stated that the inspection
 
frequency is consistent with the practical life of the coatings and the industry application of the
 
structures monitoring programs under the Maintenance Rule. The staff finds this exception to
 
GALL Report acceptable because it meets the requirements of the Maintenance Rule and is consistent with ASME Section XI Code.
The staff's review of operating experience for the Aboveground Outdoor Tanks Program finds this exception acceptable based on industry experience and plant operating experience.
Operating Experience. In LRA Section B.1.21, the applicant explained that the Aboveground Outdoor Tanks Program is being implemented at OC GS; therefore, no program experience exists.
It will replace selective inspections and will complement those activities in place for tank
 
management of petroleum and other hazardous above-ground and buried tanks. The program is based on industry guidance and the GALL Report program for above-ground carbon steel tanks.
 
The condensate storage tank (CST) has been repaired to replace a corroded tank bottom.
 
Periodic UT inspections will be performed on aluminum and carbon steel tank bottoms.
The staff believes that the corrective action process will capture internal and external plant operating issues to ensure that aging effects are adequately managed.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Aboveground Outdoor
 
Tanks Program will adequately manage the aging effects identified in the LRA for which this AMP
 
is credited.
UFSAR Supplement. In LRA Section A.1.21 and letter dated April 17, 2006, the applicant provided the UFSAR supplement for the Aboveground Outdoor Tanks Program. The staff
 
determined that the UFSAR supplement provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
3-103 Conclusion. On the basis of its audit and review of the applicant's Aboveground Outdoor Tanks Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exception, is adequate to manage the
 
aging effects for which it is credited. The staff concludes that the applicant has demonstrated that
 
the effects of aging will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes
 
that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.19  Fuel Oil Chemistry
 
Summary of Technical Information in the Application. In LRA Section B.1.22, the applicant described the existing Fuel Oil Chemistry Progr am as consistent, with exceptions andenhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry."
The Fuel Oil Chemistry Program activities are preventive and provide assurance that contaminants are maintained at acceptable levels in fuel oil for systems and components within
 
the scope of licensing renewal. The fuel oil tanks within the scope of license renewal are
 
maintained by monitoring and controlling fuel oil contaminants in accordance with the guidelines
 
of American Society for Testing and Materials (ASTM). Fuel oil sampling activities meet the intent
 
of ASTM D 4057-95 (2000). Fuel oil will be routinely sampled and analyzed for particulate in
 
accordance with modified ASTM Standard D 2276-00 Method A and for the presence of water
 
and sediment in accordance with ASTM Standard D 2709-96. Fuel oil sampling and analysis are
 
in accordance with approved procedures for new and stored fuel. Fuel oil tanks are drained
 
periodically of accumulated water and sediment and periodically drained, cleaned, and internally
 
inspected. These activities effectively manage the effects of aging by providing reasonable
 
assurance that potentially harmful contaminants are maintained at low concentrations.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.19. The staff reviewed the
 
exceptions and enhancements and their justifications to determine whether the AMP, with the
 
exceptions and enhancements, remained adequate to manage the aging effects for which it is
 
credited.The staff reviewed those portions of the Fuel Oil Chemistry Program for which the applicantclaimed consistency with GALL AMP XI.M30 and found them consistent with the GALL Report
 
AMP. Furthermore, the staff concluded that the applicant's program provides reasonable
 
assurance that the aging effects for which this program is credited will be adequately managed.
 
The staff found that the applicant's Fuel Oil Chemistry Program conforms to the recommended GALL AMP XI.M30 with exceptions and enhancements described below.
Exception 1. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program," "preventive actions," "paramet ers monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the exception stated:
NUREG-1801 indicates that fuel oil tanks should be sampled for water and sediment, biological activity, and particulate on a periodic basis, and that multilevel 3-104 sampling of tanks should be performed. Multilevel sampling and tank bottom sampling of the Emergency Diesel Generator (EDG) Day Tanks are not routinely
 
performed at Oyster Creek. The EDG Day Tanks do not have the capability of
 
being sampled, however, these tanks are supplied directly from the EDG Fuel
 
Storage Tank, which is routinely sampled and analyzed. The EDG Day Tanks are
 
small in size and experience a high turnover rate of the fuel stored within as a
 
result of routine engine operations. Stratification of fuel is not likely to occur in the
 
EDG Day Tanks due to the high turnover rate. Additionally, the Emergency Diesel
 
Generator Day Tanks are skid mounted on the Emergency Diesel Generator skid
 
and are enclosed within the diesel enclosure, which is maintained at a constant
 
temperature during cold periods through operation of the Emergency Diesel
 
Generator keepwarm system. Maintaining a constant temperature during cold
 
periods minimizes Emergency Diesel Generator Day Tank thermal cycling and
 
reduces the potential for condensation formation within the Day Tanks. The routine
 
draining of water and sediment from the bottom of the Day Tanks is therefore not
 
necessary.
In reviewing the OCGS PBD for the Aboveground Outdoor Tanks Program (PBD-AMP-B.1.22), the staff noted that OCGS experienced a problem with increasing levels of water and sediment in
 
the bottom samples and the all-level samples from the EDG fuel oil storage tank in 2003. Based
 
on this operating experience, the staff recognized that, since the EDG day tanks are filled by
 
transferring oil from the EDG fuel oil storage tank and the day tanks are not periodically sampled
 
or inspected, water and sediment could have been inadvertently introduced into the day tanks during the transfer of oil from the EDG fuel oil storage tank undetected, leading to the possibility
 
that undetected corrosion could be present in the day tanks. The applicant was asked why the
 
day tanks cannot be sampled, cleaned, or inspected and what evidence demonstrated that the
 
operating experience had not caused undetected corrosion in the day tanks.
In its response, the applicant stated that the day tanks are not equipped with sampling capability and that periodic sampling will not be done for the day tanks but that the Fuel Oil Chemistry
 
Program will be revised to include a one-time inspection of the EDG day tanks.
In its letter dated April 17, 2006, the applicant committed (Commitment No. 22) to revise the Fuel Oil Chemistry Program in the LRA to include a one-time internal inspection of the EDG day tanks to confirm the absence of aging effects. Visual and further inspections will quantify the
 
degradation if any evidence of corrosion or pitting was observed during the visual inspection.
The staff reviewed the applicant's response and determined that the new commitment to a one-time inspection of the EDG day tanks will provide objective evidence to determine whether
 
undetected aging degradation is present. If degradation is detected, further actions will be taken
 
to quantify and, if necessary, correct the degradation. On this basis, the staff concludes that the
 
applicant's response was acceptable.
Following the staff's review of this exception and the applicant's commitment to perform a one-time inspection of the EDG day tanks the staff concludes that this exception is acceptable
 
because a one-time inspection of the EDG day tanks will identify aging effects. If aging effects are
 
detected, the applicant has committed to take appropriate actions.
3-105 Exception 2. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria." Specifically, the exception stated:
Oyster Creek has not committed to ASTM D 4057-95 (2000) for manual sampling standards: Sampling of the Emergency Diesel Generator Fuel Storage Tank, although not directly comparable to any of the tank sampling methods described in
 
ASTM D 4057-95 (2000), ensures that a multilevel sample and a bottom sample
 
are obtained. The EDG Fuel Storage Tank is equipped with a sample station that
 
includes a sample recirculation pump and sample collection points located internal
 
to the tank at several tank elevations, thus making the Emergency Diesel
 
Generator Fuel Storage Tank sample station effective for obtaining multilevel
 
samples. Tank bottom samples are obtained through a sample line located 1/2" off
 
of the bottom of the tank sump.
In reviewing this exception, the staff noted that neither the LRA nor the PBD for this AMP discusses the specific sampling process for the EDG fuel oil storage tank or the differences
 
compared to ASTM 4057-95. The applicant was asked for additional information on the sampling
 
process used for the EDG fuel oil storage tank.
In its response, the applicant stated that sampling of the EDG fuel oil storage tank, although not directly comparable to any of the tank sampling methods described in ASTM D 4057-95 (2000),
ensures that an "all-levels" sample and a bottom sample are obtained. The EDG fuel oil storage
 
tank is equipped with a sample station that includes a sample recirculation pump and sample
 
collection points located internal to the tank at several tank elevations, thus making the EDG fuel
 
oil storage tank sample station effective for obtaining "all-level" samples. Tank bottom samples
 
are obtained through a sample line located off the bottom of the tank sump and specifically
 
designed to collect condensation/moisture and sediment from within the tank.
As to the sampling process for the main fuel oil storage tank, the applicant stated that the multilevel sampling of the main fuel oil tank meets the ASTM D 4057-95 (2000) guidelines and, therefore, was not identified as an exception.
The staff reviewed the applicant's response as well as ASTM D 4057-95 (2000) and the applicant's oil sampling procedure 828.7. The OCGS technical personnel were also interviewed to
 
discuss the sample station operation. The staff determined that the OCGS sampling procedure
 
will conservatively estimate fuel oil contaminants, which tend to settle to the lower levels of the
 
tank. On this basis, the staff concludes that this exception is acceptable.
Exception 3. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program," "parameters monitored or inspected," "detection of aging effects," and "acceptance criteria." Specifically, the exception stated:
Oyster Creek has not committed to ASTM D 4057-95 (2000) for manual sampling standards: Fire Pond Diesel Fuel Tank samples are obtained from the tank fuel oil
 
outlet line located 4" off of the bottom of the tanks. The Fire Pond Diesel Fuel
 
Tanks are each 2.1 cu meter (550 gallons) capacity. Spot sampling requirements in
 
ASTM D 4057-95 (2000) for tanks less than or equal to 159 cu meter include a
 
single sample from the middle (a distance of one-half of the depth of liquid below
 
the liquid's surface). Although the actual sample location is lower in the tank than 3-106 prescribed by the ASTM, the lower elevation is more likely to contain contaminants and water and sediment which tend to settle in the tank, thus making this an
 
effective spot sampling location. Bottom samples from the Fire Pond Diesel Fuel
 
Tanks are taken off of the tank drain located on the bottom of the tank.
In reviewing this exception, the staff reviewed ASTM D 4057-95 (2000). For fuel oil storage tanks of less than 159 cubic meters spot sampling recommendations in ASTM D 4057-95 (2000)
 
include a single sample from the middle (a distance of one-half of the depth of liquid below the
 
liquid's surface). The OCGS fire pond diesel fuel oil storage tanks are 2.1 cubic meters so the
 
spot sampling recommendations in ASTM D 4057 are applicable. The staff recognized that the
 
actual sample location for the OCGS fire pond diesel fuel oil storage tanks in the tanks is lower
 
than prescribed by the ASTM D 4057 standard and will result in samples more likely to capture
 
contaminants, water, and sediment. Therefore, the samples are expected to be conservatively
 
representative of the fuel in the tank. On this basis, the staff concludes that this exception is
 
acceptable.
Exception 4. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of program" and "preventive actions
." Specifically, the exception stated:
Oyster Creek does not add corrosion inhibitors to fuel oil. The analysis for particulate contaminants using modified ASTM D 2276-00 Method A is sufficient for
 
the detection of corrosion products at an early stage. Fuel contaminants and
 
degradation products will normally settle to the tank bottom where they will be
 
detected by routine analysis or by periodic draining of water and sediment from the
 
storage tank bottoms.
In evaluating this exception, the staff reviewed the applicant's fuel oil sampling activities to determine whether they are adequate for timely detection of corrosion. The staff determined that
 
fuel oil analyses for particulates as well as water and sediment are performed quarterly or more
 
frequently for the fuel oil storage tanks. In particular, the applicant stated that complete off-site lab
 
fuel oil analyses are performed for particulate contamination, bacteria, American Petroleum
 
Institute (API) gravity, water and sediment, kinematic viscosity, sulfur content, flash point, cloud
 
point, ash, distillation temperature, cetane index, carbon residue, and copper strip corrosion. The
 
analyses are weekly for the EDG fuel oil storage tank and quarterly for the main fuel oil storage
 
tank. In addition, the main fuel oil storage tank, the EDG fuel oil storage tank, and the fire pond
 
diesel fuel tanks will be periodically drained, cleaned, and inspected. A one-time inspection will be
 
performed for the EDG day tanks.
The staff determined that the applicant's fuel oil sampling together with the inspection activities will provide reasonable assurance that, if corrosion were occurring in the fuel oil tanks, it will be
 
detected in a timely manner. If evidence of corrosion is detected, corrective actions will be taken
 
to mitigate it. On this basis, the staff concludes that this exception is acceptable.
Exception 5. In Attachment 1, item B.1.22 of its reconciliation document, the applicant identified an additional exception to the GALL Report progr am element "scope of program" not included in the LRA. Specifically, the exception stated:NUREG-1801 states in XI.M30 that the fuel oil aging management program is in part based on the fuel oil purity and testing requirements of the plant's Technical
 
Specifications that are based on the Standard Technical Specifications of 3-107 NUREG-1430 through NUREG-1433. Oyster Creek has not adopted the Standard Technical Specifications as described in these NUREGs, however, the Oyster
 
Creek fuel oil specifications and procedures invoke similar requirements for fuel oil
 
purity and fuel oil testing, as described by the Standard Technical Specifications.
 
These include testing requirements for new fuel oil (API gravity, kinematic
 
viscosity, water and sediment) prior to adding the new fuel to the storage tank to
 
ensure that the oil has not been contaminated with substances that will have an
 
immediate detrimental impact on diesel engine combustion, and testing of new fuel
 
after adding it to the storage tank to confirm that the remaining fuel oil properties
 
are within specification requirements. Oyster Creek fuel oil activities also provide
 
for the trending of particulate contamination in new and stored fuel oil. Water and
 
Sediment are drained periodically (quarterl y) from the Emergency Diesel Generator Fuel Storage Tank. This periodicity exceeds the Standard Technical Specifications
 
requirements of "once every [31] days", however, it is aligned with the
 
requirements of Regulatory Guide 1.137, which states that a quarterly basis is
 
sufficient unless accumulated condensation is suspected (in which case a monthly
 
basis is appropriate).
This is a new exception based on the reconciliation of thisaging management program from the draft January 2005 GALL to the approvedSeptember 2005 GALL.
In its letter dated March 30, 2006, the applicant stated that the Fuel Oil Chemistry Program will be revised to include the exception identified in the reconciliation document stating that OCGS has
 
not adopted the Standard Technical Specifications; however, the fuel oil specifications and
 
procedures invoke similar requirements for fuel oil purity and fuel oil testing.
The applicant was asked for additional information on the specific fuel oil specifications and how they differ from the requirements in the standard technical specifications. The applicant was also
 
asked to justify the frequency for draining water and sediment from the EDG fuel storage tank in
 
light of operating experience at OCGS in which increasing water and sediment concentrations
 
were observed in the stored fuel oil.
In its response, the applicant stated that water and sediment are drained from the EDG fuel storage tank quarterly. This frequency exceeds the standard technical specifications requirements
 
of 31 days; however, it is aligned with RG 1.137, which states that a quarterly basis is sufficient
 
unless accumulated condensation is suspected, in which case a monthly basis is appropriate. As
 
to the frequency for draining water and sediment from the EDG fuel oil storage tank, the applicant
 
stated that the increasing trend in water and sediment was attributed to long-term accumulation.
 
Prior to this event, OCGS did not have in place recurring tasks to drain water and sediment
 
periodically from the bottom of fuel oil storage tanks. Current practices include quarterly tasks to
 
drain accumulated water and sediment from the bottom of the EDG fuel oil storage tank. This
 
practice has been effective in preventing recurrence of high levels of water and sediment in the
 
tank.The applicant further stated in its response that the standard technical specifications reference RG 1.137 as supplemented by ANSI N195 for recommended fuel oil practices. The fuel oil
 
properties governed by these requirements are the water and sediment content, the kinematic viscosity, specific or API gravity, and impurity level. These fuel oil properties are obtained with the
 
Fuel Oil Chemistry Program, which is implem ented by procurement specification SP-1302-38-010 and sampling and analysis procedure CY-OC-120-1107. These procedures are based on
 
RG 1.137, Revision 1, ANSI N195-1976, and ASTM D975-81. These implementing documents 3-108 include fuel oil requirements for water and sediment content, the kinematic viscosity, specific or API gravity, and impurity level for new and stored fuel consistent with the requirements identified
 
in the referenced standard technical specifications.
The staff reviewed the applicant's response as well as OCGS procurement specification SP-1302-38-010, "Oyster Creek Generating Station Diesel Fuel Oil No. 2," Revision 8, June 23, 2004; OCGS sampling and analysis procedure CY-OC-120-1107, "Fuel Oil Sample and
 
Analysis Schedule," Revision 0; and the standard technical specifications for General Electric
 
plants, NUREG-1433, "Standard Technical Specifications General Electric Plants, BWR/4,"
 
Volume 1, Revision 3, June 2004. The staff confirmed that the implementing documents included
 
fuel oil requirements for water and sediment content, the kinematic viscosity, specific or API
 
gravity, and impurity level for new and stored fuel consistent with the requirements of the
 
referenced standard technical specifications; therefore, the applicant's fuel oil specifications are
 
consistent with the requirements in the standard technical specifications. On this basis, the staff
 
concludes that this exception is acceptable.
Enhancement 1. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement
 
stated: The Oyster Creek Fuel Oil Chemistry pr ogram will be enhanced to include routine analysis for particulate contamination using modified ASTM D 2276-00 Method A
 
on fuel oil samples from the Emergency Diesel Generator Fuel Storage Tank, the
 
Fire Pond Diesel Fuel Tanks, and the Main Fuel Oil Tank.
The staff noted that the applicant's enhancement will add routine analysis for particulate contamination using modified ASTM D 2276-00 Method A on fuel oil samples from the EDG fuel
 
storage tank, the fire pond diesel fuel tanks, and the main fuel oil tank consistent with the
 
recommendations in the GALL Report. Routine analysis for particulate contamination will provide results that can be used to ensure that contamination is maintained at acceptable levels. The staff
 
finds this enhancement acceptable because when implemented the Fuel Oil Chemistry Programwill be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of
 
aging will be adequately managed.
Enhancement 2. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement
 
stated: The Oyster Creek Fuel Oil Chemistry program will be enhanced to include analysis for particulate contamination using modified ASTM D 2276-00 Method A on new
 
fuel oil.The staff noted that the applicant's enhancement will add routine analysis for particulate contamination using modified ASTM D 2276-00 Method A on new fuel oil, which is consistent with
 
the recommendations in the GALL Report. Routine analysis for particulate contamination will
 
provide results that can be used to ensure that contamination from new fuel oil is not introduced
 
into the fuel oil system. The staff finds th is enhancement acceptable because when implemented 3-109 the Fuel Oil Chemistry Program will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 3. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "parameter s monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the enhancement
 
stated: The Oyster Creek Fuel Oil Chemistry program will be enhanced to include analysis for water and sediment using ASTM D 2709-96 for Fire Pond Diesel Fuel Tank bottom samples.
The staff noted that the applicant's enhancement will add routine analysis for water and sediment using ASTM D 2709-96 for fire pond diesel fuel tank bottom samples consistent with the
 
recommendations in the GALL Report. Routine analysis for water and sediment in the fire pond
 
diesel fuel tank will provide results that can be used to ensure that these contaminants are
 
maintained at acceptable levels and that the frequency for draining water and sediment from the
 
tanks is adequate. The staff finds this enhancement acceptable because when implemented the
 
Fuel Oil Chemistry Program will be consistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging will be adequately managed.
Enhancement 4. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "prevent ive actions," and "detection of aging effects."
Specifically, the enhancement stated:
The Oyster Creek Fuel Oil Chemistry program will be enhanced to include analysis for bacteria to verify the effectiveness of biocide addition in the Emergency Diesel
 
Generator Fuel Storage Tank, the Fire Pond Diesel Fuel Tanks, and the Main Fuel
 
Oil Tank.The staff noted that the applicant's enhancement will add routine analysis for bacteria to verify the effectiveness of biocide addition in the EDG fuel storage tank, the fire pond diesel fuel tanks, and
 
the main fuel oil tank consistent with the recommendations in the GALL Report. Routine analysis
 
for bacteria will provide results that can be used to ensure that the biocide addition activities are
 
effective in preventing the growth of bacteri a in the fuel oil system. The staff finds this enhancement acceptable because when implemented the Fuel Oil Chemistry Program will beconsistent with GALL AMP XI.M30 and will provide additional assurance that the effects of aging
 
will be adequately managed.
Enhancement 5. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "scope of program," "prevent ive actions," and "detection of aging effects."
Specifically, the enhancement stated:
The Oyster Creek Fuel Oil Chemistry pr ogram will be enhanced to include periodic draining, cleaning, and inspection of the Fire Pond Diesel Fuel Tanks and the Main
 
Fuel Oil Tank (already performed for the Emergency Diesel Generator Fuel
 
Storage Tank). Inspection activities will include the use of ultrasonic techniques for
 
determining tank bottom thicknesses should there be any evidence of corrosion or
 
pitting.
3-110 The staff noted that the applicant's enhancement will add periodic draining, cleaning, and inspection of the fire pond diesel fuel tanks and the main fuel oil tank. This activity is already
 
performed for the EDG fuel storage tank. Inspection activities will include the use of ultrasonic
 
techniques for determining tank bottom thicknesses when there is any evidence of corrosion or
 
pitting. This activity is consistent with the recommendations in the GALL Report and will ensure
 
that aging of the fire pond diesel fuel tanks and the main fuel oil tank is properly managed. The
 
staff finds this enhancement acceptable becaus e when implemented the Fuel Oil ChemistryProgram will be consistent with GALL AMP XI.M 30 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.22, the applicant explained that the Fuel Oil Chemistry Program has proven to be effective in identif ying and correcting abnormal conditions promptly. In 2003, OCGS experienced high concentrations of water and sediment in main fuel oil tank
 
samples. On previous occasions, high concentrations of water and sediment also had been
 
detected in the EDG fuel storage tank and fire pond diesel fuel tanks. There were no fuel oil
 
system failures attributed to a loss of material condition or biofouling as a result of these findings.
 
Although fuel oil chemistry activities detected the high levels of contaminants in the fuel promptly
 
and corrective actions were initiated before blockage of fuel oil system supply lines or corrosion of
 
fuel oil tanks and fuel supply lines occurred, fuel oil chemistry activities were enhanced to include
 
the addition of biocides and stabilizers to fuel oil and to incorporate improved test methods for the
 
early detection of water and sediment.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no degradation
 
not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Fuel
 
Oil Chemistry Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
UFSAR Supplement. In LRA Section A.1.22 and letters dated March 30, and April 17, 2006, the applicant provided the UFSAR supplement for the Fuel Oil Chemistry Program. The staff determined that the information in the UFSAR supplement provides 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 determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their
 
justifications and determined that the AMP, with the exceptions, is adequate to manage the aging
 
effects for which it is credited. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation will make the 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
 
concluded that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3-111 3.0.3.2.20  Reactor Vessel Surveillance Summary of Technical Information in the Application. In LRA Section B.1.23, the applicant described the existing Reactor Vessel Surveillance Program as consistent, with an enhancement, with GALL AMP XI.M.31, "Reactor Vessel Surveillance."
In LRA Section B.1.23, the applicant stated that this program monitors the effects of neutron embrittlement of the RPV beltline materials. The program is based on the BWR ISP and satisfies
 
the requirements of 10 CFR 50, Appendix H, "Reactor Vessel Material Surveillance Program
 
Requirements." The Reactor Vessel Surveillance Program is based upon the BWRVIP-78 "BWR
 
Integrated Surveillance Program Plan," and the BWRVIP-86-A, "BWR Vessel and Internals
 
Project, BWR Integrated Surveillance Program Implementation," reports. The staff in its SER
 
dated April 27, 2004, approved use of the BWRVIP ISP at OCGS (license amendment 242).
The BWRVIP-116, "BWR Vessel Internals Project Integrated Surveillance Program Implementation for License Renewal," report identifies and schedules additional capsules to be
 
withdrawn and tested during the license renewal period. OCGS will continue to use the ISP during
 
the period of extended operation by implementing the requirements of the
 
BWRVIP-116 report and by addressing any additional actions required by the staff's SER
 
associated with the BWRVIP-116 report after it is issued.
The representative material and host plant for the limiting RPV plate and weld materials and the schedule for withdrawal of these materials are identified in the BWRVIP-116 report. Future
 
withdrawal and testing of the remaining OCGS surveillance capsule will be permanently deferred.
As described in the BWRVIP-116 report, BWR facilities that will not be required to remove
 
additional surveillance capsules will determine vessel fluence utilizing a staff-approved neutron
 
fluence methodology during the extended license period. The program will ensure coupon
 
availability during the period of extended operation by saving withdrawn coupons for future
 
reconstitution. If the BWRVIP-116 report is not approved by the staff a plant-specific surveillance
 
plan will be provided for the license renewal period in accordance with Appendices G and H to
 
10 CFR Part 50.
OCGS has performed the RPV fluence analysis by a staff-approved methodology to support license renewal. This analysis also satisfies the commitment associated with amendment 242 for
 
OCGS to perform a neutron fluence evaluation using a method in accordance with RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence."
Staff Evaluation. In LRA Section B.1.23, the applicant described its AMP to manage irradiation embrittlement of the RPV through testing that monitors RPV beltline materials. The LRA stated
 
that the RPV surveillance program will be enhanced by making it consistent with the BWRVIP ISP for periods of extended operation prior to the OCGS period of extended operation.
The applicant has implemented the BWRVIP ISP based on the BWRVIP-78 report, "BWR Integrated Surveillance Program Plan," and the BWRVIP-86-A report, "BWR Vessel and Internals
 
Project, BWR Integrated Surveillance Program Implementation." These reports are consistent with the GALL AMP XI.M31, "Reactor Vessel Surveillance," for the period of the current OCGS license.
 
The staff concluded that the BWRVIP ISP in BWRVIP-78 and BWRVIP-86-A reports are
 
acceptable for BWR licensee implementation provided that all participating licensees use one or
 
more compatible neutron fluence methodologies acceptable to the staff for determining 3-112 surveillance capsule and RPV neutron fluences. The staff's acceptance of the BWRVIP ISP for the current term at OCGS is documented in SER dated April 27, 2004. The applicant further stated that the enhanced program will be consistent with GALL AMP XI.M31.
The BWRVIP-116 report, "BWR Vessel And Internals Project, Integrated Surveillance Program (ISP) Implementation For License Renewal," provides guidelines for an ISP to monitor neutron
 
irradiation embrittlement of the RPV beltline materials for all US BWR power plants for the license
 
renewal period. The staff also reviewed the UFSAR supplement to determine whether it provides
 
an adequate description of the program.
The staff's review of LRA Sections B.1.23 and A.1.23 identified areas in which additional information was necessary to complete the review of the applicant's program elements. The
 
applicant responded to the staff's RAI as discussed below.
In RAI B.1.23-1 dated March 20, 2006, the staff requested that the applicant provide the following commitment in the UFSAR supplement.
OCGS will implement BWRVIP ISP as specified in the staff approved BWRVIP-116 report, or if the ISP is not approved two years prior to the commencement of the
 
extended period of operation, a plant-specific surveillance program for the OCGS
 
unit will be submitted.
In its response dated April 18, 2006, the applicant updated the UFSAR supplement to include the aforementioned commitment (Commitment No. 23) proposed by the staff.
By letter dated February 24, 2006, the staff issued the final SER of the BWRVIP-116 report and, therefore, the staff requested that the applicant include the following statements in LRA
 
Sections A.1.23 and B.1.23.
The ISP-BWRVIP-116 report which was approved by the staff will be implemented at OCGS with the conditions documented in Sections 3 and 4 of the staff's final
 
SER of the BWRVIP-116 report."
In its supplemental letter dated July 7, 2006, the applicant modified the UFSAR and its commitment (Commitment No. 23) to specify that it will comply with BWRVIP-116, including the
 
conditions specified by the staff in its SER dated February 24, 2006. The staff finds this
 
acceptable, therefore, the concern described in RAI B.1.23-1 is resolved.
Part 50, Appendix H of 10 CFR requires that an ISP used as a basis for a licensee implemented RPV surveillance program be reviewed and approv ed by the staff. The ISP to be used by the applicant is a program developed by the BWRVIP and the applicant will apply the BWRVIP ISP as
 
the method by which it will comply with the requirements of 10 CFR Part 50, Appendix H. The
 
BWRVIP ISP identifies capsules that must be tested to monitor neutron radiation embrittlement
 
for all licensees participating in the ISP and identifies capsules that need not be tested (standby
 
capsules). Tables 2-3 and 2-4 of the BWRVIP-116 report indicate that the remaining capsule from
 
OCGS is not to be tested. This untested capsule was originally part of the applicant's
 
plant-specific surveillance program and has rece ived significant amounts of neutron radiation.
In RAI B.1.23-2 dated March 20, 2006, the staff requested that the applicant include the following commitment in the UFSAR supplement.
3-113 If the OCGS standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in manner which maintains it in a condition which will
 
permit its future use, including during the period of extended operation, if
 
necessary.
In its response dated April 18, 2006, the applicant committed (Commitment No. 23) to store the standby capsules. The staff finds this acceptable, therefore, the concern described in
 
RAI B.1.23-2 is resolved.
The staff's review finds that the applicant has demonstrated that the effects of aging due to loss of fracture toughness of the reactor pressure vessel beltline region 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).
UFSAR Supplement. The applicant described the existing Reactor Vessel Surveillance Program in LRA Section A.1.23. The program periodically tests metallurgical surveillance samples to
 
monitor the loss of fracture toughness of the RPV beltline region materials consistent with the
 
requirements of 10 CFR Part 50, Appendix H. The applicant further stated that it will implement
 
the staff-approved BWRVIP-116 report for the license renewal period. The BWRVIP-116 report
 
was approved by the staff and, as described in the staff evaluation section, the applicant should
 
include the following statement in the UFSAR supplement:
The ISP BWRVIP-116 which was approved by the staff, will be implemented, and will comply with the conditions documented in Sections 3 and 4 of the staff's final
 
SER of the BWRVIP-116 report.
As to the status of the remaining standby capsule, the applicant made a commitment (Commitment No. 23) to incorporate the following statement in the UFSAR supplement:
If the OCGS standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in manner which maintains it in a condition which will
 
permit its future use, including during the period of extended operation, if
 
necessary.
The staff reviewed the applicant's proposed revision to the UFSAR supplement and determined that by implementing the most recent staff-approved version of the BWRVIP-116 report the
 
applicant demonstrated its compliance with the requirements of 10 CFR Part 50, Appendix H.
The staff's review determined that the following license condition will be required to ensure that changes in the BWRVIP withdrawal schedule will be submitted for staff review and approval.
All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC, as required by
 
10 CFR Part 50, Appendix H.
The staff concludes that the information provided in the UFSAR supplement for the aging management of systems and components is consist ent with the recommendations of the GALL Report and, therefore, provides an adequate summary of program activities as required by
 
10 CFR 54.21 (d).
3-114 Conclusion. The staff's review of the applicant's Reactor Vessel Surveillance Program and RAI responses determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed
 
that its implementation prior to the period of extended operation will make the 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).
3.0.3.2.21  Buried Piping Inspection
 
Summary of Technical Information in the Application. In LRA Section B.1.26, the applicant described the existing Buried Piping Inspection Program as consistent, with an exception and enhancement, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."
The Buried Piping Inspection Program includes preventive measures to mitigate corrosion and periodic inspection of external surfaces for loss of material to manage the effects of corrosion on
 
the pressure-retaining capacity of piping and components in a soil (external) environment.
 
Preventive measures are in accordance with st andard industry practices for maintaining external coatings and wrappings. External inspections of buried components will occur opportunistically
 
when they are excavated during maintenance. During the period of extended operation, inspection of buried piping will be within 10 years unless an opportunistic inspection occurs within
 
any 10-year period. The program will be enhanced for reasonable assurance that buried piping and piping components will perform their intended function during the period of extended
 
operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.21. The staff reviewed the exception
 
and enhancement and their justifications to determine whether the AMP, with the exception and
 
enhancement, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Buried Piping Inspection Program for which the applicantclaimed consistency with GALL AMP XI.M34 and found them consistent. Furthermore, the staff
 
concluded that the applicant's Buried Piping Inspection Program provides reasonable assurance
 
that the aging effects for these materials will be adequately managed during the period of
 
extended operation. The staff found that the applicant's Buried Piping Inspection Program conforms to the recommended GALL AMP XI.M34 with an exception and an enhancement
 
described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program elements "scope of the program," "preventive actions," and "a cceptance criteria." Specifically, the exception stated:Section X1.M.34, "Buried Piping and Tanks Inspection," AMP only includes buried carbon steel piping; however, Oyster Creek has other material, such as stainless
 
steel, aluminum, bronze and cast iron, in their buried piping program that will be
 
managed as part of this AMP.
3-115 During the audit, the staff asked the applicant whether the buried pipe will be inspected within 10 years of the end of the current period of operation and during the first 10 years of the period of
 
extended operation. The applicant replied that there will not be a focused inspection within 10
 
years of entering the period of extended operation because opportunistic inspections have
 
occurred within this 10-year period. Also, a focused inspection will occur during the first 10 years
 
of the period of extended operation unless an opportunistic inspection occurs during that time.
The staff also asked the applicant whether each buried material will be inspected. The applicant stated that all types of materials will not be exam ined. Rather, the inspections will be of a system with high likelihood of corrosion problems or systems with histories of corrosion. The Buried
 
Piping Inspection Program contains aluminum, cast iron, stainless steel, and bronze in addition to
 
the carbon steel. All but 25 feet of the aluminum pipe has been relocated to an above-ground
 
location. The remaining buried aluminum pipe is part of the condensate transfer system. The cast
 
iron pipe is part of the fire protection system. The heating and process steam and roof drain and
 
overboard discharge systems may contain coated stainless steel and bronze fittings. OCGS has
 
never experienced any failures of these materials. To be conservative, OCGS has included these
 
materials in the scope of the Buried Piping Inspection Program.
The staff finds the applicant's exception to the GALL Report acceptable after discussions with the applicant. In particular, the applicant explained that the bronze fittings are coated and that, with
 
the exception of the aluminum pipe, none of t he other materials has experienced any problems.
Only a small portion of the aluminum pipe remains buried. On this basis, the staff finds this
 
exception acceptable.
Enhancement. In the LRA, the applicant stated that there is an enhancement to meet the GALL Report program elements "scope of the program
," "parameters monitored or inspected,"
"detection of aging effects," and "acceptance criteria." Specifically, the enhancement stated:
The Buried Piping Inspection aging management program will be enhanced to include Fire Protection components in the scope of the program. Inspection of
 
buried piping within ten years of entering the period of extended operation will be
 
conducted, unless an opportunistic inspection occurs within this ten-year period.
 
Piping located inside the vault are in the scope of the program In the LRA, the applicant stated that inspections will confirm that coating and wrapping are intact.
These inspections effectively ensure that corrosion of external surfaces has not occurred and that
 
intended function has been maintained. Inspections confirm that coating and wrapping are intact.
 
External inspections of buried components occu r opportunistically when they are excavated during maintenance. Buried piping will be opportunistically inspected whenever excavated for
 
maintenance. The inspections will be on all of the areas made accessible to support the
 
maintenance activity. Areas with the highest likelihood of corrosion problems with a history of
 
corrosion problems have been identified in Topical Report (TR) "Oyster Creek Underground
 
Piping Program Description and Status". Several yard excavation activities to date have
 
uncovered buried piping that has been inspected. OCGS has focused inspection on their
 
underground piping within the past 10 years. Several inspections have been performed on the
 
ESW and SW systems, which have a high likelihood and a history of corrosion-related problems.
 
In addition other inspections and testing have been performed per the Technical Data Report
 
TDR-829, "Pipe Integrity Inspection Program," and TR-116, "Oyster Creek Underground Piping
 
Program Description and Status."
3-116 The applicant further stated that, during the period of extended operation, inspection of buried piping will be performed within 10 years unless an opportunistic inspection occurs within the
 
10-year period. Areas with the highest likelihood or a history of corrosion problems have been
 
identified in the TR. These are primarily in the ESW and SW systems. These areas have been inspected within the past 10 years. Additionally, ISI testing and monitoring for the ESW, SW, RBCCW, Fire Protection, and Condensate Transfer systems are performed. Monitoring and
 
trending from these tests can aid in the detection of system pipe leaks. Periodic leak testing and component inspections are credited as well. ASME Code Section XI, Pressure Testing, directs
 
testing of buried cooling water piping for the detection of leaks. This pressure testing is via pump
 
surveillances.
The staff noted that this enhancement adds additional components into the Buried Piping Inspection Program, which is conservative. The staff finds this enhancement acceptable because when implemented the Buried Piping Inspection Program will be consistent with GALL AMP XI.M34 and will provide additional assurance that the effects of aging will be adequately
 
managed.Operating Experience. In LRA Section B.1.26, the applicant explained that the Buried Piping Inspection Program, as enhanced, will be effective in managing aging degradation for the period
 
of extended operation by timely detecting aging effects and implementing appropriate corrective actions prior to loss of system or component intended functions. OCGS has performed numerous external inspections of buried pipe during excavation activities and repair of degraded coatings
 
when necessary. In 1992, the SW system developed a leak that resulted from failure of the external coating. The root cause evaluation determined that failure was due to improper original
 
coating application. Subsequently, OCGS initiated the Underground Piping Program. To date
 
there have been no other buried pipe leaks due to external degradation. Although failure of buried
 
piping has occurred, the applicant has determined that the leaks were caused from the inside of
 
the buried piping, which is evaluated with the Buried Piping Inspection Program. OCGS conducts
 
pressure tests of SR buried piping to identify leaks and to ensure adequate pressure integrity.
 
This pressure testing is performed by pump surveillances.
In plant operating experience, coatings and wrappings have protected the external surfaces of buried piping adequately and loss of material due to external corrosion has not been a concern.
 
There are some portions of buried stainless steel and bronze piping that may not be coated or
 
wrapped. OCGS has had no failures of this piping due to external degradation. Therefore, in
 
OCGS and industry operating experience stainless steel and copper alloy material are resistant to
 
corrosion in a buried environment. Additionally, OC GS cast iron fire hydrants are not coated or wrapped and OCGS has had no failures of any of the buried hydrants due to external
 
degradation. Furthermore, one of the hydrants was replaced in 2003 due to failure of the hydrant
 
to drain and the external condition of the hydrant was good. Thus inspection of buried piping
 
when excavated for maintenance provides reasonable assurance that the intended functions will
 
be maintained. Inspections will be performed within 10 years after the start of the period of
 
extended operation unless an opportunistic inspection occurs within this 10-year period.
The staff noted that the applicant has no exception to the GALL Report program element "parameters monitored or inspected" and has added enhancements of fire protection components to the scope of the program. In addition, the applicant has conducted numerous inspections and
 
has identified key locations to inspect on a regular basis. When coating degradation or damage to
 
pipe is discovered corrective action is taken. About half of the ESW piping has been replaced and
 
the remainder will be replaced before the period of extended operation. OCGS has performed 3-117 numerous external inspections of their buried components since 1991. These inspections have shown no significant external coating failures. Coatings have been repaired during these
 
inspections in accordance with corporate procedures.
In 2004, 50 percent of the buried ESW and 10 percent of SW piping were replaced with new, coated piping. During the audit, the staff asked the applicant when the remaining pipe will be
 
replaced. In its letter dated May 1, 2006, the applicant committed (Commitment No. 63) to replace
 
the remaining safety-related ESW piping prior to the period of extended operation.
In 1993 an inspection of 20 feet of RBCCW showed that the external coating was in good condition. In 1992 the fire protection system underground piping was inspected by excavation and
 
some internal inspection. The external coating was in good condition as well as the internal
 
carbon steel. In 1980 the uncoated aluminum underground piping in the vicinity of the CST was
 
replaced. In 1991 and 1994 buried piping adjacent to the condensate transfer shack was
 
determined to have severe corrosion during an inspection. As a result, a significant modification
 
relocated aluminum piping above ground in tunnels or vaults. Currently 90 percent of all aluminum piping is located above ground. The remaining buried aluminum pipe was inspected in 1993 and
 
has an expected service life of 15-20 year
: s. Action Request A2116126 has been submitted to inspect the remaining buried, uncoated aluminum pipe prior to December 2008. The remaining
 
buried aluminum piping does have cathodic protection.
The operating experience of the Buried Piping Inspection Program has shown objective evidence that the program has identified susceptible buried pipe locations and has created a monitoring
 
program effective in preventing failures prio r to the loss of system intended function. The operating experience of the Buried Piping Inspection Program shows no adverse trend in
 
performance. Problems identified will not cause significant impact to the safe operation of the
 
plant, and adequate corrective actions were taken to prevent recurrence. There is sufficient
 
confidence that the implementation of the Buried Piping Inspection Program will effectively
 
determine loss of material due to the effects of corrosion on the pressure-retaining capacity of
 
buried piping. Appropriate guidance for reevaluation, repair, or replacement is provided for loss of
 
material. Periodic self-assessments of the Buried Piping Inspection Program identify areas that
 
need improvement to maintain the quality performance of the program.
Continued implementation of the Buried Piping Inspection Program provides reasonable assurance that the effects of loss of material due to corrosion on the pressure-retaining capacity
 
of buried carbon steel piping is adequately managed so that the intended functions of
 
components within the scope of license renewal will be maintained during the period of extended
 
operation.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience. On the basis of its review of the above industry
 
and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Buried Piping Inspection Program will adequately manage
 
the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.26 and letter dated May 1, 2006, the applicant provided the UFSAR supplement for the Buried Piping Inspection Program. The staff determined that the
 
information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-118 Conclusion. On the basis of its audit and review of the applicant's Buried Piping Inspection Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exceptions, is adequate to manage the
 
aging effects for which it is credited. Also, the staff reviewed the enhancement and confirmed that
 
implementation of the enhancement prior to the period of extended operation will make the 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).3.0.3.2.22  ASME Section XI, Subsection IWE
 
Summary of Technical Information in the Application. In LRA Section B.1.27, the applicantdescribed the existing ASME Section XI, Subsection IWE Program as consistent, with an exception, with GALL AMP XI.S1, "ASME Section XI, Subsection IWE." The ASME Section XI, Subsection IWE Program provides for inspection of primary containment components and the containment vacuum br eakers system piping and components. It is implemented through station plans and procedures and covers steel containment shells and their
 
integral attachments; containment hatches and air locks, seals and gaskets, containment vacuum
 
breakers system piping and components, and pre ssure retaining bolting. The program includes visual examination and limited surface or volu metric examination, when augmented examination is required, to detect loss of material. The program also manages loss of sealing for seals and
 
gaskets and loss of preload for pressure-retaining bolting. Procurement controls and installation
 
practices, defined in plant procedures, ensure that only approved lubricants and tension or torque
 
are applied. The program complies with Subsection IWE for steel containments (Class MC) of ASME Section XI, 1992 Edition including 1992 Addenda, in accordance with the provisions of
 
10 CFR 50.55(a).
Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.22.
During the onsite audits of October 3-7, 2005, January 23-27, 2006, February 13-17, 2006, and April 19-20, 2006, the staff conducted an in-depth review of (1) the OCGS history of containment
 
degradation due to corrosion, (2) the corrective actions taken at the time, (3) the current IWE
 
augmented inspections and other programs and activities to monitor/mitigate additional corrosion, and (4) the applicant's license renewal commitments to manage aging of the degraded
 
containment during the period of extended operation.
Through the audit process, the applicant made a number of significant new commitments to manage aging of the drywell shell. However, three issues remain unresolved. The staff's review of
 
the applicant's original license renewal commitments, the development of the applicant's new
 
commitments, and the remaining unresolved issues are documented in the Audit and Review
 
Report. To summarize the staff's evaluation of the containment corrosion issue, the staff focused
 
on the following four specific areas:
3-119  (1)water leakage from the refueling cavity into the annulus between the drywell and the shield wall  (2)corrosion of the upper drywell region above the former sand bed region (3)corrosion of the former sand bed region of the drywell (4)pitting corrosion of the suppression chamber (torus)
The operating experience and proposed aging management activities for each of these areas were reviewed in detail, and additional information was requested, as necessary, to facilitate a
 
thorough assessment and evaluation of the applicant's aging management plans for the licence
 
renewal period. The results of this detailed audit are documented in the following paragraphs. The
 
staff's overall evaluation of the information obtained is provided for each of these four areas at the end of this section.
Water Leakage from the Refueling Cavity. During the audit, the applicant stated that a special coating is applied to the refueling cavity liner prior to flooding the reactor for refueling to prevent
 
leakage into the annular space between the drywell shell and the concrete shield wall. As a result, the applicant believes that water intrusion into the refueling cavity has been eliminated as a
 
source of further degradation on the exterior surface of the drywell shell.
Since the applicant used this special coating to minimize water intrusion into the annulus between the drywell and the concrete shield wall; the staff requested that the applicant identify whether it is
 
committed to continue the use of this special coating as part of its refueling procedure through the
 
period of extended operation. If not, the applicant was asked to identify what enhanced
 
inspections will be conducted during the period of extended operation to monitor potential
 
corrosion on the drywell exterior surface from the upper flange region to the sand bed region.
In its response, the applicant stated that the strippable coating has been effective in mitigating water intrusion into the annular space and in reducing the rate of corrosion. The applicant
 
committed to applying the strippable coating to the reactor cavity liner prior to flooding for
 
refueling during the period of extended operation. In its letter dated April 4, 2006, the applicant
 
committed (Commitment No. 27) to the following:
Consistent with current practice, a strippable coating will be applied to the reactor cavity liner to prevent water intrusion into the gap between the drywell shield wall
 
and the drywell shell during periods when the refueling cavity is flooded. This
 
commitment applies to refueling outages prior to and during the period of extended
 
operation.In reviewing PBD-AMP-B.1.27 for the applicant's ASME Section XI, Subsection IWE Program, the staff noted that, page 7 of this document states that, "Under the current term, Oyster Creek is
 
committed to the NRC to monitor the former sand bed region drains for water leakage. The
 
commitment is to investigate the source of leakage, take corrective actions, evaluate the impact of
 
the leakage and, if necessary, perform additional drywell inspections. This commitment will be
 
implemented during the period of extended operati on. This is a new commitment not previously identified in the LRA." In its letter dated April 4, 2006, the applicant committed (Commitment
 
No. 27) to the following: The reactor cavity seal leakage trough drains and the drywell sand bed
 
region drains will be monitored for water leakage periodically.
3-120 The staff requested that the applicant describe this commitment in more detail. In its response, the applicant stated that the commitment for monitoring the sand bed drains is in a staff SER
 
transmitted by letter November 1, 1995. This SER requested a commitment to perform
 
inspections "3 months after the discovery of any water leakage". Subsequent correspondence
 
from General Public Utilities Nuclear Corporation (GPUN) clarified the commitment after
 
discussions with the staff. The commitment made and accepted by the staff in a
 
February 15, 1996, letter was to additional inspections of the drywell 3 months after discovery of
 
any water leakage during power operation between scheduled drywell inspections. The
 
requirement was not meant to apply to minor leakage from normal refueling activities. This
 
commitment in part is believed to be the present commitment in PBD-AMP-B.1.27.
The applicant further stated in its response that, although there is no formal leakage monitoring in place, there has been no reported evidence of leakage from the former sand bed drains. Issue
 
Report #348545 was submitted into the corrective action process when this lack was discovered.
 
Corrective actions have been initiated to create recurring activities controlled by work
 
management process and procedures for all future required inspections to meet the present
 
commitment. Because there has been no reported leakage, there has been no need to investigate
 
the source of leakage, take corrective actions, evaluate the impact of leakage, or perform
 
additional drywell inspections.
The applicant further stated that numerous actions have been taken to alleviate the previous water leakage problem since discovery of the consequent drywell shell corrosion. Some of the
 
significant actions consisted of inspections of t he reactor cavity wall, remote visual inspection of the trough area below the reactor cavity bellows seal area, and subsequent repair of the trough
 
area and clearing of its drain. Clearing of the trough drain and repair of the trough route any
 
leakage away from the drywell shell. In addition, a strippable coating is applied to the reactor
 
cavity walls before the reactor cavity is filled with water to minimize the likelihood of leakage into
 
the trough area. These preventive actions have resu lted in no evidence of leakage over the years at the former sand bed drains.
The staff reviewed the information in its overall evaluation of the drywell degradation issue presented at the end of this section.
Corrosion of the Upper Drywell above the Former Sand Bed Region. In reviewing the license renewal information for the upper region of the drywell shell, the staff noted that the applicant
 
referred to the LRA Section 4.7.2, "Drywell Corrosion," TLAA evaluation for further discussion. In
 
LRA Section 4.7.2, the applicant stated that the disposition of this TLAA is in accordance with 10 CFR 54.21(c)(1)(iii), and the ASME Section XI, Subsection IWE Program is credited to address
 
the drywell corrosion TLAA. In LRA Section 4.7.2, under Analysis, the applicant stated that the ASME Section XI, Subsection IWE Program ensures that the reduction in vessel thickness will not
 
adversely affect the ability of the drywell to perform its safety function. The ASME Section XI, Subsection IWE Program performs periodic UT inspections at critical locations, performs
 
calculations to track corrosion rates, projects vessel thickness based on conservatives corrosion
 
rates, and demonstrates maintenance of the minimum required vessel thickness.
The applicant further stated in the LRA that inspections conducted since 1992 demonstrate that, as a result of corrective actions, the corrosion rates are very low or, in some cases, arrested. The
 
drywell surfaces that were coated show no signs of deterioration. Drywell vessel wall thickness
 
measurements indicate substantial margin to the minimum wall thickness, even when projected to
 
the year 2029 with conservative estimates of corrosion rates. The applicant stated that continued 3-121 assessment of the observed drywell vessel thickness ensures that timely action can be taken to correct degradation that could lead to loss of the intended function.
The staff reviewed the applicant's discussion of aging management activities for the upper region of the drywell shell and determined that additional information was needed on the augmented
 
scope of IWE. In its response, the applicant stated that OCGS had been committed to the drywell
 
corrosion program in 1986 before implementation of IWE in September 9, 2001. The program
 
elements, including periodic UT inspections at critical locations, calculations to track corrosion
 
rates, vessel thickness projections based on conservative corrosion rates, and demonstrations of
 
maintenance of minimum required vessel thickness, are now incorporated into IWE as an
 
augmented inspection. The applicant provided procedures ER-AA-330, ER-AA-330-007, OC-6, and 2400-GMM-3900.52 for review.
The applicant further stated in its response that examination of the drywell interior surfaces in theformer sand bed region is included as part of the ASME Code Section XI IWE inspections. The
 
inspection of the exterior surfaces of the drywell in the sand bed region is included in the
 
Protective Coatings and Monitoring Program.
The applicant also provided a tabulation of measured thicknesses for the monitored elevation of the upper region of the drywell shell along with calculation 1302-187-E310-0037, which
 
summarizes trending results, projected remaining wall thickness at the end of the period of
 
extended operation, and the CLB minimum required thickness.
The applicant further stated that UT inspections are performed every other refueling outage and that calculation 1302-187-E310-0037 provides the corrosion calculation and end-of-operating life
 
thickness calculation.
In its letter dated April 4, 2006, the applicant committed (Commitment No. 27) to conduct UT thickness measurements in the upper regions of the drywell shell every other refueling outage at
 
the same locations currently measured prior to and during the period of extended operation.
The staff reviewed the information in its overall evaluation of the drywell degradation issue presented at the end of this section.In reviewing PBD-AMP-B.1.27 for the applicant's ASME Section XI, Subsection IWE Program, the staff noted that, in the discussion on pages 25 through 31 of drywell corrosion above the sand
 
bed region, the applicant stated that, Corrective action for these regions involved providing a corrosion allowance by demonstrating, through analysis, that the original drywell design pressure was
 
conservative. Amendment 165 to the Oyster Creek Technical Specifications
 
reduced the drywell design pressure from 62 psig to 44 psig. The new design
 
pressure coupled with measures to prevent water intrusion into the gap between
 
the drywell shell and the concrete will allow the upper portion of the drywell to meet
 
ASME Code requirements.
During the audit, the staff requested that the applicant describe the measures to prevent water intrusion into the gap between the drywell shell and the concrete to allow the upper portion of the
 
drywell to meet ASME Code requirements. In addition, the applicant was further asked to clarify 3-122 whether these measures to prevent water intrusion were credited for license renewal, and, if not, to clarify how ASME Code requirements will be met during the period of extended operation.
In its response, the applicant stated that the measures taken to prevent water intrusion into the gap between the drywell shell and the concrete to allow the upper portion of the drywell to
 
maintain the ASME Code requirements are the following:
* Cleared the former sand bed region drains to improve the drainage path.
* Replaced reactor cavity steel trough drain gasket, which was found to be leaking.
* Applied stainless steel type tape and strippable coating to the reactor cavity during refueling outages to seal identified cracks in the stainless steel liner.
* Confirmed that the reactor cavity concrete trough drains are not clogged.
* Monitored former sand bed region drains and reactor cavity concrete trough drains for leakage during refueling outages and plant operation.
The applicant further stated that OCGS is committed to implement these measures during the period of extended operation.
The staff reviewed the information in its overall evaluation of the drywell degradation issue presented at the end of this section.
Corrosion of the Former Sand Bed Region of the Drywell. In reviewing information for the sandbed region at the bottom of the drywell, the staff noted that, in the ASME Section XI, Subsection IWE Program discussion of operating experience, the applicant had stated that sand
 
was removed and a protective coating was applied to the shell to mitigate further corrosion. The
 
coating is monitored periodically under the Protective Coating Monitoring and Maintenance
 
Program, which is discussed in SER Section 3.0.3.1.8. The staff reviewed the Protective Coating
 
Monitoring and Maintenance Program and determined that the coating is included within its
 
scope. The staff noted that the discussion of operating experience in the Protective Coating
 
Monitoring and Maintenance Program is similar to the discussion of operating experience in ASME Section XI, Subsection IWE Program.
The staff reviewed the applicant's aging management activities for the former sand bed region of the drywell shell and determined that additional information was needed on aging management of
 
this region. In its response, the applicant stated that monitoring and maintenance of the coating in
 
the former sand bed region are included in the scope of the Protective Coating Monitoring and
 
Maintenance Program. These activities are in accordance with specifications SP-1302-32-035
 
and SP-9000-06-003, which are included in the program.
The applicant further stated in its response that aging management of the sand bed region is notincluded in the augmented inspection required by ASME Code Section XI, Subsection IWE. As stated in ASME Code Section XI, Subsection IWE operating experience, corrective actions that
 
include cleaning and coating of the sand bed region implemented in 1992 have arrested
 
corrosion. The coated surfaces were inspected in 1994, 1996, 2000, and 2004, and the inspection
 
showed no coating failure or signs of degradation. Thus, the region is not subject to augmented
 
inspection in accordance with IWE-1240. The coating will be inspected every other refueling
 
outage during the period of extended operation consistent with commitments for the current term.
3-123 As a result of discussions between the staff and the applicant on January 26, 2006, and April 20, 2006, the applicant supplemented its initial response to include the following:
* OCGS will also perform periodic UT inspections of the drywell shell thickness in the sand bed region, as discussed previously in this section.
* OCGS will also enhance the Protective Coating Monitoring and Maintenance Program to require inspection of the coating credited for corrosion (torus internal, vent system internal, sand bed region external) in accordance with ASME Section XI, Subsection IWE Program.
 
Details are provided later in this section.
* On April 20, 2006, OCGS provided supplemental information on torus coating.
Details of the enhancement to the Protective Coating Monitoring and Maintenance Program and the staff's evaluation of this AMP are discussed in SER Section 3.0.3.1.8.
After the applicant's initial response, the applicant was asked for its technical basis for not alsocrediting its ASME Section XI, Subsection IWE Program for managing loss of material due to
 
corrosion in the former sand bed region of the drywell.
The applicant stated that visual inspection of the containment drywell shell, conducted inaccordance with ASME Code Section XI, Subsection IWE, is credited for aging management of
 
accessible areas of the containment drywell shell. Typically this inspection is for internal surfaces
 
of the drywell. The exterior surfaces of the drywell shell in the sand bed region for Mark I containment are considered inaccessible by ASME Code Section XI, Subsection IWE; thus, visual
 
inspection was not possible for a typical Mark I containment before the sand was removed from
 
the sand bed region in 1992. After removal of the sand, an epoxy coating was applied to the
 
exterior surfaces of the drywell shell in the sand bed region. The region was made accessible
 
during refueling outages for periodic inspection of the coating. Subsequently, OCGS periodically
 
visually inspected the coating under a CLB commitment implemented prior to the ASME Section XI, Subsection IWE Program. As a result, inspection of the coating was in accordance
 
with the Protective Coating Monitoring and Maintenance Program. The applicant's evaluation of
 
this AMP concluded the program is adequate to manage aging of the drywell shell in the sand bed
 
region during the period of extended operation consistent with the CLB commitment and that
 
inclusion of the coating inspection under the ASME IWE inspection is not required. However, the
 
applicant will amend this position to commit to monitor the protective coating on the exterior
 
surfaces of the drywell in the sand bed region in accordance with the requirements of ASME Code Section XI, Subsection IWE during the period of extended operation.
In its letter dated April 4, 2006, the applicant committed (Commitment No. 27) to the following:
Prior to the period of extended operation, the applicant will perform additional visual inspections of
 
the epoxy coating applied to the exterior surface of the drywell shell in the sand bed region so the
 
coated surfaces in all 10 drywell bays will have been inspected at least once. In addition, the ISI
 
program will be enhanced to require inspection of 100 percent of the epoxy coating every 10
 
years during the period of extended operation. These inspections will be in accordance with ASME Code Section XI, Subsection IWE. The inspections will be staggered so that at least three
 
bays will be examined every other refueling outage.
This commitment applies prior to the period of extended operation, and every 10 years during the period of extended operation.
In its letter dated April 4, 2006, the applicant committed (Commitment No. 27) to the following: UT thickness measurements of the drywell shell in the sand bed region will be every 10 years. The 3-124 initial inspection will occur prior to the period of extended operation. The UT measurements will be taken from the inside of the drywell at the same locations of UT measurements in 1996. The
 
inspection results will be compared to previous result
: s. Statistically significant deviations from the 1992, 1994, and 1996 UT measurements will result in corrective actions: (1) additional UT
 
measurements to confirm the readings, (2) notice to the staff within 48 hours of confirmation of
 
the condition, (3) visual inspection of the external surface in the sand bed region in areas where
 
any unexpected corrosion may be detected, (4) an engineering evaluation of the extent of
 
condition to determine whether additional inspections are required to assure drywell integrity, and
 
(5) an operability determination and justification for operation until the next inspection. These
 
actions will be completed prior to restart from the outage.
In its letter dated May 1, 2006, the applicant committed (Commitment No. 27) to the following:
During the next UT inspections of the drywell sand bed region (reference AmerGen April 4, 2006, letter to NRC), an attempt will be made to locate and evaluate some of the locally thinned areas
 
identified in the 1992 inspection from the exterior of the drywell. This testing will use the latest UT
 
methodology with existing shell paint in place. The UT thickness measurements for these locally
 
thinned areas may be taken from either inside or outside the drywell (sand bed region) to limit
 
radiation dose to as low as reasonably achievable.
The staff requested that the applicant provide a discussion of the scope of the current coating inspection program and the license renewal commitment. In its response the applicant stated that
 
protective coatings on the exterior surfaces of the drywell shell in the sand bed region are
 
monitored in accordance with the Protective Coating Monitoring and Maintenance Program. The
 
current program requires visual inspection of the coating in accordance with Engineering
 
Specification IS-328227-004. Inspection criteria are not provided by the specification. However, inspections are by individuals qualified for coating inspections. Acceptance criteria in the
 
specification are that any coating defects be submitted for engineering evaluation. The inspection
 
frequency is every other refueling outage.
The applicant further stated in its response that, as discussed with the staff, the existing Protective Coating Monitoring and Maintenance Program does not invoke all of the requirements of ASME Code Section XI, Subsection IWE. The applicant has committed (Commitment No. 27)
 
to enhance the program to incorporate coated surfaces inspection requirements specified in ASME Code Section XI, Subsection IWE and has provided specific enhancements that will be
 
made to the program as follow:
Sand bed region external coating inspections will be per Examination Category E-C (augmented examination) and will requi re VT-1 visual examinations per IWE-3412.1. a. The inspected area shall be examined (as a minimum) for evidence of flaking, blistering, peeling, discoloration, and other signs of distress. b. Areas that are suspect shall be dispositioned by engineering evaluation or corrected by repair or replacement in accordance with IWE-3122. c. Supplemental examinations in accordance with IWE-3200 shall be performed when specified as a result of engineering evaluation.
During the audit, the staff asked the applicant for information related to inspections of the drywell sand bed region. In its response, the applicant stated that the minimum recorded thickness in the 3-125 sand bed region from outside inspection is 0.618 inches. The minimum recorded thickness in the sand bed region from inside inspection is 0.603 inches. These minimum recorded thicknesses are
 
isolated local measurements and represent single point UT measurements.
On April 19, 2006, the applicant supplemented its response, stating that the lowest recorded reading was 0.603 in December 1992. The applicant stated that a review of the previous readings
 
for the period 1990 through 1992 and two subsequent readings taken in September 1994 and in
 
1996 shows that this point should not be considered valid. The average reading for this point
 
taken in 1994 and 1996 was 0.888 inches. Point 14 in location 17D was the next lowest value of
 
0.646 inches recorded during the 1994 outage. A review of readings at this same point, taken
 
during the period from 1990 through 1992, and subsequent readings taken in 1996 are consistent
 
with this value. Thus, the minimum recorded thickness in the sand bed region from inside
 
inspections is 0.646 inches instead of 0.603 inches.
The applicant further stated in its response that the 0.806 inches thickness provided to the staff verbally is an average minimum general thickness calculated based on 49 UT measurements
 
taken in an area approximately 6 inches x 6 inches. Thus, the two local isolated minimum
 
recorded thicknesses cannot be compared directly to the general thickness of 0.806 inches. The
 
0.806 inches minimum average thickness verbally discussed with the staff during the AMP audit
 
was recorded in location 19A in 1994. Lower minimum average thickness values were recorded at
 
the same location in 1991 (0.803 inches) and in 1992 (0.800 inches). However, the three values
 
are within the tolerance of +/- 0.010 inches discussed with the staff.
The applicant further stated in its response that the minimum projected thickness depends on whether the trended data is before or after 1992, as demonstrated by corrosion trends. For
 
license renewal the use of corrosion rate trends after 1992 is appropriate because of such
 
corrosion mitigating measures as removal of the sand and coating of the shell. Then, using
 
corrosion rate trends based on 1992, 1994, and 1996 UT data and the minimum average
 
thickness measured in 1992 (0.800 inches), the minimum projected average thickness through
 
2009 and beyond remains approximately 0.800 inches. The projected minimum thickness during
 
and through the period of extended operation will be reevaluated after UT inspections conducted
 
prior to the period of extended operation and after UT inspections every 10 years thereafter.
The applicant further stated in its response that the engineering analysis that demonstrated compliance with ASME Code requirements had two parts, stress and stability analysis with sand
 
and stress and stability analyses without sand. The analyses are documented in GE Reports
 
Index No. 9-1, 9-2, 9-3, and 9-4 transmitted to the staff in December 1990 and in 1991, respectively. Index Nos. 9-3 and 9-4 were revised later to correct errors identified during an
 
internal audit and resubmitted to the staff in January 1992.
The staff requested that the applicant provide information related to the evaluation of the results of the next UT inspection of the sand bed region. In its response, the applicant stated that the new
 
set of UT measurements for the former sand bed region will be analyzed by the same
 
methodology used to analyze the 1992, 1994, and 1996 UT data. The results will then be
 
compared to the 1992, 1994, and 1996 UT results to confirm the previous no corrosion trend.
 
Because of surface roughness of the exterior of the drywell shell, experience shows that UT
 
measurements can vary significantly unless the UT instrument is positioned on the exact point as for the previous measurements. Thus, acceptanc e criteria will be based on the standard deviation of the previous data (+/-11 mils) and instrument a ccuracy of (+/-10 mils) for a total of 21 mils.
3-126 Deviation from this value will be considered unexpected and requiring corrective actions described previously.
The staff reviewed the information in its overall evaluation of the drywell degradation issue presented at the end of this section.
Pitting Corrosion of the Suppression Chamber (Torus). In reviewing information in the ASMESection XI, Subsection IWE Program discussion of operating experience for the suppression
 
chamber (torus) and vent system, the staff noted that the applicant had stated that the coating is
 
inspected every outage and repaired, as required, to protect the torus shell and the vent system
 
from corrosion. The staff referred to the Protective Coating Monitoring and Maintenance Program
 
for additional details. The staff reviewed the Protective Coating Monitoring and Maintenance
 
Program and noted that, under operating experience, the applicant stated that torus and vent
 
header vapor space Service Level I coating inspections in 2002 found the coating in these areas
 
in good condition. Inspection of the immersed coating in the torus found blistering that primarily in
 
the shell invert but also on the upper shell near the water line. The majority of the blisters
 
remained intact and continued to protect the base metal. However, several areas included pitting
 
damage where the blisters were fractured. A qualitative assessment of the pits concluded that the
 
pit depths were significantly less than the established acceptance criteria. The fractured blisters
 
were repaired to reestablish the protective coating barrier.
To clarify, the applicant was asked for information pertaining to operating experience and license renewal aging management for the suppression c hamber (torus) and vent system. In its response, the applicant stated that inspection of the suppression chamber (torus) and vent
 
system coating is by divers every other out age in accordance with Engineering Specification SP-1302-52-120, which provides inspection and acceptance criteria for the coating and for pitting
 
as a contingency in the event failure of the coating results in pitting. The coating is monitored for
 
cracks, sags, runs, flaking, blisters, bubbles, and other defects described in the Protective
 
Coating Monitoring and Maintenance Program.
The applicant further stated that the specification requires inspection of the torus and vent system surfaces for coating integrity. If pitting is observed isolated pits of 0.125 inches in diameter have
 
an allowed maximum depth of 0.261 inches anywhere in the shell provided the center-to-center
 
distance between the subject pits and neighboring isolated pits or areas of pitting corrosion is
 
greater than 20 inches. Multiple pits that can be encompassed by a 2.5-inch diameter circle are
 
limited to a maximum depth of 0.141 inches provided the center-to-center distance between the
 
subject pitted area and neighboring isolated pits or areas of pitting corrosion is greater than
 
20 inches.
Plant documentation that describes the blistering and pitting and qualitative assessment performed, the established acceptance criteria, and corrective actions taken is included in
 
PBD-AMP-B.1.27.
On April 19, 2006, the applicant supplemented its response to include the statement "Pits greater that 0.040 inches in depth shall be documented and submitted to engineering for evaluation."
The applicant further stated in its response that the torus and vent system coating is classified Service Level I coating as described in the Protective Coating Monitoring and Maintenance
 
Program. The program was evaluated against the 10 elements of GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program" and found consistent without enhancements or 3-127 exceptions. Acceptance criteria are evaluated in el ement 3.6 of the Protective Coating Monitoringand Maintenance Program (PBD-AMP-B.1.33). The inspection is performed by ASME Section XI
 
Level II and Level III inspectors. Acceptance criteria for pits are based on engineering analysis
 
that uses the method of ASME Code Case N-597 as guidance for calculation of pit depths that will
 
not violate the local stress requirements of either ASME Code Section III, 1977 Edition or
 
Section VIII, 1962 Edition.
The applicant also stated in its response that the inspection that discovered the blistering was conducted under the protective coating monitoring and maintenance program. Examinations are performed by ASME Section XI Level II and Level III inspectors. The applicant further stated in its response that both the ASME Section XI, Subsection IWE and the Protective Coating Monitoring
 
and Maintenance Programs are credited to manage loss of material due to corrosion for the
 
suppression chamber (torus) and the vent sy stem for the period of extended operation.
On April 19, 2006, the applicant supplemented its response to clarify that during the period of extended operation, torus coating inspection will be performed in all 20 torus bays at a frequency
 
of every other refueling outage for the current coating system. Should the coating system be replaced, the inspection frequency and scope will be re-evaluated. The inspection scope will, as a
 
minimum, meet the requirements of ASME Code Subsection IWE. This specific commitment (Commitment No. 33) is associated with the Protective Coating Monitoring and Maintenance
 
Program.In its letter dated May 1, 2006, the applicant committed (Commitment No. 27) to the following: As noted in the applicant's April 4, 2006 letter to NRC, OCGS will perform torus coating inspections in accordance with ASME Code Section XI, Subsection IWE every other refueling outage prior to
 
and during the period of extended operation. This new commitment clarifies that the scope of
 
each of these inspections will include the wetted area of all 20 torus bays. Should the current
 
torus coating system be replaced, the inspection frequency and scope will be re-evaluated.
Inspection scope will, as a minimum, meet the requirements of ASME Code Section XI, Subsection IWE.
On April 19, 2006, the applicant supplemented its response, stating that Condition Report No. 373695 assignments 2 and 3 have been initiated to drive program improvements for the monitoring and trending of torus design margins, and to develop refined acceptance criteria and
 
thresholds for entering coating defects and unacceptable pit depths into the corrective action
 
process for further evaluation. These improvem ents will be incorporated into the inspection implementing documents prior to the next performance of these inspections, which is also prior to the period of extended operation. These improvements will be described in a letter to the NRC.
In its letter dated May 1, 2006, the applicant stated that it will develop refined acceptance criteria and thresholds for entering torus coating defects and unacceptable pit depths into the corrective
 
action process for further evaluation. These impr ovements will be incorporated into the inspection implementing documents prior to the next performance of these inspections, which is also prior to the period of extended operation.
The staff finds this acceptable since it will provide additional criteria to determine whether degradation of the suppression chamber is being adequately managed.
On April 19, 2006, the applicant supplemented its response, stating that the answers provided previously on torus wall thickness were written to address specific concerns of the AMP audit 3-128 team and were centered around worse case torus thickness margins existing on the torus shell due to corrosion. This supplemental information is being provided to reinforce that, based on all
 
available inspection results, the average thickness of the torus remains at 0.385 inches. Based on
 
the results of the inspections performed through 1993 (14R), it was concluded that the torus shell
 
thickness had remained virtually unchanged following the repair and recoating efforts performed
 
in 1984. This was communicated to the NRC via letter C321-94-2186 dated November 3, 1994, Amendment No. 177 to DPR-16 and SER dated February 21, 1995 for the electromatic relief
 
valve (EMRV) technical specification change. Coating inspections performed subsequent to 1993
 
(14R) continue to confirm that the torus shell thickness has remained virtually unchanged
 
following the repair and recoating efforts performed in 1984, and that the average thickness of the
 
torus remains at 0.385 inches. Torus integrity will continue to be evaluated during future
 
inspections (performed every other refueling outage) into the period of extended operation.
The applicant also clarified the extent of pitting corrosion. Pitting corrosion less than or equal to 0.040 inches was not repaired during the 1984 torus repair and recoating effort based on
 
available margins and was found to be acceptable without any size restriction since it satisfied
 
minimum uniform thickness requirements. Inspection activities subsequent to 1984 have identified
 
5 isolated pits that exceed 0.040 inches. The following areas have been mapped for trending and
 
analysis during future inspections: 1 pit of 0.042 inches in bay 1; 1 pit of 0.0685 inches in bay 2;
 
2 pits of 0.050 inches in bay 6; 1 pit of 0.058 inches in bay 10. Shell thicknesses have been
 
evaluated against code requirements and found to satisfy all design and licensing basis
 
requirements. Therefore, the integrity of the torus shell has been verified to have adequate shell
 
thickness margins to ensure design and licensing basis requirements can be maintained.
The applicant also supplemented its response to include the statement, "Pits greater that 0.040 inches in depth shall be documented and submitted to engineering for evaluation."
The staff reviewed the applicant's response and determined that it was responsive to the questions asked. The staff reviewed the information in its overall evaluation of the drywell
 
degradation issue presented at the end of this section.In reviewing PBD-AMP-B.1.27 for the applicant's ASME Section XI, Subsection IWE Program, the staff noted that, in the discussion of torus degradation pages 25 to 31 of this document state that, Inspections performed in 2002 found the coating to be in good condition in the vapor area of the torus and vent header, and in fair condition in immersion. Coating
 
deficiencies in immersion include blistering, random and mechanical damage.
 
Blistering occurs primarily in the shell invert but was also noted on the upper shell
 
near the water line. The fractured blisters were repaired to reestablish the
 
protective coating barrier. This is another example of objective evidence that the ASME Section XI, Subsection IWE Program can identify degradation and
 
implement corrective actions to prevent the loss of the containment's intended function. While blistering is considered a deficiency, it is significant only when it is
 
fractured and exposes the base metal to corrosion attack. The majority of the
 
blisters remain intact and continue to protect the base metal; consequently the
 
corrosion rates are low. Qualitative assessment of the identified pits indicate that
 
the measured pit depths (50 mils maximum) are significantly less than the criteria
 
established in specification SP-1302-52-120 (141- 261 mils, depending on
 
diameter of the pit and spacing between pits).
3-129 The applicant was asked to confirm or clarify that (1) only the fractured blisters found in this inspection were repaired, (2) pits were identified where the blisters were fractured, (3) pit depths
 
were measured and found to 50 mils maximum, (4) the inspection Specification SP-1302-52-120
 
includes pit-depth acceptance criteria for rapid evaluation of observed pitting, and (5) the
 
minimum pit depth of concern is 141 mils (0.141 inches) and pits as deep as 261 mils
 
(0.261 inches) may be acceptable.
In its response, the applicant stated that Specification SP-1302-52-120, "Specification for Inspection and Localized Repair of the Torus and Vent System Coating," specifies repair
 
requirements for coating defects exposing substrate and fractured blisters showing signs of
 
corrosion. The repairs to which the inspection report referred included fractured blisters as well as
 
any mechanically damaged areas which have expos ed bare metal showing signs of corrosion.
Therefore, only fractured blisters will be candidates for repair, not blisters that remain intact. The
 
number and location of repairs are tabulated in the final inspection report prepared by Underwater
 
Construction Corporation.
The applicant further stated in its response that coating deficiencies in the immersion region included blistering with minor mechanical damage. Blistering occurred primarily in the shell invert
 
but was also noted on the upper shell near the water line. Most blisters were intact. Intact blisters
 
were examined by removing the blister cap exposing the substrate. Corrosion attack under
 
non-fractured blisters was minimal and generally limited to surface discoloration. Examination of
 
the substrate revealed slight discoloration and pitting with pit depths less than 0.001 inches.
 
Several blistered areas included pitting corrosion where the blisters were fractured. The substrate
 
beneath fractured blisters generally exhibited a slightly heavier magnetite oxide layer and minor pitting (less than 0.010 inches) of the substrate.
In addition to blistering, random deficiencies that exposed base metal were identified in the torus immersion region coating (e.g., minor mechanical damage) during the 19R (2002) torus coating
 
inspections. They ranged in size from 1/16 to 1/2  inches in diameter. Pitting in these areas was
 
qualitatively evaluated and ranged from less than 10 mils to slightly more than 40 mils in a few isolated cases. Three quantitative pit depth measurements were taken in several locations in the
 
immersion area of Bay 1. Pit depths at these sites ranged from 0.008 to 0.042 inches and were
 
judged to be representative of typical conditions found on the shell. Prior to the 2002 inspection, 4
 
pits greater than 0.040 inches were identified. The pit depths were 0.058 inches (1 pit in 1988),
0.05 inches (2 pits in 1991), and 0.0685 inches (1 pit in 1992). The pits were evaluated against
 
the local pit depth acceptance criteria and found acceptable.
The applicant also stated that the acceptance criteria for pit depth are as follow: Isolated pits of 0.125 inches in diameter have an allowed maximum depth of 0.261 inches anywhere in the shell
 
provided the center-to-center distance between the subject pit and neighboring isolated pits or
 
areas of pitting corrosion is greater than 20.0 inches. This criterion includes old pits or old areas
 
of pitting corrosion that have been filled or re-coated. Multiple pits that can be encompassed by a
 
2-1/2 inches diameter circle shall be limited to a maximum pit depth of 0.141 inches provided the
 
center-to-center distance between the subject pitted area and neighboring isolated pits or areas of
 
pitting corrosion is greater than 20.0 inches. This criterion includes old pits or old areas of pitting
 
corrosion that have been filled or re-coated.
The staff reviewed the information in its overall evaluation of the drywell degradation issue presented at the end of this section.
3-130 Drywell Degradation Issue. The staff evaluated the applicant's revised aging management commitments to address four distinct issues: (1) monitoring/eliminating water leakage, (2)
 
corrosion in the upper drywell region, (3) corrosion in the former sand bed region, and (4) pitting
 
corrosion in the suppression chamber (torus). The staff's evaluation of each area is discussed in
 
the following paragraphs.  (1) Monitoring/Eliminating Water Leakage in the Gap Between the Drywell and Shield Wall
.The applicant made a commitment (Commitment No. 27), to continue the use of the
 
strippable coating for each refueling during the license renewal period. According to the
 
applicant, this coating has been effective in eliminating water intrusion into the annular
 
space between the drywell shell and the concrete shield wall. In the LRA, the applicant
 
had not committed to continue its use.
The applicant also committed (Commitment No. 27) to investigate the source of leakage, take corrective actions, evaluate the impact of the leakage and, if necessary, perform
 
additional drywell inspections in the event water leakage from the former sand bed region
 
is found during the period of extended operation. Under the current license term, OCGS is
 
committed to monitor the former sand bed region drains for water leakage. This
 
commitment was not previously identified in the LRA.
The staff noted that while these new commitments address both mitigation of and monitoring for water leakage; they are an essential element of the applicant's overall
 
program to manage aging of the degraded drywell during the license renewal period, the
 
applicant has not established a leakage monitoring program.
However, the applicant indicated that there is no formal procedure in place to monitor leakage from the sand bed drains and stated, "Issue Report #348545 was submitted into
 
the corrective action process when this was discovered. Corrective actions have been
 
initiated to create recurring activities controlled with the work management process and
 
procedures, to perform all future required inspections to meet the present commitment."
The staff found that the absence of a leakage monitoring program to meet the current license term commitment raises a question about the basis for the applicant's claim that
 
water is no longer leaking into the annular gap between the drywell shell and the concrete
 
shield wall. Subsequent to the audit, in response to RAI 4.7.2-1, by letter dated June 20, 2006, the applicant provided additional information regarding the AMP and activities
 
associated with drywell leakage monitoring program. The staff's evaluation of the
 
applicant's additional information and its commitments is documented in SER
 
Section 4.7.2.  (2) Upper Drywell Region. The applicant made a new license renewal commitment (Commitment No. 27), to continue UT measurements of the upper drywell region for the
 
period of extended operation.
The applicant manages loss of material due to corrosion in the upper drywell region (spherical and cylindrical sections) by augmented examinations in accordance with IWE-1240. An UT survey is performed every ot her refueling outage (4 years) to detect any additional loss of material due to corrosion. The UT results are evaluated and trended to
 
ensure that the drywell shell is capable of performing its intended function to the end of
 
plant life. The areas subject to periodic UT measurements were selected based on 3-131 extensive exploratory testing to establish the most severely corroded locations in the drywell above the sand bed region. Corrosion of the upper drywell region is a TLAA per
 
10 CFR 54.21(c). The applicant's TLAA is documented in LRA Section 4.7.2. The
 
applicant implements TLAA option (iii) and uses the UT inspection results from its IWE
 
program to monitor remaining thickness, to periodically update the corrosion rate, and to
 
periodically update the projected remaining thickness at the end of the license renewal
 
period. The evaluation of this TLAA is addressed in SER Section 4.  (3) Former Sand Bed Region of Drywell. In the LRA, the applicant's position was that corrosion in the former sand bed region has been completely arrested by the remedial
 
actions already taken. The original LRA commitment was to inspect a section of coating
 
every other outage (4 years) to confirm its soundness. The last UT readings were in 1996.
 
As a result of the audit, the applicant made several new commitments to manage aging of
 
the former sand bed region of the drywell during the period of extended operation. In its
 
letters dated April 4, 2006, and May 1, 2006, the applicant revised the commitments:
* Monitor the protective coating on the exterior surfaces of the drywell in the sandbed region in accordance with the requirements of ASME Code Section XI, Subsection IWE during the period of extended operation (Commitment No. 27),
* Conduct periodic UT inspection of the former sand bed region before the license renewal period and every 10 years thereafter (Commitment No. 27),
* Attempt during the UT inspections of the sand bed region prior to the period of extended operation a UT inspection from the exterior of the drywell of some of the
 
locally thinned areas identified in the 1992 inspection (Commitment No. 27),
* Inspect the remaining 50 percent of the external coating in the former sand bed region before the license renewal period (to date, only 50 percent of this coating
 
has been inspected since it was applied in the early 1990s) and conduct a 100
 
percent re-inspection of the coating every 10 years during the license renewal
 
period (Commitment No. 27),
* If additional corrosion of the sand bed region is identified by the UT inspection to be conducted before entering the license renewal period, initiate corrective actions
 
that include one or all of the following, depending on the extent of identified
 
corrosion:Perform additional UT measurements to confirm the readings. Notify the staff within 48 hours of confirmation of the identified condition. Inspect the coatings in the sand bed region in areas where the additional
 
corrosion was detected. Perform an engineering evaluation to assess the extent of the condition and
 
to determine whether additional inspections are required to assure drywell
 
integrity. Perform an operability determination and justification for continued
 
operation until next scheduled inspection.
These actions will be completed before restarting from an outage (Commitment No. 27).
3-132 The staff noted these new commitments for managing aging of the former sand bed region, but also noted the very small remaining margin between the minimum reported
 
uniform thickness and the minimum required uniform thickness (0.800 inches vs.
 
0.736 inches). This apparent lack of margin led the staff to request additional information
 
about (1) the UT inspection results and data reduction methods employed to determine
 
the minimum remaining thickness and (2) the analytical methodology employed to
 
determine the minimum required thickness for localized areas where the measured
 
thickness is less than the minimum required uniform thickness. The applicant provided
 
additional information on these subjects. During a followup onsite audit conducted
 
April 19-20, 2006, the staff discussed these responses with the applicant in detail to
 
ensure a complete understanding.
The staff reviewed the detailed UT thickness readings in the sand bed region taken from the inside surface through 1996 and on the outside surface in 1992. The staff pointed out
 
a definite bias in the 1996 readings because the average thickness (based on 49
 
readings/location) increased at almost all locations. The staff and the applicant's
 
personnel discussed possible causes for this bias, but no conclusions could be drawn.
The staff's review of the UT data confirmed that the remaining thickness in the former sand bed region significantly exceeds the minimum required thickness of 0.736 inches at
 
most monitored locations. Several locations are close to the original design thickness of
 
1.154 inches. However, in a few very localized areas, primarily in Bays 1 and 13, remaining thicknesses less than 0.736 inches have been measured. The lowest measured
 
point reading is 0.618 inches recorded in the 1992 outside surface inspection. The lowest
 
measured point reading from the inside surface inspections is 0.646 inches.
The staff also reviewed the technical basis documents that established compliance with ASME Code requirements. In response to a question, the applicant stated that the
 
engineering analysis demonstrating compliance with ASME Code requirements was
 
performed in two parts, stress and stability analysis with and without sand. The analyses
 
are documented in GE Reports Index No. 9-1, 9-2, 9-3, and 9-4 transmitted to the NRC in
 
December 1990 and in 1991, respectively. Index Nos. 9-3 and 9-4 were revised later to
 
correct errors identified during an internal audit, and were resubmitted to the staff in
 
January 1992.
The applicant stated that the drywell shell thickness in the sand bed region is based on stability analysis without sand (GE Report 9-4). The analysis is based on a 36-degree
 
section model that takes advantage of symmetry of the drywell with 10 vents. The model
 
includes the drywell shell from the base of the sand bed region to the top of elliptical head
 
and the vent and vent header. The torus is not included in this model because the bellows
 
provide a very flexible connection which does not allow significant structural interaction
 
between the drywell and the torus. The analysis conservatively assumed that the shell
 
thickness in the entire sand bed region had been reduced uniformly to a thickness of
 
0.736 inches.
The applicant further indicated that GE Letter Report "Sand Bed Local Thinning and Raising the Fixity Height Analysis" presents results demonstrating that a uniform reduction
 
in thickness of 27 percent to 0.536 inches over a 1 ft 2 area will create only a 9.5 percent reduction in the load factor and theoretical buckling stress for the whole drywell. A second
 
buckling analysis for a wall thickness reduction of 13.5 percent to 0.636 inches over a 1 ft 2
3-133 area reduced the load factor and theoretical buckling stress by only 3.5 percent for the whole drywell. To bring these results into perspective, a review of the NDE reports indicate
 
there are 20 UT measured areas in the whole sand bed region with thicknesses less than
 
the 0.736 inches thickness used in GE Report 9-4 covering a conservative total area of
 
0.68 ft 2 of the drywell surface with an average thickness of 0.703 inches or 4.5 percent reduction in wall thickness. Furthermore, all of these very local wall areas are centered
 
about the vents, significantly stiffening the shell. This stiffening effect limits the shell
 
buckling in the shell sand bed region to the midpoint between two vents.
The staff's review of the detailed UT thickness readings and the GE stability analyses that considered (1) a uniform 0.736 inches thick sand bed region and (2) the effects of a local
 
thin area of 0.536 inches and 0.636 inches thickness concluded that in 1996 the condition
 
of the former sand bed region was adequate for its intended function in accordance with
 
its design basis.
However, because there has been no UT inspection conducted since 1996 and the remaining corrosion margin in 1996 was less than 0.1 inches at several locations, the staff
 
initiated further evaluation of the applicant's aging management commitment for UT
 
inspection of the former sand bed region.
The applicant credited its Protective Coating Monitoring and Maintenance Program to monitor/maintain the protective coating on the exterior surface of the drywell in the former
 
sand bed region. The staff evaluated this program in SER Section 3.0.3.1.8. The
 
applicant's revised aging management commitment (Commitment No. 27) is to complete a
 
100 percent inspection of the coating (initiated in 1994 and currently 50 percent complete)
 
prior to the license renewal period and to conduct subsequent 100 percent reinspections
 
every 10 years during the license renewal period.
Because of the minimal corrosion margin remaining in the former sand bed region and the applicant's reliance on the coating to mitigate additional corrosion the staff initiated further
 
review of the applicant's inspection program to ensure that the coating will continue to
 
perform its intended function for the extended period of operation.
Subsequent to the audit, in response to RAI 4.7.2-1, by letter dated June 20, 2006,  the applicant provided additional information regarding the AMP and activities associated with
 
drywell shell corrosion. The staff's evaluation of the applicant's additional information and
 
its commitments is documented in SER Section 4.7.2.  (4) Suppression Chamber (Torus). The applicant credited its Protective Coating Monitoring and Maintenance Program to monitor/maintain the protective coatings inside the
 
suppression chamber (torus) to mitigate corrosion. The staff's detailed evaluation of the
 
applicant's Protective Coating Monitoring and Maintenance Program is addressed in SER
 
Section 3.0.3.1.8.
The staff questioned the applicability and implementation of ASME Code Case N-597-1 for developing pit depth acceptance criteria for the torus. Based on the acceptance criteria
 
developed by the applicant, an isolated pit of 0.125 inches diameter on the inner surface is
 
considered acceptable if its depth does not exceed 0.261 inches. According to the
 
applicant, the torus as-built wall thickness is 0.385 inches. Therefore, a pit depth equal to
 
67 percent of the as-built thickness is considered acceptable if isolated. For a cluster of 3-134 pits within a 2.5 inches diameter circle the acceptable pit depth is 0.141 inches or 37 percent of the as-built thickness. The acceptable pit depth includes allowance for an
 
assumed 0.0009 inches per year corrosion rate over the 4-year period between inspections. RG 1.147 stipulates the following condition on the use of Code Case N-597-1:
 
"(5) For corrosion phenomena other than flow-accelerated corrosion, use of the Code
 
Case is subject to NRC review and approval. Inspection plans and wall thinning rates may
 
be difficult to justify for certain degradation mechanisms such as MIC and pitting." The applicant stated that the maximum pit depth measured in the torus is 0.0685 inches (measured in 1992 in Bay 2). It was evaluated as acceptable by the design calculations at
 
that time and was not based on calculation C-1302-187-E310-038. This bounding wall
 
thickness in the torus remains. The criterion developed in 2002 for local thickness
 
acceptance provides an easier method for evaluating as-found pits. The results were
 
shown to be conservative versus the original ASME Code Section III and VIII requirements
 
for the torus. The torus inspection program will be enhanced per IR 373695 to improve the
 
detail of the acceptance criteria and ma rgin management requirements by the ASME Code Section III criteria. The approach used in C-1302-187-E310-038 will be clarified as
 
to how it maintains the code requirements. If ASME Code Case N-597-1 is required to
 
develop these criteria for future inspections, staff review and approval will be obtained. It
 
should also be noted that the program has established corrosion rate criteria and
 
continues to monitor periodically to verify that they remain bounded.
The applicant's response clarified for the staff that pit depth acceptance criteria based on ASME Code Case N-597-1 had not been implemented and that if implementation should
 
be contemplated the applicant will seek staff review and approval. The staff finds this
 
clarification acceptable to resolve its concern about the use of ASME Code Case N-597-1.
From the applicant's response, the staff determined that there was minimal margin remaining between the current thickness and the minimum required thickness for the
 
torus. During a followup onsite audit April 19-20, 2006, the staff discussed with the
 
applicant the current condition of the torus, the pit depth acceptance criteria, and the
 
scope of the coating inspection conducted every 4 years.
The applicant explained that the average remaining thickness of the torus is essentially the as-built thickness (0.385 inches). Five isolated pits, ranging from 0.042 to 0.068 inches
 
in depth, are monitored and trended during each inspection. The applicant supplemented
 
its earlier response to document this explanation.
The applicant further explained that pit depth acceptance criteria based on ASME Code Case N-597-1 had never been used to for acceptability of observed pitting. The current
 
practice is to record and monitor all pits exceeding 0.040 inches in depth. The applicant
 
supplemented its earlier response to indicate that, "Pits greater than 0.040 inches in depth
 
shall be documented and submitted to engineering for evaluation."
In its letter dated May 1, 2006, the applicant supplemented its earlier response, committing (Commitment No. 27) to inspect the coating in all 20 bays of the suppression
 
chamber (torus) during the period of extended operation. The frequency of inspection will
 
be every other refueling outage for the current coating system. If the coating system is
 
replaced, the inspection frequency and scope will be re-evaluated. The inspection scope
 
will meet, as a minimum, the requirements of ASME Code Subsection IWE.
3-135 The applicant also committed (Commitment No. 27) to develop refined acceptance criteria and thresholds for entering coating defects and unacceptable pit depths into the corrective
 
action process for further evaluation. These improvements will be incorporated into the inspection implementing documents prior to the next inspections and prior to the period of
 
extended operation.
Based on the staff's understanding of (1) the current condition of the torus, (2) the applicant's plan to refine the pit depth acceptance criteria, and (3) the scope of the coating
 
inspection conducted every 4 years, the staff concludes that the applicant's AMP for the
 
suppression chamber (torus) provides reasonable assurance that the effects of aging will
 
be adequately managed during the period of extended operation.The staff reviewed those portions of the ASME Section XI, Subsection IWE Program forwhich the applicant claimed consistency with GALL AMP XI.S1 with the exception
 
described below. Based on its review, as discussed in SER Section 4.7.2, the staff
 
identified OIs 4.7.2-1.1, 4.7.2-1.2, 4.7.2-1.3, 4.7.2-1.4, and 4.7.2-3, pertaining to aging
 
management of primary containment (drywell shell).
Exception. In the LRA, the applicant stated an exception to the GALL Report recommendations in the "Program Description." Specifically, the exception stated:NUREG-1801 evaluation is based on ASME Section XI, 2001 Edition including2002 and 2003 Addenda. The current Oyster Creek ASME Section XI, Subsection
 
IWE program plan for the First Ten-Year inspection interval effective from
 
September 9, 1998 through September 9, 2008, approved per 10CFR50.55a, is based on ASME Section XI, 1992 Edition including 1992 addenda. The next
 
120-month inspection interval for Oyster Creek will incorporate the requirements
 
specified in the version of the ASME Code incorporated into 10 CFR 50.55a 12
 
months before the start of the inspection interval.The staff noted that the 1992 ASME Code Section XI, Subsection IWE, including 1992 addenda, was incorporated into 10 CFR 50.55a at the time the applicant was required to declare its
 
inspection basis for the current 10-year IWE inspection interval. The applicant will incorporate the
 
requirements specified in the ASME Code version incorporated into 10 CFR 50.55a 12 months
 
before the start of the next 120-month inspection interval. As this incorporation is consistent with
 
the recommendations in the GALL Report, the staff did not consider it an actual exception and
 
finds it acceptable.
Operating Experience. The applicant stated, in the LRA, that ASME Section XI, Subsection IWE as described in the First 10-Year Containment (IWE) Inservice Inspection Program Plan and
 
Basis is effective September 9, 1998, to Septem ber 9, 2008. Base line inspection of containment surfaces was completed in 2000 and a second inspection was completed in 2004. The 2004
 
inspection identified two recordable conditions, a loose locknut on a spare drywell penetration and
 
a weld rod stuck to the underside of the drywell head. Engineering evaluation concluded that the
 
stuck weld rod had no adverse impact on drywell head structural integrity and that the loose
 
locknut did not affect the seal of the containment penetration.
The applicant stated that the upper region of drywell shell has experienced loss of material due to corrosion from water leakage into the gap between the containment and the reactor building in the
 
1980s. As a result the area is subject to augment ed examinations by UT thickness measurements 3-136as required by ASME Code Section XI, Subsection IWE. UT measurements taken in 2004 showed that the drywell shell thickness meets ASME Code criteria and that the rate of corrosion
 
is declining. Engineering evaluation of the UT results also concluded that the containment drywell, considering the current corrosion rate, is capable of performing its intended function through the
 
period of extended operation. Further discussion is provided in LRA Section 4.7.2.
The applicant stated that the sand bed region also experienced loss of material due to corrosion attributed to the presence of oxygenated wet sand and exacerbated by the presence of chloride
 
and sulfate in the sand bed region. As a corrective measure, the sand was removed and a
 
protective coating was applied to the shell to mitigate further corrosion. Subsequent inspections
 
confirmed that corrosion of the shell had been arrested. The coating is monitored periodically
 
under the Protective Coating Monitoring and Maintenance Program. The staff evaluation of this
 
program is addressed in SER Section 3.0.3.1.8.
The applicant stated that the suppression chamber (t orus) and vent system were originally coated with Carboline Carbo-Zinc 11 paint. The coating is inspected every outage and repaired, as
 
required, to protect the torus shell and the vent system from corrosion.The applicant stated that from operating experience it had concluded that ASME Section XI, Subsection IWE is effective for managing aging effects of primary containment surfaces.
In PBD-AMP-B.1.27, the applicant expanded its discussion of operating experience to include industry operating experience and additional details of the plant-specific containment degradation.
 
The applicant stated that industry operating experience had confirmed that corrosion had
 
occurred in containment shells. INs 86-99, 88-82, and 89-79 described occurrences of corrosion
 
in steel containment shells. GL 87-05 addressed the potential for corrosion of BWR Mark I steel
 
drywells in the "sand pocket region." More recently, IN 97-10 identified specific locations where
 
concrete containments are susceptible to liner plate corrosion. Plant operating experience shows
 
that corrosion has occurred in several containment locations including the drywell shell in the
 
sand bed region, the drywell shell above the sand bed region, and the suppression chamber and
 
vent system. In all cases the ASME Section XI, Subsection IWE Program has identified andcorrected the degradation. Experience with the ASME Section XI, Subsection IWE Program
 
shows that it is effective in managing aging effects for the primary containment and its
 
components.
The applicant included the following discussion and three examples of operating experience asevidence that the ASME Section XI, Subsection IWE Program effectively assures that intended
 
functions will be maintained consistent with the CLB for the period of extended operation:The Oyster Creek ASME Section XI, Subsection IWE Program as described in Oyster Creek 10 Year Containment (IWE) Inservice Inspection Program Plan and
 
Basis is in effect from September 9,1998 to September 9, 2008. Base line
 
inspection of the drywell was completed during 2000, refueling outage. The
 
suppression chamber (torus) vapor region base line inspection was completed
 
during 2000, refueling outage. Although the Oyster Creek ASME Section XI, Subsection IWE Program implementation is recent, the potential for loss of material, due to corrosion, in
 
inaccessible areas of the containment drywell shell was first recognized in 1980
 
when water was discovered coming from the sand bed region drains. Corrosion 3-137 was later confirmed by ultrasonic thick ness (UT) measurements taken during the 1986 refueling outage. As a result, several corrective actions were initiated to
 
determine the extent of corrosion, evaluate the integrity of the drywell, mitigate
 
accelerated corrosion, and monitor the condition of containment surfaces. The
 
corrective actions include extensive UT measurements of the drywell shell thickness, removal of the sand in the sand bed region, cleaning and coating
 
exterior surfaces in areas where sand was removed, and an engineering
 
evaluation to confirm the drywell structural integrity. A corrosion monitoring
 
program was established, in 1987, for the drywell shell above the sand bed region
 
to ensure that the containment vessel is capable of performing its intended
 
functions. Elements of the program have been incorporated into the ASME Section XI, Subsection IWE and provide for (1) periodic UT inspections of the shell
 
thickness at critical locations, (2) calculations which establish conservative
 
corrosion rates, (3) projections of the shell thickness based on the conservative
 
corrosion rates, and (4) demonstration that the minimum required shell thickness is
 
in accordance with ASME Code.
Additionally, the NRC was notified of this potential generic issue that later became the subject of NRC Information Notice 86-99 and Generic Letter 87-05. A summary
 
of the operating experience, monitoring activities, and corrective actions taken to
 
ensure that the primary containment will perform its intended functions is
 
discussed below. 1.Drywell Shell in the Sand Bed Region:
The drywell shell is fabricated from ASTM A-212-61T Gr. B steel plate. The shell was coated on the inside surface with an inorganic zinc (Carboline
 
carbozinc 11) and on the outside surface with "Red Lead" primer identified
 
as TT-P-86C Type I. The red lead coating covered the entire exterior of the
 
vessel from elevation 8' 11.25" (Fill slab level) to elevation 94' (below
 
drywell flange). The sand bed region was filled with dry sand as specified
 
by ASTM 633. Leakage of water from the sand bed drains was observed
 
during the 1980 and 1983 refueling outages. A series of investigations were
 
performed to identify the source of the water and its leak path. The results
 
concluded that the source of water was from the reactor cavity, which is
 
flooded during refueling outages. As a result of the presence of water in the
 
sand bed region, extensive UT thickness measurements (about 1000) of
 
the drywell shell were taken to determine if degradation was occurring.
 
These measurements corresponded to known water leaks and indicated
 
that wall thinning had occurred in this region.
Because of reduced thickness readings, additional thickness
 
measurements were obtained to determine the vertical profile of the
 
thinning. A trench was excavated inside the drywell, in the concrete floor, in
 
the area where thinning at the floor level was most severe. Measurements
 
taken from the excavated trench indicated that thinning of the embedded
 
shell in concrete were no more severe than those taken at the floor level
 
and became less severe at the lower portions of the sand bed region.
 
Conversely, measurements taken in ar eas where thinning was not identified at the floor level showed no indication of significant thinning in the 3-138 embedded shell. Aside from UT thickness measurements performed by plant staff, independent analysis was performed by the EPRI NDE Center
 
and the GE Ultra Image III "C" scan topographical mapping system. The
 
independent tests confirmed the UT results. The GE Ultra Image results
 
were used as baseline profile to track continued corrosion.
To validate UT measurements and characterize the form of damage and its cause (i.e., due to the presence of contaminants, microbiological species, or both) core samples of the drywell shell were obtained at seven locations.
 
The core samples validated the UT measurements and confirmed that the
 
corrosion of the drywell is due to the presence of oxygenated wet sand and
 
exacerbated by the presence of chloride and sulfate in the sand bed region.
 
A contaminate concentrating mechanism due to alternate wetting and
 
drying of the sand may have also contributed to the corrosion phenomenon.
 
It was therefore concluded that the optimum method for mitigating the
 
corrosion is by (1) removal of the sand to break up the galvanic cell, (2)
 
removal of the corrosion product from the shell and (3) application of a
 
protective coating.
Removal of sand was initiated during 1988 by removing sheet metal from around the vent headers to provide access to the sand bed from the Torus
 
room. During operating cycle 13 some sand was removed and access
 
holes were cut into the sand bed region through the shield wall. The work
 
was finished in December 1992. After sand removal, the concrete surface
 
below the sand was found to be unfinished with improper provisions for
 
water drainage. Corrective actions taken in this region during 1992
 
included; (1) cleaning of loose rust from the drywell shell, followed by
 
application of epoxy coating and (2) removing the loose debris from the
 
concrete floor followed by rebuilding and reshaping the floor with epoxy to
 
allow drainage of any water that may leak into the region. UT
 
measurements taken from the outside after cleaning verified loss of
 
material projections that had been made based on measurements taken
 
from the inside of the drywell. There were, however, some areas thinner
 
than projected; but in all cases engineering analysis determined that the
 
drywell shell thickness satisfied ASME Code requirements.
The protective coating monitoring and maintenance program was revised to include monitoring of the coatings of exterior surfaces of the drywell in the
 
sand bed region. The coated surfaces of the former sand bed region were
 
subsequently inspected during refueling outages of 1994, 1996, 2000, and
 
2004. The inspections showed no coating failure or signs of deterioration.
 
The inspections provide objective evidence that the coating is in a good
 
condition and will provide adequate protection to the drywell shell in the
 
sand bed region. Evaluation of UT measurements taken from inside the
 
drywell, in the in the former sand bed region, in 1992, 1994, and 1996
 
confirmed that corrosion is mitigated. It is therefore concluded that
 
corrosion in the sand bed region has been arrested and no further loss of
 
material is expected. Monitoring of the coating in accordance with the
 
protective coating monitoring and maintenance program, will continue to 3-139 ensure that the containment drywell shell maintains its intended function during the period of extended operation. 2.Drywell Shell above Sand Bed Region:
The UT investigation phase (1986 through 1991) also identified loss of material, due to corrosion, in the upper regions of the drywell shell. These
 
regions were handled separately from the sand bed region because of the
 
significant difference in corrosion rate and physical difference in design.
 
Corrective action for these regions involved providing a corrosion allowance
 
by demonstrating, through analysis, that the original drywell design
 
pressure was conservative. Amendment 165 to the Oyster Creek Technical
 
Specifications reduced the drywell design pressure from 62 psig to 44 psig.
 
The new design pressure coupled with measures to prevent water intrusion
 
into the gap between the drywell shell and the concrete will allow the upper
 
portion of the drywell to meet ASME Code requirements.
Originally, the knowledge of the extent of corrosion was based on UT measurements going completely around the inside of the drywell at several
 
elevations. At each elevation, a belt-line sweep was used with readings
 
taken on as little as 1" centers wherever thickness changed between
 
successive nominal 6" centers. Six-by-six grids that exhibited the worst
 
metal loss around each elevation were established using this approach and
 
included in the Drywell Corrosion Inspection Program.
As experience increased with each data collection campaign, only grids showing evidence of a change were retained in the inspection program.
 
Additional assurance regarding the adequacy of this inspection plan was
 
obtained by a completely randomized inspection, involving 49 grids that
 
showed that all inspection locations satisfied ASME Code requirements.
 
Evaluation of UT measurements taken through 2000 concluded that
 
corrosion is no longer occurring at two (2) elevations, the 3rd elevation is
 
undergoing a corrosion rate of 0.6 mils/year, while the 4th elevations is
 
subject to 1.2 mils/year. The recent UT measurements (2004) confirmed
 
that the corrosion rate continues to decline. The two elevations that
 
previously exhibited no increase in corrosion continue the no corrosion
 
increase trend. The rate of corrosion for the 3rd elevation decreased from
 
0.6 mils/year to 0.4 mils/year. The rate of corrosion for the 4th elevation
 
decreased from 1.2 mils/year to 0.75 mils/year. After each UT examination campaign, an engineering analysis is performed to ensure the required
 
minimum thickness is provided through the period of extended operation.
 
Thus corrosion of the drywell shell is considered a TLAA further described
 
in Section 4.7.2. 3.Suppression Chamber (Torus) and Vent System The Oyster Creek suppression chamber (torus) and vent system were originally coated with Carboline Carbo-Zinc 11 paint. The coating is
 
inspected periodically and repaired to protect the Torus shell and the vent
 
system in accordance with specification SP-1302-52-120. As a result wall 3-140 thinning of the torus shell and the vent system has not been an issue. A review of past inspections of the torus shell and the vent system indicates
 
the majority of the problems found have been attributed to blistering of
 
coating in small areas, localized pitting. In 1983, pitted surfaces of the
 
immersed torus shell were repair by welding. The torus shell, the interior of
 
downcomers, and the entire interior surfaces of the vent system were
 
recoated with Mobil 78-Hi Build Epoxy.
Inspection performed in 2002 found the coating to be in good condition in the vapor area of the torus and vent header, and in fair condition in
 
immersion. Coating deficiencies in immersion include blistering, random
 
and mechanical damage. Blistering occurs primarily in the shell invert but
 
was also noted on the upper shell near the water line. The fractured blisters
 
were repaired to reestablish the protective coating barrier. This is another example of objective evidence that the Oyster Creek ASME Section XI, Subsection IWE Program can identify degradation and implement
 
corrective actions to prevent the loss of the containment's intended
 
function.While blistering is considered a deficiency, it is significant only when it is fractured and exposes the base metal to corrosion attack. The majority of
 
the blisters remain intact and continues to protect the base metal;
 
consequently the corrosion rates are low. Qualitative assessment of the
 
identified pits indicate that the measured pit depths (50 mils max) are
 
significantly less than the criteria established in Specification
 
SP-1302-52-120 (141- 261 mils, depending on diameter of the pit and
 
spacing between pits).
In PBD-AMP-B.1.27, the applicant concluded that the operating experience of the ASMESection XI, Subsection IWE Program shows no adv erse trend in performance. Problems identified will not cause significant impact to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. The implementation of the ASME Section XI, Subsection IWE
 
Program will effectively identify containment aging effects prior to the loss of the containment
 
function. Appropriate guidance for evaluation, repair, or replacement is provided for locations
 
susceptible to degradation. Periodic self-assessments of the program identify areas that need
 
improvement to maintain performance of the program.
The staff reviewed the operating experience provided in the LRA and PBD and interviewed the applicant's technical personnel. The staff concludes that the OCGS plant-specific operating
 
experience is unique and not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that pending resolution of OIs 4.7.2-1.1, 4.7.2-1.2, 4.7.2-1.3, 4.7.2-1.4, and 4.7.2-3, the applicant's ASME Section XI, Subsection IWE Program will adequately manage the aging effects identified in the LRA and
 
PBD-AMP-B.1.27 for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.27 and letters dated April 4, May 1, and June 23, 2006,the applicant provided the UFSAR supplement for the ASME Section XI, Subsection IWE
 
Program. The staff determined that the information in the UFSAR supplement must be revised to 3-141 reflect the resolution of OIs 4.7.2-1.1, 4.7.2-1.2, 4.7.2-1.3, 4.7.2-1.4, and 4.7.2-3 to provide an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review, as discussed above, the staff concludes, contingent upon resolution of OIs 4.7.2-1.1, 4.7.2-1.2, 4.7.2-1.3, 4.7.2-1.4, and 4.7.2-3, that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that intended function(s)
 
will be maintained 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 found that this information must be
 
revised to reflect the resolution of the OIs, to provide an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).3.0.3.2.23  ASME Section XI, Subsection IWF
 
Summary of Technical Information in the Application. In LRA Section B.1.28, the applicantdescribed the existing ASME Section XI, Subsection IWF Program as consistent, with an exception and enhancements, with GALL AMP XI.S3, "ASME Section XI, Subsection IWF." The ASME Section XI, Subsection IWF Program consis ts of periodic visual examination of ASMESection XI Class 1, 2, 3 and MC components and piping support members for loss of mechanical
 
function and material. Bolting, included with these components, is inspected for loss of material
 
and for loss of preload from missing, detached, or loosened bolts. Procurement controls and
 
installation practices, defined in plant procedures, apply only approved lubricants and torques.
 
The program is implemented through corporate and station procedures for inspection and acceptance criteria consistent with the requirements of ASME Code Section XI, 1995 Edition with
 
1996 Addenda.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.23. The staff reviewed the exception
 
and enhancements and their justifications to determine whether the AMP, with the exception and
 
enhancements, remained adequate to manage the aging effects for which it is credited.The staff reviewed those portions of the ASME Section XI, Subsection IWF Program for which theapplicant claimed consistency with GALL AMP XI.M6 and found them consistent. Furthermore, the staff concluded that the applicant's ASME Section XI, Subsection IWF Program provides
 
reasonable assurance that the aging effects and mechanisms from such conditions as general
 
corrosion and wear of carbon steel components and piping supports will be properly managed for the period of extended operation. The staff found that the applicant's ASME Section XI, Subsection IWF Program conforms to the recommended GALL AMP XI.S3, with an exception and
 
enhancements described below.
Exception. In the LRA, the applicant stated an exception to the GALL Report program description.
Specifically, the exception stated:
NUREG-1801 evaluation covers the 2001 edition including the 2002 and 2003 Addenda, as approved in 10 CFR 50.55a. The current Oyster Creek ISI Program
 
Plan for the fourth ten-year inspection interval effective from October 15, 2002
 
through October 14, 2012, approved per 10CFR50.55a, is based on the 1995 ASME Section XI B&PV Code, including 1996 addenda. The next 120-month
 
inspection interval for Oyster Creek will incorporate the requirements specified in 3-142 the version of the ASME Code incorporated into 10 CFR 50.55a twelve months before the start of the inspection interval.The staff noted that the 1995 ASME Code Section XI, including 1996 addenda, was the edition incorporated into 10 CFR 50.55a at the time the applicant was required to declare its inspection
 
basis for the current 10-year IWE inspection interval. The applicant will incorporate the
 
requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a twelve
 
months before the start of the next 120-month in spection interval. As this incorporation is consistent with the intent of the GALL Report guidance, the staff did not consider it an actual
 
exception to the GALL Report and found it acceptable.
Enhancement 1. In the LRA, the applicant stated an enhancement in meeting the GALL Report program element "scope of program."
Specifically, the enhancement stated:
Enhancement activities, which are in addition to the existing Oyster Creek ASMESection XI, Subsection IWF program, consist of including additional MC supports
 
inside the Torus, Torus Support - Base Plate and Saddle, Inner Support Column &
 
Outer Support Column) and inspection of underwater MC supports for loss of
 
material due to corrosion and loss of mechanical function (Torus Internal -
 
Downcomer Brace Support (underwater), Vent Header Ring Header Support (above water), Vent System Inner Support Column (above and below water) and
 
Vent System Outer Support Column (above and below water)). Enhancements will
 
be implemented prior to entering the period of extended operation.
During the audit, the staff asked the applicant for clarifications about this enhancement tounderstand better what MC supports are in the ASME Section XI, Subsection IWF Program and
 
will be added to the program and also to confirm that all MC supports under IWF are included in
 
the program. In its response, the applicant stated that:  (1)The MC supports included in the existing IWF inspection program are:
* Existing containment program - IWE (above water line - internal)
* E1.20 downcomers
* E1.20 ring header within torus
* E1.20 vent lines - DW to torus vent lines
* Existing torus exterior - IWF MC supports
* F1.40 torus support - sway braces  (2)The MC supports that will be added to the scope of the IWF inspection program for the license renewal period are:
* torus (internal) - IWF MC supports
* torus support - base plate and saddle
* torus support - inner support column
* torus support - outer support column
* torus internal - downcomer brace support (underwater)
* vent header ring header support (above water)
* vent system inner support column (above and below water)
* vent system outer support column (above and below water) 3-143 OC-1 ISI Program Plan Section 4.0 Component Support ISI Plan contains the current inspection details for MC supports. Additional work will be done with the components
 
identified in (2) to confirm the current inspection practice. All MC supports will be included.  (3)The specific underwater supports that will be added to the scope of the IWF inspection program for the license renewal period are:
* downcomer brace supports (underwater)
* vent system inner support column (above and below water)
* vent system outer support column (above and below water)
The current inspection program and inspection details for the underwater supports identified in (3) are not formalized. OCGS does perform underwater inspections of the
 
torus for removal of sludge or debris (FME), inspect suction strainers for damage or
 
obstruction, improve water clarity, assess coating and reestablish the coating barrier in
 
deficient area. The applicant stated that implementing procedures for the ASME Section XI, Subsection IWF Program for all underwater MC supports will be complete before the period of extended operation.
 
The staff concludes that the applicant's response sufficiently defined the enhanced scope for
 
inspection of MC supports.The staff finds this enhancement acceptable because when implemented the ASME Section XI, Subsection IWF Program will be consistent with GALL AMP XI.S3 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.28, the applicant explained that the operatingexperience of the ISI programs, which include ASME Section XI, Subsection IWF Program
 
activities, shows no adverse trend of program per formance. Periodic self-assessments of the ISI programs have been performed to identify areas that need improvement to maintain program quality.There is sufficient confidence that the Component Support ISI Program Plan, as described in the ISI Program, will effectively monitor the condition of the component supports within the scope of
 
license renewal so that their design function will be maintained during the extended license
 
period. The applicant submitted data reports for inservice inspections covering the OCGS
 
refueling outage 20 (1R20) examinations between October 28, 2002 and November 22, 2004.
 
The reports include the first period of the fourth IS I interval examinations performed in accordance with the ASME Code. There were challenges during this inspection. Scope expansion was
 
required due to unacceptable conditions on rod hangers evaluated or repaired, as required, and
 
determined acceptable for return to service.
The staff reviewed several corrective action processes and noted problems with supports in the core spray system dating back to 2000. The staff asked the applicant for information on corrective
 
actions taken to prevent recurrence. In its response, the applicant stated that the core spray
 
system had a long history of hydraulic transient s, which over the years caused support damage of various degrees. Some of the corrective actions taken which mitigated these concerns are:
* Installation of a keep full system.
3-144
* Installation of frequency controllers on the test valves V-20-26 and V-20-27, which slow down the opening stroke.
* Modification of the pump recirculation piping to provide a continuous venting path and minimize the risk of piping voiding.
* Implementation of a weekly PM to verify that the system is filled and vented.
* Modification of the counter weight assisted check valves (i.e., V-20-51 and V-20-52) to minimize the risk of their sticking open. They were converted to regular swing check
 
valves after malfunctioning of V-20-51 was determined to be the root cause for some
 
water hammer transients experienced in Core Spray System 2.
The applicant stated that all the deficient supports found during 1R20 (2004) are scheduled for re-inspection during 1R21 (2006).
The staff concludes that the applicant's course of action for these 2 occurrences providesreasonable confirmation that its ASME Section XI, Subsection IWF Program is effective.
The staff reviewed the operating experience provided in the LRA and PBD and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's ASME Section XI, Subsection IWF Program will adequately manage the aging effects identified in the LRA for which
 
this AMP is credited.
UFSAR Supplement. In LRA Section A.1.28, the applicant provided the UFSAR supplement forthe ASME Section XI, Subsection IWF Program. The staff reviewed this section and determined
 
that the information in the UFSAR supplement provides an adequate summary description of the
 
program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's ASME Section XI, Subsection IWF Program, the staff determined that those program elements for which the applicant claimed
 
consistency with the GALL Report are consistent. In addition, the staff reviewed the exception and
 
its justifications and determined that the AMP, with the exception, is adequate to manage the
 
aging effects for which it is credited. Also, the staff reviewed the enhancements and confirmed
 
that their implementation prior to the period of extended operation will make the 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).
3.0.3.2.24  Structures Monitoring Program
 
Summary of Technical Information in the Application. In LRA Section B.1.31, the applicant described the existing Structures Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." The applicant revised the scope of the
 
Structures Monitoring Program in letters dated October 12, 2005, and December 9, 2005, to 3-145 include components within the scope of license renewal from the Station Blackout System Forked River Combustion Turbine Power Plant and the Meteorological Tower (Met Tower), respectively.
The Structures Monitoring Program was dev eloped to implement the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power
 
Plants." The program relies on periodic visual inspections to monitor the condition of structures
 
and structural components. Specifically, concrete structures are inspected for loss of material, cracking, and change in material properties. Steel components are inspected for loss of material
 
due to corrosion. Masonry walls are inspected for cracking, and elastomers are monitored for
 
change in material properties. Earthen water-control structures and the fire pond dam are
 
inspected for loss of material and loss of form. Component supports are inspected for loss of
 
material, reduction or loss of isolation function, and reduction in anchor capacity due to local
 
concrete degradation. Exposed surfaces of bolting are monitored for loss of material due to
 
corrosion, loose nuts, missing bolts, or other loss of preload. The program relies on procurement
 
controls and installation practices, defined in plant procedures, to ensure that only approved
 
lubricants and proper torques are applied consistent with the GALL Report bolting integrity
 
program. The scope of the program will be enhanced to include structures not currently monitored but requiring monitoring during the period of extended operation. Details of the enhancements are
 
that inspection frequency is every 4 years except for submerged portions of water-control
 
structures, which will be inspected when the structures are dewatered or on a frequency not to
 
exceed 10 years. The program provides for more frequent inspections to ensure that observed
 
conditions with potential impact on an intended function are evaluated or corrected in accordance
 
with the corrective action process.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.24. The staff noted that the applicant
 
did not identify any exceptions in the LRA. However, in its PBD the applicant identified an
 
exception to the GALL Report program element "detection of aging effects." The staff's review of
 
this exception is discussed below.
The staff reviewed those portions of the Structures Monitoring Program for which the applicantclaimed consistency with GALL AMP XI.S6 and found them consistent. Furthermore, the staff
 
concluded that the applicant's Structures Monitoring Program provides reasonable assurance that
 
the aging of structures within the scope of the program will be properly managed for the period of
 
extended operation. The staff found that the applicant's Structures Monitoring Program conforms to the recommended GALL AMP XI.S6 with an exception and enhancements described below.
Exception. In the LRA, the applicant did not identify exceptions to AMP XI.S6 in the GALL Report.
However, in its PBD for this AMP (PBD-AMP B.1.31), the applicant identified an exception to the
 
GALL Report program element "detection of aging e ffects" not in the LRA. Specifically, the exception stated:
The program takes exception to the inspection frequency of at least once perrefueling cycle specified in NUREG-1801, XI.M36, "External Surfaces Monitoring,"
 
Rev. 1, for monitoring external surfaces of mechanical components. The specified
 
frequency by the Oyster Creek (structures monitoring) program is every 4 years.
3-146 In its letter dated March 30, 2006, the applicant stated that it will revise the LRA to add the exception identified in its PBD for the Structures Monitoring Program, stating that the program
 
takes exception to the inspection frequency of at least once per refueling cycle specified in GALL AMP XI.M36, "External Surfaces Monitoring," Revision 1, for monitoring external surfaces of
 
mechanical components. The frequency specified by t he Structures Monitoring Program is every 4 years.The applicant provided in the PBD the following technical justifications for this exception:
The frequency of 4 years specified for monitoring of exterior surfaces of mechanical components is consistent with the frequency specified for exterior
 
surfaces of supporting structures. The 4-year frequency is consistent with industry
 
guidelines and has proven effective in detecting loss of material due to corrosion, and change in material properties of structural elastomer on exterior surfaces of
 
structures. Consequently this frequency will also be effective for detecting loss of
 
material and change in material properties on exterior surfaces of mechanical
 
components before an intended function is impacted.
Industry and plant-specific operating experience review has not identified any instances of significant loss of material or change in material properties of external
 
surfaces of mechanical components subject to indoor air environment.
Mechanical components subject to outdoor air are constructed from stainless steel, aluminum, which are not susceptible to accelerated corrosion, or carbon steel
 
components protected by protective coatings such as galvanizing, or painting.
 
Plant operating experience indicates that monitoring of exterior surfaces of
 
components made of these materials and protective coatings on a frequency of 4
 
years provides reasonable assurance that loss of material will be detected before
 
an intended function is affected.
Studies by EPRI provide a corrosion rate curve for carbon steels. This curve was constructed from 55 individual tests representing at least five different steels and
 
six different test locations and environm ents. The curve shows 0.926 mils per year thickness loss during the first 1 1/2 years, decreasing to 0.21 mils per year after 15
 
1/2 years. EPRI also conducted corrosion tests of ASTM A-36 structural steel at four
 
nuclear plants located in Elma and Richland, Washington; and Midland, Michigan.
 
The tests were conducted for up to 24 months. EPRI concluded that based on the
 
test results the corrosion rate is 0.5 mils per year. If the corrosion rate is
 
conservatively taken as 0.926 mils per year, then the loss of material projected for
 
4 years is less than 4 mils. This loss of material is insignificant and will not impact
 
the intended function of mechanical components.
On the basis that monitoring the external surfaces of mechanical components on a 4-year frequency is adequate to ensure their structural integrity, the staff determined that this exception
 
is acceptable.
Enhancement 1. In PBD-AMP-B.1.31 for the Structures Monitoring Program, the applicant stated an enhancement to the GALL Report element "sc ope of program." Specifically, the enhancement stated:
3-147 The following structures and components will be added to the scope of the program.
* Chlorination facility, Exhaust Tunnel, Heating Boiler house, Oyster Creek Substation, Fire Pond Dam, and Miscellaneous Yard Structures
* Panels and enclosures
* Exposed surfaces of concrete anchors and embedments.
* Penetration seals other than fire seals. Fire seals are included with fire protection activities
* Doors other than fire rated doors. Fire rated doors are included with fire protection activities.
* Structural seals (secondary containment, and flood barriers)
* Components 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.
* Concrete surfaces exposed to salt water and fire pond water (RG Guides 1.127).
* Miscellaneous steel
* Foundation and anchorage of equipment, tanks, panels and enclosures.
* Duct banks, and manholes
* Offsite power transmission tower
* Submerged steel and wooden components at the Intake Structure and Canal, Dilution Structure, and Fire Pond Dam.
* Liner for containment drywell and reactor building sumps
* Steel and wooden bulkheads The scope of the program will also be enhanced to include inspection of exterior surfaces of Oyster Creek and Forked River Combustion Turbines (FRCT)
 
mechanical components that are not covered by other programs, including exterior
 
surfaces of HVAC ducts, damper housings and duct closure bolting within the
 
scope of license renewal. Components that will be added to scope of the program
 
include piping components, valves, tanks, vessels, etc. located in indoor or outdoor
 
air environments. The scope of the progr am is limited to components whose exterior surfaces are not monitored by other programs such as ASME Section XI, ISI Programs and fire protection activities.
The program will also be enhanced to require periodic sampling of ground water to confirm that the environment is non-aggressive for buried reinforced concrete
 
during the period of extended operation.
The scope of the program will be enhanced to include Station Blackout System (FRCT) structures, structural components, and phase bus enclosure assemblies.
 
Inspection frequency, inspection methods, and acceptance criteria will be the same
 
as those specified for other structures in scope of the program.
Concrete foundations for Station Blackout System (FRCT) structures will be inspected for cracking and distortion due to increased stress level from settlement
 
that may result from degradation of the inaccessible wooden piles.
3-148 The program will be enhanced to include Inspection of Meteorological Tower Structures. Inspection and acceptance criteria will be the same as those specified
 
for other structures in the scope of the program.
The program will be enhanced to include inspection of exterior surfaces of piping and piping components associated with the Radio Communications system, located at the meteorological tower site, for loss of material due to corrosion.
 
Inspection and acceptance criteria will be the same as those specified for other
 
external surfaces of mechanical components.
In PBD-AMP.B.1.31, the applicant provided the following basis for these enhancements:
GALL specifies that the applicant defines the scope of this AMP for license renewal. The current OCGS structures monitoring program was developed and
 
implemented to meet the regulatory requirements of 10 CFR 50.65, Maintenance
 
Rule, USNRC Regulatory Guide 1.160, 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 program elements also incorporate the recommendations of NRC
 
Regulatory Guide 1.127, "Inspection of Water-Control Structures Associated with
 
Nuclear Power Plants."
The program is implemented through a station procedure, which identifies the structures and structural components within the scope of the Maintenance Rule;
 
however, some of the structures in the scope of License Renewal are not covered
 
by the scope of the Maintenance Rule. Thus, the scope of the program was
 
enhanced to include additional structures and structural components that are in
 
scope of license renewal. In some cases the added structure or component is
 
included in the existing inspections; however there are no procedural requirements
 
to perform the inspection for the particular structure or component. In this case the
 
enhancement consists of revising procedures to specifically address the structure
 
or component.
The staff reviewed the enhancements to the program element "scope of program" and the applicant's basis and determined that, with these enhancements, the applicant's Structures
 
Monitoring Program is consistent with the GALL Report.
Enhancement 2. In PBD-AMP-B.1.31 for the structures monitoring program, the applicant stated an enhancement to the GALL Report element "paramet ers monitored or inspected." Specifically, the enhancement stated:
The existing Oyster Creek Structures M onitoring Program implementing procedure will be revised to include the following enhancements:
* For concrete structures, the program will be enhanced to require visual inspection for change in material properties due to leaching of calcium
 
hydroxide and aggressive chemical attack. The visual inspection consists of
 
observing concrete surfaces for significant leaching or disintegration.
3-149
* Concrete structures will also be observed for a reduction in anchor capacity due to local concrete degradation. This will be accomplished by visual
 
inspection of concrete surfaces around anchors for cracking, and spalling.
* The program will be enhanced to add loss of material due to corrosion for structural steel members and other steel components, such as
 
embedments, panels and enclosures, doors, siding, metal deck, structural
 
bolting, anchors, and miscellaneous steel.
* The program will be enhanced to require inspection of penetration seals and structural seals, for change in material properties by inspecting the
 
seals for cracking and hardening.
* The program will be enhanced to require monitoring of vibration isolators,associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of isolation function by inspecting the
 
isolators for cracking and hardening.
* The program will be enhanced to require visual inspection of external surfaces of mechanical steel components that are not covered by other
 
programs for loss of material due to corrosion, and change material
 
properties, due to leaching of calcium hydroxide and aggressive chemical
 
attack for reinforced concrete. Accessible wooden piles and sheeting will be
 
inspected for loss of material and change in material properties. Concrete
 
foundations for Station Blackout System structures will be inspected for
 
cracking and distortion due to increased stress level from settlement that
 
may result from degradation of the inaccessible wooden piles. Mechanical
 
elastomers, such as hoses, will be inspected for a change in material
 
properties by observing the elastomer for cracking and hardening. These
 
enhanced requirements are applicable to both Oyster Creek and FRCT
 
mechanical components.
* Groundwater will be monitored for pH, chlorides, and sulfates.
* The program will be enhanced to require visual inspection of external surfaces of mechanical steel components that are not covered by other
 
programs for leakage from or onto external surfaces, worn, flaking, or
 
oxide-coated surfaces, corrosion stains on thermal insulation, and
 
protective coating degradation (cracking and flaking). These enhanced
 
requirements are applicable to both Oyster Creek and FRCT mechanical
 
components. Note: This is new commitment based on the reconciliation of
 
this aging management program from draft January 2005 NUREG-1801, Rev. 1 to the approved September 2005 NUREG-1801, Rev. 1.
* The program will be enhanced to require removal of piping and component insulation to permit visual inspection of insulated surfaces. Removal of
 
insulation will be on a sampling basis that bounds insulation material type, susceptibility of insulated piping or component material to potential
 
degradations that could result from being in contact with insulation, and
 
system operating temperature. These enhanced requirements are
 
applicable to both Oyster Creek and FRCT mechanical components.
* The program will be enhanced to require inspection of exterior surfaces of HVAC ducts, damper housings, for loss of material and HVAC closure 3-150 bolting for loss of material and loose or missing bolts nuts. These enhanced requirements are applicable to both Oyster Creek and FRCT components.
In its letter dated March 30, 2006, the applicant committed (Commitment No. 31) to enhance the Structures Monitoring Program to require visual inspection of external surfaces of mechanical
 
steel components not covered by other programs for leakage from or onto external surfaces, worn, flaking, or oxide-coated surfaces, corrosion stains on thermal insulation, and protective
 
coating degradation (cracking and flaking).
As justification for the adequacy of the enhancements to this program element the applicant stated: For each structure and aging effect combination, the specific parameters monitored or inspected are selected to ensure that aging degradation leading to
 
loss of intended functions will be detected and the extent of degradation can be
 
determined. Parameters monitored or inspected are based on aging effects
 
identified for Oyster Creek material and environment combinations documented in
 
PP-15, Standard Materials, Environments and Aging Effects. Where required, the
 
existing aging management activities are enhanced to ensure that parameters
 
monitored will detect degradations that could lead to a loss of an intended function.
Parameters monitored under the existing program include the following:
* Reinforced concrete structures are monitored for loss of material, and cracking. The aging effects are monitored by inspecting concrete surfaces
 
for spalling, scaling, rebar corrosion, rust stain, water stains, water
 
intrusion, rebar exposure, disintegration, and cracking
* Structural steel members and connections are monitored for loose or missing bolts, which are considered loss of preload, cracked welds, and
 
loose or distorted structural members.
* Masonry block walls are monitored for cracks, and loose blocks
* The intake canal slopes and embankments are monitored for loss of form by inspecting for cracks, sink holes, and embankment collapse.
Program enhancements required to ensure t hat parameters monitored will detect degradations that could lead to a loss of an intended function are summarized
 
below. In some cases the enhancement is included as part of existing activities.
 
However, there are no procedural requirements or commitment to perform the
 
activity. For these cases, the enhancement consists of revising the program
 
implementing procedure to proceduralize the performed inspections.
Parameters monitored or inspected are developed to implement the requirements of 10 CFR 50.65, "Maintenance Rule," USNRC Regulatory Guide 1.160, IEB
 
80-11, and RG. 1.127 for water control structures. The parameters monitored or
 
inspected are based on industry standards, including ACI 349.3R-96, "Evaluation
 
of Existing Nuclear Safety-Related Concrete Structures," NEI 96-03, "Guideline for
 
Monitoring the Condition of Structures at Nuclear power Plants," NUMARC 93-01, 3-151"Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and NUREG-1522, "Assessment of Inservice Conditions of
 
Safety-Related Nuclear Plant Structures."
Concrete parameters monitored or inspected are based on ACI 349.3R-96.
Structural steel and steel liner inspection parameters are based on design codes
 
and standards including American Institute of Steel Construction (AISC).
 
ANSI/ASCE 11-90 is not specifically referenced in program implementing documents, however its elements ar e incorporated in the program.
Oyster Creek structures are founded on highly dense soil and settlement is not a concern. Observed total settlements of the reactor building foundation have ranged
 
from 2/3 to 3/4 inches , which compares well with the predicted settlement of less
 
that one inch. Thus a settlement monitoring is not required; nor is a de-watering
 
system relied upon to control settlement. Porous concrete is not incorporated into
 
the design of Oyster Creek sub-foundation.
The enhanced Oyster Creek Structures Monitoring Program contains sufficient detail on parameters monitored or inspected to conclude with reasonable assurance that NUREG-1801 XI.S6, "Structures Monitoring Program," and XI.M36, "External Surfaces Monitoring Program," attributes are satisfied
.The staff reviewed the enhancements to the pr ogram element "parameters monitored or inspected" and the applicant's justification and determined that, with these enhancements, the
 
applicant's Structures Monitoring Program is consistent with the GALL Report.
Enhancement 3. In PBD-AMP-B.1.31 for the Structures Monitoring Program, the applicant stated an enhancement to the GALL Report program element "detection of aging effects." Specifically, the enhancement stated:
The program will be enhanced to require inspection of submerged water-control structures when dewatered, or on a frequency not to exceed 10 years.
The staff noted that the 10-year inspection frequency for submerged portions of water-control structures was not consistent with a new commitment identified in PBD-AMP-B.1.32 for RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, which
 
states that a baseline inspection of submerged water control structures should be performed prior
 
to period of extended operation, a second inspection 6 years after this baseline inspection, and a
 
third 8 years after the second. After each inspection an evaluation should determine whether the
 
identified degradations warrant more frequent inspections or corrective actions. The applicant was
 
asked to explain why the Structures Monitoring Program was not consistent with the new
 
RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, commitment. In its response to the staff's inquiry the applicant stated that both PBD-AMP-B.1.31, and the LRA will be revised to add an enhancement to the Structures Monitoring Program to
 
include an inspection frequency for submerged water-control structures consistent with the
 
enhancement described in PBD-AMP-B.1.32, Section 2.4, "Summary of Enhancements."
In its letter dated April 17, 2006, the applicant committed (Commitment No. 31) to revise the Structures Monitoring Program in the LRA to include an inspection frequency for submerged 3-152 portions of water control structures consistent with the new commitment in PBD-AMP-B.1.32 for RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program.
The staff's evaluation of RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, is documented in SER Section 3.0.3.2.25. The staff finds this
 
enhancement acceptable because the applicant's baseline inspection schedule and its
 
commitment to evaluate the identified degradations provides assurance that the effects of aging
 
will be adequately managed for the period of extended operation.
The staff reviewed the revised enhancement to the program element "detection of aging effects" and determined that, with this enhancement, the applicant's Structures Monitoring Program is
 
consistent with the GALL Report.
Enhancement 4. In PBD-AMP-B.1.31 for the Structures Monitoring Program, the applicant stated an enhancement to the GALL Report program element "acceptance criteria." Specifically, the enhancement stated:
The existing Oyster Creek Structures M onitoring Program implementing procedure will be revised to require that qualified individuals evaluate identified degradations
 
on external surfaces of mechanical components. Acceptance criteria will be
 
consistent with industry standards, design codes and guidelines, including ANSI or
 
ASME as applicable. This is applicable to Oyster Creek and FRCT exterior
 
surfaces of mechanical components.
Acceptance criteria to establish if groundwater is aggressive for concrete structures (pH <5.5, or chlorides > 500 ppm, or sulfates > 1500 ppm) will be
 
consistent with industry standards, and NUREG-1801.
The applicant provided the following basis for the enhancements:
Inspection results are evaluated by qualified engineers based on acceptance criteria selected for each structure/aging effect to ensure that the need for
 
corrective actions will be identified before loss of intended functions.
Identified degradation are evaluated by qualified individuals based on industry codes, standards, and guidelines including ACI 318, ACI 349.3R, American
 
Institute of Steel Construction (AISC). Development of acceptance criteria
 
considers industry and plant specific operating experience. These criteria are
 
directed at identification and evaluation of degradations that may affect the ability
 
of the structure or component to perform its intended function.
ACI 349.3R-96 was used to develop acceptance criteria for concrete structural elements.The enhanced Oyster Creek Structures Monitoring Program requires that identified degradations be assessed and evaluated by qualified engineering personnel, considering the extent of the degradation using design basis codes and standards
 
that include ACI 318, ACI 349.3R, AISC, and ASME/ANSI. The program
 
implementing procedure provides sufficient details on acceptance criteria for
 
structures and exterior surfaces of mechanical components to ensure that 3-153 significant degradations are identified and corrected before a loss of an intended function.The staff reviewed the enhancements and its basis and determined that, with these enhancements, the applicant's Structures Monitoring Program is consistent with the GALL Report.
 
On that basis the enhancements are acceptable.
Operating Experience. In LRA Section B.1.31, the applicant explained that program documentation and other plant operating exper ience before the program was implemented identified cracking of reinforced exterior walls of the reactor building, drywell shield wall above
 
elevation 95', and the spent fuel pool support beam. Cracking of the reactor building exterior walls
 
was generally minor and attributed to early concrete shrinkage and temperature changes.
 
Engineering evaluation concluded that the structural integrity of the walls was unaffected by the
 
cracks. Repairs to areas of concern were made to prevent water intrusion and corrosion of
 
concrete rebar. The cracks and repaired areas are monitored under the program to detect any
 
changes that will require further evaluation and corrective action.
Cracking of the drywell shield wall was attributed to high temperature in the upper elevation of the containment drywell. Engineering analysis concluded that stresses are well below allowable limits, considering the existing cracked condition. Recent inspections identified no significant change in
 
the cracked area.
Cracking of the spent fuel storage pool concrete support beams was identified in mid-1980.
Subsequently, crack monitors were installed to monitor crack growth and an engineering
 
evaluation was performed. Based on the evaluation results and additional NDE to determine the
 
depth of the cracks, the applicant concluded that the beams will perform their intended function
 
and that continued crack monitoring is not required.
Inspection of the intake canal in 2001 identified cracks and fissures, voids, holes, and localized washout of coatings that protect embankment slopes from erosion. The degradations were
 
evaluated and determined not to impact the intended function of the intake canal (UHS). However
 
the inspector recommended repair of the degradations to prevent further deterioration. A project
 
to repair the canal banks has been initiated.
Inspections conducted in 2002 concluded that degradations have not become worse and remain essentially the same as those identified in previous inspections. In addition minor cracking, rust
 
stains, water stains, localized exposed rebars and rebar corrosion, and damage to siding were
 
observed, evaluated, and determined to have no impact on structural integrity. In operating
 
experience the program is effective for m anaging aging effects of structures, structural components, and water-control structures.
The staff noted that the applicant's discussion of operating experience identified three conditions of concrete degradation: cracking of the reactor building walls, cracking of the drywell shield wall
 
due to high temperature, and cracking of the spent fuel storage pool concrete support beams. A
 
fourth condition, degradation of the intake canal, is also addressed in LRA Section B.1.32 in the
 
operating experience discussion for water-control structures. For each of the first three conditions
 
of concrete degradation the staff asked the applicant for additional information describing the
 
degradation, the assessment performed, the acceptance criteria applied, future monitoring
 
recommendations, and any corrective action taken. The staff also requested that the applicant
 
describe the monitoring activities that are or will be conducted under the Structures Monitoring 3-154 Program for each of the three regions. In response, the applicant indicated that the requested information is included in the Structures Moni toring Program basis document (PBD-AMP-B.1.31) notebook, which was available for the staff's review during the second AMP audit. The staff
 
reviewed this information and conducted additional reviews of these conditions as part of the
 
AMR audit. See SER Section 3.5.2 for documentation of the staff's review and assessment.
The staff reviewed the operating experience provided in the LRA and PBD-AMP-B.1.31, and interviewed the applicant's technical personnel to confirm that the plant-specific operating
 
experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Structures Monitoring
 
Program will adequately manage the aging effects identified in the LRA for which this AMP is
 
credited.UFSAR Supplement. In LRA Section A.1.31 and letters dated March 30, and April 17, 2006, the applicant provided the UFSAR supplement for the Structures Monitoring Program. The staff
 
determined that the information in the UFSAR supplement provides an adequate summary
 
description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring Program, the staff determined that those program elements for which the applicant claimed consistency
 
with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed
 
that their implementation prior to the period of extended operation will make the 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 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 concluded
 
that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).
3.0.3.2.25  RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Summary of Technical Information in the Application. In LRA Section B.1.32, the applicant described 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 RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with Nuclear Power Plants," AMP, part of the Structures Monitoring Program, is based on the guidance of
 
RG 1.127 and ACI 349.3R and periodically inspects the intake structure and canal (UHS), the fire
 
pond dam, and the dilution structure. The program will manage loss of material, cracking, and
 
change in material properties for concrete components, loss of material and change in material
 
properties for wooden components, and loss of material and loss of form for the dam and the
 
canal slopes. Inspection frequency is every 4 years except for submerged portions of the
 
structures inspected when the structures are dewatered or on a frequency not to exceed
 
10 years. The program will be enhanced to provi de reasonable assurance that aging effects of water-control structures are adequately managed during the period of extended operation.
3-155 Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.25. The staff reviewed the
 
enhancements and their justifications to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power program for which the applicant claimed consistency with GALL AMP XI.S7 and found them consistent. Furthermore, the staff concluded that the applicant's
 
RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Program
 
provides reasonable assurance that the OCGS water control structures will be adequately
 
managed for the period of extended operation. The staff found that the applicant's RG 1.127
 
Inspection of Water-Control Structures Associated with Nuclear Power Program conforms to the recommended GALL AMP XI.S7, with an exception and enhancements described below.
Exception. The applicant did not state any exception to the GALL Report program in the LRA.
However, PBD-AMP-B.1.32 states an exception to the GALL Report program element "detection
 
of aging effects." Specifically, the exception stated:
The Oyster Creek RG 1.127, Inspection of Water Control Structures Associated With Nuclear Power Plants takes exception to the inspection frequency specified in NUREG-1801 XI.S7, RG 1.127, Inspection of Water-Control Structures Associated
 
with Nuclear Power Plants. This exception is applicable only to submerged
 
structures. This is a new exception not previously identified in the LRA.
As justification for the exception, the applicant stated:
During the NRC aging management program (AMP) review audit (October 23-27, 2005), the staff indicated that the 10-year inspection frequency is not consistent with the 5-year frequency specified in NUREG-1801 Program XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power
 
Plants and requested the technical basis for concluding a 10 year inspection
 
frequency is sufficient for submerged portions of water control structures. Oyster
 
Creek indicated that the review of the CLB concluded that the existing Oyster
 
Creek RG 1.127, Inspection of Water Control Structures Associated With Nuclear
 
Power Plants program is based on SEP Topic III-3.C commitments, which do not
 
address submerged structures. The 10-year inspection frequency was determined
 
sufficient, based on operating experience, to detect significant age related
 
degradations before an intended function of the water control structures is
 
adversely impacted. Additionally Oyster Creek will perform a baseline inspection of underwater structures and evaluate identified age related degradations to establish
 
if there is a need for more frequent inspection to provide reasonable assurance
 
that aging effects are adequately managed. The staff noted that the present
 
existing operating experience related to underwater structure is not sufficient for
 
the staff to conclude with reasonable assurance that the 10-year inspection
 
frequency is adequate.
As a result of the staff's concern, Oyster Creek agreed to perform a baseline inspection of submerged water control structures prior to entering the period of
 
period of extended operation. A second inspection will be performed 6 years after 3-156 the baseline inspection. A third inspection will be performed 8 years after the second inspection. Following each inspection, the identified degradations will be
 
evaluated to determine if more frequent inspections are warranted or there is a
 
need for corrective actions to ensure that age related degradations are adequately
 
managed. This constitutes a new exception not previously identified in the LRA.
In its letter dated March 30, 2006, the applicant committed (Commitment No. 32) to revise theLRA to add the exception to the inspection frequency specified in GALL AMP XI.S7 and stated in
 
PBD-AMP-B.1.32. The applicant has committed to a baseline inspection prior to the period of
 
period of extended operation, a second inspection 6 years after the baseline inspection, and a
 
third 8 years after the second and has committed to evaluate the degradations to determine
 
whether more frequent inspections are warranted.
The staff finds this exception acceptable because the applicant's baseline inspection schedule and its commitment to evaluate the identified degradations provides assurance that the effects of
 
aging will be adequately managed for the extended period of operation.
In the LRA and in PBD-AMP-B.1.32, the applicant stated the following enhancements in meeting the GALL Report program elements "scope of progr am," "parameters monitored or inspected,"
and "detection of aging effects." Specifically, the enhancements stated:
(1) The program will provide for monito ring of submerged structural components and trash racks.
(2) Parameters monitored will be enhanced to include change in material properties, due to leaching of calcium hydroxide, and aggressive chemical attack.
(3) Add the requirement to inspect steel components for loss of material, due to corrosion.
(4) Add the requirement to inspect wooden piles and sheeting for loss of material and change in material properties.
(5) The program will provide for periodi c inspection of components submerged in salt water (intake structure and canal, dilution structure) and in the water of the fire
 
pond dam.(6) The program will be enhanced to include periodic inspection of the fire pond dam for loss of material and loss of form.
(7) The program will be enhanced to require performing a baseline inspection of submerged water control structures prior to entering the period of extended
 
operation. A second inspection will be performed 6 years after this baseline
 
inspection and a third 8 years after the second. After each inspection an evaluation
 
will be performed to determine if the identified degradations warrant more frequent
 
inspections or corrective actions. [This constitutes a new enhancement not
 
previously identified in the LRA.]
The staff noted that "enhancement" (7) related to the program element "detection of aging effects" is not an enhancement to meet the GALL Report recommendations. The applicant's new 3-157 commitment for inspection of submerged water cont rol structures, a significant improvement over the original LRA commitment, is still an exception to the GALL Report recommendations. The staff
 
evaluated this "enhancement" as an exception described below.
Enhancement 1. In the LRA, the applicant stated enhancements in meeting the GALL Report program element "scope of program."
Specifically, the enhancements stated:
The OCGS AMP will be enhanced to include the following:
 
(1) The program will provide for monito ring of submerged structural components and trash racks.
(5) The program will provide for periodi c inspection of components submerged in salt water (intake structure and canal, dilution structure) and in the water of the fire
 
pond dam.(6) The program will be enhanced to include periodic inspection of the fire pond dam for loss of material and loss of form.
As justification for this enhancement, the applicant stated that the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program applies to water control
 
structures of the emergency cooling water system. Water control structures in scope of license
 
renewal are included in the scope of the RG 1.127 Inspection of Water-Control Structures
 
Associated with Nuclear Power Plants Program. These structures are the intake structure and
 
canal (UHS), the dilution structure, and the intake structure trash racks. Structural components
 
and commodities of the structures monitored under the existing program include reinforced
 
concrete members and earthen water control structures (intake canal, embankments). The
 
enhanced program will include the fire pond dam and its various components, including the
 
spillway, and embankments.
The applicant further indicated that there are no water control structures credited for flood protection and no safety and performance instrumentation like seismic, horizontal and vertical
 
movement, uplift, and other instrumentation incorporated in the design of the water control
 
structures.
The staff compared the program scope of the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, including enhancements, to the program scope of GALL Report AMP XI.S7 and finds them to be consistent.
On this basis, the staff finds the enhancements to the "scope of program" program element acceptable because when implemented the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Program will be consistent with GALL AMP XI.S7 and will provide
 
additional assurance that the effects of aging will be adequately managed.
Enhancement 2. In the LRA, the applicant stated enhancements in meeting the GALL Report program element "parameters monitored or in spected." Specifically, the enhancements stated:
The OCGS AMP will be enhanced to include the following:
3-158 (2) Parameters monitored for concrete will be enhanced to include change in material properties, due to leaching of calcium hydroxide, and aggressive chemical
 
attack.(3) Parameters monitored will include inspection of steel components for loss of material due to corrosion and pitting.
(4) Parameters monitored will include inspection of wooden piles and sheeting for loss of material and change in material properties.
As justification for this enhancement, the applicant stated that parameters monitored or inspected are consistent with the guidance specified in Section C.2 of RG 1.127. For reinforced concrete
 
components, it includes loss of material due to various aging mechanisms like erosion and
 
cavitation, cracking due to various aging mechanisms like settlement, and change in material
 
properties due to leaching of calcium hydroxide. Steel components of earthen water control
 
structures (intake canal, embankments), the fire pond dam, and trash racks are monitored for loss
 
of material due to pitting and corrosion. Wooden components are monitored/inspected for loss of
 
material and change in material properties. Slopes for earthen water control structures at
 
junctions with abutments are monitored for loss of material and loss of form (cracks, sinkholes, erosion, and slope instability).
The applicant further stated that parameters monitored or inspected for earthen water control structures include settlement, depressions, sink holes, slope stability (e.g., irregularities in
 
alignment and variances from originally constructed slopes), and loss of slope protection liner.
 
These parameters are considered loss of material and loss of form. Earthen water control
 
structures have no drainage systems and thus m onitoring of drainage systems is not applicable.
The staff compared the parameters monitored or inspected in the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, including
 
enhancements, to the parameters monitored or inspected in GALL Report AMP XI.S7 and finds them consistent.
On this basis, the staff finds the enhancements to the program element "parameters monitored or inspected" acceptable because when implemented the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Program will be consistent with GALL AMP XI.S7 and
 
will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.32, the applicant explained that the operating history of the intake structure and canal and the dilution structure indicates that the structures are not
 
experiencing significant degradation. Localized cracking and spalling of the intake structure
 
concrete was identified and repaired in the mid-1980s. Recent inspection (2002) of the intake
 
structure and the dilution structure noted some concrete spalling and cracking. However, these
 
aging effects were determined to be insignificant with no adverse impact on the intended
 
function(s) of the structures. Inspection of the intake canal in 2001 identified some cracks and
 
fissures, voids, holes, and localized washout of coatings that protect embankment slopes from
 
erosion. The degradations were evaluated and determined not to impact the intended function of
 
the intake canal (UHS). The degradations are inspected periodically and evaluated to ensure that
 
the intended function of the intake canal is not adversely impacted.
3-159 The staff reviewed the operating experience provided in the LRA and PBD-AMP-B.1.32, and interviewed the applicant's technical personnel to confirm that the plant-specific operating
 
experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's RG 1.127 Inspection of
 
Water-Control Structures Associated with Nuclear Power Plants Program will adequately manage
 
the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.32 and letter dated March 30, 2006, the applicant provided the UFSAR supplement for the RG 1.127 Inspection of Water-Control Structures
 
Associated with Nuclear Power Plants Program. The staff determined that the information in the
 
UFSAR supplement provides 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 determined
 
that those program elements for which the applicant claimed consistency with the GALL Report
 
are consistent. Also, the staff reviewed the enhancements and confirmed that their
 
implementation prior to the period of extended operation will make the 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 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).
3.0.3.2.26  Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrument Circuits Summary of Technical Information in the Application. In LRA Section B.1.35, the applicant described the existing Electrical Cables and Connections Not Subject to 10 CFR 50.49
 
Environmental Qualification Requirements Used in Instrument Circuits Program as consistent,with enhancements, with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to
 
10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits."
The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrument Circuits Program manages aging for cables and connections in
 
sensitive instrumentation circuits with low-level signals. The cables of the intermediate range
 
monitoring (IRM), local power range monitori ng/average power range monitoring (LPRM/APRM), reactor building high radiation monitoring, and air ejector offgas radiation monitoring systems are
 
sensitive instrumentation circuits with low-level signals located in areas where the cables and
 
connections could be exposed to adverse environments of heat, radiation, or moisture. These
 
adverse environments can reduce insulation resistance, causing increases in leakage currents.
 
For the IRM and LPRM/APRM systems, the program is implemented by station procedures that perform current/voltage and time domain reflectometry (TDR) cable testing and have proven
 
effective in determining cable insulation condition. Testing is performed every refueling outage.
 
For the reactor building high radiation monitoring and air ejector offgas radiation monitoring
 
systems, the program is implem ented by station procedures used for calibration testing required by the technical specifications. When an instrumentation channel is found to be out of tolerance or 3-160 out of calibration, such corrective action as recalibration or circuit trouble-shooting of the instrumentation cable system is taken.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.26. The staff reviewed the
 
enhancements and their justifications to determine whether the AMP, with the enhancements, remained adequate to manage the aging effects for which it is credited.
The staff reviewed those portions of the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrument Circuits Program for which the applicant claimed consistency with GALL AMP XI.E2. The staff found that the applicant's program conforms to the recommended GALL AMP XI.E2, with enhancements described below.
Enhancement 1. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending." Specifically, the enhancement stated:Section XI.E2 of NUREG-1801 requires a review of the calibration results for cable aging degradation once every 10 years. Calibration results are not currently
 
reviewed for cable aging degradation. This program will be revised to include a
 
review of the reactor building high-radiation monitoring and air ejector off-gas
 
radiation monitoring systems calibration results for cable aging degradation before
 
the period of extended operation and every 10 years thereafter.The staff noted that, as recommended by GALL AMP XI.E2, a review of the calibration testing results for cable aging degradation will be performed before the period of extended operation and
 
every 10 years thereafter. Review of the results obtained during calibration will detect severe
 
aging degradation before loss of the cable's or connection's intended function.
The staff finds this enhancement acceptable because when implemented the program will beconsistent with GALL AMP XI.E2 and will provide additional assurance that the effects of aging
 
will be adequately managed.
Enhancement 2. In the LRA, the applicant stated an enhancement in meeting the GALL Report program elements "parameters monitored or inspected," "detection of aging effects," and "monitoring and trending." Specifically, the enhancement stated:Section XI.E2 of NUREG-1801 requires a review of test results for cable aging degradation once every 10 years. Cable test results are not currently reviewed for cable
 
aging degradation. This program will be revised to include a review of the LPRM/APRM
 
and IRM system cable testing results for cable aging degradation before the period of
 
extended operation and every 10 years thereafter.The staff noted that, as recommended by GALL AMP XI.E2, a review of cable test results for cable aging degradation will be performed before the period of extended operation and every
 
10 years thereafter. Review of the results obtained during cable testing will detect severe aging
 
degradation before the loss of the cable's or connection's intended function.
3-161 The staff finds this enhancement acceptable because when the enhancement is implemented theprogram will be consistent with GALL AMP XI.E 2 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.1.35, the applicant explained that the cable testing and calibrations for this AMP currently have proven effective in identifying degradation in the system tested. OCGS has experienced failures of monitoring system cables and connectors that were
 
identified during the conduct of routine testing. For example, a step change in the air ejector
 
offgas radiation monitor readings was corrected by replacement of the cables for both channels.
 
When equipment cannot be brought into calibration or when cable system tests indicate
 
unacceptable results evaluations are performed in accordance with the corrective action process
 
and appropriate actions are taken.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Electrical Cables and
 
Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in
 
Instrument Circuits Program will adequately manage the aging effects identified in the LRA for
 
which this AMP is credited.
UFSAR Supplement. In LRA Section A.1.35 and letters dated December 9, 2005 and May 1, 2006, the applicant provided the UFSAR supplement for the Electrical Cables and
 
Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in
 
Instrument Circuits Program. The staff determined that the information in the UFSAR supplement
 
provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in
 
Instrument Circuits Program, the staff determined that those program elements for which the
 
applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the
 
enhancements and confirmed that their implementat ion prior to the period of extended operation will make the 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).
3.0.3.2.27  Metal Fatigue of Reactor Coolant Pressure Boundary
 
Summary of Technical Information in the Application. In LRA Section B.3.1, the applicant described the existing Metal Fatigue of Reactor Coolant Pressure Boundary (RCPB) Program as consistent, with an enhancement, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant
 
Pressure Boundary."
The Metal Fatigue of Reactor Coolant Pressure Boundary Program provides for aging management of select components in the RCPB by tracking and evaluating key plant events 3-162 selected from plant-specific evaluations of the most fatigue-limited locations for critical components, including those discussed in NUREG/CR-6260, "Application of NUREG/CR-5999, Interim Fatigue Curves to Selected Nuclear Power Plant Components." The program provides
 
management of operating transients, calculates fatigue usage factors, and permits
 
implementation of corrective measures in order not to exceed the design limit on fatigue usage.
The effects of reactor coolant environment will be considered through the evaluation of, as a
 
minimum, components selected in NUREG/CR-6260 by appropriate environmental fatigue factors.
 
The RCPB design basis metal fatigue analyses ar e considered TLAAs for license renewal. The program provides an analytical basis for confirmi ng that the number of cycles established by the analysis of record will not be exceeded before the end of the period of extended operation. To
 
determine cumulative usage factors (CUFs) more accurately, the program will implement
 
FatiguePro fatigue monitoring software. FatiguePro calculates cumulative fatigue using both
 
cycle-based and stress-based monitoring, providing an analytical basis for confirming that the
 
number of cycles established by the analysis of record will not be exceeded before the end of the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Section 3.0.3.2.27. In the LRA, the applicant stated
 
that the Metal Fatigue of Reactor Coolant Pressure Boundary Program is consistent with GALL AMP X.M1 with enhancements. The staff reviewed the program elements (see SER
 
Section 3.0.2.1) of the Metal Fatigue of Reactor Coolant Pressure Boundary Program and basis documents to determine their consistency with GALL AMP X.M1.
In reviewing this program the staff noted that, in LRA Section 4.3.4, the applicant stated that the allowable CUF value is 1.0. The applicant stated that the CLB fatigue CUF limit for the RPV had
 
been changed to 1.0 in accordance with 10 CFR 50.59. The applicant stated in a letter dated
 
December 9, 2005, that it will revise the UFSAR to update the CLB to reflect that a CUF of 1.0 will
 
be used in fatigue analyses for RCPB components, as endorsed in 10 CFR 50.55a, before the
 
period of extended operation. The staff's TLAA review is discussed in SER Section 4.
The staff reviewed OCGS Power Operations Review Committee (PORC) Meeting Report 06-03 and Specification OC-2006 E-001, "Revised Method for Determination of Fatigue Cumulative
 
Usage Factor," Revision 0. The staff noted that the PORC had approved the CUF limit change
 
with some recommendations and conditions. The staff requested that the applicant clarify the
 
methodology for the determination of the fatigue CUF, to clarify the original design intent to limit
 
the CUF to 0.8, and whether the new design analysis and the revised fatigue analysis will be
 
certified by a professional engineer with significant experience with ASME Code Section III fatigue
 
analyses to demonstrate compliance with ASME Code Section III Class 1 analysis. In its
 
response, the applicant stated:
From UFSAR section 5.3.1.1, the following statement provides the basis for the General Electric method of performing fatigue analysis for the Oyster Creek reactor
 
vessel; "For reactor pressure vessels designed and built prior to the adoption of the
 
ASME Boiler and Pressure Vessel Code Section III, the General Electric Company
 
developed a method for performing a fatigue analysis which will provide assurance
 
that vessels installed in General Electric designed nuclear power plants will safely
 
withstand all anticipated operating and transient conditions, both normal and
 
emergency conditions. This method was based upon the method of analysis
 
developed for Naval reactors and upon industry's experience using it." The UFSAR 3-163 also concludes that the General Electric Specification defined analysis results in a completed vessel for the Oyster Creek plant, which has safety margins that are
 
generally equivalent to those which will result from using Section III methodology.
 
General Electric's selection of a cumulative usage factor limit of 0.8 (versus 1.0)
 
was to assure the Oyster Creek reactor pressure vessel design will remain
 
bounded by the pending ASME Section III methodology and acceptance criterion.
 
There is no evidence that consideration was given to reserving margins for any
 
other reason (e.g., for system transients or unspecified cyclic conditions not
 
considered in original analysis). The reanalyzed fatigue usage factors were
 
performed to the ASME Section III requirements to demonstrate acceptability to the
 
corresponding acceptance limit of 1.0.
The Exelon 50.59 evaluations reviewed if using ASME Section III instead of the methods by GE to calculate fatigue usage represented a departure from a method
 
of evaluation described in the UFSAR used in establishing design bases. The OC
 
procedure for preparing 50.59 evaluations, based on NEI 96-07, provides the
 
guidance that: Use of a new NRC-approved methodology (e.g., ASME Section III)
 
to reduce uncertainty, provide more precise results, or other reason is not a
 
departure from a method of evaluation described in the UFSAR, provided such use
 
is (a) based on sound engineering practice, (b) appropriate for the intended
 
application, and (c) within the limitations of the applicable SER. Oyster Creek is
 
using the ASME Boiler and Pressure Vessel Code Section III methodology to
 
revise its design basis fatigue analyses for the reactor vessel; and the NRC has
 
approved the use of ASME Boiler and Pressure Vessel Code Section III via
 
10CFR50.55a, which is within the limitations of the Oyster Creek Licensing Basis.
 
Therefore, implementing the ASME Boiler and Pressure Vessel Code Section III
 
method for analyzing fatigue is not considered a departure from a method of
 
evaluation described in the UFSAR.
The licensing change allows Oyster Creek to revise design basis analysis from the methods described in GE specification 21A1105 to the NRC-approved methods of
 
the ASME Boiler and Pressure Vessel Code Section III. The licensing basis
 
change provides Oyster Creek the ability to implement revised analysis to establish
 
new allowable cycles [N(I)], using the methods described in ASME Boiler and
 
Pressure Vessel Code Section III. The difference in methodology is primarily
 
associated with the difference between the s-N fatigue curve provided in the GE
 
specification and the fatigue curve in the ASME Section III code. The process of
 
summing transient pairs to determine total fatigue usage remains unchanged.
As part of the preparation of the Oyster Creek License Renewal application, limiting fatigue analyses of the reactor pressure vessel prepared per the original
 
GE purchase specification for the RPV have been revised in accordance with the
 
NRC approved ASME Boiler and Pressure Vessel Code Section III as permitted by Appendix L of ASME Section XI. As stated in Appendix L the new fatigue usage
 
values are compared to 1.0. This is not only a change in an acceptance limit but
 
also a change in methodology, since fatigue usage factors were revised using the
 
fatigue curve in ASME Section III instead of the fatigue curve provided in the GE
 
specification. Oyster Creek has assumed the responsibility of the RPV design
 
basis analysis in accordance with the Code requirements, and therefore, GE
 
concurrence of the changes is not required nor was it requested.
3-164 Oyster Creek has revised the fatigue analysis for the limiting RPV locations in accordance with the methods established in NRC approved ASME Boiler and Pressure Vessel Code Section III, as permitted by ASME Section XI IWB-3740. As stated in ASME XI Appendix L the revised usage factors are compared to 1.0.
 
Since all of the revised usage factors are less than the acceptance limit, there are
 
no adverse effects. The GE specification (21A1105) is still the current specification
 
for the RPV. This specification will be updated to reflect the change in methodology
 
as part the design change process.
As part of the effort for License Renewal, the current licensing basis RPV fatigue analysis was evaluated to demonstrate satisfactory results for the period of
 
extended operation. When the current licensing basis RPV fatigue analysis was
 
reevaluated, using actual thermal cycles based on plant data, it was determined
 
that for some locations the forty-year fatigue usage may exceed the 0.8
 
acceptance limit imposed by the GE spec. These locations required a more refined analysis. Under the rules of 10CFR50.55a and Section XI, Subsection IWB, the applicant is allowed to use Appendix L of Section XI to analyze the effects of
 
fatigue on components. Appendix L directs that ASME Section III fatigue usage
 
factor evaluation procedures be used to determine if they are acceptable for
 
continued service. The fatigue usage factors for the reanalyzed components are
 
less than 0.8 before environmental effects are included for License Renewal.
 
However, there is no technical basis not to compare the usage factors to 1.0 since
 
Appendix L establishes 1.0 as the appropriate acceptance limit. The revised
 
analysis for the above components can be found in Exelon Design Analysis SIA
 
No. OC-05Q-303 Revision 1.
The applicant stated that all supporting calculations and reports prepared by Structural Integrity Associates (SIA) for the fatigue activities associated with the LRA were approved (and in many
 
cases prepared) by a registered Professional Engineer. The registered Professional Engineer has
 
significant experience with ASME Code Section III fatigue analyses, and is approved in
 
accordance with SIA's Quality Assurance Program to be a qualified certifier of ASME Code, Section III, Division 1 Design Specifications and Design Reports. The approval of the Professional
 
Engineer signifies acknowledgment that all documents are correct and complete to the best of his
 
knowledge and that he or she is competent to approve the documents accordingly, and that all
 
documents meet the intent of the pertinent sections of Section III, Subsection NB of the ASME
 
Boiler and Pressure Vessel Code (in accordance with the referenced Edition and Addenda) for
 
Class 1 fatigue analysis. In its letter dated May 1, 2006, the applicant committed (Commitment
 
No. 44) to certification by a Professional Engineer of the reactor vessel design specification and
 
design reports prepared for the fatigue activities associated with the LRA. This will be performed
 
by July 31, 2006. The staff determined that the applicant's response was acceptable because it
 
meets the methods established in NRC approved ASME Boiler and Pressure Vessel Code
 
Section III.
The staff reviewed those portions of the Metal Fatigue of Reactor Coolant Pressure BoundaryProgram for which the applicant claimed consistency with GALL AMP X.M1 and found them
 
consistent with the GALL Report AMP. Furthermore, the staff concluded that the applicant's Metal
 
Fatigue of Reactor Coolant Pressure Boundary Program provides reasonable assurance that the
 
effects of fatigue will be adequately managed. The staff found that the applicant's Metal Fatigue of 3-165Reactor Coolant Pressure Boundary Program conforms to the recommended GALL AMP X.M1, with an enhancement described below.
Enhancement. In the LRA, the applicant stated the following enhancement in meeting the GALL Report program elements "parameters monitored or inspected," "detection of aging effects,"
"monitoring and trending," and acceptance criteria." Specifically, the applicant stated the following:
The program will be enhanced to use the EPRI-licensed FatiguePro cycle counting and fatigue usage factor tracking computer program. The computer program
 
provides for calculation of stress cycles and fatigue usage factors from operating
 
cycles, automated counting of fatigue stress cycles and automated calculation and
 
tracking of fatigue cumulative usage factors.
The program will provide for calculating and tracking of the cumulative usage factors for bounding locations for the reactor pressure vessel, Class I piping, the
 
torus, torus vents, torus attached piping and penetrations, and the isolation
 
condenser. The monitoring sample will include those locations where the predicted
 
40-year cumulative fatigue usage had been predicted to be 0.4 or greater, including the locations specified in NUREG/CR-6260, when applicable to Oyster
 
Creek In reviewing this enhancement, the staff noted that, in the LRA, the applicant stated that the EPRI-licensed FatiguePro computer program calc ulates stress cycles and fatigue usage factors from operating cycles, automatically counts fa tigue stress cycles, and automatically calculates and tracks fatigue CUFs. The applicant also stated that the program will calculate and track the
 
CUFs for bounding locations for the reactor pressure vessel, Class I piping, the torus, torus vents, torus attached piping and penetrations, and the isolation condenser. The monitoring sample will
 
include locations where the predicted 40-year cumulative fatigue usage had been predicted to be
 
0.4 or greater and the locations specified in NUREG/CR-6260 when applicable.
The staff evaluated the applicant's existing Fatigue Monitoring Program and noted that it had correctly identified the need for more sophisticated methods to demonstrate adequate margin to
 
fatigue limits. Improved calculation of environment al fatigue factors is also necessary. The staff determined that FatiguePro is appropriate to improve monitoring and, taken together with the
 
improved methodology for calculation of environm ental fatigue factors, this enhancement provides assurance that fatigue damage will be adequately managed.
The staff finds this enhancement acceptable because when implemented the Metal Fatigue ofReactor Coolant Pressure Boundary Program will be consistent with GALL AMP X.M1 and will
 
provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In LRA Section B.3.1, the applicant explained that it had reviewed both industry and plant-specific operating experience relating to the Metal Fatigue of Reactor Coolant
 
Pressure Boundary Program. In instances where the potential existed to exceed CUFs before the
 
end of plant life the engineering analyses showed that actual margins were larger than initially
 
estimated. The applicant also stated that the Metal Fatigue of Reactor Coolant Pressure
 
Boundary Program had been revised to incorporate changes in design basis analysis cycles. The
 
changes were made because certain types of operating events were found to be more frequent
 
than anticipated in the original design. Others were found to be less frequent. The changes 3-166 reduced the assumed design basis number of the less frequent and increased the assumed number of the more frequent events.
In response to staff concerns that early-life operating cycles at some units had caused fatigue usage factors to increase at a rate greater than anticipated in the design analyses, the industry
 
sponsored the development of the FatiguePro computer program. The program ensures that ASME Code limits are not exceeded for the remainder of the licensed life and incorporates
 
operating experience.
The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no degradation
 
not bounded by industry experience. The fatigue evaluations confirm that significant margin
 
remains for the CUF limit, and implementation of the proposed program will prevent exceeding the limit.On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Metal
 
Fatigue of Reactor Coolant Pressure Boundary Program will adequately manage the aging effects
 
identified in the LRA for which this AMP is credited.
UFSAR Supplement. In LRA Section A.3.1 and letters dated December 9, 2005, and May 1, 2006, the applicant provided the UFSAR supplement for the Metal Fatigue of Reactor Coolant Pressure
 
Boundary Program. The staff determined that the information in the UFSAR supplement provides
 
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 determined that those program elements for which
 
the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed
 
the enhancement and confirmed that the implement ation of the enhancement prior to the period of extended operation will make the 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 concluded that it provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.28  Bolting Integrity - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.12A," Bolting Integrity -
FRCT," AMP is consistent with GALL AMP X I.M18, "Bolting Integrity," with exceptions.
The Bolting Integrity - FRCT Program will be used to monitor the condition of bolts and bolted joints within the scope of license renewal at the Forked River Combustion Turbine (FRCT) station.
 
The FRCT station was originally designed and supplied by GE. This program is based on the GE
 
recommendations for proper bolting material selection, lubrication, preload application, installation, and maintenance of the combustion turbine units and auxiliary systems. The program also includes periodic walkdown inspections for bolting degradation or bolted joint leakage. The
 
program manages the loss of bolting function, including loss of material and loss of preload aging 3-167 effects. Bolted joint inspections rely on detection of visible leakage during routine observations and equipment maintenance.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7 . In its response to RAI 2.5.1.19-1
 
dated November 11, 2005, the applicant stated that the Bolting Integrity - FRCT Program is consistent with GALL AMP X.M18with excepti ons. The staff reviewed the program elements (see SER Section 3.0.2.1) of the Bolting Integrity - FRCT Program and basis documents to determine their consistency with GALL AMP X.M18.
The staff reviewed those portions of the Bolting Integrity - FRCT Program for which the applicantclaimed consistency with GALL AMP XI.M18 and found them consistent. Furthermore, the staff
 
concluded that the applicant's Bolting Integrity - FRCT Program provides reasonable assurance
 
that aging effects will be adequately managed so that the intended functions of bolting within the
 
scope of license renewal at the FRCT station are maintained consistent with the CLB during the
 
period of extended operation. The staff found that the applicant's Bolting Integrity - FRCT
 
Program conforms to the recommended GALL AMP XI.M18 with exceptions described below.
Exception 1. In its response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL Report program element s "scope of program," "preventive actions,"
"parameters monitored/inspected," "detection of aging effects," "monitoring and trending," and
 
"acceptance criteria." Specifically, the exception stated:
The Bolting Integrity - FRCT program does not specifically incorporate NRC and industry recommendations delineated in NUREG-1339, "Resolution of Generic
 
Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants." The
 
program also does not specifically address Electric Power Research Institute (EPRI) NP-5769 for safety-related bolting, or EPRI TR- 104213. These documents
 
were developed specifically for the nuclear power industry. The Forked River
 
Combustion Turbine station is a non-nuclear fossil-fueled station. The Bolting
 
Integrity - FRCT program was evaluated against the ten elements of aging management program XL.M18, "Bolting Integrity," specified in NUREG-1801. Each
 
element is evaluated, and the associated portions of the element that are
 
applicable to the Forked River Combustion Turbine power plant have been
 
incorporated into this program. This program applies good industry bolting
 
practices based on General Electric (the original FRCT designer and supplier)
 
recommendations, supplemented with periodic walkdown inspections to confirm
 
bolting integrity. The requirements for safety-related bolting, and bolting for nuclear
 
steam supply system component supports, do not apply to the Forked River
 
Combustion Turbine power plant.
The applicant stated, in its response to RAI 2.5.1.19-1 dated November 11, 2005, and in the basis document PBD-AMP-B.1.12A, the following:
The scope of the program covers bolting within the scope of license renewal at the Forked River Combustion Turbine power plant. There is no safety-related bolting or
 
bolting for nuclear steam supply system (NSSS) component supports at the Forked
 
River Combustion Turbine power plant. The program scope includes
 
pressure-retaining component bolting and structural bolting used on the Forked 3-168 River combustion turbine units and auxiliary systems and structures in the scope of license renewal. The Forked River Combustion Turbine power plant was originally
 
designed and supplied by General Electric Company, and this program is based on
 
the General Electric recommendations for proper bolting application and
 
maintenance associated with the combustion turbine units and auxiliary systems.
For preventive actions, selection of bolting material and the use of lubricants and sealants is in accordance with the recommendations provided by General Electric.
 
The GE Inspection and Maintenance manual for the units prescribe the specific
 
sealants and lubricants to be used, and how and where they are applied. Bolting
 
replacement activities include proper torquing of the bolts, proper alignment of
 
flanges, and checking for proper mating surface contact after assembly based on
 
the specific joint classification. Maintenance practices require the application of an
 
appropriate preload, as specified in the General Electric Inspection and
 
Maintenance Instructions for the combustion turbine units. Preload of gasketed
 
joints is controlled by torque wrench or by measurement of bolt or stud elongation.
 
Preload of joints with metal-to-metal contact is controlled by torque wrench, by
 
measurement of bolt or stud elongation, or by head rotation.
For parameters monitored/inspected, this program monitors the effects of aging on the intended function of bolting associated with the Forked River Combustion
 
Turbine power plant. There are no safety-related pressure retaining components or
 
NSSS component supports at the Forked River Combustion Turbine power plant.
 
Pressure retaining bolting at the Forked River Combustion Turbine power plant will
 
be periodically inspected for signs of leakage. Other bolting will be inspected for
 
signs of significant degradation including loss of material, loss of coating integrity, and obvious signs of corrosion, rust, or loose or missing bolts.
For detection of aging effects, degradation of the pressure retaining closure bolting due to crack initiation, loss of prestress, or loss of material due to corrosion of the
 
closure bolting will result in leakage. Periodic plant walkdowns will assure detection
 
of leakage before the leakage becomes excessive such that the intended function
 
of the Forked River Combustion Turbine power plant will be impacted. In addition
 
to leakage detection, plant walkdowns will include inspection of bolting for signs of
 
significant degradation including loss of material, loss of coating integrity, and
 
obvious signs of corrosion, rust, or loose or missing bolts.
For monitoring and trending, walkdown inspections for leakage and inspections for bolting degradation will be performed at least once every four years. Identified
 
leakage will be monitored daily until repaired. Much of the equipment at the Forked
 
River Combustion Turbine power plant is located outdoors, so even small leaks
 
must be immediately isolated or repaired because of potential environmental
 
concerns. If continued leakage is acceptable under the applicable permits and
 
regulations, and if the leak rate does not increase, the inspection frequency may
 
be decreased to biweekly or weekly.
For acceptance criteria, any indications of leaking pressure retaining bolting, or bolting degradation that could potentially lead to loss of system or component
 
intended functions, will be evaluated and dispositioned in accordance with the
 
corrective action process described below.
3-169 The staff noted that there are no safety-related or NSSS components supporting the operation ofFRCT station and hence the guidance for the ASME Code Section XI inspection requirements, selection of bolting material, and the use of lubricants and sealants of NUREG-1339, EPRI
 
TR-104213, and EPRI NP-5769 does not apply. On this basis, the staff finds this exception
 
acceptable.
Exception 2. In its response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL Report program elements "c orrective actions," "confirmation process," and "administrative controls." Spec ifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of 10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In its response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that in March 2004 (FRCT Unit 1) GE Energy Services performed major inspection and
 
maintenance and documented all work in an inspection report dated June 7, 2004. The equipment
 
inspections included the turbine and its internals and support equipment. All work was carried out
 
closely following the instructions and guidance of original equipment manufacturer's design, maintenance, and inspection manuals. Acceptance criteria and corrective actions for these
 
activities ensure that equipment is maintained within design specifications.
The FRCT Unit 1 inspection was major maintenance, the first major inspection of the unit since initial installation in 1988. During final alignment of the load gear following the major inspection, three load gear anchor bolt studs failed. The cause of the failure was determined to be improper
 
initial installation. All anchor bolt studs were repaired by welding new studs in place. The anchor
 
bolts had not failed during the sixteen years of operation prior to the major outage.
There is no history of bolted joint failures causing loss of intended function of the combustion turbine units. Damaged and missing bolts have been identified in the hot exhaust gas plenum, but
 
the exhaust system structural integrity was not compromised and unit operability and reliability
 
were not affected. Critical bolting of the combustion turbine assembly is inspected during
 
maintenance inspections and replaced if required.
Numerous bolts and bolted joints were observed visually during walkdowns during the FRCT Unit 2 major inspection outage that began in October 2005. Bolted joints, including pipe flanges, ventilation joints, pump casings, and valve bonnets, were observed in indoor and outdoor
 
environments and found in good condition with no signs of significant degradation or missing or
 
loose bolts. Minor surface rust was observed on some outdoor bolting. The coating of painted
 
bolting was observed to be in good condition. Bolting was observed on FRCT Units 1 and 2 and
 
common auxiliary systems.
3-170 The operating experience with the FRCT includes a significant number of past inspections including observations of bolting and bolted joints. The documented inspection results provide
 
objective evidence that existing environmental conditions do not result in significant bolting
 
degradation that could cause a loss of the bolting intended functions. Past inspections have been
 
at various frequencies, as long as 16 years for some components, with the units performing
 
reliably between inspections. Implementation of this new program will assure that proper bolting
 
maintenance practices are continued and that walkdown inspections for leakage and inspections
 
for bolting degradation will be performed at least once every four years for reasonable assurance
 
that the aging effects will be adequately managed for the period of extended operation.
The staff reviewed the operating experience provi ded in the basis document and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Bolting Integrity -
 
FRCT Program will adequately manage the aging effects identified in the LRA for which this AMP
 
is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Bolting Integrity -
FRCT Program in response to RAI 2.5.1.19-1. The staff reviewed this section and determined that
 
the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exceptions and their justifications and
 
determined that the AMP, with the exceptions, is adequate to manage the aging effects for which
 
it is credited. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that intended function(s) will be maintained 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.29  Closed-Cycle Cooling Water System - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.14A, "Closed-Cycle
 
Cooling Water System - FRCT," is consistent with GALL AMP XI.M21, "Closed-Cycle Cooling Water System," with exceptions and an enhancement.
The program manages aging of pumps, tanks, pi ping, piping components, piping elements, and heat exchangers included in the scope of license renewal and exposed to a closed cooling water
 
environment at the FRCT station. This program inco rporates experience with existing activities of the closed cooling water system at the FRCT station. The closed cooling water environment at the
 
FRCT station is blended water-glycol. This progr am includes preventive measures to minimize corrosion and SCC and monitoring and maintenance inspection activities to monitor the effects of
 
corrosion and SCC on the intended function of the components.
3-171 Preventive activities rely on maintenance of appropr iate water chemistry control parameters within the specified limits of EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline,"
 
Revision 1, for blended glycol formulations to minimize corrosion and SCC. These control
 
parameters include percent glycol or freeze point and pH. EPRI TR-1007820 does not require
 
monitoring of system corrosion inhibitor concent rations for blended glycol formulations unless corrosion inhibitors have been added. Then EPRI TR-1007820 Section 5.9 requires that the
 
corrosion inhibitor concentrations be monitored to within the range recommended by the
 
manufacturer. The FRCT closed-cycle cooling water system utilizes a proprietary inhibited glycol product and does not add supplemental corrosion inhibitors.
The applicant also stated that performance monitoring indicates degradation in closed-cycle cooling water systems with plant operating conditions indicates degradation in frequently operated
 
systems. In addition, station maintenance inspections monitor the condition of heat exchangers
 
exposed to closed-cycle cooling water environm ents. These measures will ensure that the intended functions of the systems and components serviced by the closed cooling water system are not compromised by aging.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the Closed-Cycle Cooling
 
Water System - FRCT Program is consistent with GALL AMP X.M21 with exceptions and an enhancement. The staff reviewed the program elements and basis documents to determine their consistency with GALL AMP X.M21.
The staff reviewed those portions of the Closed-Cycle Cooling Water System - FRCT Program forwhich the applicant claimed consistency with GALL AMP XI.M21 and found them consistent.
 
Furthermore, the staff concluded that the applicant's Closed-Cycle Cooling Water System - FRCT
 
Program provides reasonable assurance that aging effects of the closed cycle cooling water
 
system at the FRCT station will be adequately managed during the period of extended operation.
 
The staff found that the applicant's Closed-Cycle Cooling Water System - FRCT Program conforms to the recommended GALL AMP XI.M21, with exceptions and an enhancement
 
described below.
Exception 1. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "preventive actions,"
"parameters monitored or inspected," "monitoring and trending," and "acceptance criteria."
 
Specifically, the exception stated:
NUREG 1801 refers to EPRI TR-107396 "Closed Cooling Water Chemistry Guidelines" 1997 Revision. Oyster Creek implements the guidance provided in
 
EPRI 1007820 "Closed Cooling Water Chemistry Guideline," Revision 1, which is
 
the 2004 Revision to TR-107396. EPRI periodically updates industry water
 
chemistry guidelines, as new informati on becomes available. Oyster Creek has reviewed EPRI 1007820 and has determined that the most significant difference is
 
that the new revision provides more prescriptive guidance and has a more
 
conservative monitoring approach. EPRI 1007820 meets the same requirements of
 
EPRI TR-107396 for maintaining conditions to minimize corrosion and
 
microbiological growth in closed cooling water systems for effectively mitigating
 
many aging effects.
3-172 During the audit, the applicant described its review and evaluation of the differences between EPRI TR-107396, "Closed Cooling Water Chemistry Guidelines," the 1997 revision of the
 
guidelines referred to in the GALL Report, and EPRI TR-1007820, "Closed Cooling Water
 
Chemistry Guideline," Revision 1, which is the 2004 revision implemented by OCGS. The
 
applicant stated that the most significant difference from the original version of the closed cooling
 
water chemistry guidelines document is that EPRI TR-1007820 provides more prescriptive
 
guidance and has a more conservative monitoring approach. The applicant further stated that
 
EPRI TR-1007820 meets the same requirements of EPRI TR-107396 for maintaining conditions
 
to minimize corrosion and microbiological growth in closed cooling water systems and effectively
 
mitigate many aging effects.
In addition, the applicant stated that as part of its comparative review of the guideline documents it had contacted Anthony Selby, the author of EPRI TR-107396 and EPRI TR-1007820, to confirm
 
that the new guidance provided in TR-1007820 was not contrary to the guidance in TR-107396.
The staff reviewed EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline," Revision 1, and EPRI TR-107396, Revision 0, and confirmed the applicant's assessment that the new
 
revision provides more prescriptive guidance, has a more conservative monitoring approach, and
 
meets the same requirements for maintaining conditions to minimize corrosion and
 
microbiological growth in closed cooling water sy stems to effectively mitigate many aging effects.
On this basis, the staff finds this exception acceptable.
Exception 2. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Enhancement. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an enhancement in meeting t he GALL Report program element "scope of program." Specifically, the enhancement stated:
The closed-cycle cooling water - FRCT aging management program is a new program to be implemented for the components in the scope of license renewal
 
and subject to a closed cycle cooling water environment located at the Forked
 
River combustion Turbine power plant.
In the November 11, 2005 supplemental response to RAI 2.5.1.19-1, the applicant stated that this program manages aging of pumps, tanks, pipi ng, piping components, piping elements, and heat exchangers included in the scope of license renewal and exposed to a closed cooling water
 
environment at the FRCT system. This program inco rporates experience with activities of the 3-173 closed cooling water system at the FRCT station. The closed cooling water environment at the FRCT station is blended water-glycol. This progr am includes preventive measures to minimize corrosion and SCC and performance monitoring and maintenance inspection activities to monitor
 
the effects of corrosion and SCC on the intended function of the components; therefore, the staff
 
determined that this new program is justifiable.
The staff finds this enhancement acceptable because when implemented the Closed-Cycle Cooling Water System - FRCT Program will be consistent with GALL AMP XI.M21 and will provide additional assurance that the effects of aging will be adequately managed.
Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the FRCT system has not experienced a loss of component intended
 
function due to corrosion product buildup, through-wall loss of material, or SCC for components
 
within the scope of license renewal subject to a closed-cycle cooling water environment.
The FRCT units undergo periodic major inspection outages in accordance with manufacturer recommendations. In March 2004, GE Energy Services performed major inspection and
 
maintenance of FRCT Unit 1 and documented all work performed in an inspection report dated
 
June 7, 2004. In October 2005 GE began a major inspection and maintenance outage on FRCT
 
Unit 2. The scope of equipment inspections included the turbine and its internals and support
 
equipment. Acceptance criteria and corrective actions for these activities ensure that equipment is
 
maintained within design specifications.
The combustion turbine lube oil heat exchangers were removed, disassembled, and inspected during the major inspection outages for each combustion turbine unit. GE did not identify any
 
significant degradation of these heat exchangers in the FRCT Unit 1 outage final report. The
 
FRCT Unit 2 lube oil heat exchangers were visually inspected during the current (October 2005)
 
outage and found in good condition with only minor pitting of carbon steel components with no
 
significant signs of corrosion or wall thinning in the copper alloy tubes. Pump casings, piping, and
 
valve internal surfaces exposed to closed cooling water were also visually inspected during this
 
outage with no significant corrosion or wall thinning observed.
FRCT system components within the scope of license renewal and exposed to closed cooling water, including head tanks, the water-to-air heat exchanger located at the mechanical draft
 
cooling tower, and the various heat exchangers cooled by the closed cooling water system, have
 
experienced no loss of intended function failures due to age-related degradation.
The combustion turbine operating experience provides objective evidence that the FRCT components subject to closed cooling water experience no significant age-related degradation
 
and that the closed-cycle cooling water chemistry has been maintained adequately to manage the
 
effects of aging. This new Closed-Cycle Cooli ng Water System - FRCT Program will include additional chemistry controls and component condi tion monitoring activities, providing further assurance that a non-corrosive environment is maintained to continue to minimize aging-related
 
degradation.
The staff reviewed the operating experience provided in the November 11, 2005, supplemental response to RAI 2.5.1.19-1, and interviewed the applicant's technical personnel to confirm that the
 
plant-specific operating experience revealed no degradation not bounded by industry experience.
3-174 On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Closed-Cycle Cooling
 
Water System - FRCT Program will adequately manage the aging effects identified in the
 
applicant's LRA AMRs for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Closed-Cycle Cooling Water System - FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff
 
reviewed this section and determined that the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exceptions and their justifications and
 
determined that the AMP, with the exceptions, is adequate to manage the aging effects for which
 
it is credited. Also, the staff has reviewed the enhancement and determined that its
 
implementation prior to the period of extended operation will make the AMP consistent with the
 
GALL Report AMP to which it was compared. The staff finds that the applicant has demonstrated
 
that the effects of aging will be adequately managed so that intended function(s) of the
 
combustion turbine components exposed to closed cooling water environments within the scope of license renewal will be maintained 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 finds that it
 
provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.30  Aboveground Steel Tanks - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.21A, "Aboveground Steel Tanks - FRCT," is consistent with GALL AMP XI.M29, "Aboveground Carbon Steel Tanks," with
 
an exception.
The Aboveground Steel Tanks - FRCT Program will pr ovide management of loss of material aging effects for outdoor carbon steel storage tanks. The tanks included in this program are the main
 
fuel oil storage tank, the closed cooling water system head tanks located at the closed cooling
 
water mechanical draft cooling towers, and the diesel starter jacket water (closed cooling water)
 
head tanks located on the roof of the combustion turbine auxiliary enclosure. The program credits
 
the application of paint coating as a corrosion preventive measure and includes periodic visual
 
inspections to monitor degradation of the paint coating and any resulting metal degradation for the
 
steel tanks.
Periodic internal UT inspections will be performed on the bottom of the outdoor steel main fuel oil tank supported by an earthen/concrete foundation. Other outdoor carbon steel tanks in the scope
 
of this program are not directly supported by earthen or concrete foundations and therefore
 
undergo external visual inspections without the necessity of bottom surface UT inspections The main fuel oil tank is the only in-scope outdoor tank supported by an earthen/concrete foundation. This tank does not have caulking or sealing around the tank-foundation interface.
 
Raised tanks not directly supported by earthen or concrete foundations also have no caulking or
 
sealing. Therefore, sealant or caulking inspection at the tank-foundation interface does not apply.
The Aboveground Steel Tanks - FRCT Program is a new program. External tank inspections will 3-175 be at a frequency of every 2 years. Bottom surface UT inspections will be at a frequency of once every 20 years based on plant-specific operating exper ience with the FRCT system main fuel oil storage tank. This program, including the initial tank external paint inspections, will be
 
implemented prior to the period of extended operation. The recommended UT inspection of the
 
main fuel oil tank bottom was performed in October 2000; therefore, it is not necessary to perform
 
this initial inspection again prior to the period of extended operation. Based on the results of the
 
October 2000 inspections and subsequent repairs to the tank floor, the tank was certified to be
 
suitable for the storage of number 2 fuel oil for a period not to exceed 20 years before the next
 
internal inspection will be necessary. Therefore, UT inspections of the tank floor are not
 
necessary prior to the period of extended operation and will be performed again prior to
 
October 2020.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that Aboveground Steel Tanks -
FRCT Program is consistent with GALL AMP X.M29 with an exception. The staff reviewed the program elements and basis documents to determine their consistency with GALL AMP X.M29.
The staff reviewed those portions of the Aboveground Steel Tanks - FRCT Program for which theapplicant claimed consistency with GALL AMP XI.M29 and found them consistent with the GALL
 
Report AMP. Furthermore, the staff concluded that the applicant's Aboveground Steel Tanks -
 
FRCT Program provides reasonable assurance that aging effects are adequately managed so
 
that the intended functions of above-ground steel tanks within the scope of license renewal at the
 
FRCT station will be maintained consistent with the CLB during the period of extended operation.
 
The staff found that the applicant's Aboveground Steel Tanks - FRCT Program conforms to the recommended GALL AMP XI.M29 with an exception described below.
Exception. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that painting has protected the external surfaces of outdoor steel tanks
 
adequately and that loss of material due to external corrosion has not been a concern. Some
 
coating degradation has been observed, and the resulting exposed steel surfaces have
 
experienced minor surface rusting with no impact on the tank intended function. Implementation
 
of this new program prior to the period of ext ended operation will result in specific evaluations of any identified coating degradation, including the potential impact on the tank intended function.
3-176 These periodic inspections of tank coatings provide reasonable assurance that the intended functions will be maintained.
A certified tank inspection company inspected the main fuel oil tank on October 30, 2000. The inspection included UT of the floor, shell, and roof, magnetic flux leakage (MFL) testing of the
 
floor with UT prove-up, level surveying of the foundation settlement, and a thorough VT of the
 
entire tank structure.
The results of the MFL/UT inspection to detect floor underside corrosion indicated that some isolated underside corrosion occurs. A total of eight MFL indications were found and evaluated
 
with the deepest underside corrosion pit measuring 0.185 inches remaining floor thickness. An
 
analysis of corrosion rates since initial tank installation determined that a minimum 0.230 inches
 
remaining floor thickness was required in order to certify the tank as acceptable until the next
 
20-year internal inspection. Four locations were identified below the required 0.230 inches
 
thickness, and these locations were repaired with seal-welded patch plates.
Visual inspection of the floor internal surface revealed 15 pits with the deepest measuring 0.060 inches deep measured with a pit gauge. These pits were weld-repaired. UT inspections at a
 
number of locations on the shell and roof, coupled with a complete VT inspection of these areas, showed no signs of significant corrosion problems or structural deficiencies. There were no signs
 
of service-induced weld failures or leakage. Early signs of paint failure were noted on the tank
 
roof exterior surface. The level survey indicated that the tank foundation is level within 1/4 of
 
an inch.The main fuel oil tank was found to be generally in good condition. With the repair of the identified floor corrosion, the professional opinion of the inspection firm was that the tank is suitable for the
 
storage of number 2 fuel oil for a period of time not to exceed 20 years before the next internal
 
inspection will be necessary.
FRCT Unit 2 began a major outage inspection in October 2005 with components disassembled and visually inspected for signs of age-related degradation. The external surfaces of the closed
 
cooling water system head tanks located at the closed cooling water mechanical draft cooling
 
towers and the diesel starter jacket water (closed cooling water) head tanks located on the roof of
 
the combustion turbine auxiliary enclosure were visually inspected and showed no signs of
 
significant paint degradation or metal corrosion. The main fuel oil storage tanks were walked
 
down, including ascents of the stairs up the side of the tank to the roof. The tank walls showed no
 
signs of significant paint degradation or metal corrosion. The tank roof was observed to have
 
early signs of coating failure as had been noted in the tank inspection report. The underlying
 
metal showed minor surface rust. This condition does not threaten the structural integrity of the
 
roof and continues to be monitored by routine site inspection.
The operating experience with the above-ground steel tanks at the FRCT station provides objective evidence that existing environmental conditions cause no significant material degradation that could result in a loss of component intended functions. Recent external
 
inspections confirm that the exterior paint has prevented significant material degradation. Internal
 
inspections of the main fuel oil storage tank confirm that corrosion of the tank bottom occurs at a
 
rate that can be managed by the recommended future periodic inspections. Implementation of this
 
new program will assure that the painted external tank surfaces are inspected at least once every 2 years and that internal inspection of the main fuel oil storage tank will be at least every 20 years 3-177 for reasonable assurance that the aging effects will be adequately managed for the period of extended operation.
The staff reviewed the operating experience provi ded in the basis document and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review and discussions with the applicant's technical personnel, the staff concludes that the applicant's Aboveground Steel Tanks Program will adequately manage the
 
aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Aboveground Steel Tanks - FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed this
 
section and determined that the information in the UFSAR supplement provides an adequate
 
summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. The staff's review and audit of the applicant's program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff has reviewed the exception and its justifications and
 
determined that the AMP, with the exception, is adequate to manage the aging effects for which it
 
is credited. 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 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 found that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.31  Fuel Oil Chemistry - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005 supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.22A, "Fuel Oil Chemistry -
FRCT," is consistent with GALL AMP XI.M30, "Fuel Oil Chemistry," with exceptions.
The new Fuel Oil Chemistry - FRCT Program assures that contaminants are maintained at acceptable levels in new and stored fuel oil for systems and components within the scope of
 
license renewal. The fuel oil storage tank will be maintained by monitoring and controlling fuel oil
 
contaminants in accordance with the guidelines of the ASTM. Fuel oil sampling activities will be in
 
accordance with ASTM D 4057 for multilevel and tank bottom sampling. Fuel oil will be
 
periodically sampled and analyzed for particulate contamination in accordance with modified
 
ASTM Standard D 2276 Method A, or ASTM Standard D 6217 and for the presence of water and
 
sediment in accordance with ASTM Standard D 2709 or ASTM Standard D 1796. The fuel oil
 
storage tank will be periodically drained of accumulated water and sediment, cleaned, and
 
internally inspected. These activities effect ively manage the effects of aging by providing reasonable assurance that potentially harmful contaminants are maintained at low concentrations.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the Fuel Oil Chemistry - FRCT Program is consistent with GALL AMP X.M30 with exceptions. The staff reviewed the program elements and basis documents to determine their consistency with GALL AMP X.M30.
3-178 In reviewing this AMP, the staff noted that the "detection of aging effects" program element description for the Fuel Oil Chemistry - FRCT Program stated that based on the results of the
 
October 2000 inspections and repairs the FRCT fuel oil storage tank was certified as suitable for
 
the storage of number 2 fuel oil for a period of time not to exceed 20 years from October 2000
 
before the next internal inspection will be necessary. The applicant was asked for the technical
 
basis for establishing the 20-year inspection interval.
In its response, the applicant stated that the FRCT fuel oil tank was inspected, repaired with a material allowance for corrosion, and certified for an additional 20 years of service before
 
requiring internal re-inspection. The out-of-service inspection was consistent with the
 
requirements of API-653 and NJAC 7:1E-2.2(a)4. The certification requires ISIs conducted at
 
5-year intervals along with operation and maintenance consistent with industry standards.
The staff reviewed the applicant's response as well as the TAQ, Inc., tank certification dated October 30, 2000, for the FRCT fuel oil storage tank. The certification included an out-of-service
 
inspection report which showed that the FRCT fuel oil storage tank was in generally good
 
condition. To maintain the certification for 20 years, ISIs are required every 5 years, including the
 
following:
* visual inspection of roof and supports
* external visual inspection for paint failures, pitting, and corrosion
* visual inspection of the floating roof for grooving, corrosion, pitting, and coating failures
* inspection of man-ways and nozzles
* inspection of piping manifolds for leaks or damage The certification also noted that the tank had been constructed in 1989. The staff determined that the ISIs together with the periodic draining of water and sediment from the tank will provide an
 
acceptable means of controlling corrosion of the tank. In addition, the certification was in
 
accordance with accepted industry standards, including API-653 and NJAC 7:1E-2.2(a)4. On this
 
basis, the staff concludes that the 20-year interval for internal inspections is acceptable.
The staff reviewed those portions of the Fuel Oil Chemistry - FRCT Program for which theapplicant claimed consistency with GALL AMP XI.M30 and found them consistent. Furthermore, the staff concluded that the applicant's program provides reasonable assurance that the aging
 
effects for which this program is credited will be adequately managed. The staff found that the
 
applicant's Fuel Oil Chemistry - FRCT Program conforms to the recommended GALL AMP XI.M30, "Fuel Oil Chemistry," with exceptions described below.
Exception 1. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "preventive actions,"
"parameters monitored or inspected," and "detecti on of aging effects." Specifically, the exception stated: Preventive Actions (Element 2), Parameters Monitored or Inspected (Element 3), and Detection of Aging Effects (Element 4) require that fuel oil tanks be periodically
 
sampled, drained of accumulated water and sediment, cleaned, and internally
 
inspected. Multilevel sampling and tank bottom sampling of the diesel starter
 
engines fuel oil tanks is not performed. These tanks are supplied directly from the
 
Fuel Oil Storage Tank, which will be periodically sampled and analyzed. The diesel
 
starter engines fuel oil tanks are small in size and experience a high turnover rate 3-179 of the fuel stored within as a result of routine engine operations. Stratification of fuel is not likely to occur due to the high turnover rate. Additionally, the diesel
 
starter engines fuel oil tanks are skid mounted and enclosed within the combustion
 
turbine accessories compartment, which is maintained at a constant temperature
 
during cold periods through operation of enclosure heaters. Maintaining
 
temperature during cold periods minimizes thermal cycling and reduces the
 
potential for condensation formation within the tanks. The periodic draining of
 
water and sediment from the bottom of the diesel starter engines fuel oil tanks is
 
therefore not required and the cleaning and internal inspection of the diesel starter
 
engines fuel oil tanks is not necessary to verify degradation is not occurring due to
 
the accumulation of particulate contamination and water and sediment As part of the justification for this exception, the staff noted that the FRCT license renewal document stated that the diesel starter engine fuel oil tanks are small in size with a high turnover
 
rate of fuel stored as a result of routine engine operations and that stratification of the fuel is not
 
likely due to this high turnover rate. The applicant was asked for additional information as to (1)
 
whether the tanks have the capability to be inspected, (2) what the day tank fuel turnover rate is
 
and the basis for concluding that stratification will not occur, and (3) the operating experience with
 
water and sediment buildup in the FRCT fuel storage tank.
In its response, the applicant stated that the diesel starter engine fuel oil tanks are small tanks built into each of the combustion turbine accessory skids. These tanks do not have the capability
 
for multilevel or tank bottom sampling without disassembling tank piping connections. In addition, the FRCT units are commercially operated and used to supply peak power to the grid. As such, they are frequently started and stopped, requiring frequent starting and running of the starting
 
diesel engine. The diesel engine runs for approximately 20 minutes each time its turbine is
 
started. The tank level is checked regularly during operator rounds, and the tanks are filled
 
manually from the turbine oil header when requir ed. The tanks require filling approximately once every month on average, more frequently duri ng high usage months and less frequently during low usage months depending on seasonal grid load. Because the diesel engines are routinely
 
operated, the fuel tanks are regularly drawn down and periodically refilled, precluding fuel
 
stratification. The enclosure where the tank is located is maintained at a constant temperature
 
during cold periods by enclosure heaters.
The applicant also stated that the fuel oil storage tank that supplies the diesel engine starter fuel tanks was drained and an internal inspection in October 2000 found no evidence of water
 
accumulation in the tank. The tank floor includes a sump pit designed to collect any water. The
 
sump pit was found to be in good condition with no visible corrosion, indicating that the tank has
 
not experienced significant water accumulation or sediment buildup. Over the entire surface of the
 
floor 15 corrosion pits were found, the deepest 0.060 inches as measured with a pit gauge. These
 
were weld-repaired. In addition, the tank design includes a floating roof that precludes
 
atmospheric moisture intrusion into the oil. Water was never drained from the tank bottom prior to
 
the tank inspection. As the internal inspection revealed no significant water accumulation, there is
 
no need to drain the tank bottom periodically.
The applicant also stated in its response that one-time inspections on a number of components in the fuel oil supply system will confirm the effectiveness of the Fuel Oil Chemistry - FRCT Program. An effective Fuel Oil Chemistry - F RCT Program will preclude aging degradation of the diesel engine supply tanks without the need to disassemble and inspect them. If the results of
 
one-time inspections indicate that fuel oil chemistry controls have been ineffective, corrective 3-180 actions will be implemented, including evaluation or inspection of additional system components potentially affected, including the diesel fuel tanks.
The staff reviewed the applicant's response and determined that the turnover rate for the FRCT diesel starter engine tanks is reasonable and will prevent stratification of the fuel stored in these
 
tanks. Further, the enclosed location of the FRCT diesel starter engine tanks together with the
 
use of the enclosure heaters to minimize thermal cycling of these tanks reduces the potential for
 
condensation forming inside them. In operating experience with the FRCT fuel oil storage tank, moisture intrusion has not been a problem. If corrosion due to moisture intrusion occurred, the
 
one-time inspections of the FRCT system component s will detect it promptly. On this basis, the staff concludes that this exception is acceptable.
Exception 2. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL Repor t program elements "scope of program," and "monitoring and trending." Specifically, the exception stated:
The Program Description, Scope of Program (Element 1), and Monitoring and Trending (Element 5) refer to plant technical specifications related to fuel oil
 
quality. There are no plant technical specifications at the Forked River Combustion
 
Turbine power plant.
The staff requested additional information on the specifications that will be used to determine whether fuel oil sampling results are acceptable.
In its response, the applicant stated that water and sediment concentrations are tested in accordance with ASTM Standards D 1796 or D 2709. Particulate contamination is determined by
 
the use of modified ASTM Standard D 2276, Method A, or ASTM Standard D 6217. Acceptance
 
criteria are per ASTM D 975 consistent with GE Specification GEI-41047H for the FRCT.
The staff reviewed the applicant's response and determined that the specifications to establish acceptance criteria for the fuel oil samples are based on ASTM Standard D 975 consistent with
 
GE specification GEI-41047H for the FRCT as well as the specifications referenced in RG 1.137.
 
On this basis, the staff concludes that this exception is acceptable.
Exception 3. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
3-181 Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, Section B.1.22A, the applicant stated that fuel oil chemistry activities have been proven effective
 
in managing the aging effects of fuel oil systems so that the intended functions of components
 
within the scope of license renewal will be maintained during the period of extended operation. On
 
October 30, 2000, to satisfy the requirements of the American Petroleum Institute's (API's)
 
Standard No. 653 entitled "Tank Inspection, Repair, Alteration, and Reconstruction," TAQ, Inc.,
performed an out-of-service inspection of the FRCT fuel oil storage tank including UT and VT
 
inspection of the floor by an API-653 certified tank inspector after 10 years of service (the date of
 
original tank's construction was 1989). The following is a summary of the tank floor inspections:
 
VT inspection of the floor revealed 15 "product side" pits with the deepest 0.060 inches (measured by pit gauge). The pitting was weld-repaired. The floor is equipped with a 24 inches
 
sump serviced by a 4 inches water draw-off line. There was no topside corrosion noted on the
 
sumps floor and walls and UT inspection to detect underside corrosion revealed no appreciable
 
corrosion.
On these findings the professional opinion of the qualified inspector was that the Forked River fuel oil storage tank will be suitable for the storage of number 2 fuel oil for a period not to exceed 20
 
years before the next internal inspection. In October 2001 (FRCT Unit 2) and March 2004 (FRCT
 
Unit 1) GE Energy Services performed major inspection and maintenance and documented all
 
work in inspection reports dated January 4, 2002, and June 7, 2004, respectively. The equipment
 
inspections included the turbine and its internals and support equipment. All work was carried out
 
closely following the instructions and guidance of the original equipment manufacturer's design, maintenance, and inspection manuals. Acceptance criteria and corrective actions for these
 
activities ensure that equipment is maintained within design specifications.
The staff reviewed the operating experience provided for the FRCT fuel oil system and interviewed the applicant's technical personnel to confirm that the plant-specific operating
 
experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Fuel Oil Chemistry -
 
FRCT Program will adequately manage the aging effects identified in the LRA AMRs for which
 
this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Fuel Oil Chemistry -
FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed this section
 
and determined that the information in the UFSAR supplement provides 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 program, the staff finds that those program elements for which the applicant claimed consistency with the GALL Report are
 
consistent. In addition, the staff reviewed the exceptions and their justifications and determined
 
that the AMP, with the exceptions, is adequate to manage the aging effects for which it is
 
credited. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that intended function(s) will be maintained 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3-182 3.0.3.2.32  One-Time Inspection - FRCT Summary of Technical Information in the Application. In its November 11, 2005 supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.24A, "One-Time Inspection - FRCT," will be consistent with GALL AMP XI.M32, "One-Time Inspection," with
 
exceptions.
The new One-Time Inspection - FRCT Program will provide reasonable assurance that the loss of material and loss of heat transfer aging effects will not occur or occur so slowly as not to affect
 
fuel oil and lubricating oil system component intended functions during the period of extended operation and therefore will require no additional aging management. The program is credited for
 
components in fuel oil and lubricating oil environments where either (1) an aging effect is not
 
expected to occur but there is insufficient data to rule it out completely, (2) an aging effect is
 
expected to progress very slowly in the spec ified environment but the local environment may be more adverse than that generally expected, or (3) the characteristics of the aging effect include a
 
long incubation period.
The One-Time Inspection - FRCT Program will be used only to provide assurance that loss of material and loss of heat transfer for components subject to FRCT fuel oil and lubricating oil
 
environments do not occur or that the aging effects are insignificant. It will not be used to confirm
 
that aging does not occur or is insignificant in other FRCT environments.
The One-Time Inspection - FRCT Program will be used to verify that the fuel oil and lubricating oil system activities are effective in preventing or mi nimizing aging to the extent that it will not cause loss of intended function during the period of extended operation. The program will require
 
inspection at locations of low or stagnant flow susceptible to water pooling and gradual
 
accumulation or concentration of agents that promote loss of material and loss of heat transfer.
 
The program will inspect either to verify that unacceptable loss of material or loss of heat transfer
 
does not occur or to initiate additional actions to assure that intended functions of affected
 
components will be maintained during the period of extended operation. The new program
 
elements include (1) determination of the sample size based on an assessment of materials of
 
fabrication, environment, plausible aging effects, and operating experience, (2) identification of
 
the inspection locations in the system or component based on the aging effect, (3) determination
 
of the examination technique, including acceptance criteria that will be effective in managing the aging effect for which the component is examined, and (4) evaluation of the need for followup
 
examinations to monitor the progression of aging if age-related degradation is found that could
 
jeopardize an intended function before the end of the period of extended operation. When
 
evidence of an aging effect is revealed by a one-time inspection, an evaluation of the inspection
 
results will identify appropriate corrective actions.
The inspection sample includes "worst-case" one-time inspection of more susceptible materials in the fuel oil and the lubricating oil environments (e.g., low or stagnant flow areas) to manage the
 
effects of aging. Examination methods will include visual or volumetric examinations. Acceptance
 
criteria are based on FRCT design codes and standards and manufacturer recommendations.
 
The One-Time Inspection - FRCT Program will be implemented prior to the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to 3-183 RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the One-Time Inspection -FRCT Program is consistent with GALL AMP X.M32with exceptions. The staff reviewed the program elements and basis documents to determine their consistency with GALL AMP X.M32.
In reviewing this AMP, the staff noted in the FRCT license renewal document program description for the One-Time Inspection - FRCT Program that the description of the "parameters monitored or
 
inspected" AMP element stated that inspection methods consist of NDE including visual, volumetric, and surface techniques. The One-Time Inspection - FRCT Program is not based on
 
the requirements of the ASME Code, as stated in the first exception for this AMP, and the
 
applicant was asked to describe the rationale to be used in selecting the inspection method for
 
the various types of components in the AMP scope.
In its response, the applicant stated that this AMP performs one-time inspections to confirm the effectiveness of the Fuel Oil Chemistry - FRCT and Lubricating Oil Analysis - FRCT Programs.
The inspection methods selected will depend on the component type, intended function, material, and aging effect. Heat transfer surfaces of components with a heat transfer intended function will
 
be inspected visually to identify fouling or other surface degradation that could impair the heat
 
transfer function. This same visual inspection also assures that the pressure boundary intended
 
function is maintained. The stainless steel filter element with a filter intended function also will be
 
inspected by visual techniques to identify accumulations of dirt or sediment or degradation of the
 
filter element that could impair or reduce the effectiveness of the filter intended function. Similarly, restricting orifices will be inspected by visual techniques to identify degradation of the orifice that
 
could impair or reduce the effectiveness of the throttle intended function. This same visual
 
inspection also assures that the pressure boundary intended function is maintained.
The applicant further stated that remaining mechanical components in the scope of this program have a pressure boundary intended function and are subject to a loss of material aging effect.
 
Mechanical components will be inspected by VT or UT techniques to determine the extent of loss
 
of material by evaluation of loss of wall thickness. The technique selected will depend on the
 
component type and on whether the inspection invo lves disassembly. For combustion turbine components, the most appropriate technique will be determined based on the manufacturer's
 
experience and recommendations for the component. Piping can be inspected for wall thickness
 
by UT techniques. VT techniques are appropriate for pump casings, strainer bodies, filter
 
housings, and valve bodies when disassembled for maintenance. Such component inspections
 
will confirm the effectiveness of the Fuel Oil Chemistry - FRCT and Lubricating Oil Analysis -
 
FRCT Programs.
The staff reviewed the applicant's response and determined that these inspection techniques are reasonable for the fuel oil system and the lubric ating oil system for the FRCTs and will provide reasonable assurance that the aging effects for which this program is credited will be managed.
 
On this basis, the staff concludes that the applicant's rationale for selecting inspection techniques
 
was acceptable.
Upon further review of this AMP, the staff noted in the FRCT license renewal document description for the One-Time Inspection - FRCT Program that the program element "detection of
 
aging effects" addresses sample selection; however, the rationale for selecting the sample was
 
not provided. The applicant was asked for additional information on how the sample for the
 
one-time inspection will be selected.
3-184 In its response, the applicant stated that the component sample inspection requirements for the FRCT components will be based on an evaluation of operating experience with these and similar
 
GE combustion turbine units in service for many years. The manufacturer and power industry users have developed maintenance and inspection plans designed to attain high operational
 
reliability over time. The most appropriate sample size and inspection locations will be determined
 
based on this experience and manufacturer recommendations. A considerable amount of
 
operating experience is available for combustion turbines, and the staff determined that the use of
 
operating experience is an acceptable means of assuring that an appropriate sample will be
 
obtained. On this basis, the staff determined that the applicant's response was acceptable.
The staff reviewed those portions of the applicant's One-Time Inspection - FRCT Program forwhich the applicant claimed consistency with GALL AMP XI.M32 and found them consistent.
 
Furthermore, the staff concludes that the applicant's program provides reasonable assurance that
 
the aging effects for which this program is credited will be adequately managed. The staff found
 
that the applicant's One-Time Inspection - FRCT Program conforms to the recommended GALL AMP XI.M32, with exceptions described below.
Exception 1. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL Repor t program elements "parameters monitored or inspected" and "detection of aging effects." Specifically, the exception stated:
Parameters Monitored or Inspected (Element 3) and Detection of Aging Effects (Element 4) require that inspections be performed by qualified personnel following
 
procedures consistent with the requirements of ASME Code and 10 CFR 50, Appendix B. The Forked River Combustion Turbine fuel oil and lubricating oil
 
systems are not designed to ASME require ments and are not safety-related. Thus, ASME requirements are not applicable and AmerGen has elected not to include
 
the One-Time Inspection - FRCT under 10 CFR 50 Appendix B requirements.
 
Personnel qualified to industry standards using approved procedures consistent
 
with the combustion turbine manufacturer's recommendations will perform the
 
inspections. The One-Time Inspection - FRCT will be conducted under a separate
 
quality assurance activity specifically developed for FRCTs as discussed in the
 
Corrective Actions, Confirmation Process, and Administrative Controls elements.
The staff reviewed this exception and noted that the applicant will use personnel qualified to industry standards using approved procedures consistent with the combustion turbine
 
manufacturer's recommendations for the inspections. The staff determined that the use of
 
personnel qualified to industry standards using approved procedures consistent with the
 
combustion turbine manufacturer's recommendations will provide adequate assurance that the
 
inspections will be performed by qualified personnel. On this basis, the staff determined that this
 
exception is acceptable.
Exception 2. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
3-185 As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that in October 2001 (FRCT Unit 2) and March 2004 (FRCT Unit 1) GE
 
Energy Services performed major inspection and maintenance and documented all work in
 
inspection reports dated January 4, 2002, and June 7, 2004, respectively. The equipment
 
inspections included the turbine and its internals and support equipment. All work was carried out
 
closely following the instructions and guidance of the original equipment manufacturer's design, maintenance, and inspection manuals. Acceptance criteria and corrective actions for these
 
activities ensure that equipment is maintained within design specifications.
The applicant further stated that the FRCT Unit 1 inspection was major maintenance, the first major inspection of the unit since initial installation in 1988. During the FRCT Unit 1 inspection, the fuel forwarding pumps and emergency DC lube oil pumps were removed and sent to the GE
 
service shop for cleaning, inspection, and repairs. The GE report does not indicate any
 
degradation of these pump casings. The combustion turbine lube oil system was drained, cleaned, and inspected, various pumps were inspected, and the lube oil coolers were cleaned. No
 
degradation of these components was identified. The main lube oil pump was disassembled and
 
inspected, and no defects were observed.
The applicant further stated that the FRCT Unit 2 inspection was of the fuel nozzle and combustion section. The lube oil filters were replaced. Included were a borescope and
 
combustion inspection, removal of exhaust frame cooling piping, disconnection of the fuel lines for
 
inspection, and fuel nozzle inspection, repair, and testing. The GE report does not identify any
 
issues with the disassembled fuel oil piping. FRCT Unit 2 began a major outage inspection in
 
October 2005 with components disassembled and visually inspected for age-related degradation.
 
The internal surfaces of disassembled stainless steel piping and flexible hoses showed no
 
corrosion or wall thinning. The combustion turbine lube oil heat exchangers were disassembled, cleaned, and inspected. The carbon steel and copper alloy heat exchanger components normally
 
exposed to lubricating oil were found in excellent condition. The standby heat exchanger not
 
normally in service was found to have some minor accumulation of sediment that was cleaned off.
 
Carbon steel pump casings normally submerged in the lubricating oil reservoir were visually
 
observed to be in excellent condition no corrosion. The carbon steel internal surfaces of the
 
lubricating oil reservoir were also observed to be in excellent condition no corrosion.
The staff reviewed the operating experience provided for the FRCT to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's One-Time Inspection -
 
FRCT Program will adequately manage the aging effects identified in the LRA AMRs for which
 
this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the One-Time Inspection -
FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed this section 3-186 and determined that the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exceptions and their justifications and
 
determined that the AMP, with the exceptions, is adequate to manage the aging effects for which
 
it is credited. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that intended function(s) will be maintained 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.33  Selective Leaching of Materials - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.25A," Selective Leaching
 
of Materials - FRCT," is consistent with GALL AMP XI.M33, "Selective Leaching of Materials," with an exception.
The Selective Leaching of Materials - FRCT Program will ensure the integrity of components that may be susceptible to selective leaching at the FRCT station. The AMP includes a one-time visual
 
inspection and hardness measurement of selected components to determine whether loss of
 
materials due to selective leaching occurs and whether the process will affect the ability of the
 
components to perform intended functions for the period of extended operation. The One-Time
 
Inspection Program includes visual inspections, hardness tests, and other appropriate
 
examination methods as may be required to confirm or rule out selective leaching and to evaluate
 
the remaining component wall thickness when leaching is identified. Components of susceptible
 
materials at the FRCT site are comprised of copper alloy materials exposed to treated water (closed cooling water) environments. The purpose of the program is to determine whether loss of
 
material due to selective leaching of the zinc component of the alloy (dezincification) occurs. If
 
selective leaching is found, the program evaluates the effect it will have on the ability of the
 
affected components to perform intended functions for the period of extended operation.
The new Selective Leaching of Materials - FRCT will be implemented in the final 10 years of the period of extended operation.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the Selective Leaching of Materials - FRCT Program is consistent with GALL AMP X.M33 with exceptions. The staff
 
reviewed the program elements and basis documents to determine their consistency with GALL AMP X.M33.
The staff reviewed those portions of the Selective Leaching of Materials - FRCT Program forwhich the applicant claimed consistency with GALL AMP XI.M18 and found them consistent with
 
the GALL Report AMP. Furthermore, the staff concluded that the applicant's program provides
 
reasonable assurance that the loss of material aging effects due to selective leaching will be
 
effectively managed so that the intended functions of components within the scope of license 3-187 renewal at the FRCT station are maintained consistent with the CLB during the period of extended operation. The staff found that the applicant's Selective Leaching of Materials - FRCT
 
Program conforms to the recommended GALL AMP XI.M33 with an exception described below.
Exception. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience
: In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the selective leaching one-time inspection process is consistent with
 
industry and staff guidance in the inspection techniques utilized and the selection of components
 
inspected.
Selective leaching has not been identified at the FRCT station. In March 2004, GE Energy Services performed major inspection and maintenance in FRCT Unit 1. The work was
 
documented in an inspection report dated June 7, 2004. All work was carried out closely following
 
the instructions and guidance of the original equipment manufacturer's design, maintenance, and
 
inspection manuals. Acceptance criteria and corrective actions for these activities ensure that
 
equipment is maintained within design specifications.
The FRCT Unit 1 inspection was major maintenance, the first major inspection of the unit since initial installation in 1988. During the FRCT Unit 1 inspection the combustion turbine lubricating oil
 
system was drained, cleaned, and inspected. The equipment inspections included the lube oil
 
coolers subject to the closed cooling water environment. The coolers were removed from the
 
sump, cleaned, and inspected and no degradation of these components was identified. FRCT
 
Unit 2 began a major outage inspection in October 2005. The combustion turbine lubricating oil
 
heat exchangers were dissembled, cleaned, and inspected. On visual observations, the copper
 
alloy heat exchanger components normally exposed to closed cooling water appeared to be in
 
excellent condition. The tube ends at the tube sheet showed no signs of significant wall thinning.
 
The operating experience with the combustion tu rbine system heat exchangers subject to a closed cooling water environment and potentially s ubject to selective leaching demonstrates that selective leaching has not been a concern. This operating experience demonstrates that either
 
the FRCT closed cooling water environment is not conducive to selective leaching or that
 
selective leaching occurs so slowly as to be not yet evident. Because selective leaching is a slow
 
corrosion process, this program will include inspections for selective leaching within the final 10
 
years of the period of extended operation.
3-188 The staff reviewed the operating experience provi ded in the basis document and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Selective Leaching of
 
Materials - FRCT Program will adequately manage the aging effects and mechanism identified in
 
the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Selective Leaching of Materials - FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed this
 
section and determined that the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exception and its justifications and
 
determined that the AMP, with the exception, is adequate to manage the aging effects for which it
 
is credited. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that intended function(s) will be maintained 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.34  Buried Piping Inspection - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that AMP B.1.26A, "Buried Pipe Inspection -
FRCT," is consistent with GALL AMP XI.M34, "Buried Piping and Tanks," with an exception.
The new Buried Piping Inspection - FRCT Program includes preventive measures to mitigate corrosion and periodic inspection of external surfaces for loss of material to manage the effects of
 
corrosion on the pressure-retaining capacity of carbon steel piping in a soil (external)
 
environment. Preventive measures are in acco rdance with standard industry practices for maintaining external coatings and wrappings. External inspections of buried piping will occur
 
opportunistically during maintenance excavations. Within 10 years prior to the period of extended
 
operation, inspection of buried piping will be performed unless an opportunistic inspection occurs
 
within this period. During the period of extended operation, inspection of buried piping will be
 
performed again within the first 10 years unless an opportunistic inspection occurs during this
 
period.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the Buried Piping Inspection -
FRCT Program is consistent with GALL AMP X.M34 with an exception. The staff reviewed the
 
program elements and associated basis documents to determine their consistency with GALL AMP X.M34.
3-189 The staff reviewed those portions of the Buried Piping Inspection - FRCT Program for which theapplicant claimed consistency with GALL AMP XI.M34 and found them consistent. Furthermore, the staff concluded that the applicant's program provides reasonable assurance that aging effects
 
will be adequately managed so that intended functions of buried pipe within the scope of license
 
renewal are maintained consistent with the CLB during the period of extended operation. The staff
 
found that the applicant's Buried Piping Inspection - FRCT Program conforms to the recommended GALL AMP XI.M34 with an exception described below.
Exception. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the new Buried Piping Inspection - FRCT Program will be effective in
 
managing aging degradation for the period of ex tended operation by promptly detecting aging effects and implementing appropriate corrective ac tions prior to loss of system or component intended functions. To date, there have been no buried pipe leaks due to external degradation at
 
the FRCT station. The buried piping included in the scope of license renewal is the glycol-filled
 
cooling water piping routed below grade between the combustion turbines and the mechanical
 
draft cooling towers. A head tank normally pressurizes the system and the head tank includes
 
level monitoring instrumentation. There is no history of buried pipe leaks in this system.
In plant operating experience, coatings and wrappings have protected the external surfaces of buried piping adequately and loss of material due to external corrosion has not been a concern.
 
Thus, inspection of buried piping when excavated for maintenance provides reasonable
 
assurance that intended functions will be maintained. Inspections will be performed within 10
 
years of the period of extended operation and again within the first 10 years of the period of
 
extended operation unless opportunistic inspections occur within these periods.
The staff reviewed the operating experience provi ded in the basis document and interviewed the applicant's technical personnel to confirm that plant-specific operating experience revealed no
 
degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Buried Piping
 
Inspection - FRCT Program will adequately manage the aging effects and mechanism identified in
 
the LRA for which this AMP is credited 3-190 UFSAR Supplement. The applicant provided its UFSAR supplement for the Buried Piping Inspection - FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed
 
this section and determined that the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exception and its justifications and
 
determined that the AMP, with the exception, is adequate to manage the aging effects for which it
 
is credited. 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 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.35  Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components -
FRCT Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.38, "Inspection of Internal
 
Surfaces in Miscellaneous Piping and Ducting Components - FRCT," will be consistent with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,"
 
with an exception.
The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT Program, as implemented for the FRCT system, will consist of visual inspections of the internal surfaces of steel piping, valve bodies, ductwork, filter housings, fan housings, damper housings, mufflers, and heat exchanger shells not covered by other AMPs. These components are subject
 
to an internal environment of indoor air assumed to have sufficient moisture for loss of material
 
aging effects. In addition, this program includes piping and mufflers with diesel engine exhaust
 
gas as an internal environment. Internal inspections will be during scheduled maintenance
 
activities when the surfaces are accessible fo r visual inspection. The program includes visual inspections to assure that existing environmental conditions do not cause material degradation
 
that could result in loss of component intended functions.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1, the applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT Program is consistent with GALL AMP X.M38 with an
 
exception. The staff reviewed the program elements and associated basis documents to determine their consistency with GALL AMP X.M38.
The staff reviewed those portions of the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT Program for which the applicant claimed consistency with GALL AMP XI.M38 and found them consistent. Furthermore, the staff concluded
 
that the applicant's program provides reasonable assurance that the aging effects for which this
 
program is credited will be adequately managed. The staff found that the applicant's Inspection of
 
Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT Program conforms to the recommended GALL AMP XI.M38, with an exception described below.
3-191 Exception. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that in October 2001 (FRCT Unit 2) and March 2004 (FRCT Unit 1), GE
 
Energy Services performed major inspection and maintenance and documented all work in
 
inspection reports dated January 4, 2002, and June 7, 2004, respectively. The equipment
 
inspections included the turbine and its internals and support equipment. All work was carried out
 
closely following the instructions and guidance of the original equipment manufacturer's design, maintenance, and inspection manuals. Acceptance criteria and corrective actions for these
 
activities ensure that equipment is maintained within design specifications.
The applicant further stated that the FRCT Unit 1 inspection was major maintenance, the most comprehensive inspection performed on the combustion turbine units. The interval between major
 
inspections is based on operating experience with these and similar combustion turbine
 
installations and such factors affecting part life as fuel type and starting frequency. The purpose of
 
this type of maintenance inspection is to identify equipment degradation and, if identified, to
 
replace or refurbish the affected component in accordance with manufacturer specifications so
 
the unit will perform reliably through the next operating interval. This major inspection was the first
 
for the unit since initial installation in 1988.
The applicant further stated that during the FRCT Unit 1 inspection bare paint spots with surface rust were identified in the filter housing and cleaned and touched up with new paint to prevent
 
further rusting. The exhaust frame fan housings were cleaned and inspected, and no degradation
 
was identified. Corrosion identified in the compressor bleed valves impacted smooth valve
 
operation, but the valve body pressure boundary was not affected, and the valves were
 
refurbished and reused. Ventilation fans were refurbished, and no issues with fan housing
 
integrity were identified.
The applicant further stated that the FRCT Unit 2 inspection was of the fuel nozzle and combustion section. The FRCT Unit 2 inspection found the inlet filter housing to be in good
 
condition, with no visual defects. Included were a borescope and combustion inspection, removal
 
of exhaust frame cooling piping and disconnection of the fuel lines for inspection, and fuel nozzle
 
inspection, repair, and testing. FRCT Unit 2 began a major outage inspection in October 2005
 
with components disassembled and visually inspected for signs of age-related degradation. The
 
internal surfaces of disassembled ductwork, fan housings, and several damper housings were
 
observed and showed no signs of significant corrosion. The turbine inlet air filters were replaced
 
during the outage, and the coated internal surfaces of the filter housing were inspected and found 3-192 in good condition. Internal surfaces of frame cooling piping were also observed to be in good condition with minor surface rust and no significant pitting or loss of wall thickness. The internal
 
surfaces of the diesel starter engine exhaust piping and muffler were also observed to be in good
 
condition with surface rust and no signs of significant pitting or wall thinning.
The applicant further stated that operating experience with the FRCTs includes a significant number of past inspections of steel components in the indoor air and diesel exhaust environment.
The documented inspection results provide objecti ve evidence that environmental conditions do not cause material degradation that could result in a loss of component intended functions. Past
 
inspections have been at a frequency as long as 16 years with the units performing reliably
 
between inspections. Implementation of this new pr ogram will assure that these inspections are continued on a more conservative frequency of 10 years, providing reasonable assurance that the
 
aging effects will be adequately managed for the period of extended operation.
The staff reviewed the operating experience provided for the FRCT to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above industry and plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's
 
Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT
 
Program will adequately manage the aging effects identified in the LRA AMRs for which this AMP
 
is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components - FRCT Program in its supplemental
 
response to RAI 2.5.1.19-1. The staff reviewed this section and determined that the information in
 
the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the exception and its justifications and
 
determined that the AMP, with the exception, is adequate to manage the aging effects for which it
 
is credited. The staff finds that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that intended function(s) will be maintained 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 finds that it provides an adequate summary description of the program, as required
 
by 10 CFR 54.21(d).
3.0.3.2.36  Lubricating Oil Analysis - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that the new AMP B.1.39," Lubricating Oil
 
Analysis Program - FRCT," AMP is consistent with GALL AMP XI.M39, "Lubricating Oil Analysis Program," with exceptions.
The Lubricating Oil Analysis - FRCT Program will include measures to verify that the oil environment in mechanical equipment is maintained to the required quality. The Lubricating Oil
 
Analysis - FRCT Program maintains oil system s contaminants (primarily water and particulates) within acceptable limits, thereby preserving an environment not conducive to loss of material, 3-193 cracking, or reduction in heat transfer. Lubricating oil testing activities include sampling and analysis of lubricating oil for detrimental contaminants. The presence of water or particulates may
 
also indicate leakage and corrosion product buildup.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.19-1, the applicant stated that Lubricating Oil Analysis - FRCT Program is consistent with GALL AMP X.M39 with exceptions. The staff reviewed the program elements and basisdocuments to determine their consistency with GALL AMP X.M39.
The staff reviewed those portions of the Lubricating Oil Analysis - FRCT Program for which theapplicant claimed consistency with GALL AMP XI.M39 and found them consistent with the GALL
 
Report AMP. Furthermore, the staff concluded that the applicant's program ensures that
 
combustion turbine oil systems will be effe ctively managed to provide an acceptable oil environment so that intended functions of components within the scope of license renewal at the
 
FRCT station are maintained consistent with the CLB during the period of extended operation.
 
The staff found that the applicant's Lubricating Oil Analysis - FRCT Program conforms to the recommended GALL AMP XI.M39, with exceptions described below.
Exception 1. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL Repor t program element "parameters monitored or inspected." Specifically, the exception stated:
Parameters Monitored/Inspected requires the flash point be measured for the lubricating oils. Flash Point is not measured for lubricating oils in service, since this
 
is a quality control measurement when purchasing new oil. It is not a primary
 
measurement to determine the presence of water or contaminants, which are the
 
concerns for controlling the environment of concern.
The applicant stated in its supplemental response that no components with periodic oil changes had intended functions. Components with intended functions with no regular oil changes are
 
supplied oil from the lubricating oil system. A particle count and check for water on the lubricating
 
oil in the lubricating oil system will detect ev idence of abnormal wear rates, contamination by moisture, or excessive corrosion. In addition, viscosity and neutralization number will be
 
determined to verify the oil's suitable for continued use. Wear particles will be identified through
 
analytical ferrography and elemental analysis. The applicant takes exception to the flash point
 
monitoring recommendation specified in the GALL Report as a quality control measurement when
 
purchasing new oil and not a primary measurement to determine presence of contaminants.
The staff did not agree with the applicant's position. The staff determined that that basis for exceptions was not valid because the flash point of an industrial lubricant is an important test to
 
determine whether light-end hydrocarbons get into the oil through seal leaks or other means. It is
 
an effective way to monitor seal performance in light-end hydrocarbon compressors. Low flash
 
points pose a safety hazard that can generate heat above the flash point of the oil in the event of
 
a component like a bearing. The applicant was asked to justify not monitoring the flash point of
 
lubricating oil at the FRCT, why this exception will be acceptable for managing the effects of aging
 
for which it is credited.
3-194 In its letter dated April 17, 2006, the applicant committed (Commitment No. 59) to revise the Lubricating Oil Analysis - FRCT Program to include flash point measurement.
Exception 2. In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of
 
10 CFR Part 50, Appendix B.
As discussed in SER Section 3.0.4, the applicant stated that a QA program based on the recommendations of RG 1.155, Appendix A, will be used to implement the corrective actions, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. This
 
QA program contains attributes that are equivalent to the guidance in Branch Technical Position
 
IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds this
 
exception acceptable.
Operating Experience
: In its supplemental response to RAI 2.5.1.19-1 dated November 11, 2005, the applicant stated that the new Lubricating Oil Analysis - FRCT Program will be effective in
 
managing aging degradation for the period of extended operation by periodically sampling and
 
analyzing lubricating oil for timely detection of degradation in lubricating oil properties and in
 
taking appropriate corrective actions prior to lo ss of system or component intended functions. In October 2001 (FRCT Unit 2) and March 2004 (FRCT Unit 1), GE Energy Services performed
 
major inspection and maintenance and documented all work in inspection reports dated
 
January 4, 2002, and June 7, 2004, respectively. The equipment inspections included the turbine
 
and its internals and support equipment. All work was carried out closely following the instructions
 
and guidance of the original equipment manufacturer's design, maintenance, and inspection
 
manuals. Acceptance criteria and corrective actions for these activities ensure that equipment is
 
maintained within design specifications.
The FRCT Unit 1 inspection was major maintenance, the first major inspection of the unit since initial installation in 1988. During the FRCT Unit 1 inspection, the emergency DC lubricating oil
 
pump was removed and sent to the General Electric service shop for cleaning, inspection, and
 
repairs. The GE report does not indicate any degradation of this pump casing. The combustion
 
turbine lubricating oil system was drained, cleaned, and inspected, various pumps were
 
inspected, and the lubricating oil coolers were cleaned. No degradation of these components was
 
identified. The main lubricating oil pump was disassembled and inspected, and no defects were
 
observed.The FRCT Unit 2 inspection was of the fuel nozzle and combustion section. The lubricating oil filters were replaced. The GE report does not identify any issues with the lubricating oil system or
 
components. FRCT Unit 2 began a major outage inspection in October 2005 with components
 
disassembled and visually inspected for signs of age related degradation. The internal surfaces of
 
disassembled stainless steel piping and flexible hoses observed had no corrosion or wall thinning.
 
The combustion turbine lubricating oil heat exchangers were dissembled, cleaned, and inspected.
 
The carbon steel and copper alloy heat exchanger components normally exposed to lubricating oil
 
were found in excellent condition. The standby heat exchanger not normally in service was found to have some minor accumulation of sediment that was cleaned off. Carbon steel pump casings
 
normally submerged in the lubricating oil reserv oir were visually observed to be in excellent 3-195 condition with no corrosion. The carbon steel internal surfaces of the lubricating oil reservoir were also observed to be in excellent condition with no corrosion.
The operating experience with the combustion turbi ne system components subject to a lubricating oil environment demonstrates that the combus tion turbine lubricating oil systems have not experienced significant intrusion of water and contaminants that will result in aging degradation.
 
This new program will provide additional assurance that water and contaminant concentrations
 
and age-related degradation will continue to be minimized.
The Lubricating Oil Analysis - FRCT Program w ill monitor for adverse trends in performance.
Problems identified will not impact intended functions of the FRCT system, and adequate
 
corrective actions will be taken to prevent recurrence. There is sufficient confidence that the
 
implementation of the Lubricating Oil Analysis - FRCT Program will effectively maintain oil systems contaminants (primarily water and particulates) within acceptable limits.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Lubricating Oil
 
Analysis - FRCT Program will adequately manage the aging effects and mechanism identified in
 
the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Lubricating Oil Analysis - FRCT Program in its supplemental response to RAI 2.5.1.19-1 and letter dated
 
April 17, 2006. The staff determined that the information in the UFSAR supplement provides 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 program and RAI response, the staff finds that those program elements for which the applicant claimed consistency with the GALL
 
Report are consistent. In addition, the staff reviewed the applicant's commitment, the exceptions, and their justifications and determined that the AMP, with the exceptions and its commitment, is
 
adequate to manage the aging effects for which it is credited. 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 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 finds that it
 
provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.2.37  Buried Piping and Tank Inspection - Met Tower Repeater Engine Fuel Supply
 
Summary of Technical Information in the Application. In its December 9, 2005, supplemental applicant's response to RAI 2.5.1.15-1, the applicant stated that AMP B.1.26B, "Buried Piping and
 
Tank Inspection - Met Tower Repeater Engine Fuel Supply," is consistent with GALL AMP XI.M34, "Buried Piping and Tanks Inspection," with exceptions.
The Buried Piping and Tank Inspection - Met Tower Repeater Engine Fuel Supply Program is a new AMP that relies on coating, wrapping, and per iodic inspection as preventive measures to mitigate and manage the effects of corrosion on the pressure-retaining capacity of carbon steel
 
and copper piping and fittings and carbon steel tanks in a soil (external) environment. External
 
coatings and wrappings are maintained in accordance with standard industry practices. External
 
inspections of buried piping components will occur opportunistically during maintenance
 
excavations. Buried piping components will be inspected within 10 years prior to the period of
 
extended operation unless an opportunistic inspection occurs within this period. In the period of 3-196 extended operation, inspection of buried piping components will again be performed within the first 10 years unless an opportunistic inspection occurs during this period. The AMP activities will
 
be coordinated with First Energy, as necessary, pursuant to an Easement, License, and
 
Restrictive Covenant Agreement.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its supplemental response to
 
RAI 2.5.1.15-1 dated December 9, 2005, the applicant stated that the Buried Piping and Tank
 
Inspection - Met Tower Repeater Engine Fuel Supply Program is consistent with GALL AMP X.M34 with exceptions. The staff review ed the program elements and basis documents todetermine their consistency with GALL AMP X.M34.
The staff reviewed those portions of the Buried Piping and Tank Inspection - Met Tower RepeaterEngine Fuel Supply Program for which the applicant claimed consistency with GALL AMP XI.M34
 
and found them consistent. Furthermore, the staff concluded that the applicant's program ensures
 
that aging effects will be adequately managed to maintain intended functions of buried pipe within
 
the scope of license renewal consistent with the CLB during the period of extended operation.
 
The staff found that the applicant's Buried Piping and Tank Inspection - Met Tower Repeater Engine Fuel Supply Program conforms to the recommended GALL AMP XI.M34, "Buried Piping
 
and Tanks," with exceptions described below.
Exception 1. In its response to RAI 2.5.1.15-1 dated December 9, 2005, the applicant stated an exception to the GALL Report program elements "p reventive actions," "parameters monitored or inspected," and "detection of aging effects." Specifically, the exception stated:NUREG-1801, Section X1.M.34, "Buried Piping and Tanks Inspection," AMP relies on preventive measures such as coati ngs and wrappings, however portions of this piping may not be coated or wrapped. Inspections of buried piping that is not
 
wrapped will inspect for loss of material due to general, pitting, crevice, and
 
microbiologically influenced corrosion.
In its response the applicant stated that, in accordance with industry practice, portions of the underground piping and tank at the Forked River Met Tower were either procured with coating or
 
coated during installation with a protective coating system to protect the piping and tank from
 
contacting the potentially aggressive soil environment. Portions of the piping not coated or
 
wrapped will be inspected for loss of material due to general, pitting, crevice, and MIC.
 
Inspections will confirm that coating and wrapping are intact and determine the extent of potential
 
corrosion of buried piping components not coated or wrapped. These inspections effectively
 
ensure that corrosion of external surfaces has not occurred and that intended function has been
 
maintained. The buried piping and tank will be opportunistically inspected whenever excavated for
 
maintenance. The inspections will be of all areas made accessible for the maintenance activity.
The staff noted that the applicant follows the recommendations specified in the GALL Report for inspections of underground piping coatings and wrappings and that underground piping not
 
coated or wrapped will be inspected for loss of material due to general, pitting, crevice, and MIC.
 
On this basis, the staff finds this exception acceptable.
3-197 Exception 2. In its supplemental response to RAI 2.5.1.15-1 dated December 9, 2005, the applicant stated an exception to the GALL R eport program elements "corrective actions,"
"confirmation process," and "administrative cont rols." Specifically, the exception stated:
These elements are not accomplished in accordance with the AmerGen quality assurance (QA) program and are not in accordance with the requirements of 10 CFR Part 50, Appendix B.
In its supplemental response to RAI 2.5.1.15-1 dated June 7, 2006, the applicant stated that this exception was eliminated and that these elements will be accomplished in accordance with the
 
requirements of 10 CFR Part 50, Appendix B. In the response the applicant also stated that it will
 
meet the guidance in Branch Technical Position IQMB-1, "Quality Assurance for Aging
 
Management Programs." The adequacy of the applicant's 10 CFR 50, Appendix B program for
 
these elements is addressed in SER Section 3.0.4. On this basis, the staff finds this exception
 
acceptable.
Operating Experience. In its response to RAI 2.5.1.15-1 dated December 9, 2005, the applicant stated that the new Buried Piping and Tank Inspection - Met Tower Repeater Engine Fuel Supply
 
Program will be effective in managing aging degr adation for the period of extended operation by timely detecting aging effects and implementing appropriate corrective actions prior to loss of
 
system or component intended functions. The buried piping and tank at the Forked River Met
 
Tower included in the scope of license renewal are below-grade, propane-filled, and next to the
 
Forked River meteorological tower. There is no history of buried pipe or tank leaks in this system.
In Forked River meteorological tower repeater engine fuel supply buried piping and tank operating experience, loss of material due to external corrosion has not been a concern. Inspection of the
 
buried piping and tank when excavated for maintenance therefore ensures that intended functions
 
will be maintained. Inspections will be within 10 years of the period of extended operation, and
 
again within the first 10 years of period of extended operation, crediting opportunistic inspections
 
that may occur within each of these periods. The staff concludes that the applicant's Buried Piping
 
and Tank Inspection - Met Tower Repeater Engine Fuel Supply Program will adequately manage
 
the aging effects and mechanism identified in the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Buried Piping and Tank Inspection - Met Tower Repeater Engine Fuel Supply Program in its supplemental response
 
to RAI 2.5.1.15-1. The staff reviewed this section and determined that the information in the
 
UFSAR supplement provides 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 program and RAI response finds that the applicant has demonstrated that the effects of aging will be adequately managed so
 
that intended function(s) will be maintained during the period of extended operation, as required
 
by 10 CFR 54.21(a)(3). The Buried Piping and Tank Inspection - Met Tower Repeater Engine
 
Fuel Supply Program has been effective in monitoring OCGS buried pipe and is expected to be
 
equally effective for the Met Tower repeater engine fuel supply buried pipe and tanks. To date, there have been no leaks from the Met Tower repeater engine fuel supply buried pipe and tanks.
 
The staff's review of the UFSAR supplement for this program also finds that it provides an
 
adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in the GALL Report 3-198 In LRA Appendix B, the applicant identified the following AMPs as plant-specific:
* Periodic Testing of Containment Spray Nozzles (B.2.1)
* Lubricating Oil Monitoring Activities (B.2.2)
* Generator Stator Water Chemistry Activities (B.2.3)
* Periodic Inspection of Ventilation Systems (B.2.4)
* Periodic Inspection Program (B.2.5)
* Wooden Utility Pole Program (B.2.6)
* Periodic Monitoring of Combustion Turbine Power Plant (B.2.7)
* Periodic Monitoring of Combustion Turbine Power Plant Electrical (B.1.37)
* Periodic Inspection Program - FRCT (B.2.5A)
The staff reviewed AMPs not consistent with or not addressed in the GALL Report completely to determine whether these AMPs are 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  Periodic Testing of Containment Spray Nozzles
 
Summary of Technical Information in the Application. In LRA Section B.2.1, the applicant described the existing, plant-specific Periodic Testing of Containment Spray Nozzles Program.
Periodic tests address a GALL Report Section V.D2 concern that flow orifices and spray nozzles in the drywell and torus spray subsystems are subject to plugging by rust from carbon steel piping
 
components and therefore a plant-specific AMP is to be evaluated. The OCGS containment (drywell and torus) spray nozzles are stainless steel. There are no carbon steel flow orifices in the
 
system piping within the scope of license renewal. However, upstream carbon steel piping is
 
subject to possible general corrosion. These periodic tests every fifth refueling outage use
 
approved plant procedures to verify that the drywell and torus spray nozzles are free from
 
plugging that could result from corrosion product buildup from upstream sources.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.2.1 on the applicant's Periodic Testing of Containment Spray Nozzles Program to
 
determine whether the effects of aging will be adequately managed so that the intended functions
 
will be maintained consistent with the CLB for the period of extended operation.
The staff's review of LRA Section B.2.1 identified areas in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
The periodic tests, performed every fifth refueling outage verify that the drywell and torus spray nozzles are free from plugging that could result from corrosion product buildup from upstream
 
sources. However malfunction of the spray nozzles due to failure of the supports is not discussed
 
in this AMP.
In RAI B.2.1-1 dated March 30, 2006, the staff requested that the applicant discuss any aging mechanisms for the piping support materials in the containment air environment. In addition, the
 
applicant was asked to provide the bases for identifying these aging mechanisms or no aging
 
mechanism for the environment and material combination.
3-199 In its response dated April 28, 2006, the applicant stated:The ASME Section Xl Subsection IWF program B.1.28 addresses aging management for piping supports for the ASME Class 2 containment spray piping in
 
the containment air environment, as shown in LRA Table 3.5.2.1.18. For carbon
 
and low alloy steel support materials in an air - indoor uncontrolled environment, which is how the containment air environment is conservatively treated for piping
 
supports, the aging effect of loss of material is due to the mechanisms of general
 
and pitting corrosion, in accordance with GALL line item lll.B1.2-8 (T-24). No aging
 
effect or program is credited for cumulative fatigue damage of these piping
 
supports under GALL item Ill.B1.2-7 (T-26), as cumulative fatigue is not a TLAA in
 
the Oyster Creek CLB. The aging effect of loss of mechanical function of carbon
 
and low alloy steel supports is due to the aging mechanisms of corrosion, distortion, dirt, overload, and fatigue due to vibratory and cyclic thermal loads, in
 
accordance with GALL line item lll.B1.3-2 (T-28).
The staff finds the applicant's response reasonable and acceptable because the applicantclarified that the ASME Section Xl Subsection IWF Program addresses aging management for
 
piping supports for the ASME Code Class 2 containment spray piping in the containment air
 
environment.
 
As stated in the LRA, the applicant conducts flow tests with air rather than water. The staff
 
believes that the reaction forces on the supports and the spray nozzles are substantially less with
 
air flow versus water and that the periodic flow tests simply assure that there is no clogging of the
 
spray nozzles but do not test the structural integrity of the spray system under actual operating
 
conditions. The staff's concern is that the piping supports and nozzles may not be able to
 
withstand forces exerted during accident conditions when water is turned on, and a potential for
 
failure of the spray system exists.
In RAI B.2.1-2 dated March 30, 2006, the staff requested that the applicant provide justification to assure maintenance of the structural integrity of the system under accident conditions during the
 
period of extended operation.
In its response dated April 28, 2006, the applicant stated:
Pre-operational testing of the containment spray piping was performed with water at design flow to assure the structural integrity of the system under accident conditions.
 
During those water flow tests, the piping supports and nozzles were shown to be able to
 
withstand the forces exerted during actual operating conditions. The airflow tests were
 
subsequently implemented to demonstrate that the nozzles were clear without wetting the spray piping and containment equipment. The ASME Section Xl Subsection IWF program
 
B.1.28 addresses aging management and the continued structural integrity of the ASME
 
Class 2 containment spray piping supports during the period of extended operation, as
 
shown in LRA Table 3.5.2.1.18The staff finds the applicant's response reasonable and acceptable because the ASME Section Xl Subsection IWF Program addresses aging management and the continued structural integrity of
 
the ASME Code Class 2 containment spray piping supports during the period of extended
 
operation. Therefore air testing of the spray system is considered adequate 3-200 Operating Experience. In LRA Section B.2.1, the applicant explained that in 2000 the torus spray nozzle air test revealed no flow of air in two torus nozzles. An evaluation determined that design
 
basis accidents could be successfully mitigated with the nozzles plugged. The cause of the
 
plugging was determined to be rust particles from the cyclic wetting and drying of the piping when
 
the system had been flow-tested monthly by a method no longer used. A revision to the system
 
testing procedure to return torus test water through the drywell vent system precludes flushing
 
water through the nozzle piping and the nozzles are air-tested. The nozzles were flushed clear
 
and re-tested satisfactorily. The OCGS facility demonstrates good operating experience in
 
maintaining the operability of the drywell and torus spray headers and spray nozzles. The periodic
 
air flow tests effectively manage the plugging aging effect so that the intended function of
 
providing a quenching spray will be maintained during the period of extended operation.
The staff's review of the operating experience at OCGS found that the applicant had successfully determined the root cause of previous problems with the spray nozzles and taken appropriate
 
corrective measures. The operating experience also indicates that the applicant's maintenance
 
practices have been generally successful in managing the plugging aging effects of the spray
 
nozzles UFSAR Supplement. In LRA Section A.2.1, the applicant provided the UFSAR supplement for the Periodic Testing of Containment Spray Nozzles Program. The staff reviewed this section and
 
determined that the information in the UFSAR 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 Periodic Testing of Containment Spray Nozzles Program and RAI responses 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  Lubricating Oil Monitoring Activities
 
Summary of Technical Information in the Application. In LRA Section B.2.2, the applicant described the existing, plant-specific Lubricating Oil Monitoring Activities Program.
The Lubricating Oil Monitoring Activities Program manages loss of material, cracking, and fouling in lubricating oil coolers, systems, and components within the scope of license renewal. These
 
activities include measures to minimize corrosion and to mitigate loss of material and cracking in
 
heat exchangers by monitoring lubricating oil properties. Sampling, testing, and trending verify
 
lubricating oil properties and ensure that the intended functions of the coolers are not lost. Oil
 
analysis permits identification of specific wear mechanisms, contamination, and oil degradation
 
within operating machinery and components. The activities manage physical and chemical
 
properties in lubricating oil. The complete AMP for lubricating oil heat exchangers also includes
 
secondary side (heat sink) chemistry controls or testing.
Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.2.2 on the applicant's demonstration of the Lubricating Oil Monitoring Activities
 
Program to ensure that the effects of aging will be adequately managed so that the intended
 
functions will be maintained consistent with the CLB for the period of extended operation.
3-201 The staff reviewed the Lubricating Oil Monitoring Activities Program against the AMP elements in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1 and focused on how the program manages
 
aging effects through the effective incorporation of 10 elements (i.e., "program scope," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and
 
trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative
 
controls," and "operating experience").
The applicant indicated that "corrective actions," "confirmation process," and "administrative controls" are part of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements are
 
discussed below.  (1)Scope of Program - The "scope of program" program element in SRP-LR Section A.1.2.3.1 requires that the program scope include the specific structures and
 
components addressed with this program.
The applicant stated that the EDG lubricating oil coolers and the fire protection pump gear box lubricating oil coolers are subject to this program.
In addition, the applicant stated that the following systems and their components are also subject to this program: EDGs system, main turbine and auxiliaries system, main generator and auxiliaries system, reactor recirculation system, CRD system, RWCU system, fire protection system, feedwater system, RBCCW system, SW system, and miscellaneous floor and equipment drains system.
The staff determined that the specific components for which the program manages aging effects are identified by the applicant, satisfying SRP-LR Section A.1.2.3.1. On this basis, the staff finds the applicant's proposed program scope acceptable.  (2)Preventive Actions - The "prevent ive actions" program element in SRP-LR Section A.1.2.3.2 states that: (1) the activities for prevention and mitigation programs
 
should be described and (2) for condition or performance monitoring programs that do not
 
rely on them preventive actions need not be provided.
The applicant stated that the existing Lubricating Oil Monitoring Activities Program manages aging of components by maintaining proper lubricating oil physical and
 
chemical properties and by verifying maintenance of heat exchanger intended
 
functions. The program includes specifications for known oil degradation indicators
 
and characteristics, sampling and analysis frequencies, and corrective actions for
 
control of lubricating oil properties. Monitoring and control of oil impurities and
 
properties mitigate the loss of material, cracking, and loss of heat transfer (fouling)
 
in lubricating oil systems by preser ving an environment not conducive to loss of material, cracking, or reduction of heat transfer aging effects.
Lubricating oil physical and chemical properties are tested to standard ASTM and ISO methods for the applicable oil type for accurate numbers with repeatable
 
results. Oil is analyzed for indications of degraded chemistry, contamination, and
 
wear parameters depending on oil type and type of service. Normal, alert, and fault levels have been established for the various physical parameters, wear metals, 3-202 additives, and contaminant levels based on information from oil manufacturers, equipment manufacturers, and industry guidelines. Samples are taken and
 
surveillance testing verifies proper heat exchanger performance to support system
 
operation.
As noted, monitoring and control of oil impurities and properties mitigate the loss of material, cracking, and loss of heat transfer in lubricating oil systems by preserving
 
an environment not conducive to loss of material, cracking, or reduction of heat
 
transfer aging effects. OCGS procedures and specifications provide for sampling
 
and monitoring to verify proper lubricating oil properties and assure that the ability
 
of the lubricating oil heat exchangers and other system components to perform
 
intended functions is not lost due to aging effects.
The staff determined that the "preventive actions" program element satisfies SRP-LR Section A.1.2.3.2. The applicant is using industry standards (ASTM and
 
ISO) to establish preventive actions. On this basis, the staff finds the applicant's
 
preventive actions acceptable.    (3)Parameters Monitored or Inspected -
The "parameters monitored or inspected" program element in SRP-LR Section A.1.2.3.3 states that:
* The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s).
* For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
* For a performance monitoring program, a link should be established between degradation of the particular structure or component intended function(s) and the
 
parameter being monitored.
* For prevention and mitigation programs, the parameter monitored should be the specific parameter controlled to prevent or mitigate aging effects.
The applicant stated that the Lubricating Oil Monitoring Activities Program monitors and maintains lubricating oil physical and chemical properties to provide assurance that
 
contaminants or loss of vital characteristics that could cause or promote corrosion is kept
 
to a minimum. Lubricating oil condition monitoring is classified into three main categories;  (1)chemistry: kinematic viscosity (ASTM D445), total acid number (TAN)(ASTM D664), total base number (TBN)(ASTM D664, D4739), rotating bomb oxidation test (RBOT)(ASTM D2272), water separability (ASTM D1401), foaming characteristics, and air release  (2)contamination: ISO 4406 particle count, fuel and combustion by-products, bottom sediment (solids) and water (BS&W), Karl Fischer water (ASTM D1744, D4928, D6304-C), emission spectrometry (ICP).  (3)wear: DR ferrography, analytical ferrography, emission spectrometry (ICP).
 
The physical properties of lubricants are tested to standard ASTM methods as discussed in ASTM D6224.
3-203 To establish action levels for the various physical parameters, wear metals, additives, and contaminant levels, information from o il manufacturers, equipment manufacturers, and industry guidelines was reviewed. In addition, historical trends from existing analysis were evaluated.
Monitoring and control of oil impurities and properties mitigate loss of material, cracking, and loss of heat transfer (fouling) in lubric ating oil systems by preserving an environment not conducive to such aging effects, thus assuring that the components within the scope of
 
the program remain capable of performing intended functions.
The Lubricating Oil Monitoring Activities Program monitors the effects of corrosion by sampling and analyzing various lubricating oils in accordance with ASTM and ISO
 
standards to evaluate system and component performance. Proper lubricating oil properties are monitored to mitigate corrosion. The One-Time Inspection Program will be
 
used to confirm the absence of aging effects (loss of material) in low flow or stagnant
 
areas in lubricating oil systems.
Monitoring and control of oil impurities and properties mitigate the loss of material, cracking, and loss of heat transfer (fouling) in lubricating oil systems by preserving an
 
environment not conducive to such aging effects, thus assuring that the components
 
within the scope of the program remain capable of performing intended functions. Testing
 
activities verify maintenance of heat exchanger intended functions.
Surveillance procedures for the diesel-dri ven fire protection system pumps will be enhanced to verify flow through the gearbox lubricating oil coolers. The EDG lubricating oil
 
coolers do not require a similar procedural enhancement because temperature monitoring
 
for these coolers exists.
The Lubricating Oil Monitoring Activities Program includes specifications for known oil degradation indicators and characteristics, sampling and analysis frequencies, and
 
corrective actions for control of lubricating oil properties. Lubricating oil physical properties
 
are tested to standard ASTM and ISO methods for the applicable oil type for accurate
 
numbers with repeatable results (
 
==Reference:==
MA-AA-716-230-1001). Samples are taken
 
and analyzed for indications of degraded chemical and physical properties depending on
 
oil type and type of service. Surveillanc e testing verifies proper heat exchanger performance to support system operation.
The Lubricating Oil Monitoring Activities Program manages the aging effects of loss of material, cracking ,and reduction of heat transfer by preserving an environment not
 
conducive to these aging effects.
Flash point can be a measure to detect the contamination of lubricating oils by fuel oil, as is the case for diesel engine lubricating oil. Therefore, oil analysis guidelines will be
 
enhanced to include measurement of flash point for diesel engine lubricating oil. Flash
 
point is not measured for all lubricating oil in service. Flash point is a quality control
 
measurement when purchasing new oil. It is not a primary measurement to determine the presence of water or contaminants, the parameters for assessing the environment of
 
concern.
3-204 Monitoring for the presence of chloride ions is not performed. Based on past precedents the staff concluded that monitoring for chloride ions in lubrication oil is not required.
 
Industry guidance addresses oil environments in general and lubricating oil environments for heat exchangers, respectively. Appendix C identifies damaging effects of chlorides in
 
fuel environments but not for lubricating oil environments. Appendix G does not identify
 
any applicable aging effects from chlorides for lubricating oil environments in heat
 
exchanger components. Additionally, there is no OCGS site operating experience of failure or degradation in oil environments attributed to the presence of chlorides.
The Lubricating Oil Monitoring Activities Program will be enhanced as follows:
Surveillance procedures for the diesel driven fire protection system pumps will be enhanced to verify flow through the gearbox lubricating oil coolers.
Oil analysis guidelines will be enhanced to include measurement of flash point for diesel engine lubricating oil. This is a new enhancement based on
 
the reconciliation of this AMP from the draft January 2005 NUREG 1800, Revision 1 to the approved September 2005 NUREG-1801, Rev. 1.
The staff determined that this program element satisfies SRP-LR Section A.1.2.3.3 because it includes specific parameters being controlled to achieve prevention or
 
mitigation of aging effects. Although the applicant classified this program as plant-specific, enhancements have been added to ensure flow through the gearbox lubrication oil
 
coolers. The staff finds these enhancements acceptable because verification of flow
 
through the gearbox lubrication oil coolers will significantly increase the ability to detect the
 
effects of aging. Although the applicant has identified this program as plant-specific these
 
enhancements make the program consistent with the recommendations for lubricating oil
 
monitoring programs in the GALL Report.
The staff noted that the enhancement related to the flash points was not identified in the LRA. Subsequently, the applicant committed (Commitment No. 59) to revise LRA
 
Section B2.2 to state that oil analysis guidelines will be enhanced to include measurement
 
of flash point for diesel engine lubricating oil. The staff finds this commitment (Commitment No. 38) acceptable as it follows the recommendations in the GALL Report.  (4)Detection of Aging Effects - The "detection of aging effects" program element in SRP-LR Section A.1.2.3.4 states that the applicant should:
* Provide information that links the parameters to be monitored or inspected to the aging effects managed.
* Describe when, where, and how program data are collected (i.e., all aspects of activities to collect data as part of the program).
* Link the method or technique and frequency, if applicable, to plant-specific or industry-wide operating experience.
* Provide the basis for the inspection and sample size when sampling is used to inspect a group of SCs. The SCs inspected should be based on such aspects as a
 
similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or aging effects.
3-205 The applicant stated in the Lubricating Oil Monitoring Activities Program for the "detection of aging effects" program element that oil analysis has become an accurate method for
 
identifying specific wear mechanisms, contamination, and oil degradation characteristics
 
within operating machinery. Lube oil contaminants like metals, solids, and water can be
 
used to indicate degradation in components in lubricating oil systems. The existing
 
Lubricating Oil Monitoring Activities Program maintains lubricating oil physical and
 
chemical properties within predefined limits to mitigate the effects of aging. Monitoring of
 
diagnostic parameters in lubricating oil systems indicates degradation due to aging effects (e.g., presence of metals in lube oil sample) prior to loss of intended function. Normal, alert, and fault action levels for oil chemical and physical properties, wear metals, contaminants, and additives for the specific oil type and application are established.
 
Increased impurities and degraded oil properties indicate degradation of materials in
 
lubricating oil systems.
Periodic samples are taken and analyzed for indications of degraded chemical and physical properties depending on oil type and type of service. Surveillance testing verifies proper heat exchanger performance to support system operation.
The existing Lubricating Oil Monitoring Acti vities Program manages aging of components by maintaining proper lubricating oil physi cal and chemical properties and by verifying maintenance of heat exchanger intended functions. The program includes specifications
 
for known oil degradation indicators and characteristics, sampling and analysis
 
frequencies, and corrective actions for control of lubricating oil properties. Normal, alert, and fault action levels for oil chemical and physical properties, wear metals, contaminants
 
and additives for the specific oil type and application are established. Oil properties are
 
controlled to minimize contaminant concentration (primarily water and particulates),
preserving an environment not conducive to aging mechanisms that could lead to the
 
aging effects of loss of material, cracking, and reduction of heat transfer, thus assuring
 
that components within the scope of the program remain capable of performing intended
 
functions.
Samples are taken periodically and analyzed for indications of degraded chemical and physical properties depending on oil type and type of service. Surveillance testing verifies proper heat exchanger performance to support system operation. Monitoring frequencies have been established depending on the component and service. For example, the EDG crankcase is monitored four times a year while EDG lube oil and turbine lube oil are
 
monitored twice a year. Sampling frequency is increased if plant and equipment operating
 
conditions indicate a need.
Periodic sampling and heat exchanger testing are in accordance with controlling procedures. As noted, controlling procedures are based on industry standards and
 
plant-specific experience.
Representative sampling techniques are not used. A hundred percent of the equipment within the scope of the Lubricating Oil Monitoring Activities Program is sampled.
The staff determined that the "detection of aging" program element satisfies SRP-LR Section A.1.2.3.4. The staff finds that the applicant follows industry-accepted methods and
 
plant-specific operational history to detect aging effects and for frequency of testing. On 3-206 this basis, the staff finds the applicant's description of the detection of aging effects is acceptable.    (5)Monitoring and Trending - The "monitoring and trending" program element in SRP-LR Section A.1.2.3.5 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 applicant stated in the Lubricating Oil Monitoring Activities Program for the"monitoring and trending" program element that lubricating oil analysis results are
 
evaluated for acceptability in accordance with interpretation guidelines developed from
 
industry standards and plant-specific operating experience. Normal, alert, and fault action
 
levels for oil chemical and physical properties, wear metals, contaminants, and additives
 
for the specific oil type and application are established, monitored, and trended to assure
 
timely corrective action. Increased impurities and degraded oil properties indicate
 
degradation of materials in lubricating oil systems. Oil analysis results are monitored and
 
trended in accordance with the maintenance program and timely corrective actions are
 
initiated.
Periodic sampling and heat exchanger testing are in accordance with controlling procedures. As noted, normal, alert, and fault action levels for oil chemical and physical
 
properties, wear metals, contaminants, and additives for the specific oil type and
 
application are established, monitored, and trended to assure timely corrective action. Oil
 
analysis results are monitored and trended in accordance with the maintenance program.
The staff determined that for visual inspection, the "monitoring and trending" program element satisfies SRP-LR Section A.1.2.3.5. The staff finds that lubricating oil analysis
 
results are evaluated for acceptability in accordance with interpretation guidelines
 
developed from industry standards and plant-specific operating experience. On this basis, the staff finds the applicant's description of the monitoring and trending acceptable.    (6)Acceptance Criteria - The "acceptance criteria" program element in SRP-LR Section A.1.2.3.6 states that:
* The acceptance criteria of the program and their bases should be described. The acceptance criteria against which the need for corrective actions will be evaluated
 
should ensure that 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.
* Qualitative inspections should be to the same predetermined criteria as quantitative inspections by personnel in accordance with ASME Code and through
 
approved site-specific programs.
3-207 The applicant stated in the Lubricating Oil Monitoring Activities Program that lubricating oil properties are tested to standard ASTM, ISO, and other industry standard methods for the
 
applicable oil type for accurate numbers with repeatable results. Normal, alert, and fault
 
levels for oil physical properties, wear metals, additives, and contaminant levels are
 
established based on information from oil manufacturers, equipment manufacturers, and
 
industry guidelines for the specific oil type and application. Tolerance bands are
 
established as appropriate for the specific parameter. The program maintains contaminant
 
and parameter limits within the application-specific limits. The procedures outline potential
 
actions to be taken at alert and fault levels and actions can be chosen based on the level
 
of deviation. Aging effects or unacceptable results are evaluated and appropriate
 
corrective actions are taken.
The procedures outline potential actions (corrective) to be taken at alert and fault levels.
Additionally, the One-Time Inspection Program will be used to confirm the absence of
 
aging effects in low flow or stagnant areas in lubricating oil systems.
Specific numerical values are established for each action level (normal, alert, and fault) for oil physical properties, wear metals, additives, and contaminant levels for the specific oil
 
type and application to verify proper lubricating oil properties and assure the ability of the
 
lubricating oil heat exchangers and other system components to perform their functions is not lost due to aging effects. Tolerance bands are established as appropriate for the
 
specific parameter.
Oil analysis results are monitored and trended in accordance with the maintenance program. The Lubricating Oil Monitoring Activi ties Program does not employ qualitative inspections. This program is not part of ASME Code(s).
The staff reviewed the "acceptance criteria" program element to determine whether it satisfies SRP-LR Section A.1.2.3.6. The staff finds that lubricating oil analysis results are
 
evaluated for acceptability in accordance with interpretation guidelines developed from
 
industry standards and plant-specific operating experience. On this basis, the staff finds
 
the applicant's description of the acceptance criteria acceptable.    (10)Operating Experience - The "operati ng experience" program element in SRP-LR Section A.1.2.3.10 states that:
* Operating experience should provide objective evidence for the conclusion that the effects of aging will be managed adequately so that the structure and component
 
intended function(s) will be maintained during the period of extended operation.
* An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.
In LRA Section B.2.2, the applicant explained that the overall effectiveness of lubricating oil monitoring activities is indicated by the OCGS operating experience. Lubricating oil
 
sampling and analysis have detected particulate or water contamination (or both) in
 
lubricating oil systems. In some cases systems were declared inoperable until repaired and until the oil was flushed and replaced. Operating experience has produced procedure
 
and program changes which have improved the e ffectiveness of lubricating oil testing and inspection activities:
3-208
* In 2001, a core spray pump oil analysis detected a high ratio of large to small particles after an oil change. Further investigation determined there had been no
 
increase in pump vibration levels for an extended period and that the source of the
 
particles in the changed oil was contamination from the reservoir when the oil
 
change occurred. The reservoir was flushed to remove particles and new oil was
 
added. An increased oil surveillance frequency was established to confirm oil
 
condition.
* In 2002, a CRD pump oil analysis indicating high wear particle concentration resulted in flushing of the bearing, adding new oil, and monitoring further for
 
bearing wear. A followup oil sample was scheduled for more data for analysis in
 
addition to the scheduled pump vibration analysis.
The staff noted that the operating experience for the Lubricating Oil Monitoring Activities Program showed no adverse trend in perform ance. Problems identified will not cause significant impact to safe operation of the plant, and adequate corrective actions were
 
taken to prevent recurrence. There is confidence that implementation of the Lubricating Oil
 
Monitoring Activities Program will effectively maintain proper lubricating oil properties.
 
Periodic self-assessments of the program identify areas that need improvement to maintain the quality performance of the program.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the
 
applicant's Lubricating Oil Monitoring Activities Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Lubricating Oil Monitoring Activities Program in LRA Section A.2.2, which stated that the existing Lubricating Oil
 
Monitoring Activities Program manages loss of material, cracking, and fouling in lubricating oil
 
heat exchangers, systems, and components within the scope of license renewal by monitoring physical and chemical properties in lubricating oil. Sampling, testing, and monitoring verify
 
lubricating oil properties. Oil analysis identifies s pecific wear mechanisms, contamination, and oil degradation within operating machinery and system components within the scope of license
 
renewal. The Lubricating Oil Monitoring Activiti es Program will be enhanced to add surveillance for verification of flow through the fire protecti on system diesel-driven pump gearbox lubricating oil cooler. The enhancement will be implemented prior to the period of extended operation.
The staff also reviewed the commitment (Commitment No. 38) to confirm that this program will be implemented prior to the period of extended operation.
The staff's review of the UFSAR supplement finds that it 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 program the staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that intended
 
function(s) will be maintained during the period of extended operation, as required by 10 CFR
 
54.21(a)(3).
The staff's review of the UFSAR supplement for this program also finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3-209 3.0.3.3.3  Generator Stator Water Chemistry Activities Summary of Technical Information in the Application. In LRA Section B.2.3, the applicant stated that the Generator Stator Water Chemistry Activities Program is plant-specific and not included
 
within the GALL Report AMPs. OCGS chemistry activities manage loss of material aging effects in
 
components exposed to stator cooling water. Stator cooling water chemistry activities monitor and
 
control water chemistry by an OCGS proc edure and process based on GE Company Document GEK 45942, "Stator Winding Cooling Water System Operation and Flushing," and EPRI
 
TR-105504, "Primer on Maintaining the Integrity of Water Cooled Generator Stator Windings,"
 
which provide guidelines for stator cooling water chemistry control.
Control of stator cooling water chemistry in accordance with GE and EPRI guidelines maintains the water to a high degree of purity with no areas of low flow where pitting corrosion could occur
 
while the system is in operation whenever the ma in generator is on line. Flow instruments cause automatic actions to reduce generator electrical output if low flow occurs. This condition will cause
 
an investigation of the low flow condition and actions to restore normal flow.
Staff Evaluation. LRA Section B.2.3 describes the applicant's Generator Stator Water Chemistry Activities Program. This AMP will manage aging effects of the stator generator caused by the
 
cooling water. The Generator Stator Water Chemistry Activities Program is a plant-specific
 
program not conforming to the GALL AMPs. Therefore, the staff's evaluation focused on
 
management of aging effects through incorporati on of the AMP program elements from Branch Technical Position RLSB-1 (SRP-LR, Appendix A).
The staff reviewed the Generator Stator Water Chemistry Activities Program against the AMP elements found in SRP-LR Section A.1.2.3 and focused on how the program manages aging
 
effects through the effective incorporation of 10 program elements (i.e., "scope of program,"
"preventive actions," "parameters monitored or inspected," "detection of aging effects,"
"monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process,"
 
"administrative controls," and "operating experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" program elements are parts of the si te-controlled QA program. The staff's evaluation of the QA program is discussed in SER Section 3.0.4. The remaining seven elements are
 
discussed below.  (1) Scope of Program - In LRA Section B.2.3, the applicant stated that stator cooling water is monitored continuously for purity by installed conductivity cells and analyzed periodically
 
for impurities and dissolved oxygen. These conductivity cells annunciate alarms in the
 
event water purity decreases to a predetermined limit. Additionally, water chemistry
 
parameters are maintained in accordance with GE and EPRI guidelines for stator cooling
 
water systems. Maintaining these parameters within specifications mitigates the aging
 
effects caused by crevice and pitting corrosion.
The applicant also stated that SCC is not considered an aging mechanism requiring aging management. SCC of stator cooling water components is unlikely as contaminants are
 
maintained at very low levels and the system is normally operated at temperatures less than 140 &deg;F. The system is equipped with both filters and a resin bed that continuously
 
filters a portion of the system flow.
3-210 The staff believes that the procedure allows maintenance of generator stator cooling water at a high degree of purity. The staff finds that these activities will provide sufficient
 
safeguards to ensure that the components in the generator stator will not be damaged by
 
the corrosion caused by cooling water.
The staff confirmed that the "scope of the program" program element satisfies SRP-LR Section A.1.2.3.1 and concludes that this program attribute is acceptable.  (2) Preventive Actions - In LRA Section B.2.3, the applicant stated that loss of material due to crevice and pitting corrosion is mitigated by maintaining the stator cooling water chemistry
 
parameters within specifications and by maintaining adequate system flow. Although not
 
required for crevice corrosion, high levels of impurities or high temperatures significantly
 
increase the rate at which crevice corrosion occurs. Low flow and the presence of
 
impurities are required for pitting corrosion. Therefore, maintaining adequate flow and low
 
levels of impurities mitigates pitting corrosion and maintaining low levels of impurities
 
along with low normal system operating temperatures mitigates crevice corrosion.
The applicant also stated that SCC of stator cooling water components is unlikely as contaminants are maintained at very low levels in accordance with GE and EPRI guidelines, and the system is normally operated at temperatures less than 140 &deg;F. As
 
discussed in "scope of program" program element, SCC of stator cooling water system
 
components is unlikely to occur with the high water purity and the low operating
 
temperature of the system.
The staff agrees with the applicant that loss of the material by crevice and pitting corrosion could be reduced significantly by a low level of impurities and an adequate flow of cooling
 
water. Also, the chemistry parameters should be maintained at their optimum values. In
 
plant procedure conductivity and dissolved oxygen concentration are maintained at
 
specified limits and iron, copper, and hydrogen in cover gas are trended monthly. When
 
low flow occurs in the generator stator special instrumentation detects it and generator
 
output is lowered automatically. The staff believes that an AMP based on the OCGS plant
 
procedure will prevent damage to the generator stator by cooling water.
The staff confirmed that the "preventive actions" program element satisfies SRP-LR Section A.1.2.3.2 and concludes that this program attribute is acceptable.  (3) Parameters Monitored and Inspected - In LRA Section B.2.3, the applicant stated that water conductivity is monitored continuously to ensure purity. Additionally, site procedures
 
require periodic (monthly) analyses of water chemistry samples for conductivity, dissolved oxygen, iron, and copper. Chemistry parameter s are monitored in accordance with the guidelines provided by GE and EPRI.
The applicant monitors water conductivity to maintain it below 0.5 S/cm and dissolved oxygen above 1 ppm. It also evaluates the trends for iron, copper, and hydrogen in the cover gas. These measurements are made at monthly intervals and allow the applicant to
 
maintain coolant chemistry at the level needed for managing aging of components
 
exposed to generator stator cooling water. The staff finds the parameter monitoring
 
program acceptable because by monitoring pr oper parameters the applicant will exercise control of coolant water chemistry and prevent damage to the generator stator.
3-211 The staff confirmed that the "parameters monitored and inspected" program element satisfies SRP-LR Section A.1.2.3.3 and concludes that this program attribute is
 
acceptable.  (4) Detection of Aging Effects - In LRA Section B.2.3, the applicant stated that this program mitigates loss of material aging effects. It is not credited for detection of aging effects. The
 
staff finds this statement acceptable.
The staff confirmed that the "detection of aging effects" program element satisfies SRP-LR Section A.1.2.3.4 and concludes that this program attribute is acceptable.  (5) Monitoring and Trending - In LRA Section B.2.3, the applicant stated that water conductivity is monitored continuously with an alarm if pre-established limits are reached.
Chemistry parameters are maintained in accordance with the guidelines provided by GE
 
and EPRI.
The staff believes that OCGS plant water chemistry is monitored continuously and that if predetermined limiting values are reached an alarm will be activated, warning the
 
operators to take appropriate corrective actions. The staff finds that with this precaution
 
the system will not be operated at conditions where damage can occur.
The staff confirmed that the "monitoring and trending" program element satisfies SRP-LR Section A.1.2.3.5 and concludes that this program attribute is acceptable.  (6) Acceptance Criteria - In LRA Section B.2.3, the applicant stated that water chemistry parameters are maintained within the guidelines provided by GE and EPRI as discussed in
 
program element (2). The staff finds this statement acceptable.
The staff confirmed that the "acceptance criteria" program element satisfies SRP-LR Section A.1.2.3.6 and concludes that this program attribute is acceptable.(10)Operating Experience - In LRA Section B.2.3, the applicant stated that OCGS has exhibited a good operating history with the stator cooling water system long-lived
 
components. There has been no age-related degradation of stator cooling water system
 
components within the scope of license renewal. The current water chemistry activities
 
have been proven effective in managing aging of the stator cooling water system components.
The staff believes that OCGS has exhibited a good operating history with the generator stator cooling water system. Visual inspections of the generator stator for corrosion and
 
copper plating by the applicant during each refueling outage have indicated no
 
degradation of system components. Therefore, current activities within the AMP described
 
by the applicant proved to be effective.
The staff confirmed that the "operating exper ience" program element satisfies SRP-LR Section A.1.2.3.10 and concludes that this program attribute is acceptable.
UFSAR Supplement. In LRA Section A.2.3 the applicant provided its UFSAR supplement for the Periodic Inspection Program - FRCT Program. The staff reviewed this section and determined 3-212 that the information in the UFSAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
Conclusion. On the basis of its review, the staff's concludes that the applicant has demonstrated that the Generator Stator Water Chemistry Activities Program will adequately manage aging
 
effects from cooling water consistent with the CLB for the period of extended operation as
 
required by 10 CFR 54.29(a).
The staff's review of the UFSAR supplement for this program finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.4  Periodic Inspection of Ventilation Systems
 
Summary of Technical Information in the Application. In LRA Section B.2.4, the applicant described the existing, plant-specific Periodi c Inspection of Ventilation Systems Program.
The Periodic Inspection of Ventilation Systems Program includes periodic visual inspections of the ventilation systems within the scope of license renewal. Periodic visual inspections are
 
performed during system preventive maintenance activities on a frequency not exceeding 5 years.
Components subject to visual inspections include:
* buried ventilation ductwork
* flexible connections
* fans
* filter and heater housings
* damper housings
* access door seals
* valves
* piping and fittings
* cooling and heating coils
* thermowells
* flow elements and restricting orifices The exterior surfaces of ventilation ducts and dam per housings will be inspected by the Structures Monitoring Program. The Periodic Inspection of V entilation Systems Program inspects internal and external surfaces of ventilation system components to identify and assess aging effects that may occur. The program includes surface inspections for such indications of loss of material as
 
rust, corrosion, and pitting. Heat transfer surfaces are inspected for fouling. Flexible connection
 
and door seal elastomer materials are inspected for detrimental changes in material properties as
 
evidenced by cracking, perforations in the material, or leakage and for loss of material due to
 
wear. Existing maintenance activities will be enhanced to include ducts exposed to soil, instrument piping and valves, restricting orifices and flow elements, and thermowells.
Staff Evaluation. The staff reviewed the information in LRA Section B.2.4 on the applicant's Periodic Inspection of Ventilation Systems Program to determine whether the effects of aging will be adequately managed so that intended functions will be maintained consistent with the CLB for
 
the period of extended operation.
3-213 The staff's review of LRA Section B.2.4 identified areas in which additional information was necessary to complete the review of the applicant's program elements. The applicant responded
 
to the staff's RAI as discussed below.
In RAI B.2.4-1 dated March 30, 2006, the staff noted that LRA Section B.2.4 states that existing ventilation system periodic preventive main tenance activities will be enhanced as follows:
Instrument piping and valves, restricting orifices and flow elements, thermowells and Standby Gas Treatment System ducts exposed to soil will be added to the scope of the plant implementation documents.
The staff requested that the applicant provide a listing of the line items in the LRA AMR tables within the scope of this AMP that will be credited.
In its response dated April 28, 2006, the applicant stated:
Seven systems credit the Periodic Ins pection of Ventilation Systems program.
They include the 480V Switchgear Room Ventilation, Battery and MG Set Room Ventilation, C Battery Room, Heating
& Ventilation, Control Room HVAC, Radwaste Area Heating and Ventilation System, Reactor Building Ventilation
 
System and the Standby Gas Treatment Sy stem (SGTS). The line items in the program are included in the License Renewal Application AMR
 
Tables 3.3.2.1.03,3.3.2.1.04, 3.3.2.1.01, 3.3.2.1.10, 3.3.2.1.28, 3,3,2,1,31 and
 
3.2.2.1.3 respectively.
The list of the items crediting the Periodic Ins pection of Ventilation Systems Program was also provided by the applicant. The staff finds the applicant's response reasonable and acceptable
 
because the applicant had identified the systems and items within the scope of this AMP.
LRA Section B.2.4 states that existing vent ilation system periodic preventive maintenance activities will be enhanced to add specific guidance for identification of applicable aging effects
 
to preventive maintenance documents. The information in the LRA suggests that the
 
identification of the aging effects is based currently on qualitative acceptance criteria.
In RAI B.2.4-2 dated March 30, 2006, the staff requested that the applicant discuss the enhancements described in LRA Section B.2.4 to indicate whether any aging effects will be
 
identified on the basis of such quantitative acceptance criteria as durometer reading limits for
 
identifying aging effects in elastomers.
In its response dated April 28, 2006, the applicant stated:
The general inspection acceptance criteria for components in the Periodic Inspection of Ventilation Systems program is qualitative. When aging effects are
 
identified as not meeting acceptance criteria, such as penetrating corrosion for
 
metals and loss of material, hardening or tears in elastomers, or fouling of heat
 
transfer surfaces, the issue will be entered into the corrective action program and
 
will be evaluated. The corrective action program will ensure that conditions
 
adverse to quality are addressed. An exception to this is the quantitative
 
inspection incorporated into ventilation program inspection criteria to determine
 
loss of material of buried Standby Gas Treatment System ducts as modified with 3-214 internal aluminum sleeves. Refer to RAI 3.2-2 item a) response for the discussion of this inspection process.
The staff finds the applicant's response reasonable and acceptable because the applicant provided adequate information on its acceptance criteria as requested.
Operating Experience. In LRA Section B.2.4, the applicant explained that OCGS has experienced surface corrosion of outdoor equipment housings and ducts damage to elastomers
 
and deterioration of flexible connections resulting in leakage of ventilation systems. These
 
conditions were identified and corrected prior to loss of function of the systems. Maintenance
 
procedures were revised to include steps to inspect for corrosion of outdoor equipment
 
housings. Periodic preventive maintenance ins pections of ventilation system components, including specific guidance to identify applicable aging effects, will effectively monitor the
 
condition of system components to continue to identify degradation prior to loss of intended
 
functions. A buried section of SGTS duct failed due to external corrosion of the aluminum duct
 
exposed to a soil environment. The failure occurred after approximately 30 years in service. The failed section was repaired with a sleeve and there will be periodic inspections of the buried
 
duct section.
A review of the operating experience of t he outdoor ventilation system components noted that failures have been identified prior to loss of function of the system. With revised inspection
 
procedures to monitor corrosion more effectively, degradation is likely to be identified earlier
 
than in the past.
UFSAR Supplement. In LRA Section A.2.4, the applicant provided the UFSAR supplement for the Periodic Inspection of Ventilation Systems Program. The staff reviewed this section and
 
finds that the information in the UFSAR 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 Periodic Inspection of Ventilation Systems Program and RAI responses tje 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).
3.0.3.3.5  Periodic Inspection Program
 
Summary of Technical Information in the Application. In LRA Section B.2.5, the applicant described the new, plant-specific Periodic Inspection Program.
The Periodic Inspection Program will address systems within the scope of license renewal requiring periodic monitoring of aging effects and not covered by other periodic monitoring
 
programs. Activities will consist of a periodi c inspection of selected systems and components to verify integrity and confirm the absence of aging effects. The inspections will be condition
 
monitoring examinations intended to assure that environmental conditions cause no material
 
degradation that could result in a loss of system intended functions. This program will confirm
 
that:
3-215
* Change in material properties due to aging does not occur in elastomer expansion joints, flexible hoses and flexible connections, and in polymer tanks exposed to oil, treated
 
water, and raw water.
* Reduction of heat transfer due to aging does not occur in heat exchangers exposed to an outdoor environment.
* Loss of material in components like piping, piping components, piping elements, heat exchangers, filters, ductwork and fan housings is insignificant in a variety of
 
environments.
The program elements will include (a) determination of appropriate inspection sample size, (b) identification of inspection locations, (c) selection of examination technique acceptance criteria, and (d) evaluation of results to determine the need for additional inspections or other corrective
 
actions.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.2.5, including PBD-AMP-B.2.05, "Periodic Inspection," and interviewed the
 
applicant's technical personnel about the applicant's demonstration of the Periodic Inspection
 
Program to determine whether the effects of aging will be adequately managed so that the
 
intended functions will be maintained consistent with the CLB for the period of extended
 
operation.
The staff reviewed the Periodic Inspection Program against the AMP elements of SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1 and focused on how the program manages aging
 
effects through the effective incorporation of 10 elements (i.e., "scope of program," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and
 
trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative
 
controls," and "operating experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" are parts of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.    (1)Scope of Program - The "scope of program" program element in SRP-LR Section A.1.2.3.1 states that the program scope should include the specific structures
 
and components addressed with this program.
The applicant stated in LRA Section B.2.5 that the scope of this program includes systems within the scope of license renewal that require periodic monitoring of aging
 
effects and are not covered by other periodic monitoring programs. Inspections will be at susceptible locations in such systems.
The staff determined that the specific components for which the program manages aging effects have been identified by the applicant, satisfying SRP-LR Section A.1.2.3.1. The
 
staff agrees that systems within the scope of license renewal that require periodic
 
inspections not covered by periodic monitoring programs should be in the Periodic
 
Inspection Program. On this basis, the staff finds the applicant's proposed "program
 
scope" program element acceptable.
3-216  (2)Preventive Actions - The "prevent ive actions" program element in SRP-LR Section A.1.2.3.2 states that the activities for prevention and mitigation programs be
 
described but that preventive actions need not be provided for condition or performance
 
monitoring programs that do not rely on them.
The applicant stated in LRA Section B.2.5, that the Periodic Inspection Program activities will be condition monitoring activities to detect degradation prior to change in
 
material properties, loss of material, and reduction of heat transfer aging effects as
 
applicable for the material and environment. No mitigating or preventive attributes are
 
associated with the Periodic Inspection Program activities.
The Periodic Inspection Program monitors conditions and does not rely on preventive actions.The staff determined that the "preventive actions" program element satisfies SRP-LR Section A.1.2.3.2. The staff agrees that the Periodic Inspection Program monitors
 
conditions and does not rely on preventive actions. On this basis, the staff finds the
 
applicant's "preventive actions" program element acceptable.    (3)Parameters Monitored/Inspected - The "parameters monitored or inspected" program element in SRP-LR Section A.1.2.3.3 states that:
* The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component intended function(s).
* For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
* For a performance monitoring program, a link should be established between degradation of the particular structure or component intended function(s) and the
 
parameter monitored.
* For prevention and mitigation programs, the parameter monitored should be the specific parameter controlled to prevent or mitigate aging effects.
The applicant stated in LRA Section B.2.5 that the parameters to be monitored or inspected will be identified and linked to the degradation of the particular structure and
 
component intended function (i.e. filter, heat transfer, leakage boundary, and pressure
 
boundary) through specific work orders.
The condition monitoring program will inspect for change in material properties, loss of material, and reduction of heat transfer in accordance with station procedures based on
 
applicable codes and standards. Examination methods include visual examination, (VT-1
 
or VT-3) of disassembled components, NDE (UT) measurements, or any other specific
 
examination appropriate for detection of the specific aging effect.
The staff determined that "parameters monitored or inspected" program element satisfies SRP-LR Section A.1.2.3.3. The staff agrees that by use of applicable codes and
 
standards and station procedures the parameter monitored or inspected will be
 
adequate for the period of extended operation. On this basis, the staff finds the
 
applicant's description of the "parameters monitored or inspected" program element acceptable.
3-217  (4)Detection of Aging Effects - The "detection of aging effects" program element in SRP-LR Section A.1.2.3.4 states that the applicant should:
* Provide information that links the parameters to be monitored or inspected to the aging effects managed.
* Describe when, where, and how program data are collected (i.e., all aspects of activities to collect data as part of the program).
* Link the method or technique and frequency, if applicable, to plant-specific or industry-wide operating experience.
* Provide the basis for the inspection and sample sizes when sampling is used to inspect a group of SCs. The SCs inspected should be based on such aspects as
 
similarity of materials of construction, fabrication, procurement, design, installation, operating environment, or aging effects.
The applicant stated in LRA Section B.2.5 that the Periodic Inspection Program will inspect for change in material properties, loss of material, and reduction of heat transfer
 
and will detect degradation of the component prior to loss of its intended function.
 
Inspection for change in material properties will be specified by engineering through
 
specific work orders and be based on OCGS procedures or accepted industry practices.
 
Inspection for loss of material will consist of thickness measurements by NDE (UT),
visual examination (VT-1 or VT-3) of disassembled components, or other accepted
 
industry practices. Inspection for loss of heat transfer will be specified by engineering
 
through specific work orders and be based on OCGS procedures or accepted industry
 
practices.
The initial inspections will be before the period of extended operation. Subsequent periodic inspections will be at intervals not to exceed 10 years. OCGS will perform periodic inspections of a representative sample of the total component type, not less
 
than 10 percent, to confirm that unacceptable degradation does not occur and the
 
intended function of components will be maintained during the period of extended
 
operation.
In addition to detecting degradation with the Periodic Inspection Program condition monitoring also will be used to ensure component availability to perform intended
 
functions as designed when called upon. This program will detect age-related
 
degradation prior to component failure.
The Periodic Inspection Program ensures that initial inspections will be near the end of the current operating term but before the period of extended operation. Subsequent
 
periodic inspections will be at intervals not to exceed 10 years. OCGS will perform periodic inspections of a representative sample of the total component type, not less
 
than 10 percent, to confirm that unacceptable degradation has not occurred and that
 
component intended function will be maintained during the period of extended operation.
 
Inspection locations for systems will be determined in the work orders generated. Visual
 
and volumetric inspections will be performed based on OCGS procedures and accepted
 
industry practices.
Methods and frequencies of such inspections for degradation are in accordance with accepted industry standards. Examination methods include visual examination, (VT-1 or 3-218 VT-3) of disassembled components, NDE (UT) measurements, or any other specific examination appropriate for detection of the specific aging effect. Operating experience
 
in Section 3.10 of this PBD supports this inspection frequency.
The 10 percent sample size determination is based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience. System
 
components and locations selected for inspection are representative for the component, material, environment, and aging effect. Inspection results are evaluated to assess the
 
need for followup examinations to monitor aging progression for age-related degradation
 
found that could jeopardize an intended function before the end of the period of
 
extended operation. Unacceptable inspection results will require expansion of the
 
sample size and locations until the extent of the problem is determined. Engineering will
 
determine the sample size and location expansion based on evaluations of the
 
unacceptable inspection results.
The staff determined that this program element satisfies SRP-LR Section A.1.2.3.4.
The staff agrees that by the use of applicable codes and standards and station procedures
 
the detection of aging effects will be adequate for the period of extended operation. The
 
staff determined that the 10-year inspection frequency and sample size determination is
 
consistent with industry experience, codes and standards. On this basis, the staff finds
 
the applicant's description of the "detection of aging effects" program element
 
acceptable.    (5)Monitoring and Trending - The "monitoring and trending" program element in SRP-LR Section A.1.2.3.5 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 applicant stated in LRA Section B.2.5 that visual and volumetric inspection techniques performed on a 10-year frequency are appropriate for detecting the loss of
 
material, change in material properties, and reduction of heat transfer aging effects prior
 
to loss of intended functions based on plant-specific and industry operating experience.
 
Results of the periodic inspection activities will be monitored. Indications of loss of
 
material, change in material properties, and reduction of heat transfer in excess of
 
established acceptance criteria will require initiation of a condition report for engineering
 
evaluation that will determine the need for followup examinations to monitor the
 
progression of aging for age-related degradation found that could jeopardize an intended
 
function before the end of the period of extended operation. In addition, the engineering
 
evaluation will either demonstrate acceptability or specify the appropriate repair or
 
replacement.
The data collected will be evaluated and quantified by engineering, and appropriate corrective actions will be taken for any adver se findings. Engineering evaluation requires an assessment of the rate of degradation to schedule the next inspection before a loss
 
of intended function. Condition reports are trended within the corrective action process.
3-219 Follow-up examinations will be required if necessary to determine the extent of the degraded condition, thus expanding the sample size and locations of inspections or
 
adjusting the inspection frequency as appropriate.
The staff determined that for visual inspection the "monitoring and trending" program element satisfies SRP-LR Section A.1.2.3.5. The staff agrees that by use of applicable
 
engineering analyses and station procedures monitoring and trending will be adequate
 
for the period of extended operation. On this basis, the staff finds the applicant's
 
description of the "monitoring and trending" program element acceptable.    (6)Acceptance Criteria - The "acceptance criteria" program element in SRP-LR Section A.1.2.3.6 states that::
* The acceptance criteria of the program and its basis should be described. The acceptance criteria against which the need for corrective actions will be
 
evaluated should ensure that the 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.
* Qualitative inspections should be performed to the same predetermined criteria as quantitative inspections by personnel in accordance with the ASME Code and
 
through approved site-specific programs.
The applicant stated in LRA Section B.2.5 that examination results will be evaluated by engineering to determine whether change in material properties, loss of material, and
 
reduction of heat transfer aging is occurring. Changes in material properties are
 
identified by visual inspection for cracking and indications of elastomer hardening. For
 
loss of material, loss of wall thickness will be evaluated against design requirements or
 
accepted industry standards. The heat transfer intended function of a component will be
 
assured by inspecting for corrosion and fouling. If change in material properties, loss of
 
material, and reduction of heat transfer aging is identified engineering will determine the
 
rate at which the aging effect is occurring. Engineering evaluations of the examination
 
results will also (1) determine the need for followup examinations to monitor the
 
progression of aging degradation and (2) identify appropriate corrective actions to
 
mitigate any excessive rates of change in material properties, loss of material, and
 
reduction of heat transfer discovered or specify the appropriate repair or replacement.
 
Corrective actions, if necessary, will expand to include other components.
Change in material properties, loss of material, and reduction of heat transfer will be evaluated by engineering consistent with original design or evaluation codes and criteria.
 
Age-related degradations that could result in a spatial interaction of a nonsafety-related
 
system with a safety-related system, as det ermined by this evaluation, will be corrected.
Any acceptance criteria not currently defined in the UFSAR will be defined by engineering and accepted based on station procedures and industry practices.
 
Qualitative acceptance criteria for expansion joints and flexible connections and hoses
 
include indications of cracking, hardening, or tears of elastomers. Exterior surfaces of
 
heat exchangers will be inspected for corrosion and fouling. Loss of material will be 3-220 identified by visual or volumetric inspection of components. Component function will be maintained by the periodic monitoring of the components.
All qualitative inspections will be performed to the same predetermined criteria as quantitative inspections in accordance with ASME Code and approved site procedures.
The staff reviewed the "acceptance criteria" program element to determine whether it satisfies SRP-LR Section A.1.2.3.6. The staff determined that the acceptance criteria
 
element is satisfactory because it adheres to accepted procedures and accepted
 
industry practice and ASME Code and approved site procedures. In addition, the staff
 
determined that all qualitative inspections will be performed to the same predetermined
 
criteria as quantitative inspections in accordance with the ASME Code and approved site
 
procedures. On this basis, the staff finds the applicant's description of the "acceptance
 
criteria" program element acceptable.    (10)Operating Experience - The "operating ex perience" program element criteria in SRP-LR Section A.1.2.3.10 states that:
* Operating experience should provide objective evidence for the conclusion that the effects of aging will be managed adequately so that the structure and
 
component intended function(s) will be maintained during the period of extended
 
operation.
* An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.
In LRA Section B.2.5, the applicant stated that the Periodic Inspection Program is new; therefore, no programmatic operating experience has been gained. OCGS has
 
experienced leaks of the plant heating system resulting in the replacement of
 
components. These plant heating system l eaks were found and corrected promptly and did not result in a loss of function of any safety-related SSCs. The Periodic Inspection
 
Program is adjusted continually to account for industry and station experience and
 
research. As additional operating experience is obtained, lessons learned will be used to
 
adjust this program as needed.
Operating experience, both internal and external, is used in two ways at OCGS to enhance plant programs and to prevent repeat events and events at other plants from occurring at OCGS. The first way in which operating experience is used is through the
 
operating experience process, which screens, evaluates, and acts on documents and
 
information to prevent or mitigate the consequences of similar events. The second way
 
is through the process for managing programs. This process requires the review of
 
program-related operating experience by the program owner.
These processes review operating experience from both external and internal (also referred to as in-house) sources. External operating experience may include INPO
 
documents (e.g., SOERs, SERs, SENs, etc.), NRC documents (e.g., GLs, LERs, INs, etc.), GE documents (e.g., RCSILs, SILs, TILs, etc.), and other documents (e.g.,
10 CFR Part 21 Reports, NERs, etc.). Internal operating experience may include event
 
investigations, trending reports, and lessons learned from in-house events as captured
 
in program notebooks, self-assessments, and in the 10 CFR Part 50, Appendix B
 
corrective action process.
3-221 Demonstration of the effective management of the effects of aging is through objective evidence showing that aging effects like change in material properties, loss of material, and reduction of heat transfer are effectively managed. The following examples of
 
operating experience are objective evidence that the Periodic Inspection Program will be
 
effective in assuring that intended function(s) will be maintained consistent with the CLB
 
for the period of extended operation.
OCGS operating experience was searched for instances where change in material properties, loss of material, or reduction of heat transfer was identified as a contributing
 
cause of an incident. The following are the results of that search:
* CAP 02005-2339 documents the identification of build-up of rusted metal parts in the bottom of ductwork determined to be heat transfer fins for an electric heater
 
that did not impact intended functions.
* CAP 02005-0786 documents the identification of an s-leak on a heating coil found during operator rounds. This problem was identified before heating to the
 
reactor building was lost and did not impact any safety systems.
* CAP 02002-1116 documents the identification of a reduction of heat transfer through an M1A transformer high temperature alarm. The oil coolers were fouled
 
and a long-term cooling capability was established.
* CAP 02003-0511 documents the identification of a reduction of heat transfer in the main condenser due to fouling resolved through backwashing to restore
 
vacuum.Operating experience shows that the mean time to failure for rubber expansion joints is 12-15 years. The performance-centered maintenance template directs that rubber
 
expansion joints be inspected and replaced on appropriate intervals depending on the
 
joint classification. This combination of inspection and replacement assures that the
 
Periodic Inspection Program will find premature degradation.
This operating experience provides objective evidence that OCGS is able to recognize change in material properties, loss of material, and loss of heat transfer before these
 
aging effects become problems and supports implementation of the new Periodic
 
Inspection Program for effective aging management.
The operating experience of the parameters to be covered under the Periodic Inspection Program showed no adverse trend in perfo rmance. Problems identified caused no significant impact to the safe operation of the plant, and adequate corrective actions
 
were taken to prevent recurrence. There is sufficient confidence that implementation of
 
the Periodic Inspection Program will effectively identify degradation prior to failure.
 
Appropriate guidance for re-evaluation, repair, or replacement is provided for locations
 
where degradation is found. Periodic self-assessments of the Periodic Inspection
 
Program identify areas that need improvement to maintain the quality performance of the
 
program.This program is new and there is no specific operating history. The staff reviewed the operating experience provided in the LRA and interviewed the applicant's technical 3-222 personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the
 
applicant's Periodic Inspection Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Periodic Inspection Program in LRA Section A.2.2, which stated that the new Periodic Inspection Program will
 
consist of periodic inspections of selected systems to verify integrity and confirm the absence of
 
aging effects. The initial inspections are scheduled for implementation prior to the period of
 
extended operation. The purpose of the inspection is to determine whether a specified aging
 
effect has occurred. If the aging effect has occurred an evaluation will be performed to
 
determine its effect on the ability of affected components to perform their intended functions for
 
the period of extended operation, and appropriate corrective action will be taken. Inspection
 
methods may include visual, surface, or volumetric examinations. Acceptance criteria are in
 
accordance with industry guidelines, codes, and standards. When inspection results fail to meet
 
established acceptance criteria, an evaluation will be conducted, in accordance with the
 
corrective action process, to establish additional actions or measures necessary to provide
 
reasonable assurance that component intended function is maintained during the period of
 
extended operation. This new program will be im plemented prior to the period of extended operation.
The staff also reviewed the commitment (Commitment No. 41) to confirm that this program will be implemented prior to the period of extended operation.
The staff reviewed the UFSAR supplement and finds that it 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 program finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained during the period of extended operation, as required by 10 CFR
 
54.21(a)(3).
The staff's review of the UFSAR supplement for this program also finds that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
3.0.3.3.6  Wooden Utility Pole Program
 
Summary of Technical Information in the Application. In LRA Section B.2.6, the applicant described the new, plant-specific Wooden Utility Pole Program.
The Wooden Utility Pole Program will be used to manage loss of material and change of material properties for wooden utility poles in or near the OCGS substation that provide structural support
 
for the conductors connecting the offsite power system and the 480/208/120V utility (JCP&L)
 
non-vital power system. The program consists of inspection at 10-year intervals by a qualified inspector. The wooden poles will be inspected for loss of material due to insects and moisture
 
damage and for change in material properties due to moisture damage. This new program will be
 
implemented prior to the period of extended operation.
3-223 Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in LRA Section B.2.6 on the applicant's demonstration of the Wooden Utility Pole Program to
 
ensure that the effects of aging will be adequately managed so that intended functions will be
 
maintained consistent with the CLB for the period of extended operation.
The staff reviewed the Wooden Utility Pole Program against the AMP elements in SRP-LR Section A.1.2.3 and focused on how the program manages aging effects through the effective
 
incorporation of 10 elements (i.e., "program scope," "preventive actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria,"
 
"corrective actions," "confirmation process," "administrative controls," and "operating
 
experience").
The applicant indicated that the "corrective actions," "confirmation process," and "administrative controls" are parts of the site-controlled quality assurance program. The staff's evaluation of the
 
quality assurance program is discussed in SER Section 3.0.4. The remaining seven elements
 
are discussed below.    (1)Scope of Program -The "scope of program" program element in SRP-LR Section A.1.2.3.1 states that (1) the specific program necessary for license renewal
 
should be identified and (2) the scope of the program should include the specific structure
 
and components for which the program manages aging.
In LRA Section B.2.6, the applicant stated that the Wooden Utility Pole Program applies to all wooden utility poles which support an intended function for the offsite power system
 
and the 480/208/120V utility (JCP&L) non-vital power system.
The staff determined that the specific program and the components for which the program manages aging effects are identified by the applicant, satisfying SRP-LR
 
Section A.1.2.3.1 . On this basis, the staff finds the applicant's proposed "scope of
 
program" program element acceptable.  (2)Preventive Actions - The "prevent ive actions" program element in SRP-LR Section A.1.2.3.2 states that (1) the activities for prevention and mitigation programs
 
should be described and (2) for condition or performance monitoring programs that do not
 
rely on preventive actions prev entive actions need not be provided.
The applicant stated that this program is a condition monitoring activity. It is a means of detecting, not preventing, aging and has no preventive or mitigative actions.
The staff determined that the applicant had described the program as a condition monitoring activity and not a preventive actions program, and this description satisfies the SRP-LR Section A.1.2.3.2. The applicant uses a condition monitoring program to inspect
 
for loss of material due to insects and moisture damage and for change in material
 
properties due to moisture damage. On this basis, the staff finds the "preventive actions"
 
program element acceptable.    (3)Parameters Monitored or Inspected -
The "parameters monitored or inspected" program element in SRP-LR Section A.1.2.3.3, related to condition monitoring programs, states
 
that:
3-224
* The parameters to be monitored or inspected should be identified and linked to the degradation of the particular structure and component
 
intended function(s).
* For a condition monitoring program, the parameter monitored or inspected should detect the presence and extent of aging effects.
The applicant stated that wooden poles within the scope of this program will be inspected for loss of material due to insects and moisture damage and for change in material
 
properties due to moisture damage and that the parameters monitored or inspected are
 
capable of detecting the effects of aging.
The staff determined that the applicant has identified the parameters to be monitored or inspected, is able to detect the presence and extent of aging effects, and that the
 
program element satisfies SRP-LR Section A.1.2.3.3. On this basis, the staff finds the
 
applicant's proposed "parameters monitored or inspected" program element acceptable.  (4)Detection of Aging Effects - The "detection of aging effects" program element in SRP-LR Section A.1.2.3.4, related to condition monitoring programs, states that:
* Detection of aging effects should occur before there is a loss of the structure and component intended function(s).
* The method or technique and frequency may be linked to plant-specific or industry-wide operating experience.
The applicant stated that inspection of wooden poles every 10 years by a qualified inspector will assure that aging effects are detected prior to loss of intended function, and
 
that industry experience over several decades indicates that a 10-year inspection interval
 
is adequate.
The staff determined that the use of demonstrated industry experience of inspecting wooden poles by a qualified inspector every 10 years is a reasonable method for
 
detecting aging and that the program element satisfies SRP-LR Section A.1.2.3.4. On this
 
basis, the staff finds the applicant's description of the "detection of aging effects" program
 
element acceptable.    (5)Monitoring and Trending - The "monitoring and trending" program element in SRP-LR Section A.1.2.3.5, related to condition monitoring programs, states that monitoring and
 
trending activities and the methodology for analyzing the inspection should be described.
In LRA Section B.2.6, the applicant stated that monitoring involves a combination of visual, sounding, boring, and excavation to determine the condition of a pole sufficiently
 
to predict the extent of degradation so that timely corrective or mitigative actions are
 
possible.The staff determined that the program provides a combination of methods to monitor or inspect wooden pole conditions related to aging and that this program element satisfies
 
SRP-LR Section A.1.2.3.5. On this basis, the staff finds the applicant's description of the
 
"monitoring and trending" program element acceptable.
3-225  (6)Acceptance Criteria. The "acceptance criteria" program element in SRP-LR Section A.1.2.3.6, related to condition monitoring programs, states that:
* The acceptance criteria of the program and its basis should be described.
The acceptance criteria, against which the need for corrective actions will
 
be evaluated, should ensure that the structure and components 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 applicant stated that acceptance criteria will be provided in the specification for inspection of wooden poles carried out by approved maintenance contractors
 
experienced in the inspection, treatment, and reinforcement of wooden poles. The
 
inspector, through a combination of visual, sounding, boring, and excavation will
 
determine the condition of the pole. Remedial actions will be taken based on inspection
 
findings. The staff determined that the use of an acceptance criteria developed by an experienced
 
wooden pole inspector is reasonable and that this program element satisfies SRP-LR
 
Section A.1.2.3.6. On this basis, the staff finds the applicant's description of the
 
"monitoring and trending" program element acceptable.    (10)Operating Experience. The "operating ex perience" program element criteria in SRP-LR Section A.1.2.3.10 states that:
* Operating experience should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure and
 
component intended function(s) will be maintained during the period of extended
 
operation.
* An applicant may have to commit to providing operating experience in the future for new programs to confirm their effectiveness.
The applicant stated that although this program is new inspections of wooden utility poles has been conducted by the industry for many years. Utility experience over several decades indicates that a 10-year inspection interval is adequate to detect age-related
 
degradation before a loss of intended function.
The staff determined that the applicant provided industry experience to support an adequate 10-year inspection interval for wooden poles and that this program element
 
satisfies SRP-LR Section A.1.2.3.10 . On this basis, the staff finds the applicant's
 
description of the "operating experience" element acceptable.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Wooden Utility Pole Program in LRA Section A.2.6, which stated that this new program will be used to manage loss
 
of material and change of material properties for wooden utility poles in or near the OCGS
 
substation providing structural support for the conductors connecting the offsite power system
 
and the 480/208/120V utility (JCP&L) non-vital power system. The program consists of
 
inspection on a 10-year interval by a qualified inspector. The wooden poles will be inspected for 3-226 loss of material due to insects and moisture damage and for change in material properties due to moisture damage. This new program will be im plemented prior to the period of extended operation. The staff also reviewed the commitment (Commitment No. 42) to confirm that this
 
program will be implemented prior to the period of extended operation. The staff determined that
 
the information in the UFSAR 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 Wooden Utility Pole 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).
3.0.3.3.7  Periodic Monitoring of Combustion Turbine Power Plant
 
In its response to RAI 2.5.1.19-1 dated October 12, 2005, the applicant stated that it had revised its approach to aging management for the OCGS SBO combustion turbine power plant.
 
Specifically, the applicant has taken a more detailed approach to scoping, screening, AMRs, and
 
AMPs. As a result, the Periodic Monitoring of Combustion Turbine Power Plant Program has
 
been deleted. Therefore, the staff did not review this program.
3.0.3.3.8  Periodic Monitoring of Combustion Turbine Power Plant Electrical
 
Summary of Technical Information in the Application. In its October 12, 2005, response to RAI 2.5.1.19-1, the applicant stated that the new plant-specific Periodic Monitoring of
 
Combustion Turbine Power Plant - Electrical Program will include elements of GALL AMPs XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," XI.E3, "Inacce ssible Medium-Voltage Cables Not Subject to10 CFR 50.49 Environmental Qualification Requirements," and XI.E4, "Metal Enclosed Bus."
The Periodic Monitoring of Combustion Turbine Power Plant - Electrical Program will be used to manage aging effects for the electrical commodities that support FRCT operation. The new
 
Periodic Monitoring of Combustion Turbine Power Plant - Electrical Program, the existing
 
Structures Monitoring Program, and the new Ina ccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification R equirements Program will be used to manage aging effects for the electrical commodities that support FRCT operation. This program will include elements of GALL AMP XI.E1 for accessible electrical cables and connections; GALL AMP XI.E3 for manholes, pits, and cable trenches; and GALL AMP XI.E4 for the phase bus, connections, and phase bus insulators. This program will inspect accessible electrical cables and connections
 
before the period of extended operation with an inspection frequency of at least once every 10
 
years.This program will inspect manholes, pits, and cable trenches containing inaccessible medium-voltage cables located on the FRCT site for water collection so that draining or other corrective actions can be taken. Inspections for water collection will be performed at least once
 
every 2 years, and the frequency of inspection will be adjusted based on the results obtained.
 
The first inspections will be completed before the period of extended operation.
3-227 This program will also inspect the accessible phase bus, connections, and insulators before the period of extended operation with an inspection frequency of at least once every 5 years.
 
Inspection of the phase bus enclosure external surfaces will be performed under the existing
 
Structures Monitoring Program. The first inspection will be performed before the period of
 
extended operation with an inspection frequency of at least once every 4 years.
The following represents the the Periodic Monitoring of Combustion Turbine Power Plant -
Electrical Program scope for 13.8 kV cables that distribute the output of the FRCT to both the
 
SBO transformer and the 230 kV switchyard.
Inaccessible medium-voltage cable circuits supporting the FRCT and the associated manholes, pits, and trenches located on the OCGS site
 
will be tested or inspected by the new Inacce ssible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The first tests and
 
inspections will be before the period of extended operation with a cable test frequency of at least
 
once every 10 years, and a manhole, pit, and trench inspection frequency of at least once every
 
2 years. These aging management activities ensure the continued availability of the FRCTs as
 
the alternate AC source in the event of an SBO.
Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report. Details of the staff's audit evaluation of this AMP are
 
documented in the Audit and Review Report Attachment 7. In its response to RAI 2.5.1.19-1, the
 
applicant stated that the Periodic Monitoring of Combustion Turbine Power Plant - Electrical Program is consistent with elements of GALL AMPs XI.E1, XI.E3, and XI.E4. The staff reviewed
 
the program elements and associated basis documents to determine their consistency with GALL AMPs XI.E1, XI.E3, and XI.E4.
The staff asked the applicant whether the program elements included phase bus enclosure internal surfaces inspections. The applicant stated that this program also includes inspection of
 
the internal portion of the metal enclosed buses to identify age-related degradation of insulating
 
and metallic components, excessive dust buildup and foreign debris, and evidence of moisture or
 
debris intrusion. The staff's review concluded that the applicant's Periodic Monitoring of
 
Combustion Turbine Power Plant - Electrical Program will effectively manage the aging of
 
accessible cables and connections, inaccessible medium-voltage cables, phase bus and
 
connections, phase bus insulators, and phase bus enclosure internal surfaces for reasonable
 
assurance that intended functions of the electrical commodities supporting the FRCTs will be
 
maintained consistent with the CLB during the period of extended operation. The staff finds that
 
the applicant's Periodic Monitoring of Combustion Turbine Power Plant - Electrical Program conforms to the recommendations in GALL AMPs XI.E1, X1.E3, and X1.E4.
Operating Experience. In its response to RAI 2.5.1.19-1 dated October 12, 2005, the applicant stated that although this program is new FRCT has experienced no cable- or bus-related failure
 
during its period of operation. The applicant also stated that a 2004 inspection involved major
 
rework and repair of the exhaust plenum after and forward walls, including a complete rebuild
 
and rewiring of the load compartment and junc tion boxes as well as extensive alignment activities. These major efforts ensured that the FRCT cables and connections were in optimal
 
condition when returned to service. Lessons learned from routine inspections are incorporated
 
into the future outage scope. A review of the applicant's corrective action documents did not
 
indicate the occurrence of aging degradation with electrical commodities at the FRCT station or a
 
combustion turbine reliability below the 95 percent requirement.
3-228 The staff reviewed the operating experience prov ided in PBD-AMP-B.1.37 and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed
 
no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Periodic Monitoring of
 
Combustion Turbine Power Plant - Electrical Program will adequately manage the aging effects
 
identified in the LRA for which this AMP is credited.
UFSAR Supplement. The applicant provided its UFSAR supplement for the Periodic Monitoring of Combustion Turbine Power Plant - Electrical Program in its supplemental response to
 
RAI 2.5.1.19-1. The staff reviewed this section and determined that the information in the UFSAR
 
supplement provides 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 program and RAI response finds that the applicant has demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff's review of the UFSAR supplement for this program
 
also finds that it provides an adequate summary description of the program as required by
 
10 CFR 54.21(d).
3.0.3.3.9  Periodic Inspection Program - FRCT
 
Summary of Technical Information in the Application. In its November 11, 2005, supplemental response to RAI 2.5.1.19-1, the applicant stated that AMP B.2.5A, "Periodic Inspection Program -
 
FRCT" is a new program.
The Periodic Inspection Program - FRCT Program will address FRCT system components within the scope of license renewal requiring periodic monitoring of aging effects and not covered by
 
other AMPs. Activities will consist of a periodic inspection of selected components to verify
 
integrity and confirm the absence of aging effects. The inspections will be condition monitoring
 
examinations intended to assure that environmental conditions do not cause material
 
degradation that could result in a loss of intended functions. This program is used to confirm that:
* Change in material properties due to aging does not occur in elastomer expansion joints and flexible connections exposed to fuel oil, indoor air, or outdoor air environments.
* Reduction of heat transfer due to aging does not occur in heat exchangers exposed to indoor air or outdoor air environments.
* Loss of material in various steel and stainless steel components subject to an intermittent combustion turbine exhaust gas environment is monitored so there is no loss of component intended functions.
* Loss of material in copper heat exchanger components subject to an indoor air or outdoor air environment is monitored so there is no loss of component intended functions.
* Cracking in stainless steel components subject to an intermittent combustion turbine exhaust gas environment is monitored so there is no loss of component intended functions.
3-229 The program elements will include (1) determination of appropriate inspection sample size, (2) identification of inspection locations, (3) selection of examination technique with acceptance
 
criteria, and (4) evaluation of results to determine the need for additional inspections or other
 
corrective actions. The sample size will be based on such aspects as the specific aging effect, location, existing technical information, mate rials of construction, service environment, or previous failure history. The inspection samples will include locations where the most severe
 
aging effect(s) will be expected to occur. The inspection locations will be based on such aspects
 
as similarity of materials of construction, fabrication, operating environment, or aging effects.
Inspection methods may include visual, surface, or volumetric examinations or other established NDE techniques.
This program will assess change in material properties, loss of material, cracking, and reduction of heat transfer of FRCT mechanical components. For components in the scope of this program
 
an inspection will be conducted to confirm that change in material properties, loss of material, cracking, and reduction of heat transfer does not occur or that the aging effect occurs at a rate
 
that will not affect component intended functions. The program will provide inspection criteria, require evaluation of the results of the inspections, and recommend additional inspections as
 
necessary. Inspections will be scheduled to coincide with major combustion turbine maintenance
 
inspections, when the subject components are made accessible. These inspections will be on a
 
frequency not to exceed once every 10 years. The in itial inspections in program will be at the next major inspection outage for each unit. Based on the established inspection frequency of 10
 
years, the next inspection for FRCT Unit 1 will be by May 2014, and the next inspection for FRCT
 
Unit 2 will be by November 2015.
Staff Evaluation. The staff reviewed the Periodic Inspection Program - FRCT Program against the AMP elements in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1 and focused on how the
 
program manages aging effects through the effectiv e incorporation of 10 elements (i.e., "scope of program," "preventive actions," "
parameters monitored or inspected," "detection of aging effects,"
"monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process,"
 
"administrative controls," and "operating experience").    (1)Scope of Program - In its description of the Periodic Inspection Program - FRCT Program the applicant stated that the scope of this program includes systems within the scope of
 
license renewal requiring periodic monitoring of aging effects and not covered by other
 
existing periodic monitoring programs. Inspections will be at susceptible locations in such systems.The staff determined that the specific components for which the program manages aging effects are identified by the applicant, satisfying SRP-LR Section A.1.2.3.1. On this basis, the staff finds the applicant's proposed "program scope" program element acceptable.    (2)Preventive Actions - In its description of the Periodic Inspection Program - FRCT Program the applicant stated that the program activities will be condition monitoring
 
activities to detect degradation prior to change in material properties, loss of material, cracking, or reduction of heat transfer aging effects as applicable for the material and
 
environment with no preventive or mitigating attributes.
The staff determined that the "preventive actions" program element satisfies SRP-LR Section A.1.2.3.2. On this basis, the staff finds the applicant's "preventive actions"
 
program element acceptable.
3-230  (3)Parameters Monitored/Inspected - In its description of the Periodic Inspection Program -
FRCT Program for the "parameters monito red or inspected" program element the applicant stated that this program will inspect for change in material properties, loss of
 
material, cracking, and reduction of heat transfer. Inspection procedures will be prepared
 
in accordance with applicable codes, standards and inspection practices. Examination
 
methods include visual examination of disassembled components, surface or volumetric
 
examinations, or other established NDE techniques.
The staff determined that the "parameters monitored or inspected" program element satisfies SRP-LR Section A.1.2.3.3. On this basis, the staff finds the applicant's
 
description of the "parameters monitored or inspected" program element acceptable.  (4)Detection of Aging Effects - In its description of the Periodic Inspection Program - FRCT Program for the "detection of aging effects" program element the applicant stated that this
 
program includes inspections for change in material properties, loss of material, cracking, and reduction of heat transfer on a representative sample of susceptible locations.
 
Inspection for loss of material will consist of surface inspections, thickness measurements
 
by NDE (UT), or visual examination of disassembled components.
A representative sample of locations will be inspected to confirm that unacceptable degradation does not occur and that the intended function of components will be
 
maintained during the period of extended operation. Unacceptable inspection results will
 
require expansion of the sample size and locations until the extent of the problems is
 
determined. The sample size and location expansion will be determined based on
 
evaluations of the unacceptable inspection results. Inspections will be scheduled to
 
coincide with major combustion turbine maintenance inspections, when the subject
 
components are made accessible. These inspections will be on a frequency not to
 
exceed once every 10 years.
The initial inspections in this program will be at the next major inspection outage for each unit. As discussed under Operating Experience, the last FRCT Unit 1 major inspection
 
outage was in 2004. The outage began in March 2004 and was completed in May 2004.
 
The last FRCT Unit 2 major inspection outage began in October 2005 and was scheduled
 
for completion in November 2005. All work was carried out closely following the
 
instructions and guidance of the original equipment manufacturer's design, maintenance, and inspection manuals. Equipment is maintained within design specifications to provide
 
reliable service until the next major maintenance inspection. Based on the extent and
 
location of aging effects observed and the as-left internal component conditions following
 
the maintenance outages, additional internal inspections are not warranted prior to the
 
period of extended operation. Based on the established inspection frequency of 10 years, the next inspection for FRCT Unit 1 will be by May 2014, and the next inspection for
 
FRCT Unit 2 will be by November 2015.
The staff determined that the "detection of aging effects" program element satisfies the criteria defined in SRP-LR Section A.1.2.3.4. On this basis, the staff finds the applicant's
 
description of the "detection of aging effects" program element acceptable.    (5)Monitoring and Trending - In its description of the Periodic Inspection Program - FRCT Program for the "monitoring and trending" program element, the applicant stated that
 
results of the periodic inspection activities will be monitored. Indications of insufficient 3-231 material wall thickness, change in material properties, cracking, and reduction of heat transfer in excess of established acceptance criteria will require further evaluation either
 
to demonstrate acceptability or to specify the appropriate repair or replacement.
 
Follow-up examinations will be performed, if necessary, to determine the extent of the degraded condition, thus expanding the sample size and locations of Inspections.
 
Examination methods include visual examination, (VT-1 or VT-3) of disassembled
 
components, NDE (UT) measurements, or any other specific examination appropriate for detection of the specific aging effect.
The staff determined that for visual inspection the "monitoring and trending" program element satisfies SRP-LR Section A.1.2.3.5. On this basis, the staff finds the applicant's
 
description of the "monitoring and trending" program element acceptable.    (6)Acceptance Criteria - In its description of the Periodic Inspection Program - FRCT Program, for the "acceptance criteria" program element, the applicant stated that results
 
of the examinations will be evaluated to determine whether change in material properties, loss of material, cracking, or reduction of heat transfer aging has occurred and, if so, its
 
rate. Evaluation of the examination results also will (1) determine the need for followup
 
examinations to monitor the progression of aging degradation and (2) identify appropriate
 
corrective actions, including repairs or replacements, to mitigate any excessive rates of
 
aging degradation. Corrective actions, if necessary, will expand to include other
 
components. Change in material properties, loss of material, cracking, and reduction of
 
heat transfer will be evaluated consistently with original design or evaluation codes and
 
criteria or manufacturer's standards.
The staff reviewed the "acceptance criteria" program element to determine whether it satisfies SRP-LR Section A.1.2.3.6. On this basis, the staff finds the applicant's
 
description of the "acceptance criteria" program element acceptable.    (7)Corrective Actions - The adequacy of the applicant's program for this element is evaluated in SER Section 3.0.4.
The staff reviewed other aspects of this program element to determine whether it satisfies SRP-LR Section A.1.2.3.7. The staff noted that the FRCTs and supporting systems are
 
nonsafety-related and are not subject to 10 CFR 50 Appendix B requirements in the CLB.
 
The applicant has elected not to include this program under 10 CFR 50 Appendix B
 
Program. Instead, processes and procedures will be established to ensure that conditions
 
adverse to quality are identified and corrected promptly. Conditions that do not satisfy
 
acceptance criteria will be documented, evaluated, and corrected as required to maintain
 
the intended function of combustion turbines during the period of extended operation. Any
 
condition significantly adverse to quality will require that the cause be determined, action
 
to preclude repetition be taken, and the condition be reported to the appropriate level of
 
management. In its responses to RAI 2.5.1.19-1 dated October 12 and
 
November 11, 2005, the applicant stated that it will meet the guidance in Branch
 
Technical Position IQMB-1, "Quality Assurance for Aging Management Programs." On
 
this basis, the staff finds the applicant's description of the "corrective actions" program
 
element acceptable.  (8)Confirmation Process - The adequacy of the applicant's program for this element is evaluated in SER Section 3.0.4.
3-232 The staff reviewed other aspects of the "confirmation process" program element to determine whether it satisfies SRP-LR Section A.1.2.3.8. The staff noted that the
 
confirmation process for the FRCT will focus on followup actions that must be taken to
 
verify effective implementation of correctiv e actions and preclude repetition of conditions significantly adverse to quality. The established process and procedures require that
 
measures be taken to preclude repetition of conditions significantly adverse to quality.
 
These measures include actions to verify effective implementation of the proposed corrective actions, determination of root cause, tracking of open corrective actions to
 
completion, and reviews of corrective action effectiveness.
In its responses to RAI 2.5.1.19-1 dated October 12, 2005, and November 11, 2005, the applicant stated that it will meet the guidance in Branch Technical Position IQMB-1, "Quality Assurance for Aging Management Programs." On this basis, the staff finds the
 
applicant's description of the "confirmation process" program element acceptable.    (9)Administrative Controls - The adequacy of the applicant's program for the "administrative controls" program element is evaluated in SER Section 3.0.4. The staff noted that FRCT
 
procedures include administrative controls that provide for formal review and approval of aging management activities.
The staff reviewed other aspects of this program element to determine whether it satisfies SRP-LR Section A.1.2.3.9. In its responses to RAI 2.5.1.19-1 dated October 12, 2005, and November 11, 2005, the applicant stated that it will meet the guidance in Branch
 
Technical Position IQMB-1, "Quality Assurance for Aging Management Programs." On
 
this basis, the staff finds the applicant's description of the "administrative controls"
 
program element acceptable.  (10)Operating Experience - In its description of the Periodic Inspection Program - FRCT Program for the "operating experience" program element, the applicant stated that the
 
new Periodic Inspection Program - FRCT Program will effectively manage aging
 
degradation for the period of extended operation by timely detecting aging effects and
 
implementing appropriate corrective actions prior to loss of component intended
 
functions. This program will be incorporated into current maintenance inspection
 
practices, which have been demonstrated through operating experience to be effective in
 
managing age-related degradation to maintain intended functions of the combustion
 
turbines.The applicant stated that in October 2001 (FRCT Unit 2) and March 2004 (FRCT Unit 1), GE Energy Services performed inspection and maintenance activities and documented
 
all work in inspection reports dated January 4, 2002, and June 7, 2004, respectively. The
 
equipment inspections included the combustion turbines, internals, and support
 
equipment. All work was carried out closely following the instructions and guidance of the
 
original equipment manufacturer's design, maintenance, and inspection manuals.
 
Acceptance criteria and corrective actions for these activities ensure that equipment is
 
maintained within design specifications.
The FRCT Unit1 inspection was major maintenance, the most comprehensive inspection of the combustion turbine units. The interval between major inspections is based on
 
operating experience with these and similar combustion turbine installations and such
 
factors that affect part life as fuel type and starting frequency. The purpose of this type of 3-233 maintenance inspection is to identify equipment degradation and, if identified, to replace or refurbish the affected component in accordance with manufacturer specifications so
 
the unit will perform reliably through the next operating interval. This major inspection was
 
the first on the unit since initial installation in 1988. During the FRCT Unit 1 inspection, extensive cracking was found in the exhaus t system ductwork and expansion joint. The degradation allowed hot exhaust gasses to escape but did not prevent the combustion
 
turbine from operating. The damaged components were weld-repaired. Cracking was
 
also identified in some turbine casing sections, which were also repaired prior to loss of
 
component function. The stainless steel inlet ductwork was inspected with no deficiencies
 
noted. The generator heat exchangers were opened, cleaned, and inspected, and no
 
deficiencies were noted with the copper tubes. Maintenance personnel stated that the
 
tubes were found in good condition.
The FRCT Unit 2 inspection was of the fuel nozzle and combustion section. The FRCT Unit 2 inspection found the inlet filter housing in good condition with no visual defects.
 
Exhaust ductwork was also inspected. No serious defects were found. One channel
 
section was found with missing nuts, and new nuts were installed. Repair of identified
 
cracks was deferred to the next major overhaul outage.
FRCT Unit 2 began a major outage inspection in October 2005 with components disassembled and visually inspected for signs of age-related degradation. The internal
 
surfaces of disassembled exhaust system ductwork and turbine casing sections were
 
observed. Cracked exhaust system com ponents were replaced and casing cracks were repaired. The exhaust system and casing cr acks had not prevented combustion turbine operation prior to the scheduled outage. Minor exhaust system and casing leaks do not
 
prevent the combustion turbine from perfo rming its intended function of providing alternate AC power during an SBO event. The glycol-cooling water heat exchanger tubes
 
and fins at the mechanical draft cooling tower were visually inspected and showed no
 
signs of significant corrosion. External surfaces of elastomer flexible connections were
 
inspected and did not appear cracked or deteriorated.
The operating experience with the FRCTs includes a significant number of inspections of components in the scope of this Periodic Inspection Program - FRCT Program. The
 
documented inspection results confirm that environmental conditions have not caused
 
material degradation that could result in a loss of component intended functions. Past
 
inspections have been at a frequency as long at 16 years with the units performing
 
reliably between inspections. Implementation of this new program will continue these
 
inspections on a more conservative frequency of 10 years, providing reasonable
 
assurance that the aging effects will be adequately managed for the period of extended
 
operation.
The staff reviewed the operating experience provided in the LRA, and interviewed the applicant's technical personnel to confirm that plant-specific operating experience
 
revealed no degradation not bounded by industry experience.
On the basis of its review of the above plant-specific operating experience and discussions with the applicant's technical personnel, the staff concludes that the
 
applicant's Periodic Inspection Program - FRCT Program will adequately manage the
 
aging effects identified in the LRA for which this AMP is credited.
3-234 UFSAR Supplement. The applicant provided its UFSAR supplement for the Periodic Inspection Program - FRCT Program in its supplemental response to RAI 2.5.1.19-1. The staff reviewed this
 
section and determined that the information in the UFSAR supplement provides 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 program and RAI response finds that the applicant has demonstrated that the effects of aging will be adequately managed
 
so that the intended function(s) will be maintained during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). The staff's review of the UFSAR supplement for this program
 
also finds that it provides an adequate summary description of the program, as required by
 
10 CFR 54.21(d).3.0.4  Quality Assurance Program Attribut es Integral to Aging Management Programs 3.0.4.1  Summary of Technical Information in Application Section 3.0, "Aging Management Review Results," of the LRA provided an AMR summary for each unique component type or commodity group at OCGS determined to require aging
 
management during the period of extended operation. This summary includes identification of
 
aging effects requiring management and AMPs managing these aging effects. In LRA
 
Sections A.0.5 and B.0.3, "Quality Assurance Program and Administrative Controls," the
 
applicant described the "corrective action," "confirmation process," and "administrative controls"
 
attributes applied to both safety-related and nonsafety-related SSCs within the scope of license
 
renewal. In LRA Sections B.1 and B.2 the applicant further described the "corrective action,"
 
"confirmation process," and "administrative controls" attributes for each AMP.
The existing QA program meeting the requirements of 10 CFR 50, Appendix B, and a separate QA program based on Appendix A of RG 1.155, "S tation Blackout," will implement the AMP "corrective action," "confirmation process," and "
administrative controls" attributes. The existing QA program that meets the requirements of 10 CFR 50, Appendix B, will be applied to all but the
 
mechanical AMPs for the FRCT. A QA program based on Appendix A of RG 1.155 will be
 
applied to the FRCT mechanical AMPs described in LRA Sections B.1.12A, B.1.14A, B.1.21A, B.1.22A, B.1.24A, B.1.25A, B.1.26A, B.1.38, B.1.29, and B.2.05A. A separate QA program
 
based on Appendix A of RG 1.155 is necessary becaus e the existing QA program that meets the requirements of 10 CFR 50, Appendix B, is not implemented for activities not performed by the
 
applicant. The applicant will establish an agreement with the FRCT owner to ensure that the
 
processes and procedures that address the AMP "corrective action," "confirmation process," and "administrative controls" attributes applicable to the nonsafety-related FRCT mechanical system
 
AMPs are established prior to the period of extended operation. The existing QA program that
 
meets the requirements of 10 CFR 50, Appendix B, will be applied to the FRCT structural and
 
electrical AMP "corrective action," "confirmation pr ocess," and "administrative controls" attributes.
3.0.4.2  Staff Evaluation Pursuant to 10 CFR 54.21(a)(3), a license renewal applicant is required to demonstrate that the effects of aging on SCs subject to an AMR will be adequately managed so that their intended
 
functions will be maintained consistent with the CLB for the period of extended operation.
 
SRP-LR, Branch Technical Position RLSB-1, "Aging Management Review - Generic," describes
 
10 attributes of an acceptable AMP. Three of these 10 attributes are associated with the QA
 
activities of corrective action, confirmation process, and administrative control. Table A.1-1, 3-235"Elements of an Aging Management Program fo r License Renewal," of Branch Technical Position RLSB-1 describes these quality attributes:
* Corrective actions, including root cause determination and prevention of recurrence, should be timely.
* The confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions have been completed and are effective.
* Administrative controls should provide a formal review and approval process.
SRP-LR, Branch Technical Position IQMB-1 noted 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
 
Appendix B to 10 CFR Part 50 QA program may be used to address the elements of "corrective
 
action," "confirmation process," and "administrative control." Branch Technical Position IQMB-1
 
provides the following guidance for the QA attributes of AMPs:
SR 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 NSR SCs that are subject to an AMR for LR, 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 "corrective action," "confirmation process," and "administrative controls" attributes described in LRA Sections A.0.5 and B.0.3 to ensure that the aging management
 
activities were consistent with the staff's guidance described in SRP-LR Section A.2 for QA
 
attributes of the AMPs. The staff also reviewed the AMP descriptions for each program in LRA
 
Sections B.1 and B.2 and found that the three attributes of corrective action, confirmation
 
process, and administrative document control were specifically described and included adequate
 
reference to the application of the existing QA program meeting the requirements of 10 CFR 50, Appendix B, with the exception of the FRCT AMP.
As discussed in SER Section 2.5, in RAI 2.5.1.19-1 dated September 28, 2005, the staff requested that the applicant further describe the FRCT AMP. In its responses to RAI 2.5.1.19-1
 
dated October 11 and November 12, 2005, the applicant stated that a QA program based on
 
Appendix A of RG 1.155 will be used to implement the corrective action, confirmation process, and administrative controls attributes for the FRCT mechanical AMPs. The existing QA program
 
that meets the requirements of 10 CFR 50, Appendix B, will be applied to FRCT structural and
 
electrical AMPs. The RAI response also added a new commitment (Commitment No. 65) to
 
ensure that procedures are established to implem ent the program elements of the "corrective action," "confirmation process," and "administrative controls" attributes for the FRCT AMPs prior
 
to the period of extended operation.
The staff's evaluation of the descriptions of the AMPs quality attributes provided in LRA Sections A.0.5, B.0.3, B.1, and B.2 and the applicant's responses to the RAI 2.5.1.19-1
 
concluded that the program descriptions of the "corrective action," "confirmation process," and
 
"administrative controls" attributes are a cceptable. The existing QA program meeting the 3-236 requirements of 10 CFR 50, Appendix B, is consistent with the staff's position and the Branch Technical Position discussed in IQMB-1. The alternative means to address "corrective actions,"
 
"confirmation process," and "administrative controls" applied to the FRCT mechanical AMPs is
 
consistent with Appendix A of RG 1.155 which provides the staff's guidance for implementation
 
of the SBO rule. The staff finds this acceptable as the QA program to be used for FRCT AMPs is
 
equivalent to the Branch Technical Position discussed in IQMB-1.
3.0.4.3  Conclusion The staff concludes that the QA attributes ("corrective action," "confirmation process," and "administrative control") of the applicant's AMPs are consistent with 10 CFR 54.21(a)(3).
 
===3.1 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, internals, and reactor coolant system (RCS) components and component groups
 
associated with the following systems:
* isolation condenser system
* nuclear boiler instrumentation system
* reactor head cooling system
* reactor internals
* reactor pressure vessel
* reactor recirculation system3.1.1  Summary of Technical Information in the Application In LRA Section 3.1, the applicant provided AMR results for the reactor vessel, internals, and RCS components and component groups. In LRA Tabl e 3.1.1, "Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System," the applicant
 
provided a summary comparison of its AMRs wi th the AMRs evaluated in the GALL Report for the reactor vessel, internals, and RCS components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of aging effects requiring management (AERMs). These reviews included evaluation of plant-specific and
 
industry operating experience. The plant-specific evaluation included reviews of 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.
 
====3.1.2 Staff====
Evaluation The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient information to demonstrate that the effects of aging for the reactor vessel, internals, and RCS
 
components within the scope of license renewal and subject to an AMR will be adequately
 
managed so that the intended function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs, during the weeks of October 3-5, 2005, January 23-27, 2006, and February 13-17, 2006, to confirm the applicant's claim that certain 3-237 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.
 
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 the Audit and Review Report, Section 3.1.2.1 and are
 
summarized in SER Section 3.1.2.1.
In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.1.2.2. The staff's
 
audit evaluations are documented in the Audit and Review Report Section 3.1.2.2 and are
 
summarized in SER Section 3.1.2.2.
The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review included evaluating whether all
 
plausible aging effects had been identified and whether the aging effects listed were appropriate
 
for the combination of materials and environments specified. The staff's evaluations are
 
documented in SER Section 3.1.2.3.
For AMRs that the applicant identified as not applicable or not requiring aging management, the staff conducted a review of the AMR line items, and the plant's operating experience, to verify
 
the applicant's claims. Details of these reviews are documented in the Audit and Review Report.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the reactor vessel, internals, and RCS components.
Table 3.1-1, provided below, includes a summary of the staff's evaluation of components, aging effects and mechanisms, and AMPs listed in LRA Section 3.1 that are addressed in the GALL
 
Report.Table 3.1-1  Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant System Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Steel pressure vessel support skirt
 
and attachment welds (Item 3.1.1-1)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAA This TLAA is evaluated in SER Section 4.3.
(See SER Section
 
3.1.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-238 Steel; stainlesssteel; 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 (Item 3.1.1-2)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and
 
environmental
 
effects are to be
 
addressed for
 
Class 1 components TLAA BWR Feedwater Nozzle (B.1.5),
BWR CRD Return
 
Line Nozzle (B.1.6)This TLAA is evaluated in SER Section 4.3.
Acceptable-Crackingdue to fatigue for FW
 
and CRDRL nozzle thermal sleeves will be
 
managed in accordance with
 
10 CFR 54.21(c)(1)(iii).
(See SER Section
 
3.1.2.2.1)
Steel; stainlesssteel; steel with nickel-alloy or
 
stainless steel
 
cladding; nickel-alloy reactor
 
coolant pressure boundary piping, piping components, and piping elements
 
exposed to reactor
 
coolant (Item 3.1.1-3)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c) and
 
environmental
 
effects are to be
 
addressed for
 
Class 1 componentsTLAA This TLAA is evaluated in SER Section 4.3.
(See SER Section
 
3.1.2.2.1)
Steel pump and valve closure bolting (Item 3.1.1-4)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)
 
check Code limits for allowable cycles (less than 7000 cycles) of
 
thermal stress rangeTLAA This TLAA is evaluated in SER Section 4.3.
(See SER Section
 
3.1.2.2.1)
Stainless steel andnickel alloy reactor
 
vessel internals
 
components (Item 3.1.1-5)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAA BWR Vessel Internals (B.1.9)This TLAA is evaluated in SER Section 4.3.
Acceptable- Crackingdue to fatigue will be
 
managed in accordance with
 
10 CFR 54.21(c)(1)(iii)
(See SER Section
 
3.1.2.2.1)
Steel top headenclosure (without
 
cladding) top head
 
nozzles (vent, top head spray or RCIC, and spare) exposed
 
to reactor coolant (Item 3.1.1-11)
Loss of material due to general, pitting and crevice
 
corrosionWater Chemistry andOne-Time InspectionNot ApplicableNot Applicable since OCGS top head enclosure is clad with
 
stainless steel.
(See SER Section
 
3.1.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-239 Steel and stainless steel isolation
 
condenser components
 
exposed to reactor
 
coolant (Item 3.1.1-13)
Loss of material due to general (steel only), pitting
 
and crevice
 
corrosionWater Chemistry andOne-Time Inspection Water Chemistry (B.1.2) and an
 
augmented inspection
 
program to ASME
 
Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1) Acceptable- The augmented inspection
 
program is equivalent
 
to GALL's one-time
 
inspection program
 
and hence, consistent with GALL.
(See SER Section
 
3.1.2.2.2)
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 (Item 3.1.1-14)
Loss of material due to pitting and
 
crevice corrosionWater Chemistry andOne-Time Inspection Water Chemistryand One-Time
 
InspectionConsistent with GALL,which recommends
 
further evaluation.
(See SER Section
 
3.1.2.2.2)
Stainless steel; steelwith nickel-alloy or
 
stainless steel
 
cladding; and nickel-alloy reactor
 
coolant pressure
 
boundary components
 
exposed to reactor
 
coolant (Item 3.1.1-15)
Loss of material due to pitting and
 
crevice corrosionWater Chemistry andOne-Time Inspection Not ApplicableNot applicable since no GALL AMR line items
 
related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
(See SER Section
 
3.1.2.2.2)Steel (with orwithout stainless
 
steel cladding)
 
reactor vessel
 
beltline shell, nozzles, and welds (Item 3.1.1-17)
Loss of fracture toughness due to
 
neutron irradiation
 
embrittlementTLAA, evaluated inaccordance with
 
Appendix G of 10 CFR 50 and RG 1.99. The
 
applicant may
 
choose to demonstrate that the
 
materials of the
 
nozzles are not
 
controlling for the TLAA evaluations.TLAA, evaluatedin accordance with
 
Appendix G of 10 CFR 50 and
 
RG 1.99. This TLAA is evaluated in SER Section 4.3.
(See SER Section
 
3.1.2.2.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-240Steel (with orwithout stainless
 
steel cladding)
 
reactor vessel
 
beltline shell, nozzles, and welds; safety injection
 
nozzles (Item 3.1.1-18)
Loss of fracture toughness due to
 
neutron irradiation
 
embrittlement Reactor Vessel Surveillance Reactor Vessel Surveillance (B.1.23)Consistent with GALL,which recommends
 
further evaluation.
(See SER Section
 
3.1.2.2.3)
Stainless steel andnickel alloy top head
 
enclosure vessel
 
flange leak detection
 
line (Item 3.1.1-19)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking A plant-specific aging management
 
program is to be
 
evaluated.ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)Acceptable- ASME ISIprogram will adequately manage
 
the aging effects;
 
therefore, this is consistent with GALL.
(See SER Section
 
3.1.2.2.4)
Stainless steel isolation condenser
 
components
 
exposed to reactor
 
coolant (Item 3.1.1-20)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking InserviceInspection (IWB, IWC, and IWD),
Water Chemistry, and plant-specific
 
verification programASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1), Water Chemistry (B.1.2),
and an augmented
 
inspection
 
programConsistent with GALL,which recommends further evaluation. The
 
augmented inspection program will verify that
 
no cracking has
 
occurred.
(See SER Section
 
3.1.2.2.4)
Stainless steel jet pump sensing line (Item 3.1.1-25)
Cracking due tocyclic loading A plant-specific aging management
 
program is to be
 
evaluated.Not applicableNot applicable, since OCGS does not have
 
jet pumps and jet pump
 
sensing lines.
(See SER Section
 
3.1.2.2.8)
Steel and stainless steel isolation
 
condenser components
 
exposed to reactor
 
coolant (Item 3.1.1-26)
Cracking due tocyclic loading InserviceInspection (IWB, IWC, and IWD) and
 
plant-specific
 
verification programASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1), Water Chemistry (B.1.2),
and an augmented
 
inspection
 
programConsistent with GALL,which recommends further evaluation. The
 
augmented inspection program will verify that
 
no cracking has
 
occurred.
(See SER Section
 
3.1.2.2.8)
Stainless steelsteam dryers
 
exposed to reactor
 
coolant (Item 3.1.1-29)
Cracking due toflow-induced
 
vibration A plant-specific aging management
 
program is to be
 
evaluated.
BWR Vessel Internals (B.1.9),
with GE SIL-644, R1 recommend-ations
 
as included in BWRVIP-139 Acceptable- Consistentwith the current licensing basis and will adequately manage
 
cracking; therefore, this is consistent with
 
GALL.
(See SER Section
 
3.1.2.2.11)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-241Steel (with orwithout stainless
 
steel cladding)
 
control rod drive
 
return line nozzles
 
exposed to reactor
 
coolant (Item 3.1.1-38)
Cracking due tocyclic loading BWR CR Drive Return Line Nozzle BWR CRD Return Line Nozzle (B.1.6)Consistent with GALL.The SS thermal sleeve will be managed by the
 
BWR vessel internals
 
program (B.1.9).
(See SER Section
 
3.1.2.2.1)Steel (with orwithout stainless
 
steel cladding) feedwater nozzles
 
exposed to reactor
 
coolant (Item 3.1.1-39)
Cracking due tocyclic loadingBWR Feedwater NozzleBWR Feedwater Nozzle (B.1.5)Consistent with GALL.The nickel alloy thermal sleeves will be managed by the BWR
 
vessel internals
 
program (B.1.9).
(See SER Section
 
3.1.2.2.1)
Stainless steel and nickel alloy
 
penetrations for
 
control rod drive
 
stub tubes
 
instrumentation, jet
 
pump instrumentation, standby liquid
 
control, flux monitor, and drain line
 
exposed to reactor
 
coolant (Item 3.1.1-40)
Cracking due to stress corrosion
: cracking, Intergranular
 
stress corrosion cracking, cyclic
 
loadingBWR Penetrationsand Water ChemistryBWR Penetrations (B.1.8), Water Chemistry (B.1.2),
and BWR Vessel
 
Internals (B.1.9)Consistent with GALL.
AMP B.1.9 provides
 
additional assurance.
(See SER Section
 
3.1.2.1)Stainless steel andnickel alloy piping, piping components, and piping elements
 
greater than or
 
equal to 4 NPS;
 
nozzle safe ends
 
and associated welds (Item 3.1.1-41)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking BWR Stress Corrosion Cracking and Water Chemistry BWR Stress Corrosion Cracking (B.1.7) and Water Chemistry (B.1.2)Consistent with GALL.(See SER Section
 
3.1.2.1)Stainless steel andnickel alloy vessel
 
shell attachment welds exposed to
 
reactor coolant (Item 3.1.1-42)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking BWR Vessel ID Attachment Welds and Water Chemistry BWR Vessel ID Attachment Welds (B.1.4) and Water Chemistry (B.1.2)Consistent with GALL.(See SER Section
 
3.1.2.1)Stainless steel fuel supports and control
 
rod drive assemblies
 
control rod drive
 
housing exposed to
 
reactor coolant (Item 3.1.1-43)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking BWR VesselInternals and Water
 
Chemistry BWR Vessel Internals (B.1.9) and Water Chemistry (B.1.2)Consistent with GALL.(See SER Section
 
3.1.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-242 Stainless steel andnickel alloy core
 
shroud, core plate, core plate bolts, support structure, top guide, core spray lines, spargers, jet pump
 
assemblies, control
 
rod drive housing, nuclear instrumentation
 
guide tubes (Item 3.1.1-44)
Cracking due to stress corrosion
: cracking, intergranular stress
 
corrosion cracking, irradiation-assisted
 
stress corrosion
 
cracking BWR VesselInternals and Water
 
Chemistry BWR Vessel Internals (B.1.9) and Water Chemistry (B.1.2) Consistent with GALL.
Enhanced inspections
 
of cracked reactor components will be
 
continued.
(See SER Section
 
3.1.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to reactor
 
coolant (Item 3.1.1-45)Wall thinning dueto flow-accelerated
 
corrosionFlow-Accelerated CorrosionFlow-Accelerated Corrosion (B.1.11)Consistent with GALL.(See SER Section
 
3.1.2.1)Nickel alloy core shroud and core
 
plate access hole
 
cover (mechanical
 
covers)
(Item 3.1.1-46)
Cracking due to stress corrosion
: cracking, intergranular stress
 
corrosion cracking, irradiation-assisted
 
stress corrosion
 
cracking InserviceInspection (IWB, IWC, and IWD), and
 
Water ChemistryNot applicableNot applicable, since OCGS does not have
 
access hole covers.
Stainless steel andnickel-alloy reactor
 
vessel internals
 
exposed to reactor
 
coolant (Item 3.1.1-47)
Loss of material due to pitting and
 
crevice corrosion InserviceInspection (IWB, IWC, and IWD), and
 
Water Chemistry BWR Vessel Internals (B.1.9)Acceptable - The OCGS BWR Vessel
 
Internals Program is
 
part of the OCGS ISI
 
program. Also, all RVI components will be
 
exposed to treated reactor water;
 
therefore, the OCGS water chemistry AMP will be invoked.
(See SER Section
 
3.1.2.1.3)
Steel and stainless steel Class 1 piping, fittings and branch
 
connections
< NPS 4 exposed to
 
reactor coolant (Item 3.1.1-48)
Cracking due to stress corrosion
: cracking, intergranular stress
 
corrosion cracking (for stainless steel only), and thermal
 
and mechanical
 
loading InserviceInspection (IWB, IWC, and IWD),
Water chemistry, and One-Time
 
Inspection of ASME
 
Code Class 1
 
Small-bore PipingASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1), Water Chemistry (B.1.2),
and One-Time
 
Inspection (B.1.24).Consistent with GALL.(See SER Section
 
3.1.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-243Nickel alloy core shroud and core
 
plate access hole cover (welded
 
covers)
(Item 3.1.1-49)
Cracking due to stress corrosion
: cracking, intergranular stress
 
corrosion cracking, irradiation-assisted
 
stress corrosion
 
cracking InserviceInspection (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 weldsNot applicableNot applicable, since OCGS does not have
 
access hole covers.
High-strength lowalloy steel top head
 
closure studs and
 
nuts exposed to air with reactor coolant
 
leakage (Item 3.1.1-50)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking Reactor Head Closure Studs Reactor Head Closure Studs (B.1.3)Consistent with GALL.(See SER Section
 
3.1.2.1)Cast austenitic stainless steel jet
 
pump assembly
 
castings; orificed
 
fuel support (Item 3.1.1-51)
Loss of fracture toughness due to
 
thermal aging and
 
neutron irradiation
 
embrittlementThermal Aging and Neutron Irradiation
 
Embrittlement of
 
CASSThermal Aging and Neutron
 
Irradiation
 
Embrittlement of
 
CASS (B.1.10)Consistent with GALL.(See SER Section
 
3.1.2.1)Steel and stainless steel reactor coolant
 
pressure boundary (RCPB) pump and
 
valve closure bolting, manway and
 
holding bolting, flange bolting, and
 
closure bolting in
 
high-pressure and
 
high-temperature systems (Item 3.1.1-52)
Cracking due to stress corrosion
 
cracking, loss of
 
material due to wear, loss of
 
preload due to
 
thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity (B.1.12)Consistent with GALL.(See SER Section
 
3.1.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to closed cycle cooling water (Item 3.1.1-53)
Loss of material due to general, pitting and crevice
 
corrosionClosed-CycleCooling Water SystemNot applicableNot applicable, since OCGS has no such components within the
 
scope of license renewal.Copper alloy piping, piping components, and piping elements
 
exposed to closed cycle cooling water (Item 3.1.1-54)
Loss of material due to pitting, crevice, and
 
galvanic corrosionClosed-CycleCooling Water SystemNot applicableNot applicable, since OCGS has no such components within the
 
scope of license renewal.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-244 Cast austenitic stainless steel
 
Class 1 pump
 
casings, and valve
 
bodies and bonnets
 
exposed to reactor coolant > 250&deg;C
(> 482&deg;F)
(Item 3.1.1-55)
Loss of fracture toughness due to
 
thermal aging
 
embrittlement Inserviceinspection (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.Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1). 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.Consistent with GALL.(See SER Section
 
3.1.2.1)Copper alloy> 15% Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water (Item 3.1.1-56)
Loss of material due to selective
 
leaching Selective Leaching of MaterialsNot applicableNot applicable, since OCGS has no such components within the
 
scope of license renewal.Cast austenitic stainless steel
 
Class 1 piping, piping component, and piping elements
 
and control rod drive
 
pressure housings
 
exposed to reactor coolant > 250&deg;C
(> 482&deg;F)
(Item 3.1.1-57)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASSThermal Aging and Neutron
 
Irradiation
 
Embrittlement of
 
CASS (B.1.10)
 
used for RVI
 
componentsConsistent with GALL (RVI components).
(See SER Section
 
3.1.2.1)For pump and valve bodies in ICS and RR systems - see Item
 
3.1.1-55 RHCS valve bodies are not identified for this
 
aging effect since they are exposed to lower
 
temperature. Nickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
(Item 3.1.1-85)NoneNoneNoneConsistent with GALL.(See SER Section
 
3.1.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-245 Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor uncontrolled (External); air with borated water
 
leakage; concrete;
 
gas (Item 3.1.1-86)NoneNoneNoneConsistent with GALL.(See SER Section
 
3.1.2.1)Steel piping, piping components, and
 
piping elements in
 
concrete (Item 3.1.1-87)NoneNoneNot applicableNot applicable, since OCGS has no such
 
components in the RCS within the scope of license renewal.
The staff's review of the reactor vessel, internals, and RCS component groups followed one of several approaches. One approach, documented in SER Section 3.1.2.1, discusses the staff's
 
review of the AMR results for components that the applicant indicated are consistent with the
 
GALL Report and do not require further evaluation. Another approach, documented in SER
 
Section 3.1.2.2, discusses the staff's review of the AMR results for components that the applicant
 
indicated are consistent with the GALL Report and for which further evaluation is recommended.
 
A third approach, documented in SER Section 3.1.2.3, discusses the staff's review of the AMR
 
results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs that are credited to manage or monitor aging
 
effects of the reactor vessel, internals, and RCS components is documented in SER
 
Section 3.0.3.3.1.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the effects of aging related to the reactor vessel, internals, and RCS
 
components:
* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)
* Water Chemistry (B.1.2)
* Reactor Head Closure Studs (B.1.3)
* BWR Vessel ID Attachment Welds (B.1.4)
* BWR Feedwater Nozzle (B.1.5)
* BWR CRD Return Line Nozzle (B.1.6)
* BWR SCC (B.1.7)
* BWR Penetrations (B.1.8)
* BWR Vessel Internals (B.1.9)
* Thermal Aging and Neutron Irradiation Embrittlement of CASS (B.1.10)
* Bolting Integrity (B.1.12)
* Reactor Vessel Surveillance (B.1.23)
* One-Time Inspection (B.1.24) 3-246
* Structures Monitoring Program (B.1.31)
* Lubricating Oil Monitoring Activities (B.2.2)
Staff Evaluation. In LRA Tables 3.1.2.1.1 through 3.1.2.1.6, the applicant provided a summary of AMRs for the reactor vessel, internals, and RCS components and identified which AMRs it
 
considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report for which the applicant has claimed consistency with the GALL Report 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 contained 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 that the AMR is 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 AMP
 
identified in the GALL Report. 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. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant is 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 com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item of
 
the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the AMP identified in the GALL Report. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. The staff verified whether
 
the identified exceptions to the GALL 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.
3-247 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review Report Section 3.1.2.1. 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 is discussed below.
3.1.2.1.1  Cracking due to Stress Corrosion Cracking (SCC), Intergranular Stress Corrosion Cracking (IGSCC), and Irradiation Assisted Stress Corrosion Cracking (IASCC)
LRA Table 3.1.2.1.4 for the reactor internals credits the BWR Vessel Internals and Water Chemistry Programs to manage cracking due to SCC, IGSCC, and IASCC in the stainless steel
 
and nickel alloy reactor vessel top guide.
During the audit, the staff noted that several INs, including IN 95-17, addressed cracking of BWR top guides within the operating experience of domestic and foreign reactors. The top guide at
 
OCGS has experienced problems with cracking si nce the early nineties. Therefore, the applicant was asked to describe how cracking of the top guide will be managed by the BWR Vessel
 
Internals and Water Chemistry Programs, as stated in LRA Table 3.1.2.1.4, during the period of
 
extended operation.
In its response, the applicant stated that during the 13R refueling outage in 1991, a crack was found on the underside of a top guide beam. During the 14R and 15R refueling outages in 1992
 
and 1994, additional cracks were found on the underside of top guide beams. As a result of
 
these findings, UT inspections of the complete top guide during the 16R refueling outage in 1996
 
found 5 mid-span cracks and 12 UT indications in the notches used to interlock the beams. The
 
majority of the cracks and indications was located in the northeast quadrant of the top guide.
 
Additionally, a sample of the top guide was removed for metallurgical examination during the
 
16R refueling outage and the aging mechanism was determined to be IASCC. Furthermore, a
 
flaw growth evaluation was prepared for the most significant crack to predict future crack growth
 
and to evaluate its effects upon the structural integrity of the top guide. The flaw evaluation
 
predicted a maximum crack growth of 1.6 inches within 2 cycles of operation and determined
 
that, even if this growth occurred, the structural integrity of the top guide would not be compromised.
The applicant also stated that visual inspections of the top guide were performed again during the 18R refueling outage in 2000. The visual inspection of the limiting flaw determined that it had
 
grown approximately half of the maximum predicted crack growth value during the 2 operating
 
cycles since the previous inspection. The cra ck was still well within evaluation limits and did not impair the structural integrity of the top guide. Additional visual inspections during the 20R
 
refueling outage in 2004 to monitor crack growth indicated that there had been no additional
 
crack growth during the previous 2 operating cycles.
The applicant further stated that it plans to inspect the top guide during the next refueling outage by UT examination. As a minimum, the complete northeast quadrant of the top guide will be 3-248 inspected to determine whether the cracking has been mitigated. If significant crack growth is found in the northeast quadrant, additional inspections will be performed as necessary to
 
characterize crack growth. As discussed in BWRVIP-26-A, OCGS is a lead plant with respect to
 
top guide cracking due to its age and top guide fluence and all inspections will be performed in
 
accordance with BWRVIP-26-A. Therefore, the results of the 2006 inspections will provide key
 
information in developing top guide inspection guidelines, and the frequency and scope of future
 
inspections may be adjusted based on these inspection results. This program provides
 
reasonable assurance that the top guide will perform its intended functions during the period of
 
extended operation.
As stated in the September 2005 GALL Report, item IV.B1.17 (R-98), for top guides with neutron fluence exceeding the IASCC threshold prior to the period of extended operation, the applicant
 
shall inspect 10 percent of the top guide locations using enhanced visual inspection technique
 
EVT-1 within 12 years with one-half of the inspections (i.e., 5 percent of locations) to be
 
completed within the first 6 years of the period of extended operation. The applicant stated that
 
corrective actions will be taken, including repair or replacement of the top guide, if found
 
necessary. This statement is consistent with the GALL Report recommendations.
The staff determined that the applicant's aging management activities to manage cracking of the top guide are consistent with the recommendations in the GALL Report.
LRA Table 3.1.2.1.4 for the reactor internals credits the BWR Vessel Internals and Water Chemistry Programs to manage cracking due to SCC, IGSCC, and IASCC in the stainless steel
 
and nickel alloy reactor vessel core shroud.
The staff noted that industry experience confirms the observation of cracking in core shrouds at both horizontal (GL 94-03) and vertical (IN 97-17) welds. The core shroud has cracked and has
 
operated in its repaired configuration. In light of this condition, the staff asked the applicant to
 
describe how continued aging of the cracked core shroud and its repair hardware will be
 
managed by the BWR Vessel Internals and Water Chemistry Programs, as stated in LRA
 
Table 3.1.2.1.4, during the period of extended operation.
In its response, the applicant stated that cracking has affected shrouds fabricated from Types 304 and 304L stainless steel. In 1994 OCGS examined the shroud comprehensively and
 
found significant cracking in the core shroud H4 circumferential weld and additional minor
 
cracking in the H2 and H6 welds. The examinations were visual with cleaning and UT
 
examinations wherever practical. During the same refueling outage, repair hardware was
 
installed to ensure the shroud could continue to perform its intended function. The repair
 
hardware consisted of 10 tie rods anchored at the top and bottom of the shroud. Details of the
 
repair design were sent to the NRC in 1994. The shroud repair system structurally replaces all
 
horizontal welds. Therefore, as discussed BWRVIP-76, no further inspection of the horizontal
 
welds is required. Subsequent inspections focused on the vertical welds.
The applicant also stated that subsequent inspections of the repair hardware have confirmed that the tie rods are in good condition and continue to support the shroud structure reliably. Following
 
the guidelines of BWRVIP-76, the applicant has chosen to implement the option to inspect all
 
vertical welds. The accessible length of all vertical welds was inspected in 1998 and 2000. All
 
inspected welds were found free of indications except that the V-9 weld indicated a small flaw (less than 2 inches) acceptable by BWRVIP-76 acceptance criteria.
3-249 The applicant further stated that it will complete inspection of all vertical welds in accordance with BWRVIP-76 guidelines by 2008. Currently, the vertical welds are scheduled to be inspected by
 
UT techniques in 2006.
For the period of extended operation, the applicant stated that the inspections identified above will be continued in accordance with BWRVIP-76 guidelines. All vertical welds will be inspected
 
every 10 years by either EVT-1 or UT exami nation methods. Repair assemblies will be inspected by VT-3 of locking devices, critical gap or c ontact areas, bolting, and the overall component. The repair anchorage inspections include an EVT-1 inspection of the most highly stressed accessible
 
load bearing weld every 10 years. If indications are found the applicant will evaluate them and
 
take appropriate corrective actions.
The staff reviewed the current status of the repaired hardware and the overall structural integrity of the shroud. No particular degradation was found since the shroud had been repaired. The
 
applicant has augmented inspections of the shroud, as well as the repaired hardware, following
 
the BWRVIP-76 recommendations. The staff determined that the applicant's aging management
 
of cracking of the core shroud is consistent with the recommendations in the GALL Report.
LRA Table 3.1.2.1.4 for reactor internals credits the BWR Vessel Internals and Water Chemistry Programs to manage cracking due to SCC, IGSCC, and IASCC in stainless steel and nickel alloy
 
reactor vessel spargers.
The staff noted that instances of cracking in BWR core spray spargers have been reviewed in NRC Bulletin 80-13. Core spray spargers at OCGS have experienced cracking since the late
 
seventies. In light of this condition, the staff asked the applicant to describe how the continued
 
aging of the cracked core spray spargers and their repair hardware will be managed by the BWR
 
Vessel Internals and Water Chemistry Programs, as stated in LRA Table 3.1.2.1.4, during the
 
period of extended operation.
In its response, the applicant stated that it had found crack indications in the core spray spargers in 1978. One mechanical clamp was installed during that refueling outage to provide structural
 
support for a crack found in one of the core spray spargers. The installed clamp ensures
 
long-term structural integrity of the sparger, but no credit is taken as a leakage limiter. In 1980, additional linear indications were reported and as a result nine additional mechanical clamps
 
were installed. All four tee boxes on both spargers were clamped. The primary root cause of the
 
cracking problems found in 1978 and 1980 was reported to be high residual stresses on the
 
sparger pipes from having been forced into position during installation. Consistent with this root
 
cause, the cracking was expected to relieve the residual stresses and stop any further growth as
 
well as any initiation of new cracks. No further cracking or other degradation of the spargers has
 
been reported since 1980.
The applicant also stated that recent inspections in 1998, 2000, 2002, and 2004 have confirmed the good condition of the repair clamps. Inspection of the core spray piping welds has confirmed
 
the success of the mitigation efforts of the Water Chemistry Program as no new crack indications
 
have been found. The core spray piping and spargers inside the reactor vessel are inspected in
 
accordance with BWRVIP-18-A, which specifies inspection of core spray internals, including piping, spargers, nozzles, and brackets. There are no ASME Code Section XI requirements for
 
the core spray internals. As prescribed by BWRVIP-18-A, during each refueling outage the
 
following components are evaluated by EVT-1 enhanced visual examination methods: accessible
 
core spray piping fillet welds, 25 percent of the core spray piping brackets, 25 percent of the core 3-250 spray piping butt welds, end cap welds, and T-box cover plate welds. The following components are examined by VT-1 visual examination met hods during each refueling outage: nozzle-to-pipe welds, nozzle-to-orifice welds, sparger brackets, and repair clamps.
For the period of extended operation, the applicant stated that the inspections identified above will be continued in accordance with BWRVIP-18-A guidelines. If indications are found the
 
applicant will evaluate them and take appropriate corrective actions.
The staff reviewed the status of the repaired hardware and the overall structural integrity of the core spray piping and spargers. No particular degradation was found since the core spray
 
spargers had been repaired. The applicant has augmented inspections of the core spray piping
 
and the repaired hardware following the BWRVIP-18-A recommendations accepted by the staff.
 
The staff concludes that the applicant adequately manages aging of the core spray spargers.
3.1.2.1.2  Cracking Due to SCC of Control Rod Drive Stub Tubes
 
LRA Table 3.1.2.1.5 for the RPV credits the BWR Penetrations, BWR Vessel Internals, and Water Chemistry Programs to manage cracking due to SCC, IGSCC, and cyclic loading in stainless steel and nickel alloy penetrations for CRD stub tubes exposed to reactor coolant.
During the audit, the staff noted that several CRD stub tubes at OCGS had been leaking recently and that roll expansion repairs had been performed to limit this leakage. In light of this condition, the staff asked the applicant to describe how the continued aging of the leaking CRD stub tubes
 
and their repairs will be managed by the BWR Penetrations, BWR Vessel Internals, and Water
 
Chemistry Programs, as stated in LRA Table 3.1.2.1.5, during the period of extended operation.
In its response, the applicant stated that due to the stub tube leakage in the bottom head found in 2000, OCGS has committed to perform inspections for leakage whenever the drywell is made
 
accessible during outages. A minimal amount of leakage is permitted for rolled repaired housing.
 
This leakage allowance is valid only through the next refueling outage (2006). If the ASME Code
 
Case N-730 on roll expansion repair is approved and adopted, then weld repairs will be made for
 
leaking stub tubes that cannot be made leak tight by a roll repair prior to restarting the plant.
The staff reviewed the current status of the stub tubes and their repair, and the overall structural integrity of the vessel bottom head. No degradation was found since the stub tubes had been
 
repaired. The applicant has augmented inspections of these stub tubes following the BWRVIP
 
recommendations accepted by the staff.
In its response to RAI B1.9-3 dated April 18, 2006, the applicant committed (Commitment No. 9) to revise LRA Section B.1.9 to clarify its position on the use of roll/expansion techniques for the
 
repair of leaking CRD stub tubes to result in no leakage of the CRD of the stub tubes during the
 
period of extended operation as follows:
If Code Case N-730 is not approved, Oyster Creek will develop a permanent ASME code repair plan. This permanent ASME code repair could be performed in
 
accordance with BWRVIP-5:3-A, which has been approved by the NRC, or an
 
alternate ASME code repair plan which would be submitted for prior NRC
 
approval. If it is determined that the repair plan needs prior NRC approval, Oyster
 
Creek will submit the repair plan two years before entering the period of extended
 
operation. After the implementation of an approved permanent roll repair (draft 3-251 code case N-730), if there is a leak in a CRD stub tube, Oyster Creek will weld repair any leaking CRD stub tubes during the extended period of operation by
 
implementing a permanent NRC approved ASME Code repair for leaking stub
 
tubes that cannot be made leak tight using a roll expansion method prior to
 
restarting the plant. Appendix A.1.9 and item number 9 of Table A.5 Commitment
 
List will be updated to reflect the above commitments.
On the basis of its review, the staff finds that the applicant has appropriately addressed the aging effect and mechanism based on the commitment and that the programs provide reasonable
 
assurance that the CRD stub tube welds will perform their intended functions during the period of
 
extended operation.
3.1.2.1.3  Loss of Material Due to Pitting and Crevice Corrosion
 
The staff noted that the applicant did not credit the GALL Report AMR for loss of material due to pitting and crevice corrosion in stainless steel and nickel-alloy RVI components exposed to
 
reactor water, GALL Report item 3.1.1-47. This new AMR was not in the January 2005 draft
 
GALL Report.
In Attachment 7, Item RP-26, of its reconciliation document, the applicant stated that loss of material due to pitting and crevice corrosion in stainless steel and nickel alloy reactor vessel
 
internal components will be addressed by the BWR Vessel Internals Program to manage this aging effect.
In its letter dated March 30, 2006, the applicant committed (Commitment No. 9) to revising LRA Section 3.1 to address loss of material due to pitting and crevice corrosion in stainless steel and
 
nickel alloy reactor vessel internal components. The BWR Vessel Internals Program will manage
 
this aging effect.
The staff reviewed the applicant's commitment and noted that the GALL Report recommendsboth the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and Water
 
Chemistry Programs to manage loss of material for these RVI components. The staff reviewed the BWR Vessel Internals Program and determined that it is part of the ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD Program. In addition, although the
 
applicant did not specifically identify the Water Chemistry Program as one of the AMPs to
 
manage this aging effect, the staff recognized these RVI components are exposed to reactor
 
water and that the quality of this water is treated in accordance with BWRVIP-130. Thus, because the applicant will follow the recommendations established in BWRVIP-130, the staff
 
finds the use of the BWR Vessel Internals Program to manage this aging effect acceptable.
3.1.2.1.4  Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)
 
The staff reviewed the aging effects due to thermal aging and neutron embrittlement of CASS materials in the RVI components listed in LRA Table 3.1.2.1.4.The GALL Report recommends GALL AMP XI.M13, "Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel," for managing thermal aging and neutron embrittlement of
 
CASS materials in the following RVI components:
* control rod assemblies (housing and guide tube) 3-252
* core spray lines
* core spray nozzle elbows
* fuel support pieces.
In LRA Table 3.1.2.1.4, the applicant indicated that the Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless St eel Program will be implemented to monitor the aging effect due to thermal aging and neutron embrittlement of the CASS RVI components.
The staff's review of LRA Section 3.1.2.1 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.1.1-5 dated March 20, 2006, the staff requested that the applicant provide information on these components for an assessment of their susceptibility to thermal and neutron irradiation
 
embrittlement. Specifically, the staff reques ted that the applicant provide the following information:
* type of casting (i.e., centrifugal or static)
* composition of CASS (i.e., molybdenum content and delta ferrite values)
* previous plant-specific experience with the components cracked due to neutron and thermal embrittlement and the type and extent of subsequent inspection of CASS orificed
 
fuel support components with fluence values based on the end of the period of extended
 
operation.
In its response dated April 18, 2006, the applicant stated that it would obtain information on the type and the composition of the CASS material in RVI components and evaluate their
 
susceptibility to thermal and neutron irradiation embrittlement prior to the period of extended
 
operation. The staff requested that the applicant submit this evaluation to the staff for review and
 
approval prior to the period of extended operation.
In its supplemental letter dated July 7, 2006, the applicant modified the UFSAR and its commitment (Commitment No. 10) to specify that the following will be submitted for NRC review
 
at least 1 year prior to entering the period of extended operation:
* type and composition of CASS RVI components within the scope of license renewal
* results of evaluations performed to determine susceptibility to thermal aging and neutron irradiation embrittlement The staff finds this acceptable because the applicant's proposed Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel Program for monitoring the aging effect of the CASS materials is consistent with GALL AMP XI.M13. The staff's concern described in
 
RAI 3.1.1-5 is resolved.
Conclusion. 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes, that the applicant has demonstrated that the effects of aging for these components 3-253 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 Summary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report, for the reactor vessel, internals, and RCS components. The applicant provided information concerning
 
how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of fracture toughness due to neutron irradiation embrittlement
* cracking due to stress corrosion cracking and intergranular stress corrosion cracking
* crack growth due to cyclic loading
* loss of fracture toughness due to neutron irradiation embrittlement and void swelling
* cracking due to stress corrosion cracking
* 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 stress corrosion cracking and irradiation-assisted stress corrosion cracking
* cracking due to primary water stress corrosion cracking
* wall thinning due to flow-accelerated corrosion
* changes in dimensions due to void swelling
* cracking due to stress corrosion cracking and primary water stress corrosion cracking
* cracking due to stress corrosion cracking, primary water stress corrosion cracking, and irradiation-assisted stress corrosion cracking
* quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant had claimed consistency with the GALL Report and for which the GALL Report recommends
 
further evaluation, the staff audited and 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 of SRP-LR Section 3.1.2.2. Details of the
 
staff's audit are documented in the Audit and Review Report Section 3.2.1.1. The staff's
 
evaluation of the aging effects is discussed in the following sections.
3.1.2.2.1  Cumulative Fatigue Damage 3-254 In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staff's review of the applicant's evaluation of this TLAA.
The staff determined that some of the TLAAs for the reactor vessel and its internals may not have explicit fatigue analysis calculations (therefore, they may not have the calculated CUFs),
because the plant was originally designed based on ASME Power Piping Code B31.1.
 
Specifically, in LRA Tables 3.1.2.1.4 and 3.1.2.1.5, the applicant credited TLAA to manage
 
cumulative fatigue damage for certain components. The applicant was asked to confirm that the
 
CUFs for these components are available and that fatigue cycles are tracked in order to manage
 
the cumulative fatigue damage by TLAA in accordance with 10 CFR 54.21(c)(1)(i) or (ii), as
 
claimed in the LRA.
In its response, the applicant stated that the use of TLAA as an AMP in LRA Tables 3.1.2.1.4 and 3.1.2.1.5 indicates that the CLB was reviewed for TLAAs and the fatigue analysis was
 
evaluated where one existed for that component. However, several components for which TLAA
 
was identified as the AMP for the cumulative fatigue aging effect have no fatigue analyses.
 
These components include the reactor internals (LRA Table 3.1.1, item number 3.1.1-5) and the
 
CRD return line nozzle and feedwater nozzle thermal sleeves (LRA Table 3.1.1, item
 
number 3.1.1-2). With no fatigue analysis for these components, the effects of cumulative fatigue
 
are managed by other AMPs, in accordance with 10 CFR 54.21(c)(1)(iii).
In its letter dated April 17, 2006, the applicant revised the AMR line items in LRA Tables 3.1.2.1.4 and 3.1.2.1.5 to delete the reference to TLAA for components where a TLAA
 
does not exist. Further, the appropriate AMP will be identified with an "E" industry standard note
 
and a plant-specific note stating: "There is no fatigue analysis for this component. The aging
 
effect of cumulative fatigue is managed by the BWR Vessel Internals aging management
 
program." Similarly for the feedwater nozzle and CRD return line nozzle thermal sleeves, the
 
note will read: "There is no fatigue analysis for this component. The aging effect of cumulative
 
fatigue is managed by the BWR Feedwater Nozzle (or BWR CRD Return Line Nozzle, as
 
applicable) aging management program." The staff reviewed the applicant's response and finds that, although there is no fatigue analysis for several components for which a TLAA was credited, the effects of cumulative fatigue will be
 
managed by other AMPs in accordance with 10 CFR 54.21(c)(1)(iii) and is acceptable.
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 and Attachment 7, items RP-25 and RP-27, of the applicant's reconciliation document against the criteria in SRP-LR Section 3.1.2.2.2.
In LRA Section 3.1.2.2.2.1, the applicant addressed loss of material due to general, pitting, and crevice corrosion for the steel top head enclosure (without cladding) top head nozzles (vent, top
 
head spray or reactor core isolation cooling (RCIC), and spare) exposed to reactor coolant.
SRP-LR Section 3.1.2.2.2.1 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. Loss of material due to general, pitting, and crevice corrosion could also
 
occur for the steel top head enclosure (without cladding) top head nozzles (vent, top head spray
 
or RCIC, and spare) exposed to reactor coolant. The existing program relies on control of reactor 3-255 water chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of material due to pitting and crevice corrosion at locations of stagnant flow conditions.
 
Therefore, the effectiveness of the Water Chemistry 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 Water Chemistry Program. A one-time inspection of select components
 
at susceptible locations is an acceptable method to determine whether an aging effect does not
 
occur or progresses so slowly that the component's intended function will be maintained during
 
the period of extended operation.
LRA Section 3.1.2.2.2.1 states that this is applicable to PWRs only. The staff finds the applicant's evaluation acceptable.
In LRA Section 3.1.2.2.2.2 the applicant addressed loss of material due to pitting and crevice corrosion in stainless steel BWR isolation condenser components exposed to reactor coolant.
SRP-LR Section 3.1.2.2.2.2 states that loss of material due to pitting and crevice corrosion could occur in stainless steel BWR isolation condenser components exposed to reactor coolant. Loss
 
of material due to general, pitting, and crevice corrosion could occur in steel BWR isolation
 
condenser components. The existing program relies on control of reactor water chemistry to
 
mitigate corrosion. However, control of water chemistry does not preclude loss of material due to
 
pitting and crevice corrosion at locations of stagnant flow conditions. Therefore, the effectiveness
 
of the Water Chemistry Program should be verified to ensure that corrosion does not occur. The
 
GALL Report recommends further evaluation of progr ams to verify the effectiveness of the Water Chemistry Program. A one-time inspection of select components at susceptible locations is an
 
acceptable method to determine whether an aging effect does not occur or progresses so slowly
 
that the component's intended function will be maintained during the period of extended
 
operation.
LRA Section 3.1.2.2.2.2 states that the Water Chemistry Program will be used to manage aging of stainless steel tube side components of the isolation condenser system exposed to reactor coolant. The program activities monitor and control water chemistry by station procedures and processes for the prevention or mitigation of loss of material aging effects. The ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD Program will be used with the Water Chemistry Program to manage loss of material. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be enhanced to inspect the isolation condenser
 
tube side components, including temperature and radioactivity monitoring of the shell-side water, eddy current testing of the tubes, and inspection (VT or UT) of the tubesheet and channel head
 
to ensure that significant degradation does not occur and the component intended function will
 
be maintained during the period of extended operation. Observed conditions with the potential for
 
impacting the intended function are evaluated or corrected in accordance with the corrective
 
action process.
The staff's review of LRA Section 3.1.2.2.2 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
During a teleconference on February 2, 2006, the applicant indicated that thus far there had been no augmented inspections on isolation condenser components that the proposed
 
augmented inspections will be applicable as parts of an AMP during the period of extended
 
operation.
3-256 In RAI-3.1.1-1 dated March 20, 2006, the staff requested that the applicant provide information for an assessment of the effectiveness of the future augmented inspection program of the
 
isolation condenser and its components. Specifically, the staff requested that the applicant
 
provide the following:
* previous experience related to the frequency of occurrence of pitting and crevice corrosion in the isolation condenser and its components
* previous inspection methods and frequency implemented prior to the replacement of some of the isolation condenser components
* criteria for establishing future augmented inspection frequency In its response dated April 18, 2006, the applicant stated the following:
The carbon steel Isolation Condenser shells were fabricated with a nominal thickness of 0.375 inches, with a corrosion allowance of 0.100 inches. In 1996, NDE tests were performed on the Isolation Condenser "B" shell to determine the
 
existence and extent of pitting corrosion. Plant experience has indicated that the
 
condition of the "B" isolation condenser is the more limiting of the two condensers.
 
The results of the NDE tests showed an average shell thickness of 0.389 inches
 
with a standard deviation of 0.014 inches. In 2002, the "B" isolation condenser
 
shell was again examined. Visual examination results indicated blistering of the
 
coating at or near the waterline. NDE results from tests performed at locations just
 
below the waterline judged to have the highest probability for accelerated
 
corrosion yielded readings well within the control limits computed from the 1996
 
readings, and above or close to the fabrication nominal thickness of 0.375 inches.
Prior to tube bundle replacement in the Oyster Creek isolation condensers, the stainless steel tube bundles were found to be subject to crevice corrosion. Tube
 
OD crevice corrosion located in the crev ice formed by the roll expansion process during tube bundle fabrication was accelerated by elevated isolation condenser
 
temperatures due in part to condensate return valve leakage. In addition, numerous thermal cycles were caused by isolation condenser water level
 
oscillation due to the valve leakage conditi on, and system service as the primary heat sink during reactor shutdowns employing opening and closing of the
 
condensate return valves as needed to limit cooldown rate. Subsequent correction
 
of the condensate return valve leakage condition and changes to isolation
 
condenser operation strategy during reactor cooldown have significantly reduced
 
the thermal cycling that exacerbated the crevice corrosion conditions which
 
existed in the original tube bundle assemblies.
In 1996 and again in 2002, VT and UT inspection methods were used to evaluate the condition of the isolation condenser shell. During the evaluation of the
 
isolation condenser tube leakage conditions, UT and thermography testing were
 
used to determine the condensate/steam interface in the isolation condensers, and acoustic monitoring of boiling intensity was used to determine the presence of
 
stratified tube internal conditions. Weekly temperature monitoring of isolation
 
condenser temperature and monthly radioactivity sampling of the shell water (subsequently changed to weekly) have been performed since before tube bundle
 
replacement.
3-257 Correction of the valve leakage condition has significantly reduced the number of isolation condenser water level oscillations and resultant thermal cycles applied to
 
the isolation condenser components. The Oyster Creek isolation condenser tube
 
bundles were replaced in the "A" isolation condenser in 2000 and in the "B" isolation condenser in 1998, utilizing improved materials that are more resistant to
 
intergranular stress corrosion cracking. The physical configuration of the isolation
 
condensers and internal surfaces of the channel head require cutting and
 
re-welding of pressure boundary piping. Because of the significant reduction in
 
frequency of initiating conditions, and the relatively recent replacement of the tube
 
bundles with improved materials, these inspections will be performed once during
 
the first ten years of the period of extended operation. Radioactivity and
 
temperature monitoring of the shell side water, as specified in the GALL
 
recommendations for isolation condenser aging management, are currently being
 
performed weekly, and will continue throughout the period of extended operation.
 
Additionally, during the NRC Region 1 Inspection, AmerGen has committed to
 
performing a one-time UT inspection of the "B" Isolation Condenser shell for
 
pitting corrosion, prior to the period of extended operation. Plant experience has
 
indicated that the condition of the "B" isolation condenser is the more limiting of
 
the two condensers. This commitment will be added to the Table A.5 License
 
Renewal Commitment List Item No. 24.
In a followup discussion, the staff requested that the applicant clarify its planned corrective action activities if any tube leakage was observed. In its letter dated May 3, 2006, the applicant stated:
Should any of the monitoring activities conducted on the isolation condensers reveal conditions potentially indicative of a tube leak, initiation of the corrective
 
action process would result in an engineering evaluation of the observed
 
condition. Confirmatory testing could be performed, which may include
 
controlled-inventory testing of the shell water volume with the bundle side
 
pressurized, and enhanced radioactivity analysis of shell side water. Upon
 
confirmation of tube leakage, repair or plugging of leaking tubes would be
 
performed, and if warranted, eddy current testing of the bundles to determine
 
extent of condition would be considered. Conceivably, depending on the extent, repair could consist of tube bundle replacement. Appropriate corrective action to
 
correct a tube leakage condition in the isolation condensers would be taken, regardless of when it occurred during the period of extended operation.
The staff reviewed the applicant's response and determined that the Water Chemistry and ASMESection XI ISI, Subsection IWB, IWC, and IWD Programs and the commitment (Commitment
 
No. 24) to perform one-time UT inspection of "B" isolation condenser are adequate to manage
 
loss of material due to pitting and crevice corrosion in stainless steel BWR isolation condenser
 
components. The identified above, the staff concludes that the loss of material in the isolation
 
condenser components exposed to reactor c oolant will be adequately managed by the ASMESection XI ISI, Subsection IWB, IWC, and IWD, and Water Chemistry Programs.
The staff finds that, based on these programs identified above, the applicant has met the criteria of SRP-LR Section 3.1.2.2.2.2 for further evaluation. The staff also finds that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended functions 3-258 will be maintained during the period of extended operation. The staff's concerns described in RAI 3.1.1-1 are resolved.
In Attachment 7, items RP-25 and RP-27, of its reconciliation document, the applicant addressed loss of material due to pitting and crevice corrosion for stainless steel, nickel alloy, and steel with
 
stainless steel or nickel alloy cladding flanges, nozzles, penetrations, pressure housings, safe
 
ends, and vessel shells, heads, and welds exposed to reactor coolant.
SRP-LR Section 3.1.2.2.2.3 states that loss of material due to pitting and crevice corrosion can occur for stainless steel, nickel alloy, and steel with stainless steel or nickel alloy cladding
 
flanges, nozzles, penetrations, pressure housings, safe ends, and vessel shells, heads, and
 
welds exposed to reactor coolant. The existing program relies on control of reactor water
 
chemistry to mitigate corrosion. However, control of water chemistry does not preclude loss of
 
material due to pitting and crevice corrosion at locations of stagnant flow conditions. Therefore, the effectiveness of the Water Chemistry 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 Water Chemistry Program. A one-time inspection of select components at
 
susceptible locations is an acceptable method to determine whether an aging effect does not
 
occur or progresses so slowly that the component's intended function will be maintained during
 
the period of extended operation. , item RP-25, of the applicant's reconciliation document states that the specifications of new line item RP-25 will be addressed as follows: The aging effect of loss of
 
material due to pitting and crevice corrosion in reactor vessel flanges, nozzles, penetrations, pressure housings, safe ends, and vessel shells, heads, and welds will be managed by the
 
Water Chemistry and One-Time Inspection Programs. The selection of susceptible locations for
 
one-time inspections will be based on severity of conditions, time of service, and lowest design
 
margin.In its letter dated March 30, 2006, the applicant revised LRA Section 3.1 to address loss of material due to pitting and crevice corrosion for stainless steel, nickel alloy, and steel with
 
stainless steel or nickel alloy cladding flanges, nozzles, penetrations, pressure housings, safe
 
ends, and vessel shells, heads, and welds exposed to reactor coolant. The aging effect will be
 
managed through the use of the Water Chemistry and One-Time Inspection Programs. The
 
selection of susceptible locations for one-time inspections will be based on severity of conditions, time of service, and lowest design margin.
The staff reviewed the applicant's Water Chemistry Program and verified that this AMP includes activities for managing loss of material due to pitting and crevice corrosion. In addition, the staff
 
reviewed the applicant's One-Time Inspection Program and verified that this AMP includes
 
inspections of the reactor vessel internals (RVI) to detect loss of material as a means of verifying
 
the effectiveness of the Water Chemistry Progr am. The staff concludes that these AMPs will adequately manage loss of material due to pitting and crevice corrosion in reactor vessel flanges, nozzles, penetrations, pressure housings, safe ends, and vessel shells, heads, and welds. , item RP-27, of the applicant's reconciliation document states that for piping, piping components, and piping elements in RCPB system s and systems with RCPB interface the LRA refers to line items EP-32, A-58, and AP-57 for loss of material due to pitting and crevice
 
corrosion of stainless steel in treated water (including reactor coolant) by the Water Chemistry
 
and One-Time Inspection Programs in confor mance with the September 2005 GALL Report.
3-259 The staff reviewed GALL Report line items EP-32, A-58, and AP-57 and determined that these line items address loss of material due to pitting and crevice corrosion of stainless steel in
 
treated water and recommend the Water Chemistry and One-Time Inspection Programs to
 
manage this aging. Therefore, the staff finds the applicant's evaluation acceptable because it
 
follows the recommendations in the GALL Report. The staff concludes that, based on the
 
programs identified above, the applicant has met the criteria of SRP-LR Section 3.1.2.2.2.3 for
 
further evaluation.
The applicant did not address loss of material due to general, pitting, and crevice corrosion in the steel PWR steam generator upper and lower shell and transition cone exposed to secondary
 
feedwater and steam for the further evaluation in SRP-LR Section 3.1.2.2.2.4, which applies to
 
PWRs only. The staff finds that this aging effect does not apply to OCGS because it is a BWR
 
plant.The staff concludes that the applicant has met the criteria of SRP-LR Section 3.1.2.2.2. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is
 
following the recommendations in the GALL Report and 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.
Reactor Vessel Internal (RVI) Components. GALL Report item IV.B1-15 requires implementationof GALL AMPs XI.M1, "ASME Section XI Inservic e Inspection, Subsections IWB, IWC, IWD," andXI.M2, "Water Chemistry," to manage aging effects due to pitting and crevice corrosion in
 
stainless steel and nickel-alloy materials in RVI components. This requirement was not included
 
in LRA Table 3.1.2.1.4.
The staff's review identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the staff's RAI as
 
discussed below.
In RAI 3.1.2.1-2 dated March 20, 2006, the staff requested that the applicant address these aging effects in LRA Table 3.1.2.1.4.
In its response dated April 18, 2006, the applicant stated that it would revise the Reactor Vessel Internals Program to monitor pitting and crevice corrosion in RVI components. The applicant
 
claimed that by control of RCS water chemis try and by frequent inspections per the ASME CodeSection XI ISIs, the aging effects would be adequately managed during the period of extended
 
operation. The applicant committed (Commitment No. 9) to include this new inspection
 
requirement in the UFSAR.
3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement
 
The staff reviewed LRA Section 3.1.2.2.3 against the criteria in SRP-LR Section 3.1.2.2.3.
 
In LRA Section 3.1.2.2.3.1, the applicant addressed neutron irradiation embrittlement for all ferritic materials with a neutron fluence greater than 10 17 n/cm 2.SRP-LR Section 3.1.2.2.3.1 states that neutron irradiation embrittlement is a TLAA to be evaluated for the period of extended operation for all ferritic materials that have a neutron fluence 3-260 greater than 10 17 n/cm 2 (E >1 MeV) at the end of the license renewal term. Certain aspects of neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3.
LRA Section 3.1.2.2.3.1 states that the effects of increased neutron fluence on the fracture toughness of the reactor vessel beltline plates and welds is discussed in LRA Section 4.2. The
 
impact on the vessel's pressure-temperature cu rves and weld exam requirements are also discussed in LRA Section 4.2.
TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). This TLAA is evaluated in SER Section 4.2.
In LRA Section 3.1.2.2.3.2, the applicant addressed loss of fracture toughness for reactor vessel beltline shell, nozzle, and welds.
SRP-LR Section 3.1.2.2.3.2 states that loss of fracture toughness due to neutron irradiation embrittlement could occur in BWR and PWR reactor vessel beltline shell, nozzle, and welds
 
exposed to reactor coolant and neutron flux. A Reactor Vessel Surveillance Program monitors neutron irradiation embrittlement of the reactor vessel. The Reactor Vessel Surveillance Program
 
is plant-specific, depending on such matters as the composition of limiting materials, availability
 
of surveillance capsules, and projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant is required to submit its proposed withdrawal schedule for approval
 
prior to implementation. Untested capsules placed in storage must be maintained for future
 
insertion. Thus, further staff evaluation is required for license renewal. Specific recommendations for an acceptable AMP are in GALL Report Chapter XI, Section M31.
LRA Section 3.1.2.2.3.2 states that the Reactor Vessel Surveillance Program is based on the BWR ISP and satisfies the requirements of 10 CFR Part 50, Appendix H. The Reactor Vessel
 
Surveillance Program includes periodic testing of metallurgical surveillance samples to monitor
 
the progress of neutron embrittlement of the RPV as a function of neutron fluence, in accordance
 
with RG 1.99, "Radiation Embrittlement of Reactor Vessel Materials," Revision 2. BWRVIP-116
 
identifies and schedules additional capsules to be withdrawn and tested during the license
 
renewal period. The applicant will continue the ISP during the period of extended operation by
 
implementing the requirements of BWRVIP
-116 and by addressing any additional actions required by the SER associated with BWRVIP-116 after it is approved. Observed conditions that
 
have potential impact on the intended function are evaluated or corrected in accordance with the
 
corrective action process.
The staff reviewed the applicant's Reactor Vessel Surveillance Program and determines that, according to the recommendations in the GALL Report, it is adequate to manage the loss of
 
fracture toughness due to neutron irradiation embrittlement in reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.1.2.2.3. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant was following the recommendations of the GALL Report
 
and 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).
3-261 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.
 
In LRA Section 3.1.2.2.4.2, the applicant addressed cracking due to SCC and IGSCC in the stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection lines.
SRP-LR Section 3.1.2.2.4.1 states that cracking due to SCC and IGSCC can occur in the stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection lines. The
 
GALL Report recommends evaluation of a plant-specific AMP be evaluated because existing programs may not be capable of mitigating or detecting cracking due to SCC and IGSCC. In LRA Section 3.1.2.2.4.2, the applicant stated that it will use the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to ensure that the reactor vessel flange
 
leak detection lines do not experience aging effects caused by SCC and IGSCC. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program utilizes a VT-2 visual
 
examination on the line prior to reactor cavity drain down during each refueling outage. This
 
examination will be credited for managing cracki ng. Observed conditions that have potential impact on the intended function will be evaluated or corrected in accordance with the corrective
 
action process. The staff reviewed the applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and determined that it is consistent with the GALL Report and will adequately
 
manage the effects of SCC in the stainless steel vessel flange leak detection line. Moreover, a
 
VT-2 visual examination of the line prior to reactor cavity drain down during each refueling
 
outage will provide an additional method for detecting any incipient degradation. The staff
 
concludes that, based on the programs identified above, the applicant has met the criteria of
 
SRP-LR Section 3.1.2.2.4.1 for further evaluation.
In LRA Section 3.1.2.2.4.3, the applicant addressed cracking due to SCC and IGSCC in stainless steel BWR isolation condenser components exposed to reactor coolant.
SRP-LR Section 3.1.2.2.4.2 states that cracking due to SCC and IGSCC can occur in stainless steel BWR isolation condenser components exposed to reactor coolant. The existing program relies on control of reactor water chemistry to mitigate SCC and on ASME Code Section XI ISI.
 
However, the existing program should be augmented to detect cracking due to SCC and IGSCC.
 
The GALL Report recommends that an augmented program include temperature and
 
radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure that
 
the component's intended function will be maintained during the period of extended operation.
LRA Section 3.1.2.2.4.3 states that the Water Chemistry Program will be used to manage aging of stainless steel tube side components of the isolation condenser system exposed to reactor coolant. The program provides for monitoring and controlling of water chemistry by station
 
procedures and processes for the prevention or mitigation of cracking due to SCC and IGSCC.
The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be
 
used with the Water Chemistry Program to manage the aging effects of SCC and IGSCC. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be
 
enhanced to inspect the isolation condenser tube side components, including temperature and
 
radioactivity monitoring of the shell-side water, eddy current testing of the tubes, and inspection 3-262 (VT or UT) of the tubesheet and channel head to ensure that significant degradation does not occur and that the component intended function will be maintained during the period of extended
 
operation. Observed conditions with a potential impact on the intended function will be evaluated
 
or corrected in accordance with the corrective action process.
During a teleconference dated February 2, 2006, the applicant indicated that thus far no augmented inspections had been performed on isolation condenser components and that the
 
proposed augmented inspections will be applicable as a part of an AMP during the period of
 
extended operation. The staff requested that the applicant provide the following information so
 
that an assessment can be made as to the effectiveness of the future augmented inspection
 
program of the isolation condenser and its components:
* previous experience related to the frequency of occurrence of SCC and IGSCC in the isolation condenser and its components
* previous inspection methods and frequency implemented prior to the replacement of some of the isolation condenser components
* criteria for establishing future augmented inspection frequency In its response dated April 18, 2006, the applicant stated:
Prior to tube bundle replacement in the Oyster Creek isolation condensers, the stainless steel tube bundles were found to be subject to stress corrosion cracking.
 
Fatigue propagated cracks on the OD surface of the tubes initiated by
 
trans-granular stress corrosion cracking, and fatigue cracks at the seal weld and
 
portions of the tubesheet adjacent to the seal weld were caused by oscillating
 
conditions internal to the tubes due to condensate return valve leakage.
 
Numerous thermal cycles were caused by isolation condenser water level
 
oscillation due to the valve leakage conditi on, and system service as the primary heat sink during reactor shutdowns employing opening and closing of the
 
condensate return valves as needed to limit cooldown rate. Subsequent correction
 
of the condensate return valve leakage condition and changes to isolation
 
condenser operation strategy during reactor cooldown have significantly reduced
 
the thermal cycling that exacerbated the stress corrosion cracking conditions
 
which existed in the original tube bundle assemblies.
During the evaluation of the isolation condenser tube leakage conditions, UT and thermography testing were used to determine the condensate/steam interface in
 
the isolation condensers, and acoustic monitoring of boiling intensity was used to
 
determine the presence of stratified tube internal conditions. Weekly temperature
 
monitoring of isolation condenser temperature and monthly radioactivity sampling
 
of the shell water (subsequently changed to weekly) has been performed since
 
before tube bundle replacement.
Correction of the valve leakage condition has significantly reduced the number of isolation condenser water level oscillations and resultant thermal cycles applied to
 
the isolation condenser components. The Oyster Creek isolation condenser tube
 
bundles were replaced in the "A" isolation condenser in 2000 and in the "B" isolation condenser in 1998, utilizing improved materials that are more resistant to
 
intergranular stress corrosion cracking. Due to the physical configuration of the 3-263 isolation condensers and piping at Oyster Creek, eddy current inspection of the tubes and access to the tubesheet and internal surfaces of the channel head
 
require cutting and re-welding of pressure boundary piping. Because of the
 
significant reduction in frequency of initiating conditions, and the relatively recent
 
replacement of the tube bundles with improved materials, these inspections will
 
be performed once during the first ten years of the period of extended operation.
 
Radioactivity and temperature monitoring of the shell side water as specified in
 
the GALL recommendations for isolation condenser aging management are
 
currently being performed weekly and will continue throughout the period of
 
extended operation. Additionally, during the NRC Region I Inspection, AmerGen
 
has committed to performing a one-time UT inspection of the "B" Isolation
 
Condenser shell for pitting corrosion, prior to the period of extended operation.
 
Plant experience has indicated that the condition of the "B" isolation condenser is
 
the more limiting of the two condensers. This commitment will be added to the
 
Table A.5 License Renewal Commitment List Item No. 24.
In a followup discussion, the staff asked the applicant to clarify its planned corrective action activities if any tube leakage was observed. In its letter dated May 3, 2006, the applicant stated
 
that: Should any of the monitoring activities conducted on the isolation condensers reveal conditions potentially indicative of a tube leak, initiation of the corrective
 
action process would result in an engineering evaluation of the observed
 
condition. Confirmatory testing could be performed, which may include
 
controlled-inventory testing of the shell water volume with the bundle side
 
pressurized, and enhanced radioactivity analysis of shell side water. Upon
 
confirmation of tube leakage, repair or plugging of leaking tubes would be
 
performed, and if warranted, eddy current testing of the bundles to determine
 
extent of condition would be considered. Conceivably, depending on the extent, repair could consist of tube bundle replacement. Appropriate corrective action to
 
correct a tube leakage condition in the isolation condensers would be taken, regardless of when it occurred during the period of extended operation.The staff reviewed the applicant's response, Water Chemistry Program, and ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program and determined that these
 
programs and the commitment (Commitment No. 24) to perform one-time UT inspection of "B"
 
isolation condenser are adequate to manage cracking due to SCC and IGSCC in stainless steel
 
BWR isolation condenser components exposed to reactor coolant. The staff determined that the
 
aging effects due to SCC and IGSCC of isolation condenser system components will be adequately managed by the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and
 
IWD, and Water Chemistry Programs. The identified above, the staff concludes that the
 
applicant's programs met the criteria of SRP-LR Section 3.1.2.2.4.2 for further evaluation. The
 
staff's concerns described above are resolved.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.1.2.2.4. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant's programs are 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.
3-264 Stainless Steel Reactor Vessel Attachment Welds. The AMPs recommended by the GALL Report for managing cracking due to SCC, IGSCC, and cyclic loading for the RPV attachmentwelds are GALL AMPs XI.M4, "BWR Vessel Inner Diameter (ID) Attachment Welds," and XI.M2,"Water Chemistry."
In LRA Table 3.1.2.1.5, the applicant identified SCC as an aging effect for the stainless steel RPV attachment welds. The applicant stated that the Water Chemistry Program will be used to
 
manage this aging effect. The applicant further stated that the Water Chemistry Program is consistent with GALL AMP XI.M2 with one exception. In SER Section 3.0.3.2.2, the staff
 
evaluated the requirements of the Water Chemistry Program and determined that it is consistent with the recommendations of GALL AMP XI.M2.
The applicant indicated that the BWR Vessel ID Attachment Welds Program will manage aging degradation of the RPV attachment welds. The BWR Vessel ID Attachment Welds Program
 
invokes the inspection requirements specified in the BWRVIP-48 Report, "Vessel ID Attachment Weld Inspection and Evaluation Guidelines," and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The applicant stated that the ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD Program is consistent with GALL AMPXI.M1, "ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, IWD," with one
 
exception. In SER Section 3.0.3.2.1, the staff evaluated the requirements of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and determined that it is consistent with the recommendations of GALL AMP XI.M1.
The staff's review of LRA Section 3.1.2.2.4 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.1.1-2 dated March 20, 2006, the staff requested that the applicant provide details on the frequency and the method of inspection (as specified in the BWRVIP-48 Report,"Vessel ID
 
Attachment Weld Inspection and Evaluation Guidelines") that will be implemented for the
 
attachment welds. According to Section 2.2.3 of the BWRVIP-48 Report, furnace-sensitized
 
stainless steel vessel ID attachment welds are highly susceptible to SCC. The applicant should
 
identify whether there are any furnace-sensitized stainless steel attachment welds at the OCGS
 
unit and explain what type of AMP is im plemented, including details on any augmented inspections, for any existing furnace-sensitized stainless steel attachment welds.
In its response dated April 18, 2006, the applicant stated that the bracket materials and nickel-alloy attachment welds at OCGS were determined to have been furnace-sensitized during
 
vessel fabrication. However, results of the previous inspections did not indicate any flaws in
 
these attachment welds. As no flaws were identified in the furnace-sensitized attachment welds, the identified above, the staff concludes that so far there has been no aging degradation in these
 
attachment welds. The applicant further stated that the attachment welds would be inspected in accordance with the requirements of ASME Code Section XI and the BWRVIP-48 Report.
The staff finds that, by implementing these inspection requirements, the applicant has demonstrated that it would adequately manage the aging degradation of the RPV attachment
 
welds for the period of extended operation. The staff also concluded that the implementation of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, Chemistry
 
Control Program, and the BWR ID Attachment Welds Program would be consistent with the 3-265GALL AMPs XI.M1, XI.M2 and XI.M4, respectively. Based on its review, the staff finds this implementation acceptable. The staff's concern described in RAI 3.1.1-2 is resolved.
Reactor Vessel Penetrations. AMPs recommended by the GALL Report for managing crackingdue to IGSCC for the RPV penetrations are GALL AMPs XI.M8, "BWR Penetrations," and XI.M2, "Water Chemistry." The GALL AMP XI.M8, reco mmends that inspection and flaw evaluation guidelines specified in the BWRVIP-27 Report, "BWR Standby Liquid Control System/Core Plate delta P Inspection and Flaw Evaluation Guidelines," should be implemented for the RPV
 
penetrations. The GALL AMP for the RPV penetrations also includes implementation of
 
guidelines specified in the BWRVIP-49 Report, "Instrumentation Penetration Inspection and Flaw
 
Evaluation Guidelines."
In LRA Table 3.1.2.1.5, the applicant indicated that nickel-alloy and stainless steel materials in the RPV penetration welds experience cracking due to SCC when exposed to a treated-water
 
environment. The applicant stated that the Water Chemistry Program will monitor this aging effect. In SER Section 3.0.3.2.2 the staff evaluated the requirements of the Water Chemistry
 
Program and determined that it would be consistent with the recommendations specified in GALL AMP XI.M2. The applicant also credits the BWR Penetrations Program to manage this aging effect. The BWR Penetrations Program references the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program for monitoring aging effects of the RPV penetrations.
In SER Section 3.0.3.2.1, the staff evaluated the requirements of the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD Program and determined that it would be consistent with the recommendations specified in GALL AMP XI.M1.GALL AMP XI.M8 recommends that the inspection requirements specified in the staff's approvedversions of the BWRVIP-27 and BWRVIP-49 reports and in the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD Program should be implemented for inspecting the
 
BWR RPV penetration welds (i.e., category B-E for pressure-retaining partial penetration welds, category B-D for full penetration nozzle-to-vessel welds, category B-F for pressure-retaining
 
dissimilar metal nozzle-to-safe end welds, and category B-J for similar metal nozzle-to-safe end
 
welds). The extent and schedule of inspection prescribed by the staff's approved versions of BWRVIP-27 and BWRVIP-49 reports and in the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program would ensure that the aging effects will be discovered
 
and repaired before the loss of intended function of the RPV penetration welds.
The applicant provided PBD-B.1.08, "Oyster Creek License Renewal Project BWR Penetration,"
which addresses the inspection methods, inspection frequency, and mitigation methods
 
implemented in the AMP for the RPV penetration welds (including dissimilar welds). The staff
 
reviewed this document and concludes that the applicant has adequately demonstrated its
 
capability in managing the aging degradation of the RPV penetration welds for the period of extended operation. Furthermore, implementation of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD; Water Chemistry; and BWR Penetrations Programs would be consistent with GALL AMPs XI.M2 and XI.M8. The staff finds this implementation acceptable.
Reactor Vessel Nozzles and Safe Ends. The AMPs recommended by the GALL Report for managing cracking due to SCC, IGSCC, and cyclic loading for the RPV nozzles and safe ends are GALL AMPs XI.M7, "BWR Stress Corrosion Cracking," and XI.M2, "Water Chemistry."
In LRA Table 3.1.2.1.5, the applicant identified IGSCC as an aging effect for the stainless steel RPV safe ends, safe end-to-nozzle welds, and safe end-to-piping welds. The applicant stated 3-266 that the Water Chemistry Program will be used to manage this aging effect. In SER Section 3.0.3.2.2, the staff evaluated the requirements of the Water Chemistry Program and determined that it would be consistent with the recommendations specified in GALL AMP XI.M2.
 
The applicant indicated that it would credit the BWR Stress Corrosion Cracking Program for
 
managing the aging degradation of the RPV safe ends, safe end-to-nozzle welds, and safe
 
end-to-piping welds. The BWR Stress Corrosion Cracking Program refers to the requirements of
 
the following documents in the AMP for the RPV safe ends, safe end-to-nozzle welds, and safe
 
end-to-piping welds:
* NUREG-0313, Revision 2, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping"
* GL 88-01, "NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel Piping," and BWRVIP-75, "Technical Basis for Revisions to
 
Generic Letter 88-01 Inspection Schedules"
* BWRVIP-130, "BWR Vessel and Internals Project, BWR Water Chemistry Guidelines"
* ASME Code Section XI, "Rules For Inservice Inspection of Nuclear Power Plant Components" In RAI 3.1.1-4(B) dated March 20, 2006, the staff requested that the applicant state whether the dissimilar metal welds between RPV nozzles and their safe ends had previously experienced cracking due to SCC, IGSCC, or cyclic loading and the extent of any cracking. The staff also requested that the applicant provide information regarding the extent of mitigative techniques (i.e., structural overlay, mechanical stre ss improvement) implemented to mitigate crack propagation due to IGSCC in the dissimilar metal welds between RPV nozzles and their safe
 
ends. The applicant was also requested to provide information on the inspection methods, sample size, and the inspection frequency used thus far for these welds and the inspection
 
results. Finally, the applicant was requested to provide its basis for using the current inspection
 
program as an effective AMP in monitoring the aging effect due to IGSCC in the welds.
In its response dated April 18, 2006, the applicant stated that previous inspections of the dissimilar metal welds in nozzles, safe end components, and piping revealed no cracking. The
 
applicant further stated that it had implement ed mechanical stress improvement, hydrogen water chemistry, and induction heating stress improvem ent as mitigative methods to reduce the susceptibly to IGSCC. The applicant claimed that by implementing these mitigative methods it could effectively manage the aging effects due to IGSCC in the dissimilar welds between the
 
RPV nozzles and their safe ends.
The staff finds the response acceptable because the applicant's proposed mitigation and inspection methods for the similar and dissimilar metal welds between the RPV nozzle and safe
 
end and between the safe end and connected piping would enable the applicant to identify
 
IGSCC promptly. Implementation of the Wate r Chemistry and BWR Stress Corrosion Cracking Programs would be consistent with GALL AMPs XI.M2 and XI.M7, respectively. The staff finds this implementation acceptable. Therefore, the staff's concern described in RAI 3.1.1-4(B) is
 
resolved.Reactor Head Closure Studs. GALL AMP XI.M3, "Reactor Head Closure Studs," recommends implementation of preventive actions specified in RG 1.65, "Materials and Inspections for RPV Closure Studs," to manage the cracking due to SCC for the reactor head closure studs.
3-267 In LRA Table 3.1.2.1.5, the applicant indicated that the Reactor Head Closure Studs Program will be implemented to monitor the aging effect due to SCC of the reactor head closure studs. This program credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD
 
Program to manage SCC. In SER Section 3.0.3.2.1, the staff evaluated the requirements of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and determined that it would be consistent with the recommendations specified in GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, IWD." The applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is an established
 
AMP with appropriate requirements for inspecting the reactor head closure studs. The applicant
 
also stated that the following requirement will be included in the Reactor Head Closure Studs
 
Program:
* Mitigation of cracking is achieved by complying with the recommendations of RG 1.65,"Materials and Inspections for RPV Closure Studs." Approved lubricants will be used to
 
minimize the potential for cracking of the non-metal-plated reactor head closure studs.
Previous industry experience indicates that SCC occurs in metal-plated BWR reactor head closure studs. The applicant stated that there are no metal-plated reactor head closure studs in
 
use at OCGS and that approved lubricants are used to prevent seized studs or nuts. The
 
applicant claimed that with the lack of metal plating and the preventive use of approved
 
lubricants, the Reactor Head Closure Studs Program has been effective in managing SCC of the
 
reactor head closure studs. The applicant concluded in its LRA that the program provides
 
reasonable assurance that the aging effect due to cracking in the reactor head closure studs is
 
adequately managed so that intended functions will be maintained consistent with the CLB
 
during the period of extended operation.
The applicant provided Program Basis Document PBD-B.1.03, "Oyster Creek License Renewal Project Reactor Head Closure Studs," which addresses the inspection methods, inspection
 
frequency, and mitigation methods implemented in the AMP for the reactor head closure studs.
 
The staff reviewed this document and concluded that the applicant had adequately demonstrated
 
its capability in managing the aging degradation of the reactor head closure studs for the period
 
of extended operation.
The staff reviewed the Reactor Head Closure Studs Program and concluded that the reactor head closure studs would be less likely to experience SCC because these closure studs were
 
not metal plated and approved lubricants were used for their maintenance at OCGS. The staff
 
finds that the implementation of the Reactor Head Closure Studs Program would enforce
 
frequent inspections which would adequately identify aging effects of the reactor head closure
 
studs. In addition, satisfying RG 1.65 guidance provides adequate assurance that the integrity of
 
the reactor head closure studs will be maintained. The staff also concludes that the implementation of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and Reactor Head Closure Studs Programs would be consistent with the GALL AMPs XI.M1 and XI.M3, respectively. The staff finds this implementation acceptable.
3.1.2.2.5  Crack Growth Due to Cyclic Loading
 
LRA Section 3.1.2.2.5 states that cracking due to cyclic loading of PWR vessel shells with reference to further evaluation in SRP-LR Section 3.1.2.2.5, applies to PWRs only. The The staff
 
finds acceptable the applicant's evaluation that this aging effect is not applicable to OCGS
 
because it is a BWR plant.
3-268 Feedwater Nozzles. The AMP recommended by the GALL Report for managing cracking due tocyclic loading for the feedwater nozzles is GALL AMP XI.M5, "BWR Feedwater Nozzle," which
 
recommends implementation of the inspection requirements specified in the GE
 
NE-523-A71-0594 Report, "Alternate BWR Feedwater Nozzle Inspection Requirements," for the
 
feedwater nozzles.
The applicant included the BWR Feedwater Nozzle Program for managing the aging effect of cracking due to cyclic loading in the feedwater nozzles at the OCGS unit. The applicant also credited the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program
 
for monitoring the aging degradation of the feedwater nozzles. In SER Section 3.0.3.2.1, the staff evaluated the requirements of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and determined that it would be consistent with the recommendations specified in GALL AMP XI.M1. The applicant's ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is an established AMP with appropriate requirements
 
for inspecting the feedwater nozzle components. The applicant also stated that by implementing
 
the recommendations of the GE-NE-523-A71-0594 Report in conjunction with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program the aging degradation
 
of the feedwater nozzle would be identified promptly.
The applicant provided Program Basis Document PBD-B.1.05, "Oyster Creek License Renewal Project BWR Feed Water Nozzle," which addresses the inspection methods, inspection
 
frequency, and mitigation methods implemented in the AMP for the feedwater nozzle. The staff
 
reviewed this document and concludes that the applicant hasd adequately demonstrated its
 
capability in managing the aging degradation of the feedwater nozzle for the period of extended operation. Furthermore, implementation of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD, and BWR Feedwater Nozzle Programs would be consistent with GALL AMPs XI.M1 and XI.M5, respectively.
The staff finds this implementation acceptable.
The staff's review of LRA Section 3.1.2.2.5 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.1.1-4(A) dated March 20, 2006, the staff stated that the BWR Feedwater Nozzle Program refers to the GE-NE-523-A71-0594 Report, which is not the staff-approved version. The
 
staff requested that applicant to confirm that it will implement the recommendations of
 
Revision 1, Version A, of the report (GE-NE-523-A71-0594-A, Revision 1) approved by the staff.
In its response dated April 18, 2006, the applicant committed (Commitment No. 5) to implement the recommendations of the GE-NE-523-A71-0594-A, Revision 1, Report as a part of the BWR
 
Feedwater Nozzle Program. Based on applicant's response, the staff determined that its concern
 
described in RAI 3.1.1-4(A) is resolved.
CRD Return Line Nozzle. GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle,"
recommends that enhanced inspection recommendations in NUREG-0619, "BWR Feedwater
 
Nozzle and Control Rod Drive Return Line Nozzle Cracking," should be implemented for the
 
CRD return line nozzles for managing the cracking due to cyclic loading for the CRD return line
 
nozzle. LRA Table 3.1.2.1.5 refers to the BWR Control Rod Drive Return Line Nozzle Program for managing this aging effect in the CRD return line. The applicant indicated that inspections 3-269 specified in NUREG-0619 will be implemented for monitoring the aging degradation in the CRD return line. The BWR Control Rod Drive Return Line Nozzle Program in turn credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. In SER Section 3.0.3.2.1, the staff evaluated the requirements of the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD Program and determined that it would be consistent with the recommendations in GALL AMP XI.M1, "ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, IWD." The BWR Control Rod Drive Return Line Nozzle Program has
 
appropriate requirements for inspecting the CRD return line nozzle components and is consistent with the GALL AMP XI.M6. The applicant's augmented ISI program for the CRD return line
 
nozzle includes UT in lieu of liquid PT. The applicant previously requested and received staff
 
approval to substitute UT examinations fo r the PT examinations recommended for the CRD return line nozzle welds by NUREG-0619.
The staff's review identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the staff's RAIs as discussed
 
below.In RAI 3.1.1-3(A) dated March 20, 2006, the staff stated that LRA Table 3.1.1, item number 3.1.1-36, indicates that augmented inspection for the CRD return line weld is required in
 
accordance with the requirements of NUREG-0619, which recommends a periodic examination
 
by a PT technique to evaluate the aging effects in the CRD return line weld. The BWR Control
 
Rod Drive Return Line Nozzle Program states t hat the applicant obtained approval from the staff to substitute UT for PT as a part of the augmented inspection program and that this approval
 
applies to the current ISI interval. Therefore, the staff requested that the applicant provide
 
justification for continuing UT inspections in lieu of PT for the subject weld during the period of
 
extended operation.
In response dated April 18, 2006, the applicant stated that the staff's approval for the substitution of UT for PT for the CRD nozzle was not limited to the current ISI interval and would be valid for
 
the period of extended operation. The applicant claimed that the application of the latest PDI
 
technology in the UT examinations would prov ide equivalent or improved means of detecting cracking as compared to the PT examinations. In addition, the application of PT methods would
 
require removal of the thermal sleeve, resulting in exposure of plant personnel to significant
 
radiation.
The staff reviewed the applicant's response and concludes that the application of the PDI qualified UT examinations will adequately identif y any cracks in the CRD nozzle promptly and, therefore, the staff's concern described in RAI 3.1.1-3(A) is resolved.
In RAI 3.1.1-3(B) dated March 20, 2006, the staff requested that the applicant provide information on whether the CRD return line nozzle had been capped. If the CRD return line
 
nozzle had been capped, the staff requested that the applicant provide the following information
 
about the cap and the weld:  (1)Configuration, location, and material of construction of the capped nozzle including the existing base material for the nozzle, piping (if piping remnants exist) and cap material, and any welds.  (2)Inspection criteria for this weld and cap in accordance with the guidelines of BWRVIP-75,"BWR Vessel and Internals Project (BWRVIP), Technical Basis for Revisions to Generic
 
Letter 88-01 Inspection Schedule."
3-270  (3)The effect of the event at Pilgrim Nuclear Power Station (leaking weld at capped nozzle, September 30, 2003) on the OCGS unit. The staff's IN 2004-08, "Reactor Coolant
 
Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor Vessel
 
Nozzle Welds," dated April 22, 2004, stated that the cracking occurred in a
 
nickel-alloy 182 (trade name) weld previously repaired extensively. The staff requested that the applicant provide information on the plant experience with previous leakage at
 
the capped nozzle including the past inspection techniques applied, the results obtained, and mitigative strategies imposed.
In its response dated April 18, 2006, the applicant stated that the CRD return line has not been capped and therefore, RAIs 3.1.1-3(B) (1) through (3) would not be applicable to OCGS. The
 
applicant claimed that implementation of the BWR Control Rod Drive Return Line Nozzle
 
Program and the prior installation of an improv ed thermal sleeve design inside the nozzle bore ensures that the aging effect in the CRD return line nozzle is effectively managed.
The staff finds that the implementation of the BWR CRD Return Line Nozzle and ASME Section XI Inservice Inspection Programs for the CRD return lines would be consistent with GALL AMP XI.M6. The staff finds this implementation acceptable. The staff's concerns described
 
in RAI 3.1.1-3(B) are resolved.
3.1.2.2.6  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void Swelling LRA Section 3.1.2.2.6 states that loss of fracture toughness of PWR reactor internals with reference to the further evaluation in SRP-LR Section 3.1.2.2.6 applies to PWRs only. The staff
 
finds acceptable the applicant's evaluation that this aging effect does not apply to OCGS
 
because it is a BWR plant.
3.1.2.2.7  Cracking Due to Stress Corrosion Cracking
 
LRA Section 3.1.2.2.7.1 states that cracking due to SCC for PWR stainless steel reactor flange leak detection lines with reference to the further evaluation in SRP-LR Section 3.1.2.2.7.1, applies to PWRs only. The staff finds acceptable the applicant's evaluation that this aging effect
 
does not apply to OCGS because it is a BWR plant.
LRA Section 3.1.2.2.7.2 states that cracking due to SCC of PWR Class 1 CASS piping, piping components, and piping elements, with reference to the further evaluation in SRP-LR
 
Section 3.1.2.2.7.2, applies to PWRs only. The staff finds acceptable the applicant's assessment
 
that this aging effect does not apply to OCGS because it is a BWR plant.
3.1.2.2.8  Cracking Due to Cyclic Loading
 
The staff reviewed LRA Sections 3.1.2.2.8.1 and 3.1.2.2.4.3 against the criteria in SRP-LR Section 3.1.2.2.8.
LRA Section 3.1.2.2.8.1 states that cracking due to cyclic loading for jet pump sensing lines, with reference to the further evaluation in SRP-LR Section 3.1.2.2.8.1, does not apply. OCGS has no
 
jet pumps or jet pump sensing lines. The staff determined that the OCGS reactor has no jet
 
pumps and, therefore, the staff finds acceptable the applicant's assessment that this aging effect
 
and mechanism is not applicable.
3-271 In LRA Section 3.1.2.2.4.3, the applicant addressed cracking due to cyclic loading in steel and stainless steel BWR isolation condenser components exposed to reactor coolant.
SRP-LR Section 3.1.2.2.8.2 states that cracking due to cyclic loading can occur in steel and stainless steel BWR isolation condenser components exposed to reactor coolant. The existing program relies on ASME Code Section XI ISI, but should be augmented to detect cracking due to
 
cyclic loading. The GALL Report recommends an augmented program to include temperature and radioactivity monitoring of the shell-side water and eddy current testing of tubes to ensure
 
that the component's intended function will be maintained during the period of extended
 
operation.
LRA Section 3.1.2.2.4.3 states that the Water Chemistry Program will be used to manage aging of stainless steel tube side components of the isolation condenser system exposed to reactor coolant. The program activities monitor and control water chemistry by station procedures and
 
processes for the prevention or mitigation of cracking due SCC and IGSCC. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be used with the
 
Water Chemistry Program to manage the aging effects of SCC and IGSCC. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will be enhanced to
 
inspect the isolation condenser tube side components, including temperature and radioactivity
 
monitoring of the shell-side water, eddy current testing of the tubes, and inspection (VT or UT) of
 
the tubesheet and channel head to ensure that significant degradation does not occur and that
 
the component intended function will be maintained during the period of extended operation.
 
Observed conditions with potential impact on the intended function will be evaluated or corrected
 
in accordance with the corrective action process. The staff reviewed the applicant's Water Chemistry and ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Programs and determined that they are adequate to manage
 
cracking due to cyclic loading in the isolation condenser components exposed to reactor coolant.
 
In addition, the staff finds that the augmented inspections proposed by the applicant for the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program are consistent with the GALL
 
Report recommendations. The staff concludes that the applicant's programs meet the criteria of
 
SRP-LR Section 3.1.2.2.8.2 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.1.2.2.8. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant's programs are consistent with the GALL Report and 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 Part 54.
3.1.2.2.9  Loss of Preload Due to Stress Relaxation
 
LRA Section 3.1.2.2.9 states that loss of preload due to stress relaxation of PWR RVI components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.9, applies to
 
PWRs only. The staff finds acceptable the applicant's evaluation that this aging effect does not
 
apply to OCGS because it is a BWR plant.
3.1.2.2.10  Loss of Material Due to Erosion 3-272 LRA Section 3.1.2.2.10 states that loss of material due to erosion of PWR steam generator components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.10, applies to
 
PWRs only. The staff finds acceptable the applicant's assessment that this aging effect does not
 
apply to OCGS because it is a BWR plant.
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.
 
In LRA Section 3.1.2.2.11, the applicant addressed cracking due to flow-induced vibration for the BWR stainless steel steam dryers exposed to reactor coolant.
SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration can occur in BWR stainless steel steam dryers exposed to reactor coolant. The GALL Report recommends further
 
evaluation of a plant-specific AMP to ensure adequate management of this aging effect.
LRA Section 3.1.2.2.11 states that the BWR Vessel Internals Program will be used to manage the effects of cracking of the steam dryer. The applicant also stated that it will implement the
 
guidelines of BWRVIP-139 for the steam dryer when issued. Observed conditions with potential
 
impact on the intended function are evaluated or corrected in accordance with the corrective
 
action process.
During the audit, the applicant was asked to describe how cracking in the steam dryer will be managed by the BWR Vessel Internals and Water Chemistry Programs during the period of
 
extended operation. In its response, the applicant stated that currently the steam dryer is
 
inspected in accordance with the recommendation of SIL 644, Revision 1. Inspections in 2006
 
will continue to follow the inspections of SIL 644. The OCGS inspection is not impacted by the
 
comments on SIL 644 from the staff to the BWROG in January 2005 (Letter Report from Robert
 
A Gramm of NRC to Kenneth S Putnam of BWROG, January 12, 2005). The NRC comments
 
primarily address concerns about extended power uprate (EPU). The applicant has not
 
implemented EPU, nor is such an implementation planned.
For the period of extended operation, the applicant stated that the BWRVIP-139 dryer inspections already performed are meant to establish a baseline. The results of these
 
inspections will be evaluated to establish future scope and schedule for steam dryer inspections.
 
The applicant will comply with the BWRVIP recommendations on steam dryer inspections. Any
 
flaws found during inspections will be evaluated and reinspected if required. Performing the
 
inspections in accordance with BWRVIP-139 provides reasonable assurance that the steam
 
dryer will perform its intended function during the period of extended operation.
The staff reviewed the applicant's response and determined that it represents an adequate method of managing cracking in the steam dryers during the period of extended operation. The
 
use of baseline inspections to compare future inspection results will provide a means of
 
determining whether any new cracking is occurring and requiring further action. The staff
 
concludes that the applicant's approach is acceptable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.1.2.2.11. For those LRA line items that apply to this SRP-LR
 
section, the staff determined that the applicant's programs are consistent with the GALL Report
 
and the applicant has demonstrated that the effects of aging will be adequately managed so that 3-273 the intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR Part 54.
3.1.2.2.12  Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress Corrosion Cracking (IASCC)
LRA Section 3.1.2.2.12 states that cracking due to SCC and IASCC of PWR RVI components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.12, applies to PWRs only. The
 
staff finds acceptable the applicant's assessment that this aging effect does not apply to OCGS
 
because it is a BWR plant.
3.1.2.2.13  Cracking Due to Primary Water Stress Corrosion Cracking (PWSCC)
 
LRA Section 3.1.2.2.13 states that cracking due to primary water SCC of PWR components inside the reactor vessel, with reference to the further evaluation in SRP-LR Section 3.1.2.2.13, applies to PWRs only. The staff finds acceptable the applicant's assessment that this aging
 
effect does not apply to OCGS because it is a BWR plant.
3.1.2.2.14  Wall Thinning Due to Flow-Accelerated Corrosion
 
LRA Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion of PWR steam generator feedwater inlet ring and supports, with reference to the further evaluation in SRP-LR
 
Section 3.1.2.2.14, applies to PWRs only. The staff finds acceptable the applicant's assessment
 
that this aging effect does not apply to OCGS because it is a BWR plant.
3.1.2.2.15  Changes in Dimensions Due to Void Swelling
 
LRA Section 3.1.2.2.15 states that changes in dimensions due to void swelling of PWR RVI components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.15, applies to
 
PWRs only. The staff finds acceptable the applicant's assessment that this aging effect does not
 
apply to OCGS because it is a BWR plant.
3.1.2.2.16  Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion Cracking LRA Section 3.1.2.2.16.1 states that cracking due to SCC and primary water SCC of PWR CRD penetration components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.16.1, applies to PWRs only. The staff finds acceptable the applicant's assessment that this aging
 
effect does not apply to OCGS because it is a BWR plant.
LRA Section 3.1.2.2.16.2 states that cracking due to SCC and primary water SCC of PWR pressurizer head spray components, with reference to the further evaluation in SRP-LR
 
Section 3.1.2.2.16.2, applies to PWRs only. The staff finds acceptable the applicant's
 
assessment that this aging effect does not apply to OCGS because it is a BWR plant.
3.1.2.2.17  Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking LRA Section 3.1.2.2.17 states that cracking due to SCC, primary water SCC, and IASCC of PWR RVI components, with reference to the further evaluation in SRP-LR Section 3.1.2.2.17, applies 3-274 to PWRs only. The staff finds acceptable the applicant's assessment that this aging effect does not apply to OCGS because it is a BWR plant.
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 quality assurance program for safety-related and nonsafety-related components.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determined that the applicant has adequately
 
addressed the issues further evaluated. 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  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.1.2.1.1 through 3.1.2.1.6, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
In LRA Tables 3.1.2.1.1 through 3.1.2.1.6, 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.
Staff Evaluation. 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 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 discussed in the following sections.
3.1.2.3.1  Isolation Condenser System Summary of Aging Management Evaluation -
LRA Table 3.1.2.1.1 The staff reviewed LRA Table 3.1.2.1.1, which summarizes the results of AMR evaluations for the isolation condenser system component groups.
The applicant stated that it will manage this aging effect by implementing the Bolting Integrity Program. The Bolting Integrity Program complies with the recommendations of GALL AMP XI.M18, "Bolting Integrity," which recommends application of ASME Code Section XI, Subsection IWB, Table IWB 2500-1 requirements for the bolts included in the ASME Section XI Inservice 3-275 Inspection, Subsections IWB, IWC, and IWD Program to monitor this aging effect. In addition,GALL AMP XI.M18 invokes the guidelines specified in NUREG-1339, "Resolution of Generic
 
Safety Issue 29: Bolting Degradation Failure in Nuclear Power Plants." NUREG-1339 provides
 
adequate technical bases and inspection guidelines as a part of the AMP for safety-related bolting. For bolts not included in the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, the applicant proposed to use routine inspection methods in its
 
maintenance activities to identify any degradation of the closure bolting in the isolation
 
condenser systems. The applicant's proposed AMP complies with the recommendations of
 
NUREG-1339 for safety-related bolting and is consistent with the recommendations of GALL AMP XI.M18. The staff determined that the applicant's compliance with the recommendations specified in NUREG-1339 and in GALL AMP XI.M18 provides reasonable assurance that the
 
aging degradation of safety-related bolting in the isolation condenser systems will be adequately
 
managed at OCGS.
The applicant provided Program Basis Document PBD-B.1.12, "Oyster Creek License Renewal Project, Bolting Integrity Program," which addresses the inspection methods, inspection
 
frequency, and mitigation methods implemented in the AMP for the closure bolting components.
 
The staff reviewed this document and concluded that the applicant had adequately demonstrated
 
its capability in managing the aging degradation of the closure bolting in the isolation condenser
 
systems for the period of extended operation. The st aff finds that, by implementing the Bolting Integrity Program, the applicant has demonstrated that the aging effect due to loss of pre-load in the stainless steel closure bolting (covered by ASME Code Section XI) will be adequately
 
managed during the period of extended operation. The staff, however, recommended that the
 
applicant comply with the inspection frequency specified in the "monitoring and trending" program element of the GALL AMP XI.18 for stainless steel closure bolting not covered by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff also
 
concludes that the implementation of the Bolting Integrity Program would be consistent with the GALL AMP XI.M18.
In its supplemental letter dated July 7, 2006, the applicant modified its Bolting Integrity Program UFSAR to specify that these non-ASME pressure retaining bolted joint connections are observed
 
to be leaking, the leakage will be evaluated as part of the corrective action process. The process will allow for pressure retaining components (not covered by ASME Code Section XI) that are
 
reported to be leaking to be inspected daily. If the leak rate does not increase, the inspection
 
frequency will be decreased to biweekly or weekly. The staff finds this acceptable because it
 
follows the recommendations in the GALL Report.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the isolation condenser system 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).
3.1.2.3.2  Nuclear Boiler Instrumentation Summary of Aging Management Evaluation -
LRA Table 3.1.2.1.2 The staff reviewed LRA Table 3.1.2.1.2, which summarizes the results of AMR evaluations for the nuclear boiler instrumentation component groups.
The applicant stated that it will manage this aging effect by implementing the Bolting Integrity Program. The Bolting Integrity Program complies with the recommendations of GALL 3-276AMP XI.M18, "Bolting Integrity." GALL AMP XI.M18 recommends application of ASME CodeSection XI, Subsection IWB, Table IWB 2500-1 for bolts included in the ASME Code Section XI Program to monitor this aging effect. In addition, GALL AMP XI.M18 invokes the guidelines
 
specified in NUREG-1339, which provides adequate technical bases and inspection guidelines
 
as a part of the AMP for safety-related bolting. For closure bolts not included in the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, the applicant
 
proposed to use routine inspection methods in its maintenance activities to identify any
 
degradation of the closure bolting in the nuclear boiler instrumentation systems. The applicant's
 
proposed AMP is consistent with the recommendations of NUREG-1339 for safety-related bolting and is consistent with the recommendations of GALL AMP XI.M18.
The staff determined that the applicant's consistency with the recommendations specified inNUREG-1339 and in GALL AMP XI.M18 provides reasonable assurance that the aging
 
degradation of safety-related bolting in the nuclear boiler instrumentation systems will be
 
adequately managed at OCGS.
The applicant provided Program Basis Document PBD-B.1.12, "Oyster Creek License Renewal Project, Bolting Integrity Program," which addresses the inspection methods, inspection
 
frequency, and mitigation methods implemented in the AMP for the closure bolting components.
 
The staff reviewed this document and concluded that the applicant had adequately demonstrated
 
its capability in managing the aging degradation of the closure bolting in the nuclear boiler
 
instrumentation system components for the per iod of extended operation. The staff determined that by implementing the Bolting Integrity Program the applicant demonstrated that the aging
 
effect due to loss of pre-load of the stainless steel closure bolting in the nuclear boiler
 
instrumentation systems (covered by ASME Code Section XI) will be adequately managed during the period of extended operation. The staff, however, recommended that the applicant adopt the
 
inspection frequency specified in the "monitoring and trending" program element of the GALL AMP XI.18 for stainless steel closure bolting not covered by the ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD Program. The staff also concludes that
 
implementation of the Bolting Integrity Program would be consistent with GALL AMP XI.M18.
In its supplemental letter dated July 7, 2006, the applicant modified its Bolting Integrity Program UFSAR to specify that these non-ASME pressure retaining bolted joint connections are observed
 
to be leaking, the leakage will be evaluated as part of the corrective action process. The process will allow for pressure retaining components (not covered by ASME Code Section XI) that are
 
reported to be leaking to be inspected daily. If the leak rate does not increase, the inspection
 
frequency will be decreased to biweekly or weekly. The staff finds this acceptable because it
 
follows the recommendations in the GALL Report.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the nuclear boiler instrumentation
 
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).
3.1.2.3.3  Reactor Head Cooling System Summary of Aging Management Evaluation -
LRA Table 3.1.2.1.3 The staff reviewed LRA Table 3.1.2.1.3, which summarizes the results of AMR evaluations for the reactor head cooling system component groups.
3-277 LRA Table 3.1.2.1.3 did not identify any aging effect for the carbon steel valve body exposed to RCS water. However, LRA Table 3.1.2.1.3 footnotes I-3 and I-4 state that the carbon steel valve
 
body is not susceptible to SCC and IGSCC and that thus far no failures in carbon steel valve
 
bodies due to SCC or IGSCC have been reported.
The staff's review identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the staff's RAI as
 
discussed below.
In RAI 3.1.2.1-1(B) dated March 20, 2006, the staff requested that the applicant address whether there was any previous plant experience with cracking (due to SCC or IGSCC) in carbon steel valve bodies of the RPV head cooling system when exposed to treated water.
In its response dated April 18, 2006, the applicant stated that there are no carbon steel valve bodies in the reactor head cooling system. As there are no carbon steel valve bodies in the
 
reactor head cooling system, the staff's concern described in RAI 3.1.2.1-1(B) is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the reactor head cooling system
 
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).
3.1.2.3.4  Reactor Internals Summary of Aging Management Evaluation - LRA Table 3.1.2.1.4
 
The staff reviewed LRA Table 3.1.2.1.4, which summarizes the results of AMR evaluations for the reactor internals component groups.
LRA Table 3.1.2.1.4 states that the AMRs for the reactor internals either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this table
 
are consistent with the GALL Report. The staff's evaluation for AMR items that are consistent
 
with the GALL Report is documented in SER Sections 3.1.2.1 and 3.1.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the reactor internals 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).
3.1.2.3.5  Reactor Pressure Vessel Summary of Aging Management Evaluation -
LRA Table 3.1.2.1.5 The staff reviewed LRA Table 3.1.2.1.5, which summarizes the results of AMR evaluations for the RPV component groups.
LRA Table 3.1.2.1.5 identifies cracking as an aging degradation mechanism in the SA 105 GradeII carbon steel RPV components. The applicant stated that it will credit the ASME Section XI
 
Inservice Inspection, Subsections IWB, IWC, and IWD, and Water Chemistry Programs to
 
monitor this aging effect in the following RPV components:
* bottom head drain nozzle
* feedwater and main steam nozzles and safe ends 3-278
* core spray nozzle
* isolation condenser nozzle
* top head nozzles
* top head flange
* bottom head flange
* RPV shell welds The staff's review of LRA Section 3.1.2.1 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.1.2.1-1(A) dated March 20, 2006, the staff requested that the applicant provide the following information on the subject aging effect in the carbon steel components:    (1)previous plant experience with cracking in carbon steel RPV components when exposed to treated water  (2)any established mechanism of the cracking in carbon steel RPV components (3)the scope and the techniques of the past inspections, the results obtained, applied mitigative methods, repairs, frequency of the inspections, and any other relevant
 
information related to identification of the subject aging effect In its response dated April 18, 2006, the applicant stated that thus far the only cracking experienced in the components was due to thermal fatigue of the feedwater nozzles, which were
 
subsequently repaired. The applicant also has inspected the components (except the bottom head drain nozzle) in accordance with the ASME Code Section XI requirements and found no
 
cracking. The applicant did not inspect the bottom head drain nozzles because they are exempt from ASME Code Section XI inspection (UT) requirements. Previous industry experience indicates that carbon steel bottom head nozzles are not prone to cracking.
The staff reviewed the applicant's response and concluded that there is no active aging degradation due to SCC in the bottom head nozzles. The carbon steel RPV components are not
 
susceptible to SCC and with no previous failures identified in inspections of these components, the staff determined that there is no active aging degradation in these carbon steel RPV
 
components. Therefore, the staff's concerns described in RAI 3.1.2.1-1(A) are resolved.
LRA Table 3.1.2.1.5 did not identify any aging effect specified in GALL Report Table V.C-1 for the carbon and low alloy steel RPV components. This table identifies loss of material due to
 
general corrosion as an aging effect of the carbon and low alloy steel materials of the RPV
 
components externally exposed to inside (atm ospheric) environments. The applicant stated that based on past precedents (NUREG-1796, "Safety Evaluation Report Related to the License
 
Renewal of Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power
 
Station, Units 1 and 2," Section 3.1.2.4.1) the staff had concluded that the loss of material due to
 
corrosion is not considered a credible aging effect for carbon steel components in a containment
 
nitrogen environment because a negligible amount of free oxygen (less than 4 percent by
 
volume) is present in this environment during normal operation. Both oxygen and moisture must
 
be present for general corrosion to occur because oxygen alone or water free of dissolved
 
oxygen (high humidity in a nitrogen atmosphere) does not corrode carbon steel to any practical
 
extent. Therefore, the applicant determined that loss of material due to general corrosion would
 
not be applicable to the following carbon steel RPV components:
3-279
* bottom head drain nozzle
* core spray nozzle
* CRD return line nozzle
* feedwater nozzle
* main steam nozzle
* isolation condenser nozzle
* re-circulation inlet and outlet nozzle
* top head flange
* top head enclosure head
* vessel bottom head
* vessel shell
* vessel shell flange The staff finds the applicant's evaluation acceptable because the carbon and low-alloy steel components are exposed to negligible amounts of free oxygen and, therefore, are not likely to
 
experience corrosion. In addition, the external surface of the carbon and low-alloy steel RPV
 
components are exposed to an inside (atmospheric) environment containing no aggressive ions to cause loss of material due to corrosion. The staff concludes that in the absence of oxygen the
 
carbon steel RPV components are not susceptib le to corrosion when externally exposed to inside (atmospheric) environments. Based on this re view consistent with the industry experience, the staff determined that the exclusion of the aging effect (general corrosion) from carbon steel
 
RPV materials listed in LRA Table 3.1.2.1.5 is acceptable.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the RPV 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).
3.1.2.3.6  Reactor Recirculation System Summary of Aging Management Evaluation -
LRA Table 3.1.2.1.6 The staff reviewed LRA Table 3.1.2.1.6, which summarizes the results of AMR evaluations for the reactor recirculation system component groups.
LRA Table 3.1.2.1.6 does not identify any aging effect specified in GALL Report Table VII.I-7 for the carbon and low alloy steel materials used in reactor recirculation system piping and valve
 
components. Table VII.I-7 of the GALL Report identified loss of material due to general corrosion
 
as an aging effect for the carbon and low alloy steel materials of the reactor recirculation system
 
piping and valve components externally expos ed to inside (atmospheric) environments. The applicant stated that based on past precedence (NUREG-1796 Section 3.1.2.4.1) the staff had
 
concluded that the loss of material due to corrosion is not considered a credible aging effect for
 
carbon steel components in a containment ni trogen environment because a negligible amount of free oxygen (less than 4% by volume) is present in this environment during normal operation.
 
Both oxygen and moisture must be present for general corrosion to occur because oxygen alone
 
or water free of dissolved oxygen (high humidity in a nitrogen atmosphere) does not corrode
 
carbon steel to any practical extent. Therefore, the applicant determined that loss of material due
 
to general corrosion would not be applicable to the carbon and low alloy steel materials of the
 
reactor recirculation system piping and valve components.
3-280 The staff finds the applicant's evaluation acceptable because the carbon and low-alloy steel reactor recirculation system components are exposed to negligible amounts of free oxygen and, therefore, are not likely to experience corrosion. In addition, the external surface of the carbon
 
and low-alloy steel reactor recirculation syst em components is exposed to inside (atmospheric) environment that does not contain any aggressive ions that would cause loss of material due to
 
corrosion. The staff concludes that in the absence of oxygen the carbon and low-alloy steel
 
reactor recirculation system components are not susceptible to corrosion when externally exposed to inside (atmospheric) environments. Based on this review, consistent with the industry
 
experience, the staff determined that the exclusion of the aging effect (general corrosion) from
 
carbon steel RPV materials listed in LRA Table 3.1.2.1.6 is acceptable.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the reactor recirculation system 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).
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environm ent, AERMs, 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 reactor vessel, internals, and RCS components, that are 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).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
 
engineered safety features (ESF) components and component groups of the following systems:
* containment spray system
* core spray system
* standby gas treatment system3.2.1  Summary of Technical Information in the Application In LRA Section 3.2, the applicant provided AMR results for the ESF system components and component groups. In LRA Table 3.2.1, "Summary of Aging Management Evaluations for the
 
Engineered Safety Features," the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for t he ESF systems components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with
 
appropriate site personnel to identify AERMs. The applicant's review of industry operating 3-281 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 had 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 function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs during the weeks of October 3-5, 2005, January 23-27, 2006, and February 13-17, 2006, 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 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 the Audit and Review Report and summarized in SER
 
Section 3.2.2.1.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations
 
were consistent with the acceptance criteria in SRP-LR Section 3.2.2.2. The staff's audit
 
evaluations are documented in the Audit and Review Report and summarized in SER
 
Section 3.2.2.2.
The staff also conducted a technical review of the remaining AMRs not consistent with, or not addressed in, the GALL Report. The technical review included evaluating whether all plausible
 
aging effects had been identified and whether the aging effects listed were appropriate for the
 
combinations of materials and environments specified. The staff's evaluations are documented in
 
SER Section 3.2.2.3.
For SCCs that the applicant identified as not applicable or not requiring aging management the staff conducted a review of the AMR line items, and the plant's operating experience, to verify
 
the applicant's claims. Details of these reviews are documented in the Audit and Review Report.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the ESF systems components.
Table 3.2-1, provided below, includes a summary of the staff's evaluation of components, aging effects and mechanisms, and AMPs, listed in LRA Section 3.2, that are addressed in the GALL
 
Report.
3-282Table 3.2-1  Staff Evaluation for Engineered Safety Features Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Steel and stainless steel piping, piping
 
components, and
 
piping elements in emergency core cooling system (Item 3.2.1-1)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAA This TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.2.2.2.1)
Stainless steel containment
 
isolation piping and
 
components
 
internal surfaces
 
exposed to treated water (Item 3.2.1-3)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2), and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.2.2.2.3)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to soil (Item 3.2.1-4)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.Not applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.3)
Stainless steel and aluminum piping, piping components, and piping
 
elements exposed to treated water (Item 3.2.1-5)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.2.2.2.3)
Stainless steel andcopper alloy piping, piping components, and piping
 
elements exposed
 
to lubricating oil (Item 3.2.1-6)
Loss of material due to pitting and crevice
 
corrosion Lubricating OilAnalysis and One-Time InspectionNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-283Partially encased stainless steel tanks with breached
 
moisture barrier
 
exposed to raw water (Item 3.2.1-7)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program 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.Not applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.3)
Stainless steel piping, piping
 
components, piping
 
elements, and tank
 
internal surfaces
 
exposed to
 
condensation (internal)
(Item 3.2.1-8)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.Not applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.3)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil (Item 3.2.1-9)
Reduction of heat transfer due to
 
fouling Lubricating OilAnalysis and One-Time InspectionNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.4)
Stainless steel heat exchanger tubes
 
exposed to treated water (Item 3.2.1-10)
Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.2.2.2.4)
Elastomer seals and components in standby gas treatment system
 
exposed to air -
 
indoor uncontrolled (Item 3.2.1-11)
Hardening and loss of strength due to
 
elastomer degradation A plant-specific aging management
 
program is to be
 
evaluated.
Periodic Inspection of Ventilation Systems (B.2.4)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.2.2.2.5)Steel drywell and suppression
 
chamber spray system nozzle and flow orifice internal
 
surfaces exposed
 
to air - indoor
 
uncontrolled (internal)
(Item 3.2.1-13)
Loss of material due to general corrosion
 
and fouling A plant-specific aging management
 
program is to be
 
evaluated.Not applicableNot applicable,since Oyster Creek
 
has stainless steel spray nozzles and
 
orifices.
(See SER Section
 
3.2.2.2.7)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-284 Steel piping, piping components, and
 
piping elements
 
exposed to treated water (Item 3.2.1-14)
Loss of material due to general, pitting, and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.2.2.2.8)
Steel containment isolation piping, piping components, and piping
 
elements internal
 
surfaces exposed to treated water (Item 3.2.1-15)
Loss of material due to general, pitting, and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.2.2.2.8)
Steel piping, piping components, and
 
piping elements
 
exposed to
 
lubricating oil (Item 3.2.1-16)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating OilAnalysis and One-Time InspectionNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
(See SER Section
 
3.2.2.2.8)Steel (with orwithout coating or wrapping) piping, piping components, and piping
 
elements buried in
 
soil (Item 3.2.1-17)
Loss of material due to general, pitting, crevice, and microbiologically-influ
 
enced corrosion Buried Piping andTanks Surveillance or Buried Piping andTanks Inspection Buried Piping Inspection (B.1.26)Consistent withGALL, which
 
recommends further
 
evaluation.
(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)
(Item 3.2.1-18)
Cracking due to stress corrosion
 
cracking and
 
intergranular stress
 
corrosion cracking BWR Stress Corrosion Cracking and Water ChemistryNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water (Item 3.2.1-19)Wall thinning due toflow-accelerated
 
corrosionFlow-Accelerated CorrosionFlow-Accelerated Corrosion (B.1.11) Consistent with GALL.
(See SER Section
 
3.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-285 Cast austenitic stainless steel
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water (borated or unborated) > 250&deg;C
(> 482&deg;F)
(Item 3.2.1-20)
Loss of fracture toughness due to
 
thermal aging
 
embrittlementThermal Aging Embrittlement of
 
CASSNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.High-strength steel closure bolting exposed to air with steam or water
 
leakage (Item 3.2.1-21)
Cracking due tocyclic loading, stress
 
corrosion crackingBolting IntegrityNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel closure bolting exposed to air with steam or water leakage (Item 3.2.1-22)
Loss of material due to general corrosionBolting IntegrityNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel bolting and closure bolting
 
exposed to air -
 
outdoor (external),
or air - indoor
 
uncontrolled (external)
(Item 3.2.1-23)
Loss of material due to general, pitting, and crevice
 
corrosionBolting IntegrityBolting Integrity (B.1.12)Consistent with GALL.
(See SER Section
 
3.2.2.1)Steel closure bolting exposed to
 
air - indoor
 
uncontrolled (external)
(Item 3.2.1-24)
Loss of preload due to thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity (B.1.12)Consistent with GALL.
(See SER Section
 
3.2.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water
> 60&deg;C (> 140&deg;F)
(Item 3.2.1-25)
Cracking due to stress corrosion
 
crackingClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel piping, piping components, and
 
piping elements
 
exposed to closed cycle cooling water (Item 3.2.1-26)
Loss of material due to general, pitting, and crevice
 
corrosionClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-286 Steel heat exchanger components
 
exposed to closed cycle cooling water (Item 3.2.1-27)
Loss of material due to general, pitting, crevice, and galvanic
 
corrosionClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Stainless steel piping, piping
 
components, piping
 
elements, and heat
 
exchanger components
 
exposed to closed-cycle cooling water (Item 3.2.1-28)
Loss of material due to pitting and crevice
 
corrosionClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Copper alloy piping, piping components, piping elements, and heat exchanger
 
components
 
exposed to closed cycle cooling water (Item 3.2.1-29)
Loss of material due to pitting, crevice, and galvanic
 
corrosionClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Stainless steel andcopper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water (Item 3.2.1-30)
Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.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)
(Item 3.2.1-31)
Loss of material due to general corrosion External Surfaces Monitoring Structures Monitoring (B.1.31)Acceptable-The OCGS structures
 
monitoring AMP is consistent with the
 
GALL external
 
surfaces monitoring
 
AMP for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.2.2.1.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-287 Steel piping and ducting components and
 
internal surfaces
 
exposed to air -
 
indoor uncontrolled (Internal)
(Item 3.2.1-32)
Loss of material due to general corrosion Inspection of Internal Surfaces in
 
Miscellaneous
 
Piping and Ducting
 
Components Periodic Inspection of Ventilation Systems (B.2.4)Acceptable - The OCGS periodic
 
inspection of ventilation systems
 
AMP is consistent with the GALL
 
inspection of internal
 
surfaces in
 
miscellaneous
 
piping and ducting
 
components AMP
 
for this component
 
group/ aging effect
 
combination.
(See SER Section
 
3.2.2.1.1)
Steel encapsulation components
 
exposed to air -
 
indoor uncontrolled (internal)
(Item 3.2.1-33)
Loss of material due to general, pitting, and crevice
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous
 
Piping and Ducting
 
ComponentsNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel piping, piping components, and
 
piping elements
 
exposed to
 
condensation (internal)
(Item 3.2.1-34)
Loss of material due to general, pitting, and crevice
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous
 
Piping and Ducting
 
ComponentsNot applicableNot applicable,since Oyster Creek
 
has no such ESF components within
 
the scope of license renewal.Steel containment isolation piping and
 
components
 
internal surfaces
 
exposed to raw water (Item 3.2.1-35)
Loss of material due to general, pitting, crevice, and microbiologically-influ
 
enced corrosion, and
 
foulingOpen-Cycle CoolingWater SystemNot applicableNot Applicable since, in ESF, the drywell floor and
 
equipment drain line
 
is the only
 
component subject
 
to this aging effect, and it is managed by one-time
 
inspection.
Steel heat exchanger components
 
exposed to raw water (Item 3.2.1-36)
Loss of material due to general, pitting, crevice, galvanic, and microbiologically-influ
 
enced corrosion, and
 
foulingOpen-Cycle CoolingWater SystemNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to raw water (Item 3.2.1-37)
Loss of material due to pitting, crevice, and microbiologically-influ
 
enced corrosionOpen-Cycle CoolingWater SystemNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-288 Stainless steel containment
 
isolation piping and
 
components
 
internal surfaces
 
exposed to raw water (Item 3.2.1-38)
Loss of material due to pitting, crevice, and microbiologically-influ
 
enced corrosion, and
 
foulingOpen-Cycle CoolingWater SystemNot ApplicableNot Applicable since, in ESF, the drywell floor and
 
equipment drain line
 
is the only
 
component subject
 
to this aging effect
 
and it is managed by One-time
 
Inspection.
Stainless steel heat exchanger components
 
exposed to raw water (Item 3.2.1-39)
Loss of material due to pitting, crevice, and microbiologically-influ
 
enced corrosion, and
 
foulingOpen-Cycle CoolingWater SystemNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Steel and stainless steel heat
 
exchanger tubes (serviced by open-cycle cooling water) exposed to raw water (Item 3.2.1-40)
Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Copper alloy> 15% Zn piping, piping components, piping elements, and heat exchanger
 
components
 
exposed to closed cycle cooling water (Item 3.2.1-41)
Loss of material due to selective leaching Selective Leaching of MaterialsNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Gray cast iron piping, piping
 
components, piping
 
elements exposed to closed-cycle cooling water (Item 3.2.1-42)
Loss of material due to selective leaching Selective Leaching of Materials Selective Leaching of Materials (B.1.25)Consistent with GALL.
(See SER Section
 
3.2.2.1)Gray cast iron piping, piping
 
components, and
 
piping elements
 
exposed to soil (Item 3.2.1-43)
Loss of material due to selective leaching Selective Leaching of MaterialsNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Gray cast iron motor cooler
 
exposed to treated water (Item 3.2.1-44)
Loss of material due to selective leaching Selective Leaching of Materials Selective Leaching of Materials (B.1.25)Consistent with GALL.
(See SER Section
 
3.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-289 Aluminum piping, piping components, and piping
 
elements exposed
 
to air - indoor
 
uncontrolled (internal/external)
(Item 3.2.1-50)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.2.2.1)Galvanized steel ducting exposed to
 
air - indoor
 
controlled (external)
(Item 3.2.1-51)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.2.2.1)Glass piping elements exposed
 
to air - indoor
 
uncontrolled (external),
lubricating oil, raw water, treated water, or treated borated water (Item 3.2.1-52)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.2.2.1)Stainless steel,copper alloy, and nickel alloy piping, piping components, and piping
 
elements exposed
 
to air - indoor
 
uncontrolled (external)
(Item 3.2.1-53)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.2.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
(Item 3.2.1-54)NoneNoneNot applicableNot applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
concrete (Item 3.2.1-55)NoneNoneNot applicableNot Applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-290 Steel, stainless steel, and copper alloy piping, piping
 
components, and
 
piping elements
 
exposed to gas (Item 3.2.1-56)NoneNoneNot applicableNot Applicable, since OCGS has no
 
such ESF components within
 
the scope of license renewal.The staff's review of the ESF systems component groups followed one of several approaches.
One approach, documented in SER Section 3.2.2.1, discusses the staff's review of the AMR
 
results for components that the applicant indicated are consistent with the GALL Report and
 
require no further evaluation. Another approach, documented in SER Section 3.2.2.2, discusses
 
the staff's review of the 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 3.2.2.3, discusses the staff's review of the AMR results for
 
components that the applicant indicated are not consistent with, or not addressed in, the GALL
 
Report. The staff's review of AMPs credited to manage or monitor aging effects of the ESF
 
systems components is documented in SER Section 3.0.3.3.2.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicant identified the materials, environments, AERMs, and the following programs that manage the
 
effects of aging related to the ESF systems components:
* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)
* Water Chemistry (B.1.2)
* BWR SCC (B.1.7)
* Bolting Integrity (B.1.12)
* One-Time Inspection (B.1.24)
* Selective Leaching of Materials (B.1.25)
* Buried Piping Inspection (B.1.26)
* Structures Monitoring Program (B.1.31)
* Periodic Testing of Containment Spray Nozzles (B.2.1)
* Periodic Inspection of Ventilation Systems (B.2.4)
Staff Evaluation. In LRA Tables 3.2.2.1.1 through 3.2.2.1.3, the applicant provided a summary of AMRs for the ESF systems components and identified which AMRs it considered to be
 
consistent with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report 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 contained 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 that the AMR is consistent with the GALL Report.
3-291 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 AMP
 
identified in the GALL Report. 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. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant is 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 in the GALL Report. This note indicates that the applicant was
 
unable to find a listing of some system com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component under review. The staff audited these line items to
 
verify consistency with the GALL Report. The staff also determined whether the AMR line item of
 
the different component was applicable to the component under review and whether the AMR
 
was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the AMP identified in the GALL Report. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. The staff verified whether
 
the identified exceptions to the GALL 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 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review 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. The staff's evaluation is
 
discussed below.
3.2.2.1.1  Loss of Material Due to General Corrosion
 
LRA Table 3.2.2.1.3 for the standby gas treatment system included AMR line items that credited the Periodic Inspection of Ventilation Systems Program to manage loss of material due to
 
general corrosion for piping, piping components, piping elements, and fan and damper housings
 
exposed to indoor air (internal) or outdoor air (external). Generic Note E was cited for these AMR 3-292 line items, indicating that the material, environment, and aging effect were consistent with the GALL Report; however, a different AMP was credited. The GALL Report recommended GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,"
 
for this aging effect.
The staff reviewed the applicant's Periodic Inspection of Ventilation Systems Program and verified that this AMP includes activities consistent with the recommendations of GALLAMP XI.M38 to manage loss of material in components with an indoor air (internal) or outdoor air (external) environment. The identified above, the staff concludes that this AMP is adequate to
 
manage the aging effect for which it is credited.
LRA Tables 3.2.2.1.1 to 3.2.2.1.3 for the ESF systems included AMR line items that credited the Structures Monitoring Program to manage loss of material due to general corrosion for the
 
external surfaces of steel piping, piping components, piping elements, and ducting in indoor air
 
or outdoor air environments. Generic Note E was cited for these AMR line items, indicating that
 
the material, environment, and aging effect were consistent with the GALL Report; however, a different AMP was credited. The GALL Report recommends GALL AMP XI.M36, "External
 
Surfaces Monitoring," for this aging effect.
The staff reviewed the applicant's Structures Monitoring Program and verified that this AMPincludes activities consistent with GALL AMP XI.M36 to manage the loss of material in
 
components exposed to indoor or outdoor air exte rnal environments. The staff concludes that this AMP is adequate to manage the aging effect for which it is credited.
3.2.2.1.2  Loss of Material Due to General, Pitting, and Crevice Corrosion
 
LRA Section 3.2.2.2.8.2 states that the ESF systems have no steel piping, piping components, or piping elements (internal surfaces) exposed to condensation, treated water, or air-indoor
 
uncontrolled environments.
The staff noted that the containment isolati on system includes steel components exposed to treated water on the internal surface. Therefore, the applicant was asked to clarify why it had
 
credited AMPs for loss of material due to general, pitting, and crevice corrosion in steel piping, piping components, and piping elements in contact with treated water, and to clarify the
 
discrepancy in the statement, "Oyster Creek E ngineered Safety Features Systems have no steel piping, piping components, or piping elements (internal surfaces) exposed to condensation, treated water, or air-indoor uncontrolled environments."
In its letter dated April 17, 2006, the applicant revised the further evaluation in LRA Section 3.2.2.2.8.2 to state that OCGS ESF systems have no steel piping, piping components, or
 
piping elements (internal surfaces) exposed to condensation, treated water (in the form of
 
condensation wetting the internal surface), or air-indoor uncontrolled environments.
The staff reviewed LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and confirmed that no steel components exposed to condensation are identified for the ESF systems. Therefore, the staff
 
finds that the applicant's revision of the further evaluation in LRA Section 3.2.2.2.8.2 acceptable.
On the basis of its review, the staff finds that the applicant appropriately addressed the loss of material due to general, pitting, and crevice corrosion for internal surfaces of carbon and low
 
alloy steel components.
3-293 Conclusion. 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes that the applicant has demonstrated that the effects of aging for these components will
 
be adequately managed so that their intended 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 Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report, for the ESF systems components and information about how it will manage the following aging effects:
* cumulative fatigue damage
* loss of material due to cladding
* loss of material due to pitting and crevice corrosion
* reduction of heat transfer due to fouling
* hardening and loss of strength due to elastomer degradation
* loss of material due to erosion
* loss of material due to general corrosion and fouling
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion (MIC)
* quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant had claimed consistency with the GALL Report and for which the GALL Report recommends
 
further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether
 
it adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria of SRP-LR Section 3.2.2.2. Details of the
 
staff's audit are documented in the Audit and Review Report. The staff's evaluation of the aging
 
effects is discussed in the following sections.
3.2.2.2.1  Cumulative Fatigue Damage
 
In LRA Section 3.2.2.2.1, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staff's review of the applicant's evaluation of this TLAA.
3.2.2.2.2  Loss of Material Due to General Corrosion
 
LRA Section 3.2.2.2.2 states that loss of material due to general corrosion of carbon steel PWR charging pump casings, with reference to the further evaluation in SRP-LR Section 3.2.2.2.2, is 3-294 applicable to PWRs only. The staff finds acceptable the applicant's evaluation that this aging effect is not applicable to OCGS because it is a BWR plant.
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.
 
In LRA Section 3.2.2.2.3.1, the applicant addressed loss of material due to pitting and crevice corrosion for internal surfaces of stainless steel containment isolation piping, piping components, and piping elements exposed to treated water.
SRP-LR Section 3.2.2.2.3.1 states that loss of material due to pitting and crevice corrosion can occur on internal surfaces of stainless steel containment isolation piping, piping components, and piping elements exposed to treated water. The existing AMP relies on monitoring and control
 
of water chemistry to mitigate degradation. However, control of water chemistry does not
 
preclude loss of material due to pitting and crevice corrosion at locations of stagnant flow
 
conditions. Therefore, the effectiveness of the Water Chemistry 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 Wa ter Chemistry Program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an
 
aging effect does not occur or progresses so slowly that the component's intended function will
 
be maintained during the period of extended operation.
LRA Section 3.2.2.2.3.1 states that the Water Chemistry Program will be used to manage aging of stainless steel piping and components exposed to treated water in the containment spray
 
system, containment vacuum br eakers system, condensate transfer system, core spray system, isolation condenser system, nuclear boiler in strumentation system, post-accident sampling system, and reactor recirculation system. The pr ogram activities provide for monitoring and controlling of water chemistry by station procedures and processes for the prevention or
 
mitigation of loss of material aging effects. The One-Time Inspection Program will be used in
 
each of these systems for verification of chemistry control and confirmation of the absence of
 
loss of material. Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process. The ASME Section XI Inservice
 
Inspection, Subsections IWB, IWC, and IWD Program will be used to inspect the isolation
 
condenser stainless steel tubes and tube side components to ensure that significant degradation
 
does not occur and that the component intended function will be maintained during the period of
 
extended operation.
The staff reviewed the applicant's Water Chemistry and One-Time Inspection Programs and determined that these programs are adequate to manage aging of stainless steel piping and
 
components exposed to treated water. The identified above, the staff concludes that, based on
 
these programs, the applicant has met the criteria of SRP-LR Section 3.2.2.2.3.1 for further
 
evaluation.
In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material from pitting and crevice corrosion for stainless steel piping, piping components, and piping elements exposed to soil.
SRP-LR Section 3.2.2.2.3.2 states that loss of material from pitting and crevice corrosion can occur in stainless steel piping, piping components, and piping elements exposed to soil. The 3-295 GALL Report recommends further evaluation of a plant-specific AMP to ensure adequate management of this aging effect.
LRA Section 3.2.2.2.3.2 states that the AMR for this further evaluation is not used at OCGS. The ESF systems have no stainless steel piping, pi ping components, or piping elements in contact with soil, untreated, or raw water (including internal condensation). OCGS has no external or
 
partially encased stainless steel tanks within the scope of license renewal.
The staff reviewed the AMR line items for the ESF systems and verified that no stainless steel piping, piping components, or piping elements in contact with soil, untreated, or raw water (including internal condensation) were within the scope of license renewal. Therefore, the staff
 
finds acceptable the applicant's conclusion that this AMR is not applicable.
In LRA Section 3.2.2.2.3.3, the applicant addressed loss of material from pitting and crevice corrosion for BWR stainless steel and aluminum piping, piping components, and piping elements
 
exposed to treated water.
SRP-LR Section 3.2.2.2.3.3 states that loss of material from pitting and crevice corrosion can occur in BWR stainless steel and aluminum piping, piping components, and piping elements
 
exposed to treated water. The existing AMP relies on monitoring and control of water chemistry
 
for BWRs to mitigate degradation. However, control of water chemistry does not preclude loss of
 
material due to pitting and crevice corrosion at locations in stagnant flow conditions. Therefore, the effectiveness of the Water Chemistry 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 Water Chemistry Program. A one-time inspection of select components at
 
susceptible locations is an acceptable method to determine whether an aging effect does not
 
occur or progresses so slowly that the component's intended function will be maintained during
 
the period of extended operation.
LRA Section 3.2.2.2.3.1 states that the Water Chemistry and the One-Time Inspection Programs will be used to manage loss of material from pitting and crevice corrosion for stainless steel
 
piping components, and piping elements exposed to treated water.
The staff reviewed the applicant's Water Chemistry and One-Time Inspection Programs and determined that they are adequate to manage loss of material from pitting and crevice corrosion
 
for stainless steel piping components and piping elements exposed to treated water. The staff
 
noted that the applicant had not provided a furt her evaluation for aluminum piping exposed to treated water. The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3
 
and determined that there is no aluminum piping exposed to treated water in the ESF systems.
Therefore, there was no need for a further evaluation for this material. The staff concludes that, based on the programs identified above, the applicant has met the criteria of SRP-LR
 
Section 3.2.2.2.3.3 for further evaluation.
The staff noted that the applicant had not credited the GALL Report AMR for loss of material due to pitting and crevice corrosion for stainless steel and copper alloy piping, piping components, and piping elements exposed to lubricating oil, addressed in SRP-LR Section 3.2.2.2.3.4 for the
 
ESF systems. This new AMR was not in the January 2005 draft GALL Report. The applicant was
 
asked to clarify which AMPs it credited for loss of material from pitting and crevice corrosion for
 
stainless steel and copper alloy piping, piping components, and piping elements exposed to
 
lubricating oil in the ESF systems.
3-296 In its letter dated April 17, 2006, the applicant revised LRA Table 3.2.1, item number 3.2.1-34, as to stainless steel piping, piping components, and piping elements exposed to lubricating oil in the
 
ESF systems, to state that this material and environment combination is not applicable.
The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and verified that no stainless steel or copper alloy components exposed to lubricating oil are present in ESF
 
systems. Therefore, the staff finds acceptable the applicant's conclusion that this further
 
evaluation is not applicable.
In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material from pitting and crevice corrosion for partially encased stainless steel tanks exposed to raw water due to cracking of the
 
perimeter seal from weathering.
SRP-LR Section 3.2.2.2.3.5 states that loss of material from pitting and crevice corrosion can occur in partially encased stainless steel tanks exposed to raw water due to cracking of the
 
perimeter seal from weathering. The GALL R eport recommends further evaluation to ensure adequate management of the aging effect. The GALL Report recommends evaluation of a
 
plant-specific AMP because moisture and water can egress under the tank if the perimeter seal
 
is degraded LRA Section 3.2.2.2.3.2 states that the ESF systems have no stainless steel piping, piping components, or piping elements in contact with soil, untreated, or raw water (including internal
 
condensation). OCGS has no external or partially encased stainless steel tanks within the scope
 
of license renewal.
The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and confirmed that these ESF systems have no stainless steel piping, piping components, or piping elements in contact with soil, untreated, or raw water (including internal condensation). Therefore, the staff
 
finds acceptable the applicant's conclusion that this further evaluation is not applicable.
In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material from pitting and crevice corrosion for stainless steel piping, piping components, piping elements, and tanks exposed to
 
internal condensation.
SRP-LR Section 3.2.2.2.3.6 states that loss of material from pitting and crevice corrosion can occur for stainless steel piping, piping components, piping elements, and tanks exposed to
 
internal condensation. The GALL Report recommends further evaluation of a plant-specific AMP
 
to ensure adequate management of the aging effect LRA Section 3.2.2.2.3.2 states that the ESF systems have no stainless steel piping, piping components, or piping elements in contact with soil, untreated, or raw water (including internal
 
condensation). OCGS has no external or partially encased stainless steel tanks within the scope
 
of license renewal.
The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and confirmed that the ESF systems have no stainless steel piping, piping components, or piping elements in contact with soil, untreated, or raw water (including internal condensation). Therefore, the staff
 
finds acceptable the applicant's conclusion that this further evaluation is not applicable.
3-297 Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.3. For those LRA line items that apply to this SRP-LR section, the staff determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.2.2.2.4  Reduction of Heat Transfer Due to Fouling
 
The staff reviewed LRA Section 3.2.2.2.4 and Attachment 3, item EP-34, of the applicant's reconciliation document against the criteria in SRP-LR Section 3.2.2.2.4.
The staff noted that the applicant had not credited the GALL Report AMR for reduction of heat transfer due to fouling for stainless steel and copper alloy heat exchanger tubes exposed to
 
lubricating oil with reference to the further evaluation in SRP-LR Section 3.2.2.2.4.1. This new
 
AMR was not in the January 2005 draft GALL Report. The applicant was asked to clarify which
 
AMPs it credited for reduction of heat transfer due to fouling for steel, stainless steel, and copper
 
alloy heat exchanger tubes exposed to lubricating oil in the ESF systems.
In its response, the applicant stated that Section 3.2.2.2.4.1 of the September 2005 SRP-LR addresses line items EP-40, EP-47, and EP-50, all new line items not included in the
 
January 2005 draft SRP-LR and consequently not in the LRA. This material and environment
 
combination is not present in ESF systems. The LRA credits the Lubricating Oil Monitoring
 
Activities Program for reduction of heat transfer in aluminum heat exchanger fins, cast iron
 
bearing cooler housings, and copper alloy heat exchanger tubes exposed to a lubricating oil
 
environment in the EDG, RBCCW, and fire protection systems. The January 2005 draft SRP-LR
 
does not contain these material and environment combinations, therefore, plant-specific notes
 
were applied to these line items.
The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and confirmed that the ESF systems have no stainless steel or copper alloy heat exchanger tubes exposed to lubricating oil. Therefore, the staff finds acceptable the applicant's conclusion that this further
 
evaluation is not applicable.
In Attachment 3, item EP-34, of the applicant's reconciliation document, the applicant addressed reduction of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to
 
treated water.
SRP-LR Section 3.2.2.2.4.2 states that reduction of heat transfer due to fouling can occur in stainless steel heat exchanger tubes exposed to treated water. The existing program relies on
 
control of water chemistry to manage reduction of heat transfer due to fouling. However, control
 
of water chemistry may be inadequate. Therefore, the GALL Report recommends that the
 
effectiveness of the Water Chemistry Program be verified to ensure that reduction of heat
 
transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure
 
that reduction of heat transfer does not occur and that the component's intended function will be
 
maintained during the period of extended operation. , item EP-34, of the applicant's reconciliation document states that the line item for stainless steel heat exchanger tubes in treated water, addressing reduction of heat transfer due
 
to fouling, credited the Water Chemistry Program with no further evaluation recommended, per 3-298 the January 2005 draft GALL Report. This draft was changed in the September 2005 GALL Report to the one-time inspection with an evaluation of aging effects recommended. There are
 
two instances of this line item in the LRA, both in the isolation condenser system, for heat
 
exchanger tubes, internal and external.
In its letter dated March 30, 2006, the applicant revised LRA Table 3.1.2.1.1 for the isolation condenser system to include two new line items crediting the One-Time Inspection Program to supplement the Water Chemistry Program for reduction of heat transfer due to fouling for the
 
internal and external surfaces of the isolation condenser heat exchanger tubes. These new
 
additions are based on reconciliation of the LRA with the January 2005 draft GALL Report and
 
the approved September 2005 GALL Report.
The staff finds that based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.2.2.2.4.2 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.4 and 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
 
The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.
 
In LRA Section 3.2.2.2.5, the applicant addressed hardening and loss of strength due to elastomer degradation in elastomer seals and components of the BWR standby gas treatment
 
system ductwork and filters exposed to air-indoor uncontrolled.
SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer degradation can occur in elastomer seals and components of the BWR standby gas treatment
 
system ductwork and filters exposed to ai r-indoor uncontrolled. The GALL Report recommends further evaluation of a plant-specific AMP to ensure adequate management of the aging effect.
LRA Section 3.2.2.2.5 states the Periodic Inspection of Ventilation Systems Program will be used to evaluate elastomer door seals and flexible c onnections in the standby gas treatment system.
Periodic inspections of elastomer door seals and flexible connections will identify leakage or
 
detrimental changes in material properties evidenc ed by cracking, material perforations, material.
Observed conditions with potential impact on an intended function will be evaluated or corrected
 
in accordance with the corrective action process.
The staff reviewed the applicant's Periodic Inspection of Ventilation Systems Program and determined that it is adequate to detect hardening and loss of strength of elastomer seals and
 
components.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.5. For those LRA line items that apply to this SRP-LR section, the staff determined 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).
3-299 3.2.2.2.6  Loss of Material Due to Erosion LRA Section 3.2.2.2.6 states that loss of material due to erosion of the PWR high pressure safety injection pump mini flow orifice, with reference to the further evaluation in SRP-LR
 
Section 3.2.2.2.6, is applicable to PWRs only. The staff finds acceptable the applicant's
 
assessment that this aging effect is not applicable to OCGS because it is a BWR plant.
3.2.2.2.7  Loss of Material Due to General Corrosion and Fouling
 
The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.7.
 
In LRA Section 3.2.2.2.9, the applicant addressed loss of material due to general corrosion and fouling for steel drywell and suppression chamber spray system nozzle and flow orifice internal
 
surfaces exposed to air - indoor uncontrolled.
SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling can occur on steel drywell and suppression chamber spray system nozzle and flow orifice internal
 
surfaces exposed to air - indoor uncontrolled and could plug the spray nozzles and flow orifices.
 
This aging mechanism and effect applies because the spray nozzles and flow orifices are
 
occasionally wetted, even though most of the time this system is on standby. The wetting and
 
drying of these components can accelerate corrosion and fouling. The GALL Report
 
recommends further evaluation of a plant-specific AMP to ensure adequate management of the
 
aging effect.
LRA Section 3.2.2.2.9 states that the AMR associated with this further evaluation is not applicable because the containment spray nozzle and orifice assemblies used are stainless
 
steel.The staff reviewed the AMR line items in LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and verified that the containment spray nozzle and orifice assemblies used are stainless steel, not steel.
 
Therefore, the staff agrees with the applicant's conclusion that this further evaluation is not
 
applicable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.9. For those LRA line items that apply to this SRP-LR section, the staff determined that the LRA is consistent with the GALL Report and 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).
3.2.2.2.8  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.
 
In LRA Section 3.2.2.2.8.1, the applicant addressed loss of material due to general, pitting, and crevice corrosion of BWR steel piping, piping components, and piping elements exposed to
 
treated water.
SRP-LR Section 3.2.2.2.8.1 states that loss of material due to general, pitting, and crevice corrosion can occur in BWR steel piping, piping components, and piping elements exposed to 3-300 treated water. The existing AMP relies on monitoring and control of BWR water chemistry to mitigate degradation. However, control of water chemistry does not preclude loss of material due
 
to general, pitting, and crevice corrosion at locations of stagnant flow conditions. Therefore, the
 
effectiveness of the Water Chemistry 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 Water Chemistry Program. A one-time inspection of select components at
 
susceptible locations is an acceptable method to determine whether an aging effect does not
 
occur or progresses so slowly that the component's intended function will be maintained during
 
the period of extended operation.
LRA Section 3.2.2.2.8.1 states that the Water Chemistry Program will be used to manage aging effects of steel piping, piping components, and piping elements exposed to a treated water
 
environment in the containment spray system, co re spray system, isolation condenser system, post-accident sampling system, and RPV. The progr am activities provide for monitoring and controlling of water chemistry by station procedures and processes for the prevention or
 
mitigation of loss of material aging effects. The One-Time Inspection Program will be used in
 
each of these systems for verification of chemistry control and confirmation of the absence of
 
loss of material. The Periodic Testing of Containment Spray Nozzles Program will also be used
 
to manage corrosion of steel piping and piping components in the containment spray system.
 
Observed conditions with potential impact on intended function will be evaluated or corrected in
 
accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry and One-Time Inspection Programs and determined that these programs are adequate to manage loss of material for steel piping, piping
 
components, and piping elements exposed to a treated water environment. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR
 
Section 3.2.2.2.8.1 for further evaluation.
The staff noted that the applicant had not credited the GALL Report AMR for steel containment isolation components exposed to treated water, with reference to the further evaluation in
 
SRP-LR Section 3.2.2.2.8.2. This was a new AMR that was not identified in the January 2005
 
draft GALL Report.
The staff reviewed LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and noted that other GALL Report AMR line items that address same material and environment combinations were appropriately
 
credited. Therefore, the identified above, the staff concludes that this further evaluation is not
 
applicable.
The staff noted that the applicant had not credited the GALL Report AMR for steel piping, piping components, and piping elements exposed to lubricating oil, with reference to the further
 
evaluation in SRP-LR Section 3.2.2.2.8.3. This new AMR was not identified in the January 2005
 
draft GALL Report.
The applicant was asked which AMPs it credited for loss of material due to general, pitting, and crevice corrosion for steel piping, piping components, and piping elements exposed to lubricating
 
oil in the ESF systems. In its response, the applicant stated that Section 3.2.2.2.8.3 of the
 
September 2005 SRP-LR addresses new line item EP-46, which is not in the January 2005 draft
 
SRP-LR. This material and environment combinati on is not present in ESF systems. The LRA credits line items AP-30 (3.3.1-16) and SP-25 (3.4.1-3) for carbon steel piping, piping
 
components, and piping elements exposed to lubricating oil in other systems.
3-301 The staff reviewed LRA Tables 3.2.2.1.1 through 3.2.2.1.3 and confirmed that no steel components exposed to lubricating oil were identified. Therefore, the staff finds the applicant's
 
response acceptable and concluded that this further evaluation is not applicable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.8. For those LRA line items that apply to this SRP-LR section, the staff determined 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).
3.2.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion (MIC)
The staff reviewed LRA Section 3.2.2.2.8.3 against the criteria in SRP-LR Section 3.2.2.2.9.
 
In LRA Section 3.2.2.2.8.3, the applicant addressed loss of material due to general, pitting, crevice, and MIC for steel (with or without coating or wrapping) piping, piping components, and
 
piping elements buried in soil.
SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC can occur in steel (with or without coating or wrapping) piping, piping components, and piping
 
elements buried in soil. The Buried Piping and Tanks Inspection Program relies on industry
 
practice, frequency of pipe excavation, and operating experience to manage the effects of loss of
 
material from general, pitting, and crevice corrosion, and MIC. 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 to ensure that loss of material does
 
not occur.
LRA Section 3.2.2.2.8.3 states that a Buried Piping Inspection Program will be implemented to manage the loss of material in steel piping, piping components, and piping elements exposed to
 
soil in the containment spray system. The Buri ed Piping Inspection Program includes preventive measures to mitigate corrosion and periodic inspection to manage the effects of corrosion on the
 
pressure-retaining capacity of buried steel piping, piping components, and piping elements.
 
Observed conditions with potential impact on an intended function are evaluated or corrected in
 
accordance with the corrective action process. ESF systems have no buried steel tanks within
 
the scope of license renewal.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.2.2.2.9. For those LRA line items that apply to this SRP-LR section, the staff determined 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).
3.2.2.2.10  Quality Assurance for Aging Management of Nonsafety-Related Components
 
SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program for safety-related and nonsafety-related components.
3-302 Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determines that the applicant has adequately
 
addressed the issues further evaluated. 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).3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.2.2.1.1 through 3.2.2.1.3, the staff reviewed additional details concerning the results of the AMRs for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL
 
Report.In LRA Tables 3.2.2.1.1 through 3.2.2.1.3, 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 about how the aging effects
 
will be managed. Specifically, Note F indicates t hat 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, materi al, 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.
Staff Evaluation. 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 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 discussed in the following sections.
3.2.2.3.1  Containment Spray System (CSS)
Summary of Aging Management Evaluation -
LRA Table 3.2.2.1.1 The staff reviewed LRA Table 3.2.2.1.1, which summarizes the results of AMR evaluations for the CSS component groups.
In LRA Table 3.2.2.1.1 the applicant states that there are no aging effects for carbon and low alloy piping and fittings providing a pressure boundary function in a containment atmosphere
 
environment (internal and external). The staff finds this acceptable because the containment
 
atmosphere environment has a relatively small amount of moisture which is not likely to result in
 
any significant corrosion of the carbon steel and low alloy piping and fittings. Based on operating
 
experience, the staff concludes that the extent of any corrosion which may occur is not likely to
 
affect the pressure boundary function.
The applicant also stated that there are no aging effects for stainless steel spray nozzles providing pressure boundary and spray functions in a containment atmosphere environment (internal and external). The staff finds this acceptable because moisture in the containment 3-303 atmosphere forms a passive film on stainless steel surfaces which prevents further progression.
The spray and pressure boundary functions of the nozzles are not likely to be affected in this
 
environment. Therefore, the staff finds that the intended function of the stainless steel
 
components will not be affected.
On the basis of its review, as discussed above, the staff concludes that there are no aging effects associated with core spray system components which would impair the intended
 
functions of the core spray system components. 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).
3.2.2.3.2  Core Spray (CS) System Summary of Aging Management Evaluation -
LRA Table 3.2.2.1.2 The staff reviewed LRA Table 3.2.2.1.2, which summarizes the results of AMR evaluations for the CS system component groups.
In LRA Table 3.2.2.1.2, the applicant stated that the AMRs for the CS system components either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results
 
presented in this table are consistent with the GALL Report. The staff's evaluation for AMR items
 
that are consistent with the GALL Report is documented in SER Sections 3.2.2.1 and 3.2.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associat ed with the CS system 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).
3.2.2.3.3  Standby Gas Treatment System (SGT S) Summary of Aging Management Evaluation -
LRA Table 3.2.2.1.3 The staff reviewed LRA Table 3.2.2.1.3, which summarizes the results of AMR evaluations for the SGTS component groups.
The staff's review of LRA Table 3.2.2.1.3 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
LRA Table 3.2.2.1.3 states that there are no AERMs for stainless steel closure bolting in an indoor air (external) environment. In RAI 3.2-1 dated March 30, 2006, the staff requested that the
 
applicant provide the following information:  (a)justification for excluding loss of preload and loss of closure integrity as aging mechanisms  (b)specific industry guidance for ventilation closure bolting relating to AERMs (e.g., EPRI documents, published reports, operating experience, etc.)  (c)sizes and locations of the bolting In its response dated April 28, 2006, the applicant stated:
3-304  (a)Ventilation system duct bolting is similar to structural bolting in that it provides structural support for ventilation system assemblies, which is
 
functionally different from piping system pressure retaining closure bolting.
 
Typical ventilation system operati ng pressures and temperatures do not result in significant loads on the closure bolting such that ventilation
 
system joint integrity would be compromised. Ventilation bolting
 
applications at Oyster Creek do not require specific predetermined bolting
 
preload to assure the associated intended functions are maintained. Loss
 
of preload or loss of closure integrity for stainless steel ventilation system
 
bolting in an indoor air environment is not a significant aging effect
 
requiring management.  (b)NUREG-1801 does not specifically address ventilation closure bolting.
NUREG-1801 item TP-5 identifies stainless steel bolted connections in an
 
indoor air environment, with no aging effects or aging management
 
program required. No other industry reports were identified specifically
 
relating to ventilation closure bolting AERMs. Oyster Creek has not
 
experienced age related degradation failures of stainless steel ventilation
 
closure bolting in an indoor air environment.  (c)Ventilation bolting is used at fan and damper connections, filter unit connections, valve connections, flexible connections, access ports, duct
 
support locations, and connections between duct sections. Most bolting is
 
less than one-half inch nominal diameter. Larger bolting is used when
 
ducting is connected to large butterfly valves, because the design of the
 
butterfly valve flange is based on pipe flange applications and not ducting
 
connections.
The staff finds the applicant's response acceptable because it adequately justified the exclusion of loss of preload and loss of closure integrity as aging mechanisms for stainless steel ventilation
 
system bolting in an indoor air environment LRA Table 3.2.2.1.3 states that loss of material in a number of components is managed by the Periodic Inspection of Ventilation Systems Program.
In RAI 3.2-2 dated March 30, 2006, the staff requested that the applicant provide the specific tests and inspections including frequency and methods of inspections, preventive actions, parameters monitored and inspected, detection of aging effects, acceptance criteria, and
 
operating experience in the applicant's program that relate to each of the following line items in
 
the standby gas treatment system:  (a)Loss of material in aluminum duct work in an external soil environment.  (b)Loss of material in brass piping and fitting in an outdoor air (external) environment and the specific brass composition.  (c)Loss of material in copper piping and fittings in an outdoor air (external) environment and the specific copper composition.
In its response dated April 28, 2006, the applicant stated :
3-305  (a)The buried ductwork at Oyster Creek is contained in the Standby Gas Treatment System (SGTS). It is comp rised of two aluminum duct exhaust lines that pass through approximately six feet of structural backfill above
 
the roof of the Exhaust Tunnel. Above ground, the ducts connect to the
 
Ventilation Stack. Oyster Creek has experienced age related material
 
degradation failure of aluminum duct in this application. Corrosion of one
 
of the original buried aluminum ducts near the roof of the Exhaust Tunnel
 
required modification and repair after 25 years of service. The duct was
 
internally sleeved with type B209 aluminum sheet with a wall thickness
 
greater than the original duct and the surrounding backfill stabilized. The
 
redundant buried duct was also modified such that all aluminum ducts with
 
an external soil environment are now sleeved.
UT thickness measurements will be performed to detect the aging effect of loss of material of the buried aluminum duct. The acceptance criteria is
 
measured loss of material of the sleeve caused by corrosion. Measured
 
loss of material of the sleeve will be entered into the corrective action
 
program and trended as required. The inspection frequency is every five
 
years. There are no preventive actions associated with these components.  (b)There is no brass pipe in the SGTS system. Brass fittings are used with copper tubes for the flow instrumentation downstream of the SGTS
 
outdoor fans. Brass fittings are included under the listed component type
 
piping and fittings since they are part of the copper tubing assembly. The
 
brass fittings are visually inspected. The acceptance criteria is no evidence
 
of penetrating corrosion. Identification of penetrating corrosion will be
 
entered into the corrective action program. The inspection frequency is
 
yearly. Identification of aging effects does not require determination of the
 
specific material composition in this application. Therefore, the specific
 
brass composition was not researched. Oyster Creek has not experienced
 
aged related material degradation failures of tubing fittings in this
 
application. There are no preventive actions associated with these
 
components.  (c)Copper tubing as listed under piping and fittings is used for the flow instrumentation downstream of the SGTS outdoor fans. The tubing is
 
visually inspected. The acceptance criteria is no evidence of penetrating
 
corrosion. Identification of penetrating corrosion will be entered into the
 
corrective action program. The inspection frequency is yearly.
Identification of aging effects does not require determination of the specific material composition in this application. Therefore, the specific copper
 
composition was not researched. Oyster Creek has not experienced age
 
related material degradation failures of tubing in this application. There are
 
no preventive actions associated with these components. The function of
 
the SGTS is routinely demonstrated by the monthly surveillance tests.
The staff finds the applicant's response acceptable because the applicant had provided an adequate description of the tests and inspections for managing the loss of material in aluminum 3-306 duct work in an external soil environment and brass and copper piping and fitting in an outdoor air (external) environment.
LRA Table 3.2.2.1.3 identifies no AERMs for Plexiglass duct work in an internal and external indoor air environment. In RAI 3.2-3 dated March 30, 2006, the staff requested that the applicant
 
discuss its current maintenance practices as well as vendor recommendations for Plexiglass in
 
this environment. In addition, the staff requested that the applicant identify the specific composition of this Plexiglass material and its operating experience
.In its response dated April 28, 2006, the applicant stated that Plexiglass duct panels are installed on the absolute filter inlet and exhaust boxes of each SGTS train. As no maintenance or cleaning
 
is performed, the industry cleaning and care recommendations to preclude scratching or crazing
 
when cleaning are not implemented. Although not identified, the specific material composition of
 
the Plexiglass is not required as there are no aging effects for acrylics (thermoplastics) in an
 
indoor air environment. Acceptability for the use of thermoplastics is a design-driven criterion.
After the appropriate material is chosen, there are no aging effects. Thermoplastics are
 
susceptible to aging effects due to such stressors as high temperature, chemicals, radiation, and
 
UV rays. None of these are present in this application. OCGS has experienced no aged-related
 
material degradation failures of Plexiglass in the SGTS system.
The staff finds that the stressors which may produce aging effects in acrylics are not present in this application. The staff finds acceptable the applicant's evaluation because there are no aging
 
effects associated with the Plexiglass duct panels.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that either there are no aging effects or the aging effects associated with the
 
SGTS 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).
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environm ent, AERMs, 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 systems components, that are 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).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 associated with the following systems:  * "C" battery room heating & ventilation 3-307
* 4160 V switchgear room ventilation
* 480 V switchgear room ventilation
* battery and MG set room ventilation
* chlorination system
* circulating water system
* containment inerting system
* containment vacuum breakers
* control rod drive system
* control room heating, ventilation, and air conditioning (HVAC)
* drywell floor and equipment drains
* emergency diesel generator and auxiliary system
* emergency service water system
* fire protection system
* fuel storage and handling equipment
* hardened vent system
* heating & process steam system
* hydrogen & oxygen monitoring system
* instrument (control) air system
* main fuel oil storage & transfer system
* miscellaneous floor and equipment drain system
* nitrogen supply system
* noble metals monitoring system
* post-accident sampling system
* process sampling system
* radiation monitoring system
* radwaste area heating and ventilation system
* reactor building closed cooling water system
* reactor building floor and equipment drains
* reactor building ventilation system
* reactor water cleanup system
* roof drains and overboard discharge
* sanitary waste system
* service water system
* shutdown cooling system
* spent fuel pool cooling system
* standby liquid control system (liquid poison system)
* traveling in-core probe system
* turbine building closed cooling water system
* water treatment & distribution system3.3.1  Summary of Technical Information in the Application In LRA Section 3.3, the applicant provided AM R results for the auxiliary systems components and component groups. In LRA Table 3.3.1, "Summary of Aging Management Evaluations for the
 
Auxiliary Systems," the applicant provided a su mmary comparison of its AMRs with those evaluated in the GALL Report for the auxilia ry systems components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of condition reports and discussions with 3-308 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 the auxiliary systems components within the scope of license renewal and subject to an AMR will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs during the weeks of October 3-7, 2005, January 23-27, 2006, and February 13-17, 2006, 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 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 the Audit and Review Report and are summarized in SER
 
Section 3.3.2.1.
In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations
 
were consistent with the acceptance criteria in SRP-LR Section 3.3.2.2. The staff's audit
 
evaluations are documented in the Audit and Review Report, and are summarized in SER
 
Section 3.3.2.2.
The staff also conducted a technical review of the remaining AMRs not consistent with, or not addressed in, the GALL Report. The technical review included evaluating whether all plausible
 
aging effects were identified and whether the aging effects listed were appropriate for the
 
combination of materials and environments specified. The staff's evaluations are documented in
 
SER Section 3.3.2.3.
For AMRs that the applicant identified as not applicable or not requiring aging management, the staff conducted a review of the AMR line items and the plant's operating experience, to verify the
 
applicant's claims. Details of these reviews are documented in the Audit and Review Report.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the auxiliary systems components.
Table 3.3-1, provided below, includes a summary of the staff's evaluation of components, aging effects, and 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 3-309Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Steel cranes -
structural girders
 
exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-1)
Cumulative fatigue damageTLAA to be evaluated for
 
structural girders of
 
cranes. See the
 
Standard Review
 
Plan, Section 4.7 for
 
generic guidance for
 
meeting the
 
requirements of 10 CFR 54.21(c)(1).TLAAThis TLAA is evaluated in Section
 
4.3.
(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 (Item 3.3.1-2)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.3.2.2.1)
Stainless steel heat exchanger tubes
 
exposed to treated water (Item 3.3.1-3)
Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2)Acceptable, since one-time inspection
 
is credited for other
 
aging effects in the same systems.
(See SER Section
 
3.3.2.2.2)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution
> 60 &deg;C (> 140 &deg;F)
(Item 3.3.1-4)
Cracking due to stress corrosion
 
cracking Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.3)
Stainless steel and stainless clad steel
 
heat exchanger
 
components
 
exposed to treated water > 60 &deg;C
(> 140 &deg;F)
(Item 3.3.1-5)
Cracking due to stress corrosion
 
cracking A plant specific aging management
 
program is to be
 
evaluated.One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.3)
Stainless steel diesel engine
 
exhaust piping, piping components, and piping elements
 
exposed to diesel
 
exhaust (Item 3.3.1-6)
Cracking due to stress corrosion
 
cracking A plant specific aging management
 
program is to be
 
evaluated.Not ApplicableNot applicable since the diesel engine
 
exhaust piping is
 
carbon steel.
(See SER Section
 
3.3.2.2.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-310 High-strength steel closure bolting exposed to air with steam or water
 
leakage.
(Item 3.3.1-10)
Cracking due to stress corrosion cracking, cyclic
 
loadingBolting Integrity The AMP is to be
 
augmented by
 
appropriate
 
inspection to detect
 
cracking if the bolts are not otherwise
 
replaced during
 
maintenance.
Bolting Integrity (B.1.12)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.4)
Elastomer seals and components
 
exposed to air -
 
indoor uncontrolled (internal/external)
(Item 3.3.1-11)
Hardening and loss of strength due to
 
elastomer degradation A plant specific aging management
 
program is to be
 
evaluated Periodic Inspection of Ventilation Systems (B.2.4)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.5)
Elastomer lining exposed to treated water or treated borated water (Item 3.3.1-12)
Hardening and loss of strength due to
 
elastomer degradation A plant-specific aging management
 
program is to be
 
evaluated.
Periodic Inspection (B.2.5)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.5)
Boral, boron steel spent fuel storage
 
racks neutron-absorbing
 
sheets exposed to treated water or
 
treated borated water (Item 3.3.1-13)
Reduction of neutron-absorbing capacity and loss of
 
material due to
 
general corrosion A plant specific aging management
 
program is to be
 
evaluatedNoneAcceptable since operating experience shows
 
that aging effects for
 
this component are
 
insignificant.
(See SER Section
 
3.3.2.2.6)
Steel piping, piping component, and
 
piping elements
 
exposed to
 
lubricating oil (Item 3.3.1-14)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.3.2.2.7)
Steel reactor coolant pump oil collection system piping, tubing, and valve
 
bodies exposed to
 
lubricating oil (Item 3.3.1-15)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating OilAnalysis and One-Time InspectionNot ApplicableNot applicable sinceOyster Creek does
 
not have a reactor
 
coolant pump oil collection system.
(See SER Section
 
3.3.2.2.7)
Steel reactor coolant pump oil collection system tank
 
exposed to
 
lubricating oil (Item 3.3.1-16)
Loss of material due to general, pitting, and crevice
 
corrosion Lubricating OilAnalysis and One-Time Inspection to
 
evaluate the
 
thickness of the lower portion of the
 
tankNot ApplicableNot applicable sinceOyster Creek does
 
not have a reactor
 
coolant pump oil collection system.
(See SER Section
 
3.3.2.2.7)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-311 Steel piping, piping components, and
 
piping elements
 
exposed to treated water (Item 3.3.1-17)
Loss of material due to general, pitting, and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.3.2.2.7)
Stainless steel and steel diesel engine
 
exhaust piping, piping components, and piping elements
 
exposed to diesel
 
exhaust (Item 3.3.1-18)
Loss of material/general (steel only), pitting
 
and crevice
 
corrosion A plant specific aging management
 
program is to be
 
evaluated Periodic Inspection (B.2.5)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.7)Steel (with orwithout coating or wrapping) piping, piping components, and piping elements
 
exposed to soil (Item 3.3.1-19)
Loss of material due to general, pitting, crevice, and
 
microbiologically
 
influenced corrosion Buried Piping andTanks Surveillance or Buried Piping andTanks Inspection Buried Piping Inspection (B.1.26)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.8)
Steel piping, piping components, piping
 
elements, and tanks
 
exposed to fuel oil (Item 3.3.1-20)
Loss of material due to general, pitting, crevice, and
 
microbiologically
 
influenced
 
corrosion, and
 
foulingFuel Oil Chemistryand One-Time
 
InspectionFuel Oil Chemistry (B.1.22) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.9)
Steel heat exchanger components
 
exposed to
 
lubricating oil (Item 3.3.1-21)
Loss of material due to general, pitting, crevice, and
 
microbiologically
 
influenced
 
corrosion, and
 
fouling Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.9)Steel with elastomer lining or stainless
 
steel cladding
 
piping, piping
 
components, and
 
piping elements
 
exposed to treated water and treated borated water (Item 3.3.1-22)
Loss of material due to pitting and crevice corrosion (only for
 
steel after
 
lining/cladding
 
degradation)
Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-312 Stainless steel andsteel with stainless
 
steel cladding heat
 
exchanger components
 
exposed to treated water (Item 3.3.1-23)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)
Stainless steel and aluminum piping, piping components, and piping elements
 
exposed to treated water (Item 3.3.1-24)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)Copper alloy HVAC piping, piping
 
components, piping
 
elements exposed
 
to condensation (external)
(Item 3.3.1-25)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.
Periodic Inspection of Ventilation Systems (B.2.4)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)Copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil (Item 3.3.1-26)
Loss of material due to pitting and crevice
 
corrosion Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)
Stainless steel HVAC ducting and
 
aluminum HVAC
 
piping, piping
 
components and
 
piping elements
 
exposed to
 
condensation (Item 3.3.1-27)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.
One-time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)Copper alloy fire protection piping, piping components, and piping elements
 
exposed to
 
condensation (internal)
(Item 3.3.1-28)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.Not ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
(See SER Section
 
3.3.2.2.10)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-313 Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to soil (Item 3.3.1-29)
Loss of material due to pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluated.Not ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
(See SER Section
 
3.3.2.2.10)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to sodium
 
pentaborate solution (Item 3.3.1-30)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.10)Copper alloy piping, piping components, and piping elements
 
exposed to treated water (Item 3.3.1-31)
Loss of material due to pitting, crevice, and galvanic
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.11)
Stainless steel, aluminum and copper alloy piping, piping components, and piping elements
 
exposed to fuel oil (Item 3.3.1-32)
Loss of material due to pitting, crevice, and microbiologically
 
influenced corrosionFuel Oil Chemistryand One-Time
 
InspectionFuel Oil Chemistry (B.1.22) and One-Time Inspection (B.1.24)
(aluminum and copper alloy) or Fuel Oil Chemistry (B.1.22) (stainless
 
steel)Consistent with GALL (aluminum and copper alloy),
which recommends
 
further evaluation.
Acceptable (stainless steel)
 
since one-time
 
inspection is
 
performed for other
 
materials in the
 
same environment
 
that are leading
 
indicators of
 
corrosion.(See SER Section 3.3.2.2.12)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to
 
lubricating oil (Item 3.3.1-33)
Loss of material due to pitting, crevice, and microbiologically
 
influenced corrosion Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.12)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-314 Elastomer seals and components
 
exposed to air -
 
indoor uncontrolled (internal or external)
(Item 3.3.1-34)
Loss of material due to Wear A plant specific aging management
 
program is to be
 
evaluated.
Periodic Inspection of Ventilation Systems (B.2.4)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.3.2.2.13)
Boraflex spent fuel storage racks
 
neutron-absorbing
 
sheets exposed to treated water (Item 3.3.1-36)
Reduction of neutron-absorbing capacity due to
 
boraflex degradation Boraflex MonitoringBoraflex Rack Management (B.1.15)Consistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60 &deg;C
(> 140 &deg;F)
(Item 3.3.1-37)
Cracking due to stress corrosion
: cracking, intergranular stress
 
corrosion cracking BWR Reactor WaterCleanup System BWR Reactor WaterCleanup System (B.1.18)Consistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to treated water > 60 &deg;C
(> 140 &deg;F)
(Item 3.3.1-38)
Cracking due to stress corrosion
 
cracking BWR Stress Corrosion Cracking and Water ChemistryNot ApplicableNot applicable sinceOyster Creek has no
 
stainless steel
 
non-RCPB shutdown cooling system piping
 
exposed to treated water >140 &deg;F.Stainless steel BWR spent fuel storage racks exposed to treated water
> 60 &deg;C (> 140 &deg;F)
(Item 3.3.1-39)
Cracking due to stress corrosion
 
crackingWater ChemistryNot ApplicableNot applicable since stainless steel spent
 
fuel storage racks
 
are exposed to treated water
<140 &deg;F.Steel tanks in dieselfuel oil system
 
exposed to air -
 
outdoor (external)
(Item 3.3.1-40)
Loss of material due to general, pitting, and crevice
 
corrosion Aboveground SteelTanks AbovegroundOutdoor Tanks (B.1.21)Consistent with GALL.
(See SER Section
 
3.3.2.1)High-strength steel closure bolting exposed to air with steam or water
 
leakage (Item 3.3.1-41)
Cracking due tocyclic loading, stress
 
corrosion crackingBolting IntegrityNot ApplicableNot applicable sinceauxiliary system
 
high strength steel
 
closure bolting is only applicable to the CRD system, and this is
 
addressed in item
 
3.3.1-7.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-315 Steel closure boltingexposed to air with steam or water
 
leakage (Item 3.3.1-42)
Loss of material due to general corrosionBolting IntegrityNot ApplicableNot applicable sinceno auxiliary system
 
steel closure bolting
 
is exposed to air with steam or water
 
leakage, except the CRD system, which
 
is addressed in item
 
3.3.1-7.Steel bolting and closure bolting
 
exposed to air -
 
indoor uncontrolled (external) or air -
 
outdoor (External)
(Item 3.3.1-43)
Loss of material due to general, pitting, and crevice
 
corrosionBolting IntegrityBolting Integrity (B.1.12), or ASME Section XI,Subsection IWE (B.1.27), or Inspection of Overhead Heavy
 
Load and Light Load Handling System (B.1.16), or Structures Monitoring (B.1.31) Consistent with GALL for AMRs
 
crediting the OCGS
 
bolting integrity
 
program.Acceptable for AMRs crediting the
 
OCGS ASME Section XI, Subsection IWE, inspection of
 
overhead heavy
 
load and light load handling system, or
 
structures
 
monitoring programs since they are consistent with the
 
GALL bolting integrity program for
 
this component
 
group/ aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Steel compressedair system closure
 
bolting exposed to
 
condensation (Item 3.3.1-44)
Loss of material due to general, pitting, and crevice
 
corrosionBolting IntegrityNot ApplicableNot applicable since instrument air system steel closure
 
bolting is not
 
exposed to
 
condensation.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-316 Steel closure bolting exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-45)
Loss of preload due to thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity (B.1.12), or ASME Section XI,Subsection IWE (B.1.27)Consistent with GALL for AMRs
 
crediting the OCGS
 
bolting integrity
 
program.Acceptable for AMRs crediting the
 
OCGS ASME Section XI, Subsection IWE
 
Program, since it is consistent with the
 
GALL bolting integrity program for
 
this component
 
group/ aging effect
 
combination.
(See SER Section
 
3.3.2.1.4)
Stainless steel and stainless clad steel
 
piping, piping
 
components, piping
 
elements, and heat
 
exchanger components
 
exposed to closed cycle cooling water > 60 &deg;C
(> 140 &deg;F)
(Item 3.3.1-46)
Cracking due to stress corrosion
 
crackingClosed-CycleCooling Water SystemNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Steel piping, piping components, piping
 
elements, tanks, and heat exchanger
 
components
 
exposed to closed cycle cooling water (Item 3.3.1-47)
Loss of material due to general, pitting, and crevice
 
corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)
 
and One-Time Inspection (B.1.24)Consistent with GALL. Addition of
 
one-time inspection
 
provides additional
 
assurance that
 
aging effects are
 
adequately
 
managed.Steel piping, piping components, piping
 
elements, tanks, and heat exchanger
 
components
 
exposed to closed cycle cooling water (Item 3.3.1-48)
Loss of material due to general, pitting, crevice, and
 
galvanic corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-317 Stainless steel; steelwith stainless steel
 
cladding heat
 
exchanger components
 
exposed to closed cycle cooling water (Item 3.3.1-49)
Loss of material due to microbiologically
 
influenced corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to closed cycle cooling water (Item 3.3.1-50)
Loss of material due to pitting and crevice
 
corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.3.2.1)Copper alloy piping, piping components, piping elements, and heat exchanger
 
components
 
exposed to closed cycle cooling water (Item 3.3.1-51)
Loss of material due to pitting, crevice, and galvanic
 
corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water (Item 3.3.1-52)
Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel compressedair system piping, piping components, and piping elements
 
exposed to
 
condensation (internal)
(Item 3.3.1-53)
Loss of material due to general and
 
pitting corrosion Compressed Air MonitoringNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Stainless steel compressed air system piping, piping components, and piping elements
 
exposed to internal
 
condensation (Item 3.3.1-54)
Loss of material due to pitting and crevice
 
corrosion Compressed Air MonitoringNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-318 Steel ducting closure bolting
 
exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-55)
Loss of material due to general corrosion External Surfaces MonitoringNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Steel HVAC ducting and components
 
external surfaces
 
exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-56)
Loss of material due to general corrosion External Surfaces Monitoring Structures Monitoring (B.1.31), or Periodic Inspection (B.2.5)or Periodic Inspection of Ventilation Systems (B.2.4)
Acceptable since the OCGS structures
 
monitoring, periodic
 
inspection, and
 
periodic inspection
 
of ventilation systems programs are consistent with
 
the GALL external
 
surfaces monitoring
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Steel piping and components
 
external surfaces
 
exposed to air -
 
indoor uncontrolled (External)
(Item 3.3.1-57)
Loss of material due to general corrosion External Surfaces MonitoringFire Protection (B.1.19), or Fire Water System (B.1.20), or Structures Monitoring (B.1.31) or Periodic Inspection of Ventilation Systems (B.2.4)
Acceptable since the OCGS fire protection, fire water system, structures
 
monitoring, and
 
periodic inspection
 
of ventilation systems programs are consistent with
 
the GALL external
 
surfaces monitoring
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-319 Steel external surfaces exposed to
 
air - indoor
 
uncontrolled (external), air -
 
outdoor (external),
and condensation (external)
(Item 3.3.1-58)
Loss of material due to general corrosion External Surfaces MonitoringFire Protection (B.1.19), or Fire Water System (B.1.20), or Structures Monitoring (B.1.31) or Periodic Inspection of Ventilation Systems (B.2.4)
Acceptable since the OCGS fire protection, fire water system, structures
 
monitoring, and
 
periodic inspection
 
of ventilation systems programs are consistent with
 
the GALL external
 
surfaces monitoring
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Steel heat exchanger components
 
exposed to air -
 
indoor uncontrolled (external) or air
-outdoor (external)
(Item 3.3.1-59)
Loss of material due to general, pitting, and crevice
 
corrosion External Surfaces MonitoringNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Steel piping, piping components, and
 
piping elements
 
exposed to air -
 
outdoor (external)
(Item 3.3.1-60)
Loss of material due to general, pitting, and crevice
 
corrosion External Surfaces Monitoring10 CFR 50, Appendix J (B.1.29) plus One-Time
 
Inspection (B.1.24), or One-Time Inspection (B.1.24), or Fire Protection (B.1.19), or Fire Water System (B.1.20), or Structures Monitoring (B.1.31), or Periodic Inspection of Ventilation Systems (B.2.4)
Acceptable since the OCGS one-time
 
inspection, fire protection, fire water system, structures
 
monitoring, and
 
periodic inspection
 
of ventilation systems programs are consistent with
 
the GALL external
 
surfaces monitoring
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-320 Elastomer fire barrier penetration
 
seals exposed to
 
air - outdoor or
 
air - indoor
 
uncontrolled (Item 3.3.1-61)
Increased hardness, shrinkage and loss
 
of strength due to weatheringFire ProtectionFire Protection (B.1.19)or Structures Monitoring (B.1.31)Consistent with GALL for AMRs crediting the Fire
 
Protection Program.
Acceptable for AMRs crediting the
 
structures
 
monitoring program
 
since the OCGS
 
structures
 
monitoring program is consistent with the GALL Fire
 
Protection Program
 
for this component
 
group/ aging effect
 
combination.(See SER Section 3.3.2.1.6)
Aluminum piping, piping components, and piping elements
 
exposed to raw water (Item 3.3.1-62)
Loss of material due to pitting and crevice
 
corrosionFire ProtectionFire Water System (B.1.20)No applicable aging effects.
(See SER Section
 
3.3.2.3)Steel fire rated doors exposed to air
- outdoor or
 
air - indoor
 
uncontrolled (Item 3.3.1-63)
Loss of material due to WearFire ProtectionFire Protection (B.1.19)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to fuel oil (Item 3.3.1-64)
Loss of material due to general, pitting, and crevice
 
corrosionFire Protection andFuel Oil ChemistryFire Protection(B.1.19) and Fuel
 
Oil Chemistry (B.1.20)Consistent with GALL.
(See SER Section
 
3.3.2.1)Reinforced concrete structural fire barriers - walls, ceilings and floors
 
exposed to air -
 
indoor uncontrolled (Item 3.3.1-65)
Concrete cracking and spalling due to
 
aggressive chemical
 
attack, and reaction with aggregatesFire Protection and Structures
 
Monitoring ProgramFire Protection (B.1.19) and
 
Structures
 
Monitoring (B.1.31)Consistent with GALL.
(See SER Section
 
3.3.2.1)Reinforced concrete structural fire barriers - walls, ceilings and floors
 
exposed to air -
 
outdoor (Item 3.3.1-66)
Concrete cracking and spalling due to freeze thaw, aggressive chemical
 
attack, and reaction with aggregatesFire Protection and Structures
 
Monitoring ProgramFire Protection (B.1.19) and
 
Structures
 
Monitoring (B.1.31)Consistent with GALL.
(See SER Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-321 Reinforced concrete structural fire barriers - walls, ceilings and floors
 
exposed to air -
 
outdoor or air -
 
indoor uncontrolled (Item 3.3.1-67)
Loss of material due to corrosion of
 
embedded steelFire Protection and Structures
 
Monitoring ProgramFire Protection (B.1.19) and
 
Structures
 
Monitoring (B.1.31)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to raw water (Item 3.3.1-68)
Loss of material due to general, pitting, crevice, and
 
microbiologically
 
influenced
 
corrosion, and
 
foulingFire Water SystemFire Water System (B.1.20)Consistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to raw water (Item 3.3.1-69)
Loss of material due to pitting and crevice
 
corrosion, and
 
foulingFire Water SystemFire Water System (B.1.20)Consistent with GALL.
(See SER Section
 
3.3.2.1)Copper alloy piping, piping components, and piping elements
 
exposed to raw water (Item 3.3.1-70)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
foulingFire Water SystemFire Water System (B.1.20)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to moist air
 
or condensation (Internal)
(Item 3.3.1-71)
Loss of material due to general, pitting, and crevice
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous
 
Piping and Ducting
 
ComponentsNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Steel HVAC ducting and components
 
internal surfaces
 
exposed to
 
condensation (Internal)
(Item 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 Periodic Inspection of Ventilation Systems (B.2.4)
Acceptable since the OCGS periodic
 
inspection of ventilation systems
 
program is consistent with the
 
GALL inspection of
 
internal surfaces in
 
miscellaneous
 
piping and ducting
 
components
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-322 Steel crane structural girders in
 
load handling system exposed to
 
air - indoor
 
uncontrolled (external)
(Item 3.3.1-73)
Loss of material due to general corrosion Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems (B.1.16)Consistent with GALL.
(See SER Section
 
3.3.2.1)Steel cranes - rails exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-74)
Loss of material due to Wear Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems Inspection of Overhead Heavy
 
Load and Light Load (Related to
 
Refueling) Handling Systems (B.1.16)Consistent with GALL.
(See SER Section
 
3.3.2.1)Elastomer seals and components
 
exposed to raw water (Item 3.3.1-75)
Hardening and loss of strength due to
 
elastomer degradation; loss of
 
material due to
 
erosionOpen-Cycle CoolingWater System Periodic Inspection (B.2.5)Acceptable since the OCGS periodic
 
inspection program is consistent with
 
the GALL open-cycle cooling water system
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.3)Steel piping, piping components, and
 
piping elements (without lining/
coating or with
 
degraded lining/coating)
 
exposed to raw water (Item 3.3.1-76)
Loss of material due to general, pitting, crevice, and
 
microbiologically
 
influenced
 
corrosion, fouling, and lining/coating
 
degradationOpen-Cycle CoolingWater SystemNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.
Steel heat exchanger components
 
exposed to raw water (Item 3.3.1-77)
Loss of material due to general, pitting, crevice, galvanic, and microbiologically
 
influenced
 
corrosion, and
 
foulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13)Consistent with GALL.
(See SER Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-323 Stainless steel,nickel alloy, and copper alloy piping, piping components, and piping elements
 
exposed to raw water (Item 3.3.1-78)
Loss of material due to pitting and crevice
 
corrosionOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13), or One-Time Inspection (B.1.24)Consistent with GALL for AMRs
 
crediting the OCGS open-cycle cooling water system
 
program.Acceptable for AMRs crediting the
 
OCGS one-time
 
inspection program
 
since it is consistent with the GALL open-cycle cooling water system
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.5)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to raw water (Item 3.3.1-79)
Loss of material due to pitting and crevice
 
corrosion, and
 
foulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13)Consistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel andcopper alloy piping, piping components, and piping elements
 
exposed to raw water (Item 3.3.1-80)
Loss of material due to pitting, crevice, and microbiologically
 
influenced corrosionOpen-Cycle CoolingWater SystemNot ApplicableNot applicable since no GALL AMR line
 
items related to this
 
component group/
 
aging effect combination were
 
credited in the LRA.Copper alloy piping, piping components, and piping
 
elements, exposed to raw water (Item 3.3.1-81)
Loss of material due to pitting, crevice, and microbiologically
 
influenced
 
corrosion, and
 
foulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13), or Periodic Inspection (B.2.5)Consistent with GALL for AMRs
 
crediting the OCGS open-cycle cooling water system.
Acceptable for AMRs crediting the
 
OCGS periodic
 
inspection program
 
since it is consistent with the GALL open-cycle cooling water system
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.5)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-324Copper alloy heat exchanger components
 
exposed to raw water (Item 3.3.1-82)
Loss of material due to pitting, crevice, galvanic, and
 
microbiologically
 
influenced
 
corrosion, and
 
foulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13), or Fire Water System (B.1.20)Consistent with GALL for AMRs
 
crediting the OCGS open-cycle cooling water system.
Acceptable for AMRs crediting the
 
OCGS Fire Water System Program
 
since it is consistent with the GALL open-cycle cooling water system
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.5)
Stainless steel andcopper alloy heat
 
exchanger tubes
 
exposed to raw water (Item 3.3.1-83)
Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemOpen-Cycle CoolingWater System (B.1.13)Consistent with GALL.
(See SER Section
 
3.3.2.1)Copper alloy> 15% Zn piping, piping components, piping elements, and heat exchanger
 
components
 
exposed to raw water, treated water, or closed cycle cooling water (Item 3.3.1-84)
Loss of material due to selective leaching Selective Leaching of Materials Selective Leaching of Materials (B.1.25)Consistent with GALL.
(See SER Section
 
3.3.2.1)Gray cast iron piping, piping
 
components, and
 
piping elements
 
exposed to soil, raw water, treated water, or closed-cycle cooling water (Item 3.3.1-85)
Loss of material due to selective leaching Selective Leaching of Materials Selective Leaching of Materials (B.1.25)Consistent with GALL.
(See SER Section
 
3.3.2.1)Structural steel (new fuel storage rack assembly) exposed
 
to air - indoor
 
uncontrolled (external)
(Item 3.3.1-86)
Loss of material due to general, pitting, and crevice
 
corrosion Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-325 Galvanized steel piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor uncontrolled (Item 3.3.1-92)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)Glass piping elements exposed
 
to air, air - indoor
 
uncontrolled (external), fuel oil, lubricating oil, raw water, treated water, and treated borated water (Item 3.3.1-93)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)Stainless steel andnickel alloy piping, piping components, and piping elements
 
exposed to air -
 
indoor uncontrolled (external)
(Item 3.3.1-94)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)Steel and aluminum piping, piping
 
components, and
 
piping elements
 
exposed to air -
 
indoor controlled (external)
(Item 3.3.1-95)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
concrete (Item 3.3.1-96)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)Steel, stainless steel, aluminum, and copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to gas (Item 3.3.1-97)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-326 Steel, stainless steel, and copper alloy piping, piping
 
components, and
 
piping elements
 
exposed to dried air (Item 3.3.1-98)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.3.2.1)The staff's review of the auxiliary system s component groups followed one of several approaches. One approach, documented in SER Section 3.3.2.1, discusses the staff's review of
 
the AMR results for components that the applicant indicated are consistent with the GALL Report
 
and require no further evaluation. Another approach, documented in SER Section 3.3.2.2, discusses the staff's review of the AMR results for components that the applicant indicated are
 
consistent with the GALL Report and for which further evaluation is recommended. A third
 
approach, documented in SER Section 3.3.2.3, discusses the staff's review of the AMR results
 
for components that the applicant indicated are not consistent with, or not addressed in, the
 
GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the
 
auxiliary systems components is doc umented in SER Section 3.0.3.3.3.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicant identified the materials, environments, AERMs, and the following programs that manage the
 
effects of aging related to the auxiliary systems components:
* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)
* Water Chemistry (B.1.2)
* BWR SCC (B.1.7)
* Bolting Integrity (B.1.12)
* Open-Cycle Closed Cooling Water System (B.1.13)
* Closed-Cycle Closed Cooling Water System (B.1.14)
* Boraflex Rack Management Program (B.1.15)
* Compressed Air Monitoring (B.1.17)
* BWR Reactor Water Cleanup System (B.1.18)
* Fire Protection (B.1.19)
* Fire Water System (B.1.20)
* Aboveground Outdoor Tanks (B.1.21)
* Fuel Oil Chemistry (B.1.22)
* One-Time Inspection (B.1.24)
* Selective Leaching of Materials (B.1.25)
* Buried Piping Inspection (B.1.26)
* ASME Section XI, Subsection IWE (B.1.27)
* 10 CFR Part 50, Appendix J (B.1.29)
* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.1.16)
* Structures Monitoring Program (B.1.31)
* Lubricating Oil Monitoring Activities (B.2.2)
* Periodic Inspection of Ventilation Systems (B.2.4)
* Periodic Inspection Program (B.2.5) 3-327 Staff Evaluation. In LRA Tables 3.3.2.1.1 through 3.3.2.1.41, the applicant provided a summary of AMRs for the auxiliary syst ems components and identified which AMRs it considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report 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 contained 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 that the AMR is 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 AMP
 
identified in the GALL Report. 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. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant is 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 com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component that was under review. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the AMR
 
line item of the different component was applicable to the component under review and whether
 
the AMR was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the AMP identified in the GALL Report. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. The staff verified whether
 
the identified exceptions to the GALL 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.
3-328 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review 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. The staff's evaluation is
 
discussed below.
3.3.2.1.1  Loss of Material Due to Pitting and Crevice Corrosion
 
LRA Table 3.3.2.1.18 for the heating and process st eam system includes AMR line items for loss of material in heat exchangers constructed of copper exposed to auxiliary steam and steam traps constructed of copper alloy exposed to boiler treated water on the internal surface. The applicant
 
credited the One-Time Inspection Program to manage loss of material for these components.
 
The applicant was asked to justify the conclusion that the One-Time Inspection Program alone
 
was sufficient to manage loss of material for these components.
In its letter dated April 17, 2006, the applicant revised LRA Table 3.3.2.1.18 to include the Water Chemistry Program to address loss of material due to pitting and crevice corrosion for heating
 
and process steam system copper and copper a lloy components exposed to auxiliary steam and boiler treated water.
The staff determined that the addition of the Water Chemistry Program would make these line items consistent with the GALL Report recommendations for managing loss of material due to
 
pitting and crevice corrosion and, therefore, acceptable.
The staff finds that, by using the Water Chemistry Program with the One-Time Inspection Program to manage loss of material due to pitting and crevice corrosion, the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended functions
 
will be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).
LRA Table 3.3.2.1.41 for the water treatment and distribution system includes AMR line items for loss of material in brass and bronze valve bodies exposed to treated water on the internal
 
surface. The applicant credited the Selective Leaching of Materials Program to manage loss of
 
material for these components. The staff reviewed the program and determined that it manages
 
loss of material due to selective leaching, but not loss of material due to pitting and crevice
 
corrosion. The applicant was asked to clarify how loss of material due to pitting and crevice
 
corrosion would be managed for these components.
In its response dated April 17, 2006, the applicant revised LRA Table 3.3.2.1.41 to address aging management of loss of material due to pitting and crevice corrosion of brass and bronze valve
 
bodies exposed to treated water on the internal surface by adding the following AMR line items:
3-329
* Valve Body - leakage boundary - brass - treated water (internal) - loss of material - water chemistry (B.1.2) - VII.E4-8 (AP-64) 3.3.1-38
* Valve Body - leakage boundary - brass - treated water (internal) - loss of material - one-time inspection (B.1.24) - VII.E4-8 (AP-64) 3.3.1-38
* Valve Body - leakage boundary - bronze - treated water (internal) - loss of material - water chemistry (B.1.2) - VII.E4-8 (AP-64) 3.3.1-38
* Valve Body - leakage boundary - bronze - treated water (internal) - loss of material - one-time inspection (B.1.24) - VII.E4-8 (AP-64) 3.3.1-38 The staff reviewed the applicant's response and determined that the line items to be added were consistent with the GALL Report recommendations for managing loss of material due to pitting
 
and crevice corrosion and, therefore, acceptable.
The staff finds that, by using the Water Chemistry Program with the One-Time Inspection Program to manage loss of material due to pitting and crevice corrosion, the applicant has
 
demonstrated that the effects of aging will be adequately managed so that intended functions will
 
be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.1.2  Reduction of Heat Transfer Due to Fouling
 
LRA Table 3.3.2.1.13 for the EDG and auxiliary syst em includes AMR line items for the lube oil cooler and radiator heat exchangers exposed to closed-cycle cooling water. The staff noted that
 
the aging effect for reduction of heat transfer due to fouling was not addressed. The applicant
 
was asked to clarify why this aging effect was not identified for these components.
In its letter dated April 17,2006, the applicant revised LRA Table 3.3.2.1.13 to address the aging effect for reduction of heat transfer due to fouling for the brass lube oil cooler and radiator tubes
 
exposed to a closed cooling water environment by crediting the Closed-Cycle Cooling Water System Program.
The staff reviewed the applicant's revision and determined that the addition of line items to address reduction of heat transfer due to fouling using the Closed-Cycle Cooling Water System
 
Program is consistent with the GALL Report recommendations and, therefore, acceptable.
3.3.2.1.3  Loss of Material Due to General, Pitting, and Crevice Corrosion LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the ASME Section XI, Subsection IWE, Inspection of Overhead Heavy Load and Light Load Handling System, or
 
Structures Monitoring Program to manage loss of material due to general, pitting, and crevice
 
corrosion of the external surfaces of structural and closure bolting constructed of carbon and low
 
alloy steel exposed to indoor or outdoor air. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends the Bolting Integrity Program
 
for this aging effect.
3-330The staff reviewed the applicant's ASME Section XI, Subsection IWE, Inspection of Overhead Heavy Load and Light Load Handling System, and Structures Monitoring Programs and verified
 
that these programs include activities consistent with the recommendations in GALL AMP XI.M18 to manage loss of material due to general, pitting, and crevice corrosion on the
 
external surfaces of structural and closure bolting. The staff concludes that these AMPs are
 
adequate to manage the aging effect for which they are credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the One-Time Inspection Program with the 10 CFR Part 50, Appendix J Program to manage the loss of material
 
due to general, pitting, and crevice corrosion in primary containment boundary steel piping, piping components, and piping elements exposed to indoor air internal environments. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging
 
effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M36, "External Surfaces Monitoring," for this aging effect.
The staff reviewed the applicant's 10 CFR Part 50, Appendix J, Program and verified that itincludes activities consistent with the recommendations in GALL AMP XI.M36 to manage loss of
 
material in components exposed to indoor air internal environments. In addition, the staff
 
reviewed the applicant's One-Time Inspection Program and verified it includes inspections of
 
components to detect loss of material as a means of verifying the effectiveness of the
 
10 CFR Part 50, Appendix J, Program. The staff concludes that these AMPs are adequate to
 
manage the aging effect for which they are credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Fire Protection Program to manage the loss of material due to general, pitting, and crevice corrosion for the
 
internal surfaces of steel piping, piping components, and piping elements with an indoor air
 
internal environment for halon/carbon dioxide fi re suppression systems. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were
 
consistent with the GALL Report but, a different AMP was credited. The report recommends GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting
 
Components," for this aging effect.
The staff reviewed the applicant's Fire Protection Program and verified that this AMP includesactivities consistent with the recommendations in GALL AMP XI.M38 to manage loss of material
 
in components in indoor air internal environments. The staff concludes that this AMP is adequate
 
to manage the aging effect for which it is credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Fire Water System Program to manage loss of material due to general, pitting, and crevice corrosion for the internal surfaces of steel piping, piping components, and piping elements with an indoor air
 
internal environment for water-based fire protecti on systems. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were consistent with
 
the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M38 for this aging effect.
The staff reviewed the applicant's Fire Water System Program and verified that this AMPincludes activities consistent with the recommendations in GALL AMP XI.M38 to manage loss of 3-331 material on internal surfaces of components in indoor air internal environments. The staff concludes that this AMP is adequate to manage the aging effect for which it is credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Periodic Inspection Program to manage the loss of material due to general, pitting, and crevice corrosion
 
for EDG ventilation system steel components ex posed to indoor air internal or external environments. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMPs XI.M36 or XI.M38 for this aging effect.
The staff reviewed the applicant's Periodic Inspection Program and determined that it isconsistent with the recommendations in GALL AMPs XI.M36 and XI.M38 to manage the loss of
 
material for the external or internal surfaces, respectively, of steel components exposed to an
 
indoor air external or internal environment. The staff concludes that this AMP is adequate to
 
manage the aging effect for which it is credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Periodic Inspection of Ventilation Systems Program to m anage the loss of material in ventilation system steel piping, piping components, and piping elements exposed to indoor air internal or external
 
environments. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M36 for managing this aging effect on external surfaces and GALL AMP XI.M38 for managing this aging effect on internal surfaces.
The staff reviewed the applicant's Periodic Inspection of Ventilation Systems Program anddetermined that it is consistent with the recommendations in GALL AMPs XI.M36 and XI.M38 to
 
manage the loss of material in ventilation system steel piping, piping components, and piping
 
elements exposed to an indoor air external or internal environment, respectively. The staff concludes that this AMP is adequate to manage the aging effect for which it is credited.
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Structures Monitoring Program to inspect the external surfaces of steel piping, piping components, piping
 
elements, and ductwork exposed to indoor air exte rnal or outdoor air external environments in the EDG and auxiliary system, chlorination syst em, and control room HVAC system. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging
 
effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M36 for this aging effect.
The staff reviewed the applicant's Structures Monitoring Program and verified that this AMPincludes activities consistent with the recommendations in GALL AMP XI.M36 to manage the
 
loss of material in components exposed to indoor or outdoor air external environments. The staff concludes that this AMP is adequate to manage the aging effect for which it is credited.
3.3.2.1.4  Loss of Preload Due to Stress Relaxation LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the ASME Section XI, Subsection IWE, Program or the Inspection of Overhead Heavy Load and Light Load (Related to 3-332 Refueling) Handling System Program to manage loss of preload due to stress relaxation of structural and closure bolting constructed of carbon and low alloy steel exposed to indoor air
 
environments. Generic Note E was cited for these AMR line items, indicating that the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M18, "Bolting Integrity Program," for this
 
aging effect.The staff reviewed the applicant's ASME Section XI, Subsection IWE, Program and Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling System Program and verified that these programs are consistent with the recommendations in GALL AMP XI.M18 to
 
manage loss of preload due to stress relaxation of structural and closure bolting. The staff
 
concludes that these AMPs are adequate to manage the aging effect for which they are credited.
3.3.2.1.5  Loss of Material Due to Pitting, Crevice, and Microbiologically Influenced Corrosion, and Fouling LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Fire Water System, One-Time Inspection, or Periodic Inspection Program to manage loss of material due to
 
pitting and crevice corrosion and MIC and fouling of the internal surfaces of piping and fittings
 
constructed of carbon and low alloy steel, cast iron, copper alloy, bronze and brass exposed to
 
raw water-salt water or raw water-fresh water. Generic Note E was cited for these AMR line
 
items, indicating that the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M20, "Open-Cycle Cooling Water System," for this aging effect.
The staff reviewed the applicant's Fire Water System, One-Time Inspection, and Periodic Inspection Programs and verified that they include activities consistent with the recommendations in GALL AMP XI.M20 to manage loss of material due to pitting and crevice
 
corrosion and MIC and fouling on the internal surfaces of piping and fittings. The staff concludes
 
that these AMPs are adequate to manage the aging effects for which they are credited.
3.3.2.1.6  Increased Elastomer Hardness, Shrinkage and Loss of Strength due to Weathering
 
LRA Tables 3.3.2.1.1 through 3.3.2.1.41 include AMR line items that credit the Structures Monitoring Program to manage increased elastomer hardness, shrinkage, and loss of strength
 
due to weathering for elastomer fire barrier penetration seals exposed to air-outdoor or indoor
 
uncontrolled environments. Generic Note E was cited for these AMR line items, indicating that
 
the material, environment, and aging effect were consistent with the GALL Report, but a different AMP was credited. The GALL Report recommends GALL AMP XI.M26, "Fire Protection" for this
 
aging effect.
The staff reviewed the applicant's Structures Monitoring Program and verified that it is consistentwith the recommendations in GALL AMP XI.M26 to manage increased elastomer hardness, shrinkage, and loss of strength due to weathering for elastomer fire barrier penetration seals
 
exposed to uncontrolled air. The staff concludes that this AMP is adequate to manage the aging
 
effects for which it is credited.
3-333 Conclusion. 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes that the applicant has demonstrated that the effects of aging for these components will
 
be adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report for the auxiliary systems components, and information about how it will manage the following aging effects:
* cumulative fatigue damage
* reduction of heat transfer due to fouling
* cracking due to stress corrosion cracking
* cracking due to stress corrosion cracking and cyclic loading
* hardening and loss of strength due to elastomer degradation
* reduction of neutron-absorbing capacity and loss of material due to general corrosion
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion
* loss of material due to general, pitting, crevice, microbiologically-influenced corrosion and fouling
* 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
* quality assurance for aging management of nonsafey-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL Report recommends
 
further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether
 
it adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. Details 3-334 of the staff's audit are documented in the Audit and Review Report. The staff's evaluation of the aging effects is discussed in the following sections.
3.3.2.2.1  Cumulative Fatigue Damage
 
In LRA Section 3.3.2.2.1, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staff's evaluation of this TLAA.
3.3.2.2.2  Reduction of Heat Transfer Due to Fouling
 
The staff reviewed Attachment 3, item AP-62, of the reconciliation document against the criteria in SRP-LR Section 3.3.2.2.2.
In Attachment 3, item AP-62, of its reconciliation document, the applicant addressed reduction of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated water.
SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling can occur in stainless steel heat exchanger tubes exposed to treated water. The existing program relies on
 
control of water chemistry to manage reduction of heat transfer due to fouling. However, control
 
of water chemistry may be inadequate. Therefore, the GALL Report recommends that the
 
effectiveness of the Water Chemistry Program be verified to ensure that reduction of heat
 
transfer due to fouling does not occur. A one-time inspection is an acceptable method to ensure
 
that reduction of heat transfer does not occur and that the component's intended function will be
 
maintained during the period of extended operation. , item AP-62, of the applicant's re conciliation document states that the SRP-LR line item for stainless steel heat exchanger tubes in treated water, addressing reduction of heat
 
transfer due to fouling, recommends the Water Chemistry Program with no further evaluation
 
required in the January 2005 draft SRP-LR, which was changed in the September 2005 SRP-LR
 
to recommend both the Water Chemistry and One-Time Inspection Programs with an evaluation
 
of aging effects. There are two instances of this line item in the LRA applicable to the treated
 
water side of heat exchanger components in the RBCCW system. In the LRA, there are 229 line
 
item instances of one-time inspections of stainless steel components in treated water
 
environments. These instances are applied to aging effects of loss of material or cracking and
 
provide ample inspection opportunity for the condition of the components. Observed conditions with potential impact on intended function are evaluated and corrected, as necessary, in
 
accordance with the corrective action process. As one of the functions of the Water Chemistry
 
Program is to prevent reduction of heat transfer due to fouling, a noted fouling condition on any
 
of the inspected items would be identified and entered into the corrective action process. Thus, there is high confidence that any instance of the Water Chemistry Program's failure to prevent
 
fouling would be identified during the inspections for loss of material due to corrosion and
 
cracking. In addition, for the shutdown cooling system heat exchangers addressed in this line
 
item, the treated water environment is reactor coolant. The Water Chemistry Program
 
requirements for reactor water quality provi de added assurance that an environment conducive to fouling does not exist. The applicant concluded that no change is required in the LRA due to
 
this item.
3-335 The staff reviewed the applicant's reconciliation document as well as LRA Table 3.3.2.1.29 for the RBCCW system. The staff noted that the One-Time Inspection Program is cited to manage
 
loss of material for the stainless steel heat exchanger components exposed to treated water in
 
this system; therefore, although the One-Time Inspection Program is not noted for the AMR that
 
addresses the reduction of heat transfer aging effect, it is credited as part of the aging
 
management for loss of material. On this basis, the staff determined that the applicant
 
adequately manages reduction of heat transfer due to fouling for stainless steel heat exchanger
 
components exposed to treated water in the RBCCW system and that no change is required in
 
the LRA.Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.2. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.3  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.
 
In LRA Section 3.3.2.2.3.1, the applicant addressed cracking due to SCC in the stainless steel piping, piping components, and piping elements of the BWR standby liquid control system thatare exposed to sodium pentaborate solution greater than 60 &deg;C (>140 &deg;F).
SRP-LR Section 3.3.2.2.3.1 states that cracking due to SCC can occur in BWR standby liquid control system stainless steel piping, piping components, and piping elements exposed tosodium pentaborate solution greater than 60 &deg;C (>140 &deg;F). The existing AMP relies on monitoring
 
and control of water chemistry to manage the aging effects of cracking due to SCC. However, high concentrations of impurities at crevices and locations of stagnant conditions can cause
 
SCC. Therefore, the GALL Report recommends that the effectiveness of the Water Chemistry
 
Program be verified to ensure that SCC does not occur. A one-time inspection of select
 
components at susceptible locations is an acceptable method to ensure that SCC does not occur
 
and that the component's intended function will be maintained during the period of extended
 
operation.
LRA Section 3.3.2.2.3.1 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage SCC of stainless steel components exposed to a sodium pentaborate environment in the standby liquid control system (liquid poison system).
The management of SCC of standby liquid control system components exposed to sodium pentaborat e relies on monitoring and control of liquid poison tank makeup water chemistry. The makeup water is monitored in lieu of the sodium
 
pentaborate solution because the sodium pentaborate would mask most of the chemistry
 
parameters monitored by the Water Chemistr y Program. The effectiveness of this approach is verified by a one-time inspection of susceptible locations. Observed conditions with potential
 
impact on intended function are evaluated or corrected in accordance with the corrective action
 
process.
3-336 The staff reviewed the applicant's Water Chemistry Program and verified that this AMP includes activities that will mitigate cracking due to SCC. In addition, the staff reviewed the applicant's
 
One-Time Inspection Program and verified that it includes inspections of the standby liquid
 
control system to detect cracking due to SCC as a means of verifying the effectiveness of the Water Chemistry Program. The staff finds acceptable the applicant's approach to manage SCC
 
of standby liquid control system components ex posed to sodium pentaborate by monitoring and controlling liquid poison tank makeup water chemistry because the sodium pentaborate would
 
mask most of the chemistry parameters monito red by the Water Chemistry Program. The staff determined that these AMPs will adequately manage cracking due to SCC for stainless steel
 
piping, piping components, and piping elements in the BWR standby liquid control system. The
 
staff concludes that, that applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.3.1 for
 
further evaluation.
In LRA Section 3.3.2.2.3.2, the applicant addressed cracking due to SCC in stainless steel andstainless clad steel heat exchanger components exposed to treated water greater than 60 &deg;C
 
(>140 &deg;F).
SRP-LR Section 3.3.2.2.3.2 states that cracking due to SCC can occur in stainless steel andstainless clad steel heat exchanger components exposed to treated water greater than 60 &deg;C
(>140 &deg;F). The GALL Report recommends further evaluation of a plant-specific AMP to ensure
 
adequate management of these aging effects.
LRA Section 3.3.2.2.3.2 states that stainless steel components in closed cooling water systemsare exposed to a closed cycle cooling water environment <140 &deg;F and are not susceptible to
 
cracking due to SCC. The reactor water cleanup (RWCU) system non-regenerative heat
 
exchanger shell side components are carbon steel and are not susceptible to cracking due to
 
SCC. RWCU system regenerative heat exchanger stainless steel tube and shell side
 
components, and non-regenerative heat exchanger stainless steel tube side components areexposed to treated water environments >140 &deg;F and are susceptible to cracking due to SCC.
 
OCGS will implement a One-Time Inspection Progr am for susceptible locations to verify the effectiveness of the Water Chemistry Program to manage SCC of stainless steel RWCU heat
 
exchanger components exposed to treated water environments >140 &deg;F. Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the
 
corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that this AMP includes activities that will mitigate cracking due to SCC. In addition, the staff reviewed the applicant's
 
One-Time Inspection Program and verified that it includes inspections of the RWCU system
 
regenerative heat exchanger stainless steel tube and shell side components, and
 
non-regenerative heat exchanger stainless steel tube side components to detect cracking due to
 
SCC as a means of verifying the effectivene ss of the Water Chemistry Program. The staff determined that these AMPs will adequately manage the aging effect for which they are credited.
 
Based on the programs identified above, the staff concludes that the applicant has met the
 
criteria of SRP-LR Section 3.3.2.2.3.2 for further evaluation.
In LRA Section 3.3.2.2.3.2, the applicant addressed cracking due to SCC in stainless steel diesel engine exhaust piping, piping components, and pi ping elements exposed to diesel exhaust.
3-337 SRP-LR Section 3.3.2.2.3.3 states that cracking due to SCC can occur in stainless steel diesel engine exhaust piping, piping components, and pi ping elements exposed to diesel exhaust. The GALL Report recommends further evaluation of any plant-specific AMP to ensure adequate
 
management of these aging effects.
LRA Section 3.3.2.2.3.2 states that LRA Table 3.3.1, item number 3.3.1-5, for stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust gases is not used. EDG components exposed to diesel exhaust gases are carbon steel not
 
susceptible to cracking due to SCC.
The staff reviewed LRA Table 3.3.2.2.1.13, which addresses aging management of the EDG and auxiliary system, and confirmed that the diesel engine exhaust piping is identified as constructed of carbon and low alloy steel, not stainless steel. Therefore, the staff finds acceptable the
 
applicant's conclusion that this further evaluation is not applicable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.3. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.4  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.
 
LRA Section 3.3.2.2.4.2 states that cracking due to SCC and cyclic loading of stainless steel heat exchanger components exposed to treated borated water, with reference to the further
 
evaluation in SRP-LR Section 3.3.2.2.4.1, is applicable to PWRs only. The The staff finds
 
acceptable the applicant's evaluation that this aging effect is not applicable to OCGS because it
 
is a BWR plant.
In LRA Section 3.3.2.2.4.3, the applicant stated that cracking due to SCC and cyclic loading of stainless steel regenerative heat exchanger co mponents exposed to treated borated water, with reference to the further evaluation in SRP-LR Section 3.3.2.2.4.2, is applicable to PWRs only.
 
The The staff finds acceptable the applicant's evaluation that this aging effect is not applicable to
 
OCGS because it is a BWR plant.
The staff noted that the applicant did not address cracking due to SCC or cyclic loading for PWR high pressure pumps in the chemical and volume control system, with reference to the further
 
evaluation in SRP-LR Section 3.4.2.2.3, for the OCGS plant. The concludes that this further
 
evaluation is not applicable to OCGS because it is a BWR plant.
In LRA Section 3.3.2.2.4.1, the applicant addressed cracking due to SCC and cyclic loading for high-strength steel closure bolting in auxiliary systems exposed to air with steam or water leakage.
1 The staff noted that Section 3.3.2.2.4.4 had been omitted unintentionally from the SRP-LR (NUREG-1800, Revision 1,September 2005); however, this section is cited in the SRP-LR summary tables (e.g., Table 3.3-1, Item 10).
3-338 SRP-LR Section 3.3.2.2.4.4 1 states that cracking due to SCC and cyclic loading can occur for high-strength steel closure bolting in auxiliary systems exposed to air with steam or water leakage. The GALL Report recommends the Bolting Integrity Program to manage this aging
 
effect and that this AMP be augmented by appropriate inspection to detect cracking if the bolts
 
are not otherwise replaced during maintenance.
LRA Section 3.3.2.2.4.1 states that the only auxiliary system that contains high-strength steel closure bolting exposed to air with steam or water leakage is the CRD. The Bolting Integrity
 
Program addresses aging management requirements for this ASME Code Class 1 high-strength steel closure bolting. Bolting integrity management follows published EPRI guidelines and other
 
industry recommendations for material selection and testing, ISI, and plant surveillance and
 
maintenance practices. The extent and schedule of the inspections for the Class 1 high-strength steel closure bolting in the CRD system is in accordance with ASME Code Section XI and
 
assures that detection of leakage or fastener degradation will occur prior to loss of system or
 
component intended function. Observed conditions with potential impact on intended function are
 
evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Bolting Integrity Program and verified that this AMP includes activities that will manage cracking of high-strength steel closure bolting due to SCC and cyclic loading. This program includes ISI of high-strength bolting as part of the ASME Code Section XI
 
ISI requirements; therefore, the requirements for augmented inspection are met. The staff
 
determined that this AMP will adequately manage cracking of high-strength steel closure bolting
 
due to SCC and cyclic loading in the CRD system. The staff concludes that the applicant's
 
program meets the criteria of SRP-LR Section 3.3.2.2.4.4 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.4. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.5  Hardening and Loss of Strength Due to Elastomer Degradation
 
The staff reviewed LRA Section 3.3.2.2.5 against the criteria in SRP-LR Section 3.3.2.2.5.
 
In LRA Section 3.3.2.2.5.1, the applicant addressed hardening and loss of strength due to elastomer degradation in elastomer seals and components of heating and ventilation systems
 
exposed to air - indoor uncontrolled (internal/external) environments.
SRP-LR Section 3.3.2.2.5.1 states that hardening and loss of strength due to elastomer degradation can occur in elastomer seals and components of heating and ventilation systems
 
exposed to air - indoor uncontrolled (internal/external) environments. The GALL Report 3-339 recommends further evaluation of a plant-specific AMP to ensure adequate management of these aging effects.
LRA Section 3.3.2.2.5.1 states that a Periodic Inspection of Ventilation Systems Program will be implemented for the internal and external inspection of elastomer components exposed to indoor
 
air internal or external environments in the "C" battery room heating and ventilation system, 480V switchgear room ventilation system, battery and MG set room ventilation system, control room HVAC system, radwaste area heating and ventila tion system, and reactor building ventilation system. Periodic inspections of elastomer door seals and flexible connections identify detrimental changes in material properties, as evidenced by cracking, perforations in the material, or
 
leakage. Observed conditions with potential impact on intended function will be evaluated or
 
corrected in accordance with the corrective action process.
The staff reviewed the applicant's Periodic Inspection of Ventilation Systems Program and determined that it is adequate to inspect the internal and external environments of elastomer
 
components exposed to indoor air inte rnal or external environments.
LRA Section 3.3.2.2.5.1 also states that a St ructures Monitoring Program will be implemented for the external inspections of expansion joint and flexible connection elastomers exposed to indoor
 
air external environments in the circulating wa ter system, heating and process steam system, fire protection system, process sampling syst em, condensate system, and condensate transfer system. OCGS utilizes the Structures Monitoring Program to inspect the external surfaces of piping, piping components, and piping elements when no AMPs specifically inspect the
 
component in question. The Structures Monitoring Program relies on periodic visual inspections
 
by qualified individuals to identify and evaluate the degradation of elastomer components to
 
ensure that there is no loss of intended function. Observed conditions with potential impact on
 
intended function will be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Structures Monitoring Program and verified that this AMP includes external inspections of expansion joint and flexible connection elastomers exposed to
 
indoor air external environments. The staff c oncludes that these AMPs will adequately manage hardening and loss of strength of elastomer seals and components due to elastomer degradation
 
in elastomer components in auxiliary systems in the circulating water system, heating and process steam system, fire protection system , process sampling system, condensate system, and condensate transfer system. The staff finds that the applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.5.1 for further evaluation.
In LRA Section 3.3.2.2.5.2, the applicant addressed 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.
SRP-LR Section 3.3.2.2.5.2 states that hardening and loss of strength due to elastomer degradation can occur in elastomer linings of the filters, valves, and ion exchangers in spent fuel
 
pool cooling and cleanup systems exposed to treated water. The GALL Report recommends
 
evaluation of a plant-specific AMP to determine and assess the qualified life of the linings in the
 
environment to ensure adequate management of these aging effects.
3-340 LRA Section 3.3.2.2.5.2 states that a Periodic Inspection Program will be implemented for the internal inspection of expansion joint and flexible connection elastomers exposed to treated
 
water internal environments in the condensate system, condensate transfer system, heating and process steam system, and process sampling system. The Periodic Inspection Program to periodically used to monitor component aging effects when the component is not covered by
 
other existing periodic monitoring programs. The Periodic Inspection Program relies on periodic inspections to identify and evaluate the internal degradation of elastomer components exposed
 
to treated water internal environments to ensure that there is no loss of intended function.
 
Observed conditions with potential impact on intended function will be evaluated or corrected in
 
accordance with the corrective action process.
The staff reviewed the applicant's Periodic Inspection Program and determined that it is adequate to manage hardening and loss of strength of elastomer linings of the filters, valves, and
 
ion exchangers in spent fuel pool cooling and cleanup systems due to elastomer degradation.
 
The staff finds that the applicant's program meets the criteria of SRP-LR Section 3.3.2.2.5.2 for
 
further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.5. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.6  Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General Corrosion The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.6.
 
In LRA Section 3.3.2.2.14, the applicant addressed reduction of neutron-absorbing capacity and loss of material due to general corrosion in the neutron absorbing sheets of the spent fuel
 
storage racks.
SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of material due to general corrosion can occur in the neutron-absorbing sheets of BWR spent fuel
 
storage racks exposed to treated water. The GALL Report recommends further evaluation of a
 
plant-specific AMP to ensure adequate management of these aging effects.
LRA Section 3.3.2.2.14 states that the aging effects of the Boral spent fuel storage racks exposed to treated water environments are in significant and require no aging management. The potential aging effects resulting from sustained irradiation of Boral were previously evaluated by
 
the staff (BNL-NUREG-25582, dated January 1979; NUREG-1787, "Safety Evaluation Report
 
Related to the License Renewal of Virgil C. Summer Nuclear Station," Section 3.5.2.4.2) and
 
determined to be insignificant. In the year 2000, four spent fuel storage racks manufactured by
 
HOLTEC International that utilized Boral neutron absorbing material were installed at OCGS.
 
The Boral coupons kept inside the spent fuel storage pool were removed and inspected in 2002
 
and again in 2004. Inspection results showed no blisters, pits, dimensional changes, or other 3-341 age-related degradations. Neutron transmission tests on the irradiated coupon showed that the average Boron-10 areal density in the irradiated coupon is 0.0209 g/cm 2 , meaning that, within the experimental accuracy, no Boron-10 has been lost from the coupons. Plant operating experience is therefore consistent with the staff's previous conclusion and, therefore, no AMP is required.
The staff reviewed HOLTEC International Report No. HI-2043279, "Summary Report of the Examination of Oyster Creek Nuclear Stat ion Boral Surveillance Coupon No. HO910070-2-6," October 19, 2004, which concludes that the coupon tested showed no blisters, pits, or other
 
degradation. Neutron transmission tests on the irradiated coupon showed the average Boron-10
 
areal density is 0.0209 g/cm 2 , meaning that Boron-10 has not been lost from the coupon. In addition, the staff reviewed Holtec International Report No. HI-2033000, Revision 1, "Examination of Oyster Creek Nuclear Station Boral Surveillance Coupon No. HO920023-2-6,"
April 8, 2003, which concludes that the coupon tested showed no blisters, pits, or other
 
degradation. Neutron transmission tests on the irradiated coupon showed an average Boron-10
 
areal density of 0.0194 g/cm 2 , meaning that Boron-10 has not been lost from the coupon. Based on these reports, the staff determined that the results of the Boral coupon tests support the
 
applicant's conclusion that the aging effects of the Boral spent fuel storage racks exposed to
 
treated water environments are insignificant and require no aging management.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.6. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.7  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.
 
In LRA Sections 3.3.2.2.7.1 and 3.3.2.2.7.3, the applicant addressed loss of material due to general, pitting, and crevice corrosion in steel piping, piping components, and piping elements, including the tubing, valves, and tanks in the r eactor coolant pump oil collection system exposed to lubricating oil (as part of the fire protection system).
SRP-LR Section 3.3.2.2.7.1 states that loss of material due to general, pitting, and crevice corrosion can occur in steel piping, piping components, and piping elements, including the
 
tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed to lubricating oil (as part of the fire protection system). The existing AMP relies on the periodic sampling and
 
analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving
 
an environment not conducive to corrosion. However, control of lube oil contaminants may not
 
always be adequate to prevent corrosion; therefore, the effectiveness of lubricating oil control
 
should be verified to ensure that corrosion does not occur. The GALL Report recommends
 
further evaluation of programs to manage corrosion to verify the effectiveness of the Lubricating Oil Monitoring Activities Program. 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.
3-342 In addition, the SRP-LR states that corrosion can occur at locations in the reactor coolant pump oil collection tank where water from wash downs may accumulate. Therefore, the effectiveness
 
of the program should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage loss of material due to general, pitting, and crevice corrosion, to include the thickness of the lower portion of the tank. A one-time
 
inspection is an acceptable method to ensure that corrosion does not occur and that the
 
component's intended function will be maintained during the period of extended operation.
LRA Section 3.3.2.2.7.1 states that item numbers 3.3.1-13 and 3.3.1-14 are not applicable.
Part 50, Appendix R Section III.O of 10 CFR does not apply because the containment is inert
 
during normal operation.
The staff recognized that the containment is inert during normal operation, effectively eliminating the possibility of a fire. Therefore, the requirements of 10 CFR Part 50, Appendix R, Section III.O
 
for a reactor coolant pump oil collection system do not apply. The staff finds acceptable the
 
applicant's conclusion that this aging effect is not applicable.
LRA Section 3.3.2.2.7.3 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectiveness of the Lubricating Oil Monitoring Activities
 
Program to manage the loss of material in steel piping, piping components, and piping elements
 
exposed to lubricating oil internal or exter nal environments in the EDG and auxiliary system, reactor recirculation system, RWCU system, RBCCW system, CRD system, fire protection system, miscellaneous floor and equipment drai n system, and service water system. The Lubricating Oil Monitoring Activities Program manages physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear mechanisms, contamination, and oil degradation that could affect intended functions. Observed conditions with
 
potential impact on intended function will be evaluated or corrected in accordance with the
 
corrective action process.
The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it is adequate to manage the loss of material in steel piping, piping components, and piping
 
elements exposed to lubricating oil internal or external environments. The staff finds that the applicant has met the criteria of SRP-LR Section 3.3.2.2.7.1 for further evaluation.
In LRA Section 3.3.2.2.7.2, the applicant addressed loss of material due to general, pitting, and crevice corrosion in steel piping, piping components, and piping elements in the BWR RWCU
 
and shutdown cooling systems exposed to treated water.
SRP-LR Section 3.3.2.2.7.2 states that loss of material due to general, pitting, and crevice corrosion can occur in steel piping, piping components, and piping elements in the BWR RWCU
 
and shutdown cooling systems exposed to treated water. The existing AMP relies on monitoring and control of reactor water chemistry to manage the aging effects of loss of material from
 
general, pitting, and crevice corrosion. However, high concentrations of impurities at crevices
 
and locations of stagnant flow conditions could cause general, pitting, or crevice corrosion.
 
Therefore, the effectiveness of the Water Chemistry Program should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs to
 
manage loss of material from general, pitting, and cr evice corrosion to verify the effectiveness of 3-343 the Water Chemistry Program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion does not occur and that the
 
component's intended function will be maintained during the period of extended operation.
LRA Section 3.3.2.2.7.2 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in steel and aluminum pipi ng, piping components, and piping elements exposed to treated water environments in the CRD syst em, post-accident sampling system, process sampling system, reactor head cooling system, reactor recirculation system, RWCU system, shutdown cooling system, spent fuel pool cooli ng system, standby liquid control system (liquid poison system), water treatment and distributi on system, and in aluminum fuel pool gates and fuel storage and handling equipment and structures in the fuel storage and handling equipment
 
system exposed to treated water environments.
Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process.
 
With steel ASME Code Class MC components and steel ASME Classes 2 and 3 piping and components in treated water environments, the applicant will use the ASME Section XI, Subsection IWF, Program to verify the effectiv eness of the Water Chemistry Program to mitigate loss of material. Observed conditions with potential impact on intended function will be evaluated
 
or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it includes activities that will mitigate loss of material due to general, pitting, and crevice corrosion. In addition, the staff reviewed the applicant's One-Time Inspection and ASME Section XI, Subsection IWF, Programs and verified that they include inspections to detect loss of material due to general, pitting, and crevice corrosion as a means of veri fying the effectiveness of the Water Chemistry Program. The staff concludes that these AMPs will adequately manage loss of material due to
 
general, pitting, and crevice corrosion for steel piping, piping components, and piping elements
 
exposed to treated water. The staff finds that the applicant's programs meet the criteria of
 
SRP-LR Section 3.3.2.2.7.2 for further evaluation.
In LRA Section 3.3.2.2.7.3, the applicant addressed loss of material of steel and stainless steel diesel exhaust piping, piping components, and piping elements due to general (steel only) pitting
 
and crevice corrosion.
SRP-LR Section 3.3.2.2.7.3 states that loss of material due to general (steel only) pitting and crevice corrosion can occur for steel and stainless steel diesel exhaust piping, piping
 
components, and piping elements exposed to diesel exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to ensure adequate management of these aging
 
effects.LRA Section 3.3.2.2.7.3 states that a Periodic Inspection Program will be implemented to manage the loss of material in steel EDG exhaust piping, piping components, and piping
 
elements exposed to a diesel exhaust environm ent. The Periodic Inspection Program includes periodic condition monitoring examinations to assure that existing environmental conditions cause no material degradation that could result in the loss of system intended functions.
 
Observed conditions with potential impact on intended function will be evaluated or corrected in
 
accordance with the corrective action process.
3-344 The staff reviewed the applicant's Periodic Inspection Program and determined that it is adequate to manage the loss of material in steel piping, piping components, and piping elements
 
exposed to lubricating oil internal or external environments. The staff finds that the applicant's program meets the criteria of SRP-LR Section 3.3.2.2.7.3 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.7. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.8  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion (MIC)
The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.
 
LRA Section 3.3.2.2.8.1 addresses loss of material due to general, pitting, and crevice corrosion and MIC for steel (with or without coating or wrapping) piping, piping components, and piping
 
elements buried in soil.
SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice corrosion and MIC can occur for steel (with or without coating or wrapping) piping, piping
 
components, and piping elements buried in soil. The Buried Piping Inspection Program relies on
 
industry practice, frequency of pipe excavation, and operating experience to manage the effects
 
of loss of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the
 
Buried Piping 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.
LRA Section 3.3.2.2.8.1 states that a Buried Piping Inspection Program will be implemented to manage the loss of material in steel piping, piping components, and piping elements exposed to
 
soil in the SW system, ESW system, fire prot ection system, drywell floor and equipment drain system, miscellaneous floor and equipment drain system, spent fuel pool cooling system, RBCCW system, and roof drains and overboard discharge system. The Buried Piping Inspection Program includes preventive measures to mi tigate corrosion and periodic inspection to manage the effects of corrosion on the pressure-retaining capacity of buried steel piping, piping
 
components, and piping elements. Observed conditions with potential impact on intended
 
function will be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Buried Piping Inspection Program and verified that it includes inspections to detect loss of material of steel piping, piping components, and piping elements
 
due to general, pitting, and crevice corrosion and MIC. The staff determined that, for each of the
 
material and environment combinations for which the Buried Piping Inspection Program will be
 
credited, at least one inspection (opportunistic or focused) has been or will be performed prior to
 
the period of extended operation in addition to a focused inspection within the first 10-year period
 
of the period of extended operation for objective evidence that the component coatings were in 3-345 acceptable condition and that no significant aging was present for these buried components. The staff concludes that the Buried Piping Inspection Program will adequately manage loss of
 
material in steel piping, piping components, and piping elements exposed to soil.
The LRA further states that an Aboveground Outdoor Tanks Program will be implemented to manage the loss of material from the bottom of outdoor steel tanks supported by earthen
 
foundations in the fire protection system. The Aboveground Outdoor Tanks Program provides for periodic internal UT inspections on the bottom of aboveground outdoor steel tanks supported by
 
earthen foundations. Observed conditions with potential impact on intended function will be
 
evaluated or corrected in accordance with the corrective action process. OCGS has no buried
 
tanks within the scope of license renewal.
The staff reviewed the applicant's Aboveground Outdoor Tanks Program and verified that this AMP includes inspections to manage the loss of material from the bottom of outdoor steel tanks
 
supported by earthen foundations in the fire protection system. The staff concludes that this AMP
 
will adequately manage loss of material from the bottom of outdoor steel tanks supported by
 
earthen foundations.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.8. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.9  Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced Corrosion and Fouling The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9.
 
In LRA Section 3.3.2.2.9.1, the applicant addressed loss of material due to general, pitting, and crevice corrosion, MIC, and fouling for steel piping, piping components, piping elements, and
 
tanks exposed to fuel oil.
SRP-LR Section 3.3.2.2.9.1 states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling can occur for steel piping, piping components, piping elements, and
 
tanks exposed to fuel oil. The existing AMP relie s on the Fuel Oil Chemistry Program to monitor and control fuel oil contamination to manage loss of material due to corrosion or fouling.
 
Corrosion or fouling may occur at locations where contaminants accumulate. The effectiveness
 
of the fuel oil chemistry control should be verified to ensure that corrosion does not occur. The
 
GALL Report recommends further evaluation of programs to manage loss of material due to
 
general, pitting, and crevice corrosion, MIC, and fouling to verify the effectiveness of the Fuel Oil
 
Chemistry Program. 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.
3-346 LRA Section 3.3.2.2.9.1 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Fuel Oil Chemistry Program to manage the loss of material in steel piping, piping components, and piping elements exposed to a fuel oil
 
internal environment in the EDG and auxiliary syst em, main fuel oil storage and transfer system, and fire protection system. Verification of the Fuel Oil Chemistry Program to manage the loss of material in steel fuel oil tanks is through the Fuel Oil Chemistry Program tank inspection, which
 
requires that fuel oil tanks be periodically drained, cleaned, and internally inspected to ensure
 
that corrosion does not occur and that there is no loss of intended function. Observed conditions
 
with potential impact on intended function will be evaluated or corrected in accordance with the
 
corrective action process.
The staff reviewed the applicant's Fuel Oil Chemistry Program and verified that it includes activities that will mitigate loss of material due to general, pitting, and crevice corrosion, MIC, and
 
fouling. In addition, the staff reviewed the applicant's One-Time Inspection Program and verified
 
that it includes inspections to detect loss of material due to general, pitting, and crevice
 
corrosion, MIC, and fouling as a means of verify ing the effectiveness of the Fuel Oil Chemistry Program. The staff concludes that these AMPs will adequately manage loss of material due to
 
general, pitting, and crevice corrosion, MIC, and fouling for steel piping, piping components, piping elements, and tanks exposed to fuel oil. The staff finds that the applicant's programs meet
 
the criteria of SRP-LR Section 3.3.2.2.9.1 for further evaluation.
In LRA Section 3.3.2.2.9.2, the applicant addressed loss of material due to general, pitting, and crevice corrosion, MIC, and fouling for steel heat exchanger components exposed to lubricating
 
oil.SRP-LR Section 3.3.2.2.9.2 states that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling can occur for steel heat exchanger components exposed to
 
lubricating oil. The existing AMP relies on the periodic sampling and analysis of lubricating oil to
 
maintain contaminants within acceptable lim its, preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be adequate to prevent
 
corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs to
 
manage corrosion to verify the effectiveness of the lube oil program. A one-time inspection of
 
selected components at susceptible locations is an acceptable method to ensure that corrosion
 
does not occur and that the component's intended function will be maintained during the period
 
of extended operation.
LRA Section 3.3.2.2.9.2 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectiveness of the Lubricating Oil Monitoring Activities
 
Program to manage the loss of material in steel heat exchanger shell side components exposed to lubricating oil in the EDG and auxiliary sy stem, RWCU system, and reactor recirculation system. The Lubricating Oil Monitoring Activi ties Program manages physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear
 
mechanisms, contamination, and oil degradation that could affect intended functions. Observed
 
conditions with potential impact on intended function will be evaluated or corrected in accordance
 
with the corrective action process.
3-347 The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it is adequate to manage the loss of material in steel heat exchanger shell side components
 
exposed to lubricating oil. The staff finds that the applicant's programs meet the criteria of
 
SRP-LR Section 3.3.2.2.9.2 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.9. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.10  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.
 
In the LRA Section 3.3.2.2.10.1, the applicant addressed loss of material due to pitting and crevice corrosion in BWR steel piping with elastomer lining or stainless steel cladding exposed to
 
treated water.
SRP-LR Section 3.3.2.2.10.1 states that loss of material due to pitting and crevice corrosion can occur in BWR steel piping with elastomer lining or stainless steel cladding exposed to treated
 
water if the cladding or lining is degraded. The existing AMP relies on monitoring and control of
 
reactor water chemistry to manage the aging effects of loss of material from pitting and crevice
 
corrosion. However, high concentrations of impurities at crevices and locations of stagnant flow
 
conditions could cause pitting or crevice corrosion. Therefore, the effectiveness of the Water
 
Chemistry Program should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of the Water Chemistry Program. A one-time inspection of
 
select components at susceptible locations is an acceptable method to ensure that corrosion
 
does not occur and that the component's intended function will be maintained during the period
 
of extended operation.
LRA Section 3.3.2.2.10.1 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in stainless steel or elastomer lined steel piping, piping components, piping
 
elements, and heat exchanger tube side component s exposed to treated water environments in the CRD system, post-accident sampling system , process sampling system, RBCCW system, RWCU system, shutdown cooling system, spent f uel pool cooling system, standby liquid control system (liquid poison system), water treatm ent and distribution system, reactor head cooling system, and in the primary containment. Obse rved conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process. The
 
applicant will implement a One-Time Inspection Progr am for susceptible locations to verify the effectiveness of the Water Chemistry Program to manage the loss of material in stainless steel
 
fuel storage and handling equipment and structures exposed to treated water environments in
 
the fuel storage and handling equipment system and to manage the loss of material in the
 
stainless steel fuel pool skimmer surge tank liner exposed to treated water environments in the 3-348 reactor building structure. Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process. For stainless steel
 
ASME Class MC components and to stainless steel ASME Classes 2 and 3 piping and components in treated water environments, the applicant will use the ASME Section XI, Subsection IWF, Program to verify the effectiv eness of the Water Chemistry Program to mitigate loss of material. Observed conditions with potential impact on intended function will be evaluated
 
or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it includes activities that will manage loss of material due to pitting and crevice corrosion. In addition, the staff reviewed the applicant's One-Time Inspection and ASME Section XI, Subsection IWF, Programs
 
and verified that these AMPs include inspections to detect loss of material due to pitting and
 
crevice corrosion as a means of verifying the effectiveness of the Water Chemistry Program. The staff concludes that these AMPs will adequately manage loss of material due to pitting and
 
crevice corrosion in BWR steel piping with elastomer lining or stainless steel cladding exposed to
 
treated water. The staff finds that the applicant's programs meet the criteria of SRP-LR
 
Section 3.3.2.2.10.1 for further evaluation.
In LRA Sections 3.3.2.2.10.1 and 3.3.2.2.7.2, the applicant addressed loss of material due to pitting and crevice corrosion of 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.
SRP-LR Section 3.3.2.2.10.2 states that loss of material due to pitting and crevice corrosion can 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 existing AMP relies on monitoring and control of reactor water chemistry to
 
manage the aging effects of loss of material from pitting and crevice corrosion. However, high
 
concentrations of impurities at crevices and locations of stagnant flow conditions could cause
 
pitting or crevice corrosion. Therefore, the effe ctiveness of the Water Chemistry Program should be verified to ensure that corrosion does not occur. The GALL Report recommends further
 
evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of the Water Chemistry Program. A one-time inspection of select components at
 
susceptible locations is an acceptable method to ensure that corrosion does not occur and that
 
the component's intended function will be maintained during the period of extended operation.
LRA Section 3.3.2.2.10.1 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in stainless steel or elastomer lined steel piping, piping components, piping
 
elements, and heat exchanger tube side component s exposed to treated water environments in the CRD system, post-accident sampling system , process sampling system, RBCCW system, RWCU system, shutdown cooling system, spent f uel pool cooling system, standby liquid control system (liquid poison system), water treatm ent and distribution system, reactor head cooling system, and in the primary containment. Obse rved conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process. The
 
applicant will implement a One-Time Inspection Progr am for susceptible locations to verify the effectiveness of the Water Chemistry Program to manage the loss of material in stainless steel 3-349 fuel storage and handling equipment and structures exposed to treated water environments in the fuel storage and handling equipment system and to manage the loss of material in the
 
stainless steel fuel pool skimmer surge tank liner exposed to treated water environments in the
 
reactor building structure. Observed conditions with potential impact on intended function will be
 
evaluated or corrected in accordance with the corrective action process. When applied to
 
stainless steel ASME Code Class MC components in treated water environments and to
 
stainless steel ASME Code Classes 2 and 3 piping and components in treated water environments, the ASME Section XI, Subsection IWF, Program will be used to verify the effectiveness of the Water Chemistry Program to mitigate loss of material. Observed conditions
 
with potential impact on intended function will be evaluated or corrected in accordance with the
 
corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it includes activities that will manage loss of material due to pitting and crevice corrosion. In addition, the staff reviewed the applicant's One-Time Inspection and ASME Section XI, Subsection IWF, Programs
 
and verified that these AMPs include inspections to detect loss of material due to pitting and
 
crevice corrosion as a means of verifying the effectiveness of the Water Chemistry Program. The staff concludes that these AMPs will adequately manage loss of material due to pitting and
 
crevice corrosion for the fuel storage and handling equipment system, for the stainless steel fuel
 
pool skimmer surge tank liner, and for the stainless steel ASME Code Class MC and Classes 2
 
and 3 piping and components exposed to treated water environments.
LRA Section 3.3.2.2.7.2 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in steel and aluminum pipi ng, piping components, and piping elements exposed to treated water environments in the CRD syst em, post-accident sampling system, process sampling system, reactor head cooling system, reactor recirculation system, RWCU system, shutdown cooling system, spent fuel pool cooli ng system, standby liquid control system (liquid poison system), water treatment and distributi on system, and in aluminum fuel pool gates and fuel storage and handling equipment and structures in the fuel storage and handling equipment
 
system exposed to treated water environments.
Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process.
 
When applied to steel ASME Code Class MC components in treated water environments and to
 
steel ASME Code Classes 2 and 3 piping and components in treated water environments, the ASME Section XI, Subsection IWF, Program will be used to verify the effectiveness of the Water
 
Chemistry Program to mitigate loss of material. Observed conditions with potential impact on
 
intended function will be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that this AMP includes activities that will mitigate loss of material due to general, pitting, and crevice corrosion. In addition, the staff reviewed the applicant's One-Time Inspection and ASME Section XI, Subsection IWF, Programs and verified that they include inspections to detect loss of material
 
due to general, pitting, and crevice corrosion as a means of verifying the effectiveness of the
 
Water Chemistry Program. The staff concludes that these AMPs will adequately manage loss of
 
material due to general, pitting, and crevice corrosion for steel piping, piping components, and
 
piping elements exposed to treated water. The staff finds that the applicant's programs meet the
 
criteria of SRP-LR Section 3.3.2.2.10.2 for further evaluation.
3-350 In LRA Section 3.3.2.2.10.2, the applicant addressed loss of material due to pitting and crevice corrosion for copper alloy HVAC piping, piping components, and piping elements exposed to
 
condensation (external).
SRP-LR Section 3.3.2.2.10.3 states that loss of material due to pitting and crevice corrosion can occur for copper alloy HVAC piping, piping components, and piping elements exposed to
 
condensation (external). The GALL Report recommends further evaluation of a plant-specific
 
AMP to ensure adequate management of these aging effects.
LRA Section 3.3.2.2.10.2 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in stainless steel and copper alloy piping, piping components, and piping
 
elements exposed to a treated water internal or external environment in the heating and process steam system, RWCU system, noble metals monitoring system, and CRD system. Observed conditions with potential impact on intended function will be evaluated or corrected in accordance
 
with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that this AMP includes activities that will manage loss of material due to pitting and crevice corrosion. In addition, the
 
staff reviewed the applicant's One-Time Inspection Program, and verified that this AMP includes
 
inspections to detect loss of material due to pitting and crevice corrosion as a means of verifying
 
the effectiveness of the Water Chemistry Progr am. The staff concludes that these AMPs will adequately manage loss of material due to pitting and crevice corrosion for copper alloy HVAC
 
piping, piping components, and piping elements exposed to condensation (external). The staff
 
finds that the applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.10.3 for further
 
evaluation.
In LRA Section 3.3.2.2.11, the applicant addressed loss of material due to pitting and crevice corrosion can occur for copper alloy piping, piping components, and piping elements exposed to
 
lubricating oil.
SRP-LR Section 3.3.2.2.10.4 states that loss of material due to pitting and crevice corrosion can occur for copper alloy piping, piping components, and piping elements exposed to lubricating oil.
 
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. However, control of lube oil contaminants may not always be adequate to prevent
 
corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs to
 
manage corrosion to verify the effectiveness of t he Lubricating Oil Monitoring Activities Program.
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.
LRA Section 3.3.2.2.11 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectiveness of the Lubricating Oil Monitoring Activities
 
Program to manage the loss of material in copper alloy piping, piping components, piping 3-351 elements, and heat exchangers exposed to a lubric ating oil environment in the SW system, RWCU system, EDG and auxiliary system, and fi re protection system. The Lubricating Oil Monitoring Activities Program manages physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear mechanisms, contamination, and oil
 
degradation that could affect intended functions. Observed conditions with potential impact on
 
intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it is adequate to manage the loss of material in copper alloy piping, piping components, piping elements, and heat exchangers exposed to a lubricating oil environment. The staff finds that the applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.10.4 for further
 
evaluation.
LRA Section 3.3.2.2.10.2 addresses 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.
SRP-LR Section 3.3.2.2.10.5 states that loss of material due to pitting and crevice corrosion can occur in HVAC aluminum piping, piping co mponents, and piping elements, and stainless steel ducting and components exposed to condensation. The GALL Report recommends further
 
evaluation of a plant-specific AMP to ensure adequate management of these aging effects.
LRA Section 3.3.2.2.10.2 states that a One-Time Inspection Program will be implemented to manage the loss of material in stainless steel piping, piping components, and piping elements
 
exposed to a condensation internal environment in the hydrogen and oxygen monitoring system, and nitrogen supply system. Observed conditions with potential impact on intended function will
 
be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's One-Time Inspection Program and determined that it is adequate to manage loss of material of stainless steel components exposed to condensation.
 
The staff concludes that the applicant had appropriately addressed loss of material in stainless
 
steel piping, piping components, and piping elements exposed to a condensation internal
 
environment in the hydrogen and oxygen monitori ng system and the nitrogen supply system. The staff finds that the applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.10.5 for
 
further evaluation.
The staff noted that the applicant did not credit the GALL Report AMR for loss of material due to pitting and crevice corrosion for copper alloy fire protection piping, piping components, and
 
piping elements exposed to condensation (internal), with reference to the further evaluation in
 
SRP-LR Section 3.3.2.2.10.6. This new AMR was not in the January 2005 draft GALL Report.
 
The staff reviewed LRA Tables 3.3.2.1.1 through 3.3.2.1.41 and determined that AMR line items
 
that address the same material and environment combinations were appropriately credited.
 
Therefore, the staff concludes that this further evaluation is not applicable as the material and
 
environment combinations have been evaluated.
The staff noted that the applicant did not credit the GALL Report AMR for loss of material due to pitting and crevice corrosion for stainless steel piping, piping components, and piping elements 3-352 exposed to soil, with reference to the further evaluation in SRP-LR Section 3.3.2.2.10.7. This new AMR was not in the January 2005 draft GALL Report. The staff reviewed LRA
 
Tables 3.3.2.1.1 through 3.3.2.1.41 and noted that other GALL Report AMR line items that
 
address same material and environment combinations were appropriately credited. Therefore, the staff concludes that this further evaluation is not applicable.
LRA Section 3.3.2.2.10.1 addresses loss of material due to pitting and crevice corrosion of the BWR standby liquid control system stainless steel piping, piping components, and piping
 
elements exposed to sodium pentaborate solution.
SRP-LR Section 3.3.2.2.10.8 states that loss of material due to pitting and crevice corrosion can occur in BWR standby liquid control system stainless steel piping, piping components, and piping
 
elements exposed to sodium pentaborate soluti on. The existing AMP relies on monitoring and control of water chemistry to manage the aging effects of loss of material due to pitting and
 
crevice corrosion. However, high concentrations of impurities at crevices and locations of
 
stagnant conditions could cause loss of material due to pitting and crevice corrosion. Therefore, the GALL Report recommends that the effectiveness of the Water Chemistry Program be verified
 
to ensure that this aging does not occur. A one-time inspection of select components at
 
susceptible locations is an acceptable method to ensure that loss of material due to pitting and
 
crevice corrosion does not occur and that the component's intended function will be maintained
 
during the period of extended operation.
LRA Section 3.3.2.2.10.1 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in stainless steel or elastomer lined steel piping, piping components, piping
 
elements, and heat exchanger tube side component s exposed to treated water environments in the CRD system, post-accident sampling system , process sampling system, RBCCW system, RWCU system, shutdown cooling system, spent f uel pool cooling system, standby liquid control system (liquid poison system), water treatm ent and distribution system, reactor head cooling system, and in the primary containment. Obse rved conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it will manage loss of material of steel piping in the standby liquid control system due to pitting and crevice
 
corrosion. In addition, the staff reviewed the applicant's One-Time Inspection Program and
 
verified that it includes inspections of the standby liquid control system to detect loss of material
 
as a means of verifying the effectiveness of the Water Chemistry Program. The staff concludes that these AMPs will adequately manage loss of material due to pitting and crevice corrosion for
 
stainless steel piping, piping components, and piping elements in the BWR standby liquid control
 
system. The staff finds that the applicant's programs meet the criteria of SRP-LR Section 3.3.2.2.10.8 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.10. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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 3-353 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
 
The staff reviewed Attachment 3, item AP-64, of the applicant's reconciliation document against the criteria in SRP-LR Section 3.3.2.2.11.
In Attachment 3, item AP-64, of its reconciliation document, the applicant addressed loss of material due to pitting, crevice, and galvanic corrosion of copper alloy piping, piping components, and piping elements exposed to treated water.
SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic corrosion can occur on copper alloy piping, piping components, and piping elements exposed to
 
treated water. Therefore, the GALL Report recommends that the effectiveness of the Water
 
Chemistry Program be verified to ensure that this aging does not occur. A one-time inspection of
 
select components at susceptible locations is an acceptable method to ensure that loss of
 
material due to pitting and crevice corrosion does not occur and that the component's intended
 
function will be maintained during the period of extended operation. , item AP-64, of the applicant's reconciliation document states that the AMR line item for copper alloy piping elements in treated water, addressing loss of material due to
 
corrosion, recommends the Closed-Cycle Cooling Water System Program with no further
 
evaluation in the January 2005 draft GALL Report that was changed in September 2005 to
 
recommend the Water Chemistry and One-Time Inspection Programs with further evaluation of
 
detected aging effects. There are four instances of this line item used in the condensate transfer
 
and RBSSW systems. In the LRA, these instances already specify the Water Chemistry and
 
One-Time Inspection Programs (with generic Note E stating that an AMP different from that
 
specified in the January 2005 draft GALL Report was credited). Therefore, the LRA implements
 
the One-Time Inspection Program consistent with the GALL Report. Observed conditions with potential impact on Intended function are evaluated or corrected in accordance with the
 
corrective action process, and there is high confidence that the aging effect will be adequately
 
managed.The staff reviewed the applicant's Water Chemistry Program and verified that it will manage loss of material of copper alloy piping, piping components, and piping elements exposed to treated
 
water due to pitting, crevice, and galvanic corrosion. In addition, the staff reviewed the
 
applicant's One-Time Inspection Program and verified that it includes inspections to detect loss
 
of material as a means of verifying the effectiveness of the Water Chemistry Program. The staff
 
concludes that these AMPs will adequately manage loss of material for copper alloy piping, piping components, and piping elements exposed to treated water due to pitting, crevice, and
 
galvanic corrosion.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.11. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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 3-354 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.12  Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion
 
The staff reviewed LRA Section 3.3.2.2.12, and Attachment 3, item AP-54, of the applicant's reconciliation document against the criteria in SRP-LR Section 3.3.2.2.12.
LRA Section 3.3.2.2.12.1 addresses loss of material due to pitting, crevice, and MIC for aluminum and copper alloy piping, piping components, and piping elements exposed to fuel oil.
 
In Attachment 3, item AP-54, of its reconciliation document, the applicant addressed loss of
 
material due to pitting and crevice corrosion and MIC of stainless steel piping, piping
 
components, and piping elements exposed to fuel oil.
SRP-LR Section 3.3.2.2.12.1 states that loss of material due to pitting and crevice corrosion and MIC can occur in stainless steel, aluminum, and copper alloy piping, piping components, and
 
piping elements exposed to fuel oil. The existi ng AMP relies on the Fuel Oil Chemistry Program to monitor and control fuel oil contamination to manage loss of material due to corrosion.
 
However, corrosion may occur at locations where contaminants accumulate and the
 
effectiveness of fuel oil chemistry control should be verified to ensure that corrosion does not
 
occur. The GALL Report recommends further evaluation of programs to manage corrosion to
 
verify the effectiveness of the Fuel Oil Chemis try Program. 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.
LRA Section 3.3.2.2.12.1 states that a One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Fuel Oil Chemistry Program to manage the loss of material in aluminum and copper alloy piping, piping components, and piping elements
 
exposed to a fuel oil environment in the EDG and auxiliary system, main fuel oil storage and transfer system, and fire protection system.
Observed conditions with potential impact on intended function will be evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Fuel Oil Chemistry Program and verified that it will mitigate loss of material due to pitting and crevice corrosion and MIC. In addition, the staff reviewed the
 
applicant's One-Time Inspection Program and verified that it includes inspections to detect loss
 
of material due to pitting and crevice corrosion and MIC as a means of verifying the effectiveness
 
of the Fuel Oil Chemistry Program. The staff concludes that these AMPs will manage loss of material due to pitting and crevice corrosion and MIC for steel piping, piping components, piping
 
elements, and tanks exposed to fuel oil in the EDG and auxiliary system, main fuel oil storage and transfer system, and fire protection system. , item AP-54, of the applicant's reconciliation document states that the line item for stainless steel piping elements in fuel oil, addressing loss of material due to corrosion, recommends the Fuel Oil Chemistry Program wi th no further evaluation required per the January 2005 draft GALL Report that was changed in the September 2005 GALL Report to
 
recommend the Fuel Oil Chemistry and One-Time In spection Programs with a further evaluation 3-355 of detected aging effects to be consistent with other line items applicable to fuel oil environments.
There are six instances of this line item used in the EDG and auxiliary systems, and in the main fuel oil storage and transfer system. Numerous items in the EDG and auxiliary systems and main fuel oil storage systems are already subjec t to both the Fuel Oil Chemistry and One-Time Inspection Program requirements to detect loss of material due to corrosion. The basis for
 
sample size for the One-Time Inspection Program would not be significantly affected by the
 
addition of the (comparatively few) AP-54 line items. Evaluations of any detected aging effects
 
from inspections of those components (with obs erved conditions of potential impact on intended function evaluated and corrected as necessary in accordance with the corrective action process)
 
provide ample opportunity to verify the effectiv eness of the Fuel Oil Chemistry Program with the One-Time Inspection Program in these two systems. The applicant concluded that no change
 
was necessary to the LRA for this item.
The staff reviewed LRA Tables 3.3.2.1.13 and 3.3.2.1.21 for the EDG and auxiliary system and for the main fuel oil transfer system, respectively, and noted multiple line items for components
 
constructed of carbon steel, copper, and aluminum exposed to fuel oil that already credit both the
 
Fuel Oil Chemistry and One-Time Inspection Programs to manage loss of material. Stainless
 
steel is expected to be more resistant to corrosion than carbon steel, copper, and aluminum, and
 
the latter materials can be considered leading indicators expected to be included in the scope of
 
the one-time inspection sample basis. One-time inspection of the stainless steel components
 
would not significantly change the one-time inspection sample basis. On this basis, the staff
 
concludes that the Fuel Oil Chemistry Program is adequate to manage loss of material due to
 
corrosion for the stainless steel components expos ed to fuel oil in the EDG and auxiliary system and the main fuel oil transfer system. The staff finds acceptable the applicant's conclusion that
 
no change was needed to the LRA for this item as the line items have been addressed under the
 
above programs. Based on its review, the staff concludes that the applicant has met the criteria
 
of SRP-LR Section 3.3.2.2.12.1 for further evaluation.
In LRA Section 3.3.2.2.12.2, the applicant addressed loss of material due to pitting and crevice corrosion and MIC in stainless steel piping, piping components, and piping elements exposed to
 
lubricating oil.
SRP-LR Section 3.3.2.2.12.2 states that loss of material due to pitting and crevice corrosion and MIC can occur in stainless steel piping, piping components, and piping elements exposed to
 
lubricating oil. The existing program relies on the periodic sampling and analysis of lubricating oil
 
to maintain contaminants within acceptable limits, preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be adequate to prevent
 
corrosion. Therefore, the effectiveness of lubricating oil control should be verified to ensure that
 
corrosion does not occur. The GALL Report recommends further evaluation of programs to
 
manage corrosion to verify the effectiveness of t he Lubricating Oil Monitoring Activities Program.
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.
LRA Section 3.3.2.2.12.2 states that a One-Time Inspection Program of susceptible locations will verify the effectiveness of the Lubricating Oil M onitoring Activities Program to manage the loss of material in stainless steel piping, piping components, and piping elements exposed to a 3-356 lubricating oil environment in the EDG and aux iliary system. The Lubricating Oil Monitoring Activities Program manages physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear mechanisms, contamination, and oil degradation
 
that could affect intended functions. Observed conditions with potential impact on intended
 
function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it is adequate to manage the loss of material in stainless steel piping, piping components, and piping elements exposed to a lubricating oil environment. The staff finds that the applicant's
 
programs meet the criteria of SRP-LR Section 3.3.2.2.12.2 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.12. For those LRA line items to which this SRP-LR section
 
applies, the staff determined 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).
3.3.2.2.13  Loss of Material Due to Wear
 
The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.
 
In LRA Section 3.3.2.2.13, the applicant addressed loss of material due to wear that can occur in the elastomer seals and components exposed to air indoor uncontrolled (internal or external).
SRP-LR Section 3.3.2.2.13 states that loss of material due to wear can occur in the elastomer seals and components exposed to air indoor uncont rolled (internal or external) environments.
The GALL Report recommends further evaluation to ensure adequate management of these
 
aging effects.
LRA Section 3.3.2.2.13 states that Periodic In spection of Ventilation Systems Program will be implemented for the inspection of elastomer door seals exposed to indoor air internal or external
 
environments in the "C" battery room heati ng and ventilation system, 480V switchgear room ventilation system, battery and MG set room v entilation system, contro l room HVAC system, radwaste area heating and ventilation system, reactor building ventilation system, and standby gas treatment system. Periodic inspections of elastomer door seals identify detrimental changes
 
in material properties, as evidenced by cracking, perforations in the material, or leakage.
 
Observed conditions with potential impact on intended function are evaluated or corrected in
 
accordance with the corrective action process.
The staff reviewed the applicant's Periodic Inspection of Ventilation Systems Program and determines that it is adequate to detect loss of material of elastomer seals and components.
Based on the program identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.3.2.2.13. For those LRA line items to which this SRP-LR section applies, the staff determined 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 3-357 function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.3.2.2.14  Loss of Material Due to Cladding Breach
 
The staff noted that the applicant did not address loss of material due to cladding breach for PWR steel charging pump casings with stainless steel cladding exposed to treated borated
 
water, with reference to the further evaluation in SRP-LR Section 3.3.2.2.14, applicable to PWR
 
plants. The staff determines that this further evaluation is not applicable to OCGS because it is a
 
BWR plant.
3.3.2.2.15  Quality Assurance for Agi ng Management of Nonsafey-Related Components SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program for safety-related and nonsafety-related components.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determines that the applicant has adequately
 
addressed the issues further evaluated. 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  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.3.2.1.1 through 3.3.2.1.41, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
In LRA Tables 3.3.2.1.1 through 3.3.2.1.41, 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 Repor
: t. 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.
Staff Evaluation. 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 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.
3-358 The staff reviewed LRA Table 3.3.1, which summarizes aging management evaluations for the auxiliary systems evaluat ed in the GALL Report.
LRA Table 3.1.1, items 3.3.1-16 and 3.3.1-12 state that loss of material of piping and fittings and valve bodies constructed from carbon and low alloy steel in the containment inerting system, the CRD system, the RBCCW system, the reactor bu ilding ventilation system, the RWCU system, the spent fuel pool cooling system, and the water treatment and distribution system due to
 
exposure to the containment atmosphere (internal) is not applicable.
The staff finds acceptable the applicant's evaluation because that the containment atmosphere is blanketed with nitrogen and does not cause loss of material for carbon and low alloy steel except
 
during refueling outages.
LRA Table 3.1.1, item 3.1.1-9 states that SSC and IGSCC of piping and fittings, valve bodies and flow elements constructed from carbon and low alloy steel in the CRD and the shutdown cooling
 
systems due to exposure to treated water (internal) is not applicable.
This conclusion is a result of work completed by EPRI and reported in EPRI Mechanical Tools Appendix A. The staff finds this conclusion acceptable because the applicant had followed EPRI
 
recommendations.
LRA Table 3.1.1, item 3.3.1-12 state that loss of material of piping and fittings, heat exchangers, pump casings, and valve bodies constructed from carbon and low alloy steel in the drywell floor
 
and equipment drains due to exposure to the containment atmosphere (internal) is not
 
applicable.
The staff understands that the containment atmosphere is blanketed with nitrogen and does not cause loss of material for carbon and low alloy steel except during short periods of time during
 
the refueling outages.
LRA Table 3.1.1, items 3.3.1-16 and 3.3.1-12 state that the loss of material of accumulators, piping and fittings, and valve bodies constructed from carbon and low alloy steel in the
 
instrument (control) air system due to exposure to the containment atmosphere (internal) is not applicable. The reason is that the containment atmosphere is blanketed with nitrogen and does
 
not cause loss of material for carbon and low alloy steel except during refueling outages. The
 
staff finds this statement acceptable.
LRA Table 3.1.1, items 3.3.1-16 and 3.3.1-12 state that SCC and IGSCC of piping and fittings, valve bodies, and heat exchangers (drywell equipment drain tank) constructed from carbon and low alloy steel in the post-accident sampling system and RBCCW system due to exposure to the
 
treated water (internal) is not applicable.
This conclusion is a result of work completed by the industry. The staff finds this acceptable because the applicant had followed EPRI recommendations.
In LRA Tables 3.3.2.1.1 through 3.3.2.1.41, the applicant identified line-items where no aging effects were identified from its aging review process.
3-359 The applicant stated that no aging effects are considered applicable to components fabricated from stainless steel material exposed to indoor air environments.
On the basis of its review of current industry research and operating experience, the staff finds that indoor air on stainless steel will not cause aging of concern during the period of extended
 
operation. Stainless steel forms a passive film that indoor air does not affect. Therefore, the
 
identified above, the staff concludes that there are no applicable aging effects requiring
 
management for stainless steel component s exposed to indoor air environments.
The applicant stated that no aging effects are considered applicable to components fabricated from polypropylene material exposed to outdoor air environments.
On the basis of its review of current industry research and operating experience, the staff finds that outdoor air environments on polypropylene material will not cause aging of concern during
 
the period of extended operation. The staff questioned the applicant about the presence of such
 
stressors as ultraviolet, thermal, radiation, or ozone that would cause aging effects for
 
polypropylene exposed to outdoor air. Based on industry standards, the applicant responded that
 
there are no stressors present. Therefore, the staff concludes that there are no applicable aging
 
effects requiring management for polypr opylene components exposed to outdoor air environments because the material does not react in these environments.
The applicant stated that no aging effects are considered applicable to components fabricated from polyvinyl chloride (PVC, CPVC) materials exposed to outdoor air (exterior), raw water (interior), and indoor air (exterior) environments.
On the basis of its review of current industry research and operating experience, the staff finds that outdoor air (exterior), raw water (interior), and indoor air (exterior) on PVC, CPVC will not
 
cause aging of concern during the period of extended operation. The staff questioned the
 
applicant about the presence of such stressors as ultraviolet, thermal, radiation, or ozone that
 
would cause aging effects for polypropylene exposed to outdoor air (exterior), raw water (interior), and indoor air (exterior) environments and the applicant responded that the presence
 
of stressors is precluded by industry standards. Therefore, the staff concludes that there are no
 
applicable aging effects requiring management for PVC, CPVC components exposed to outdoor air (exterior), raw water (interior), and indoor air (exterior) environments.
The applicant stated that no aging effects are considered applicable to components fabricated from carbon and low alloy steel material exposed to treated water (interior), containment air (exterior), and containment air (internal) environments.
On the basis of its review of current industry research and operating experience, the staff finds that treated water (interior), containment air (exterior), and containment air (internal)
 
environments on carbon and low alloy steel will not cause aging of concern during the period of
 
extended operation. SCC and IGSCC of carbon and low alloy steel are not considered applicable
 
aging mechanisms in treated water per EPRI Mechanical Tools Appendix A.
Based on NRC-approved past precedent, the staff determined that this material and environment combination has been found acceptable. The staff concludes that loss of material due to 3-360 corrosion is not considered a credible aging effect for carbon steel components in a containment nitrogen environment because of negligible amounts of free oxygen (less than 4 percent by
 
volume during normal operation). Both oxygen and moisture must be present for general
 
corrosion to occur because oxygen alone or water free of dissolved oxygen (high humidity in a
 
nitrogen atmosphere) does not corrode carbon steel to any practical extent. The staff finds the
 
applicant's statement of no loss of material for the carbon steel components exposed to a
 
containment nitrogen environment acceptable because, with the negligible amounts of free
 
oxygen, anodic reactions do not take place and the corrosion cell does not form. Therefore, loss
 
of material due to corrosion is not a significant aging effect in the containment atmosphere
 
environment.
During operation, plant technical specifications require oxygen levels to be maintained below 5 percent. Prior to startup following an outage where the primary containment has been opened for
 
maintenance activities, the drywell and torus are purged with nitrogen until oxygen levels are
 
brought below the technical specification limit. A review of operating data indicates that the
 
oxygen level continues to decrease over the next several weeks following startup until the level
 
falls below 1 percent. During the remainder of the operating cycle, the oxygen level is normally
 
maintained below 1 percent. Therefore, the staff concludes that there are no applicable aging
 
effects requiring management for carbon and low alloy steel components exposed to treated
 
water (interior), containment air (exterior), and containment air (internal) environments.
The applicant stated that no aging effects are considered applicable to components fabricated from galvanized steel material exposed to concrete (exterior) environments.
On the basis of its review of current industry research and operating experience, the staff finds that concrete (exterior) environments on galvanized steel will not cause aging of concern during
 
the period of extended operation. There is no aging effect for galvanized steel encased in
 
concrete. This finding is consistent with industry guidance. Therefore, the identified above, the
 
staff concludes that there are no applicable aging effects requiring management for galvanized
 
steel components exposed to indoor air (internal) and concrete (exterior) environments.
The applicant stated that no aging effects are considered applicable to components fabricated from cast iron material exposed to containment air (internal) and containment air (external)
 
environments.
On the basis of its review of current industry research and operating experience, the staff finds that containment air (internal), containment air (external) environments on cast iron will not cause aging of concern during the period of extended operation. Based on past precedent, the staff
 
concludes that the loss of material due to corrosion is not considered a credible aging effect for
 
cast iron components in a containment nitr ogen environment because of negligible amounts of free oxygen (less than 4 percent by volume during normal operation). Both oxygen and moisture
 
must be present for general corrosion to occur because oxygen alone or water free of dissolved
 
oxygen (high humidity in a nitrogen atmosphere) does not corrode carbon steel to any practical
 
extent. The staff finds the applicant's statement of no loss of material for the carbon steel
 
components exposed to a containment nitrogen environment acceptable because, with the negligible amounts of free oxygen, anodic reactions do not take place and the corrosion cell does
 
not form. Therefore, loss of material due to corrosion is not a significant aging effect in the 3-361 containment atmosphere environment. Therefore, the identified above, the staff concludes that there are no applicable aging effects requiring management for cast iron components exposed to
 
containment air (internal) and containment air (external) environments The applicant stated that no aging effects are considered applicable to components fabricated from brass (tubing) material exposed to closed cooling water environments.
On the basis of its review of current industry research and operating experience, the staff finds that closed cooling water environment on brass (tubing) will not cause aging of concern during
 
the period of extended operation. Aging effects on heat transfer function are based on industry
 
standards. Fouling is not a significant aging mechanism for brass tubes in closed cooling water
 
environments. Therefore, the identified above, the staff concludes that there are no applicable
 
aging effects requiring management for brass components exposed to closed cooling water
 
environments.
The applicant stated that no aging effects are considered applicable to components fabricatedfrom glass material exposed to closed cooling water (internal) and treated water <140 &deg;F (internal) environments.
On the basis of its review of current industry research and operating experience, the staff finds that closed cooling water (internal) and treated water <140 o F (internal) environments on glass will not cause aging of concern during the period of extended operation. There is no aging effect
 
for glass in the closed cooling water or treated water <140 o F environments. This finding is consistent with industry standards and the GALL Report for treated water and raw water.
 
Therefore, the identified above, the staff concludes that there are no applicable aging effects
 
requiring management for glass components exposed to closed cooling water (internal) and
 
treated water <140 o F (internal) environments.
The applicant stated that no aging effects are considered applicable to components fabricated from polyethylene material exposed to dry gas (internal) and indoor air (external) environments.
On the basis of its review of current industry research and operating experience, the staff finds that dry gas (internal) and indoor air (external) environments on polyethylene will not cause aging
 
of concern during the period of extended operation. Polyethylene does not react with dry gas or
 
indoor air. There are no stressors for polyethylene like ultraviolet, thermal, radiation, or ozone
 
that would cause aging effects in dry gas (internal) or indoor air (external). Therefore, the
 
identified above, the staff concludes that there are no applicable aging effects requiring
 
management for polyethylene components exposed to dry gas (internal) or indoor air (external)
 
environments.
The applicant stated that no aging effects are considered applicable to components fabricated from zinc material exposed to dry gas (internal) or indoor air (external) environments.
On the basis of its review of current industry research and operating experience, the staff finds that dry gas (internal) or indoor air (external) environments on zinc will not cause aging of
 
concern during the period of extended operation. The environment of dry gas was used for the
 
instrument air system. The compressed air monito ring program is applied to the Instrument Air 3-362 system components to confirm that the internal environment remains sufficiently dry to prevent aging effects. Indoor air also will not cause any aging effects on zinc components. Therefore, the
 
identified above, the staff concludes that there are no applicable aging effects requiring
 
management for zinc components exposed to dry gas (internal) or indoor air (external)
 
environments.
The applicant stated that no aging effects are considered applicable to components fabricated from aluminum material exposed to concrete (external) environments.
On the basis of its review of current industry research and operating experience, the staff finds that concrete environments on aluminum materials will not cause aging of concern during the
 
period of extended operation. There is no aging effect for galvanized steel and aluminum
 
encased in concrete. This finding is consistent with industry guidance. Therefore, the identified
 
above, the staff concludes that there are no applicable aging effects requiring management for
 
aluminum components exposed to c oncrete (external) environments.
The applicant stated that no aging effects are considered applicable to components fabricated from titanium (tubes) material exposed to closed cooling water (external) and outdoor air (external) environments.
On the basis of its review of current industry research and operating experience, the staff finds that closed cooling water (external) and outdoor air (external) environments on titanium (tubes)
 
will not cause aging of concern during the period of extended operation. Titanium is not
 
addressed in the GALL Report and the aging effects are based on industry standards. The staff
 
concludes, based on industry operating experience, that aging of titanium tubes in closed cooling
 
water (external) and outdoor air (external) environments is not an applicable aging effect
 
requiring management.
The applicant stated that no aging effects are considered applicable to components fabricated from polymers material exposed to indoor air (external) and treated water (internal)
 
environments.
On the basis of its review of current industry research and operating experience, the staff finds that indoor air (external) on polymers will not cause aging of concern during the period of
 
extended operation. According to industry operating experience aging of thermoplastics in indoor
 
air and treated water environments is not an applicable aging effect. Therefore, the identified
 
above, the staff concludes that there are no applicable aging effects requiring management for
 
polymer components exposed to indoor air (ext ernal) and treated water (internal) environments.
On the basis of its audit and review of the applicant's program, the staff finds that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended
 
functions will be maintained during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
3-363 3.3.2.3.1  Fire Protection System Summary of Aging Management Evaluation -
LRA Table 3.3.2.1.15 The staff reviewed LRA Table 3.3.2.1.15, which summarizes the results of AMR evaluations for the fire protection system component groups.
The staff's review identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the staff's RAI as discussed
 
below. In RAI 3.3.2.1.15-1 dated January 5, 2006, the staff noted that LRA Table 3.3.2.1.15, ?Fire Protection System," shows no AERM and no AMP for fire barrier walls and slabs made of
 
gypsum board exposed to indoor air. The staff requested that the applicant explain why gypsum
 
board requires no AMP for indoor environment.
In its response dated February 3, 2006, the applicant stated that the gypsum board within the scope of license renewal is installed in a location protected from weather, not in a destructive
 
environment. Review of OCGS operating experience with gypsum board fire barriers indicates no significant age-related degradation that would require an AMP. This operating experience was
 
confirmed by the Fire Protection System manager.
The applicant stated that there are no aging effects for gypsum board and therefore no AMPs required. The applicant's AMR conclusion for the gypsum board is consistent with GALL Report, which calls for aging management of only fire barriers exposed to outdoor environments. The
 
gypsum board in LRA Table 3.3.2.1.15 is expos ed only to indoor air environment. Consistent with guidance in the GALL Report, the identified above, the staff concludes that gypsum board
 
requires no aging management for the period of extended operation. Therefore, the staff's
 
concern described in RAI 3.3.2.1.15-1 is resolved.
In RAI 3.3.2.1.15-2 dated January 5, 2006, the staff noted that LRA Table 3.3.2.1.15 shows no AERM and no AMP for flexible hose made of polyethylene (teflon) exposed to internal and
 
external environments. The staff requested that the applicant explain why polyethylene (teflon)
 
requires no AMP for internal and external environments.
In its response, by letter dated February 3, 2006, the applicant stated that the polyethylene (Teflon) flexible hose is located in the halon system and subject to dry air internally and indoor air
 
externally, not to significant radiation (includi ng ultraviolet radiation) or high temperatures. The full chemical name for this polyethylene is Poly tetrafluoroethylene (PTFE). DuPont's trademark for this compound is Teflon
. PTFE is a thermoplastic member of the fluoropolymer family of plastics. PTFE has a low coefficient of friction, excellent insulating properties, and is chemically
 
inert to most substances. PTFE can withstand high heat applications and is well known for its
 
anti-stick properties. PTFE material has no significant aging effects in the halon fire protection
 
system environment at OCGS and therefore requires no AMR.
Based on its review, the staff finds the applicant's response to RAI 3.3.2.1.15-2 acceptable because the flexible hose in question is located in the halon system and subject to dry air
 
internally and indoor air externally environment.
Furthermore, halon system flexible hose is not 3-364 subject to significant radiation (including ultraviolet radiation) or high temperatures. In addition, the Fire Protection Program provides inspection guidance for external surfaces of the CO 2 and halon fire suppression system components for corrosion and mechanical damage. Therefore, the
 
staff's concern described in RAI 3.5.2.1.15-2 is resolved.
 
In RAI 3.3.2.1.15-3, dated January 5, 2006, the staff noted that LRA Table 3.3.2.1.15 lists spray
 
nozzles (CO 2 and halon) but not spray nozzles (water). The staff requested that the applicant explain why water spray nozzles require no AMP.
 
In its response dated February 3, 2006, the applicant stated that for the fire water systems all
 
spray nozzles are included under "sprinkler heads." Based on its review, the staff finds the applicant's response to RAI 3.3.2.1.15-3 acceptable because it explains that the spray nozzles in question are within the scope of license renewal in
 
accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a).
 
Further, the applicant stated that the spray nozzles are represented in the LRA table by the
 
component type "sprinkler heads." Therefore, the staff's concern described in RAI 3.5.2.1.15-3 is
 
resolved.On the basis of its review, the staff concludes that the applicant has demonstrated that the aging effects of the fire protection system 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).
3.3.2.3.2  Fuel Storage and Handling Equipment Summary of Aging Management Evaluation -
LRA Table 3.3.2.1.16 The staff reviewed LRA Table 3.3.2.1.16, which summarizes the results of AMR evaluations for the fuel storage and handling equipment component groups.
Boral is a neutron-absorbing material used for reactivity control in the spent fuel pool.
The GALL Report does not address the issue of its aging effect. LRA Table 3.3.2.1.16 indicates
 
that when Boral is exposed to the treated water at the temperature of <140 &deg;F it exhibits no aging effects; therefore, no AMP is needed. The applicant based its assertion on a precedent in a
 
similar plant where use of Boral was approved by the NRC in NUREG-1787. The NRC approved
 
the use of Boral because its aging effects were found to be insignificant. In addition to this
 
precedent, in 2000 the applicant performed its own verifying tests on Boral by installing four
 
spent fuel racks, manufactured by HOLTEC International, that utilize Boral neutron-absorbing
 
material. The applicant also installed Boral coupons in the spent fuel storage pool. In 2002 and
 
2004, these coupons were removed and inspected.
The inspection results showed no blisters, pits, dimensional changes, or other age-related degradations. Neutron transmission tests on the irradiated coupon showed an average boron-10
 
areal density in the irradiated coupon of 0.0209 g/cm 2 , meaning that, within the experimental accuracy, boron-10 had not been lost from the coupons. These results and plant operating
 
experience were consistent with the staff's conclusions in NUREG-1787.
3-365 The staff's review identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the staff's RAI as
 
discussed below.
In RAI 3.3.2.1.16-1 dated March 10, 2006, the staff requested that the applicant provide information on the location of the test coupons relative to the spent fuel racks, the way they were
 
mounted, and whether they are fully exposed to the spent fuel pool water. Also, requested was
 
what specific testing procedures had been used for determining boron-10 density, surface
 
corrosion, and blister formation, if any. The staff also expressed its concern over the effect of
 
blisters on plant performance if they ever fo rm and the appropriate action by plant personnel to manage this aging effect.
In its response dated April 7, 2006, the applicant stated that the coupons are mounted in a coupon tree in an environment similar to that of the in-service Boral panels and located in a
 
spent fuel storage rack cell. The coupons in the coupon tree, like those in-service panels, are
 
fully exposed to the spent fuel pool water. Theref ore, it can be assumed that any mechanisms for Boral degradation will be similar.
OCGS Procedure 1002.7, "In-service Surveillance Program fo Boral Poison Racks," is used to verify the integrity of Boral neutron absorber. Neutron attenuation measurements are per
 
Procedure Section 6.3, "Neutron Attenuation," to verify acceptable values of boron-10. All
 
measurements are performed with a sufficient counting interval to obtain the desired confidence
 
limits. Degree of attenuation is obtained by comparing the areal density of the irradiated coupon
 
to its pre-irradiated value. Therefore, the neutron transmission tests by the applicant
 
demonstrated that within measurement accura cy no boron-10 loss occurred. This demonstration indicates expected Boral performance in the spent fuel pool.
Surface corrosion and blister formation on coupons are characterized through visual examination and measurement of coupon weight, length, width, and thickness. Blisters are characterized by a
 
local area where the Boral aluminum cladding separ ates from the aluminum-boron carbide core, most probably due to internal pressure buildup in the Boral core. Blisters in Boral that occur
 
under a relatively thin stainless steel wrapper can cause its deformation. Although no blisters were observed, in BWR fuel racks, as at OCGS, blisters in the Boral can occur. If they occur in
 
more than one Boral plate at any coincident axial location in the same rack cell, the deformed
 
wrapper may impede fuel insertion and withdrawal from the spent fuel rack or displace water
 
from the flux trap region, increasing the reactivity state. However, this occurrence would not
 
apply to OCGS because the plant does not utilize flux traps for thermalizing neutrons and has
 
not experienced such because no blisters have formed. If they form in the future, visual
 
inspection and the operation of fuel insertion and withdrawal would alert plant personnel of their
 
presence.
 
Although Boral blistering may become an operational concern if sufficient blistering occurs to
 
impede rack cell use, Boral blisters are not a safety concern because of OCGS rack design and
 
industry operational and testing experience. Any Boral aging effect will be observed as part of
 
the surveillance program and the use of the Boraflex Rack Management Program.
3-366 The staff found that the applicant had presented evidence that Boral neutron-absorbing material in the spent fuel racks will not undergo aging effects which would negate its function of
 
controlling reactivity of the spent fuel in the spent fuel pool. The applicant compared its Boraflex
 
Rack Management Program to the program in a similar plant that had been approved by the staff. The applicant also described its methods for demonstrating the stability of Boral in the
 
environment of treated water at 140 &deg;F temperature.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the fuel storage and handling equipment
 
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).
Conclusion. On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR results involving material , environment, AERMs, 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).
 
====3.3.3 Conclusion====
The staff concludes that the applicant has provided sufficient information to demonstrate that the effects of aging for the auxiliary systems com ponents, that are 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).3.4  Aging Management of Steam and Power Conversion System 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 co mponent groups of the following systems:
* condensate system
* condensate transfer system
* feedwater system
* main condenser
* main generator and auxiliary system
* main steam system
* main turbine and auxiliary system3.4.1  Summary of Technical Information in the Application In LRA Section 3.4, the applicant provided AMR results for the steam and power conversion system components and component groups. LRA Tabl e 3.4.1, "Summary of Aging Management Evaluations for the Steam and Power Conversion System," provides a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the steam and power conversion system components and component groups.
3-367 The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of 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.
 
====3.4.2 Staff====
Evaluation The staff reviewed LRA Section 3.4 to determine whether the applicant had 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 function(s) will be maintained consistent with the CLB for the
 
period of extended operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs during the weeks of October 3-7, 2005, January 23-27, 2006, and February 13-17, 2006, 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 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 the Audit and Review Report and summarized in SER
 
Section 3.4.2.1.
In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.4.2.2. The staff's
 
audit evaluations are documented in the Audit and Review Report and are summarized in SER
 
Section 3.4.2.2.
The staff also conducted a technical review of the remaining AMRs that were not consistent with or not addressed in the GALL Report. The technical 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. The staff's evaluations are documented in SER
 
Section 3.4.2.3.
For AMRs that the applicant identified as not applicable, or not requiring aging management, the staff conducted a review of the AMR line items, and the plant's operating experience, to verify
 
the applicant's claims. Details of these reviews are documented in the Audit and Review Report.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the steam and power conversion system components.
Table 3.4-1, provided below, includes a summary of the staff's evaluation of components, aging effects and mechanisms, and AMPs, listed in LRA Section 3.4, that are addressed in the GALL
 
Report.
3-368Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water (Item 3.4.1-1)
Cumulative fatigue damageTLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAConsistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.1)
Steel piping, piping components, and
 
piping elements
 
exposed to steam (Item 3.4.1-2)
Loss of material due to general, pitting
 
and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.2)
Steel piping, piping components, and
 
piping elements
 
exposed to treated water (Item 3.4.1-4)
Loss of material due to general, pitting
 
and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.2)
Steel heat exchanger components
 
exposed to treated water (Item 3.4.1-5)
Loss of material due to general, pitting, crevice, and
 
galvanic corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.9)
Steel and stainless steel tanks exposed to treated water (Item 3.4.1-6)
Loss of material due to general (steel only) pitting and
 
crevice corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation. (See
 
SER Section
 
3.4.2.2.7 and
 
3.4.2.2.2 for steel
 
tanks)Steel piping, piping components, and
 
piping elements
 
exposed to
 
lubricating oil (Item 3.4.1-7)
Loss of material due to general, pitting
 
and crevice
 
corrosion Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-369 Steel piping, piping components, and
 
piping elements
 
exposed to raw water (Item 3.4.1-8)
Loss of material due to general, pitting, crevice, and microbiologically-infl
 
uenced corrosion, and foulingPlant specificNot ApplicableNot applicable, refers to auxiliary feedwater system of a PWR and is not
 
applicable to OCGS.
(See SER Section
 
3.4.2.2.3)
Stainless steel andcopper alloy heat
 
exchanger tubes
 
exposed to treated water (Item 3.4.1-9)
Reduction of heat transfer due to
 
fouling Water Chemistryand One-Time
 
InspectionNot ApplicableNot applicable, there are no in-scope
 
stainless steel heat
 
exchanger tubes
 
exposed to treated water with a heat
 
transfer intended
 
function in the steam and power conversion system
 
at OCGS (See SER Section
 
3.4.2.2.4)
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to
 
lubricating oil (Item 3.4.1-10)
Reduction of heat transfer due to
 
fouling Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2)Acceptable (See SER Section
 
3.4.2.3)Buried steel piping, piping components, piping elements, and tanks (with or without coating or wrapping) exposed
 
to soil (Item 3.4.1-11)
Loss of material due to general, pitting, crevice, and microbiologically-infl
 
uenced corrosion Buried Piping andTanks Surveillance or Buried Piping andTanks Inspection Buried Piping Inspection (B.1.26)Consistent withGALL, which
 
recommends further
 
evaluation (See
 
SER Section
 
3.4.2.2.5)
Steel heat exchanger components
 
exposed to
 
lubricating oil (Item 3.4.1-12)
Loss of material due to general, pitting, crevice, and microbiologically-infl
 
uenced corrosion Lubricating OilAnalysis and One-Time InspectionNot ApplicableNot applicable - there
 
are no steel heat
 
exchanger components
 
exposed to
 
lubricating oil in the steam and power conversion system
 
at OCGS.
(See SER Section
 
3.4.2.2.5)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-370 Stainless steel piping, piping
 
components, piping
 
elements exposed
 
to steam (Item 3.4.1-13)
Cracking due to stress corrosion
 
cracking Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.6)
Stainless steel piping, piping
 
components, piping
 
elements, tanks, and heat exchanger
 
components
 
exposed to treated water > 60 &deg;C
(> 140 &deg;F)
(Item 3.4.1-14)
Cracking due to stress corrosion
 
cracking Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.6)
Aluminum andcopper alloy piping, piping components, and piping elements
 
exposed to treated water (Item 3.4.1-15)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.7)
Stainless steel piping, piping
 
components, and
 
piping elements;
 
tanks, and heat
 
exchanger components
 
exposed to treated water (Item 3.4.1-16)
Loss of material due to pitting and crevice
 
corrosion Water Chemistryand One-Time
 
Inspection Water Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.4.2.2.7)
Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to soil (Item 3.4.1-17)
Loss of material due to pitting and crevice
 
corrosionPlant specificBuried Piping Inspection (B.1.26) Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.7)Copper alloy piping, piping components, and piping elements
 
exposed to
 
lubricating oil (Item 3.4.1-18)
Loss of material due to pitting and crevice
 
corrosion Lubricating OilAnalysis and One-Time InspectionNot applicableNot applicable, there are no in-scope copper alloy piping, piping components, or piping elements
 
in the steam and power conversion system at OCGS.
(See SER Section
 
3.4.2.2.7)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-371 Stainless steel piping, piping
 
components, piping
 
elements, and heat
 
exchanger components
 
exposed to
 
lubricating oil (Item 3.4.1-19)
Loss of material due to pitting, crevice, and microbiologically-infl
 
uenced corrosion Lubricating OilAnalysis and One-Time Inspection Lubricating Oil Monitoring Activities (B.2.2) and One-Time Inspection (B.1.24)Consistent withGALL, which
 
recommends further
 
evaluation.
(See SER Section
 
3.4.2.2.8)
Steel tanks exposed to air - outdoor (external)
(Item 3.4.1-20)
Loss of material/
general, pitting, and
 
crevice corrosion Aboveground SteelTanks AbovegroundOutdoor Tanks (B.1.21)Consistent with GALL.
(See SER Section
 
3.4.2.1)High-strength steel closure bolting exposed to air with steam or water
 
leakage (Item 3.4.1-21)
Cracking due tocyclic loading, stress
 
corrosion crackingBolting IntegrityNot ApplicableNot applicable line item not used in the
 
LRA.Steel bolting and closure bolting exposed to air with steam or water
: leakage, air - outdoor (external), or
 
air - indoor
 
uncontrolled (external);
(Item 3.4.1-22)
Loss of material due to general, pitting
 
and crevice
 
corrosion; loss of
 
preload due to
 
thermal effects, gasket creep, and
 
self-looseningBolting IntegrityBolting Integrity (B.1.12)Consistent with GALL.
(See SER Section
 
3.4.2.1)Stainless steel piping, piping
 
components, and
 
piping elements
 
exposed to closed-cycle cooling water > 60 &deg;C
(> 140 &deg;F)
(Item 3.4.1-23)
Cracking due to stress corrosion
 
crackingClosed-CycleCooling Water SystemNot ApplicableNot applicable line item not used in the
 
LRA. Steel heat exchanger components
 
exposed to closed cycle cooling water (Item 3.4.1-24)
Loss of material due to general, pitting, crevice, and
 
galvanic corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.4.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-372 Stainless steel piping, piping
 
components, piping
 
elements, and heat
 
exchanger components
 
exposed to closed cycle cooling water (Item 3.4.1-25)
Loss of material due to pitting and crevice
 
corrosionClosed-CycleCooling Water SystemClosed-CycleCooling Water System (B.1.14)Consistent with GALL.
(See SER Section
 
3.4.2.1)Copper alloy piping, piping components, and piping elements
 
exposed to closed cycle cooling water (Item 3.4.1-26)
Loss of material due to pitting, crevice, and galvanic
 
corrosionClosed-CycleCooling Water SystemNot Applicable.Not applicable, there are no in-scope
 
copper alloy
 
components
 
exposed to CCCW
 
in the steam and power conversion system at OCGS.
Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to closed cycle cooling water (Item 3.4.1-27)
Reduction of heat transfer due to
 
foulingClosed-CycleCooling Water SystemNot Applicable. Not applicable, there are no in-scope
 
steel, stainless
 
steel, or copper alloy heat
 
exchanger tubes
 
exposed to CCCW with heat transfer
 
intended function in
 
the steam and power conversion system at OCGS.
Steel external surfaces exposed to
 
air - indoor
 
uncontrolled (external),
condensation (external), or air
 
outdoor (external)
(Item 3.4.1-28)
Loss of material due to general corrosion External Surfaces Monitoring Structures Monitoring (B.1.31)
Acceptable - the OCGS structures
 
monitoring program is consistent with
 
the GALL external
 
surfaces monitoring
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Steel piping, piping components, and
 
piping elements
 
exposed to steam or treated water (Item 3.4.1-29)Wall thinning due toflow-accelerated
 
corrosionFlow-Accelerated CorrosionFlow-Accelerated Corrosion (B.1.11)Consistent with GALL.
(See SER Section
 
3.4.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-373 Steel piping, piping components, and
 
piping elements
 
exposed to air
 
outdoor (internal) or
 
condensation (internal)
(Item 3.4.1-30)
Loss of material due to general, pitting, and crevice
 
corrosion Inspection of Internal Surfaces in
 
Miscellaneous
 
Piping and Ducting
 
Components Periodic Inspection (B.2.5)Acceptable - the OCGS periodic
 
inspection program is consistent with
 
the GALL inspection
 
of internal surfaces
 
in miscellaneous
 
piping and ducting
 
components
 
program for this
 
component group/
 
aging effect
 
combination.
(See SER Section
 
3.3.2.1.3)
Steel heat exchanger components
 
exposed to raw water (Item 3.4.1-31)
Loss of material due to general, pitting, crevice, galvanic, and microbiologically-infl
 
uenced corrosion, and foulingOpen-Cycle CoolingWater SystemNot Applicable Not applicable, there are no in-scope
 
steel heat
 
exchanger components
 
exposed to raw water in the steam and power conversion system
 
at OCGS.Stainless steel andcopper alloy piping, piping components, and piping elements
 
exposed to raw water (Item 3.4.1-32)
Loss of material due to pitting, crevice, and microbiologically-infl
 
uenced corrosionOpen-Cycle CoolingWater SystemNot Applicable Not applicable, there are no in-scope
 
stainless steel or copper alloy piping, piping components, or piping elements
 
exposed to raw water in the steam and power conversion system
 
at OCGS Consistent with GALL.
Stainless steel heat exchanger components
 
exposed to raw water (Item 3.4.1-33)
Loss of material due to pitting, crevice, and microbiologically-infl
 
uenced corrosion, and foulingOpen-Cycle CoolingWater SystemNot ApplicableNot applicable, there are no in-scope
 
stainless steel heat
 
exchanger components
 
exposed to raw water in the steam and power conversion system
 
at OCGS.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-374 Steel, stainless steel, and copper alloy heat
 
exchanger tubes
 
exposed to raw water (Item 3.4.1-34)
Reduction of heat transfer due to
 
foulingOpen-Cycle CoolingWater SystemNot ApplicableNot applicable, there are no in-scope
 
steel, stainless
 
steel, or copper alloy heat
 
exchanger tubes
 
exposed to raw water in the steam and power conversion system
 
at OCGS.Copper alloy>15% Zn piping, piping components, and piping elements
 
exposed to closed cycle cooling water, raw water, or treated water (Item 3.4.1-35)
Loss of material due to selective leaching Selective Leaching of MaterialsNot Applicable Not applicable, there are no in-scope copper alloy >15%
Zn components
 
exposed to CCCW or raw water in the steam and power conversion system
 
at OCGS.Gray cast iron piping, piping
 
components, and
 
piping elements
 
exposed to soil, treated water, or raw water (Item 3.4.1-36)
Loss of material due to selective leaching Selective Leaching of Materials Selective Leaching of Materials (B.1.25)Consistent with GALL.
(See SER Section
 
3.4.2.1)Steel, stainless steel, and
 
nickel-based alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to steam (Item 3.4.1-37)
Loss of material due to pitting and crevice
 
corrosionWater ChemistryWater Chemistry (B.1.2) and One-Time Inspection (B.1.24)Consistent with GALL.
(See SER Section
 
3.4.2.1)Glass piping elements exposed
 
to air, lubricating oil, raw water, and treated water (Item 3.4.1-40)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.4.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-375 Stainless steel,copper alloy, and nickel alloy piping, piping components, and piping elements
 
exposed to
 
air - indoor
 
uncontrolled (external)
(Item 3.4.1-41)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.4.2.1)Steel piping, piping components, and
 
piping elements
 
exposed to
 
air - indoor
 
controlled (external)
(Item 3.4.1-42)NoneNoneNot ApplicableNot Applicable Controlled air
 
environments are
 
not credited at
 
OCGS. Components
 
are evaluated as
 
part of the
 
uncontrolled indoor
 
air environment.
Steel and stainless steel piping, piping
 
components, and
 
piping elements in
 
concrete (Item 3.4.1-43)NoneNoneNot Applicable Not applicable.There are no
 
in-scope steel or
 
stainless steel
 
piping, piping
 
components, and
 
piping elements in a
 
concrete environment in the Steam and Power Conversion systems
 
at OCGS.Steel, stainless steel, aluminum, and copper alloy
 
piping, piping
 
components, and
 
piping elements
 
exposed to gas (Item 3.4.1-44)NoneNoneNot Applicable Not applicable.There are no
 
in-scope steel, stainless steel, aluminum, or copper alloy piping, piping
 
components, and
 
piping elements
 
exposed to a gas
 
environment in the Steam and Power Conversion systems
 
at OCGS.The staff's review of the steam and power c onversion system component groups followed one of several approaches. One approach, documented in SER Section 3.4.2.1, discusses the staff's
 
review of the AMR results for components that the applicant indicated are consistent with the
 
GALL Report and do not require further evaluation. Another approach, documented in SER 3-376 Section 3.4.2.2, discusses the staff's review of the 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 3.4.2.3, discusses the staff's review of the AMR
 
results for components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the
 
steam and power conversion sy stem components is documented in SER Section 3.0.3.3.4.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicant identified the materials, environments, AERMs, and the following programs that manage the
 
effects of aging related to the steam and power conversion system components:
* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)
* Water Chemistry (B.1.2)
* Flow-Accelerated Corrosion (B.1.11)
* Bolting Integrity (B.1.12)
* Closed-Cycle Cooling Water System (B.1.14)
* Aboveground Outdoor Tanks (B.1.21)
* One-Time Inspection (B.1.24)
* Selective Leaching of Materials (B.1.25)
* Buried Piping Inspection (B.1.26)
* Structures Monitoring Program (B.1.31)
* Lubricating Oil Monitoring Activities (B.2.2)
* Generator Stator Water Chemistry Activities (B.2.3)
* Periodic Inspection Program (B.2.5)
Staff Evaluation. In LRA Tables 3.4.2.1.1 through 3.4.2.1.7, the applicant provided a summary of AMRs for the steam and power conversion sy stem components and identified which AMRs it considered to be consistent with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant claimed consistency with the GALL Report 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 that the AMR is 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 AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
3-377 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. The staff verified that the identified exceptions to the GALL 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 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 com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component that was under review. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the AMR
 
line item of the different component was applicable to the component under review and whether
 
the AMR was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the AMP identified in the GALL Report. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. In SER Section 3.0, the staff
 
verified whether the identified exceptions to the GALL 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 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review 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.
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
 
steam and power conversion system components subject to an AMR. On the basis of its audit and review, the staff determined that, for AMRs not requiring further evaluation, as identified in
 
LRA Table 3.4.1, the applicant's references to the GALL Report are acceptable and no further
 
staff review is required.
3-378 Conclusion. 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes that the applicant has demonstrated that the effects of aging for these components will
 
be adequately managed so that their intended 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 Summary of Technical Information in the Application. In LRA Section 3.4.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report, for the steam and power conversion system com ponents. 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-influenced 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 stress corrosion cracking
* 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 Staff Evaluation. 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 evaluation to determine whether it
 
adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria in SRP-LR Section 3.4.2.2. Details of the staff's
 
audit are documented in the Audit and Review Report. The staff's evaluation of the aging effects
 
is discussed in the following sections.
3.4.2.2.1  Cumulative Fatigue Damage
 
In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3.
Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3
 
documents the staff's review of the applicant's evaluation of this TLAA.
3-379 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.
 
In LRA Section 3.4.2.2.2.1, the applicant addressed loss of material due to general, pitting, and crevice corrosion of steel and aluminum piping, piping components, and piping elements
 
exposed to treated water for steel heat exchanger shell side components exposed to treated
 
water and for steel piping, piping components, and piping elements exposed to steam.
SRP-LR Section 3.4.2.2.2.1 states that loss of material due to general, pitting, and crevice corrosion can occur in steel piping, piping components, piping elements, tanks, and heat
 
exchanger components exposed to treated water and for steel piping, piping components, and
 
piping elements exposed to steam. The existing AMP relies on monitoring and controlling water chemistry to manage the effects of loss of material due to general, pitting, and crevice corrosion.
 
However, control of water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow conditions. Therefore, the effectiveness of the
 
Water Chemistry Program should be verified to ensure that corrosion does not occur. The GALL
 
Report recommends further evaluation of program s to verify the effectiveness of the Water Chemistry Program. A one-time inspection of select components and 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.
LRA Section 3.4.2.2.2.1 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in steel and aluminum pipi ng, piping components, and piping elements exposed to a treated water environment, steel heat exc hanger components exposed to steam or a treated water environment, and steel piping, piping components, and piping elements exposed to a
 
steam environment in the condensate system, c ondensate transfer system, feedwater system, main steam system, main turbine and auxilia ry system, ESW syst em, RBCCW system, and heating and process steam system. Observed c onditions with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it includes activities for monitoring and controlling water chemistry to manage the effects of loss of material due to
 
general, pitting, and crevice corrosion. In addition, the staff verified that the One-Time Inspection
 
Program verifies the effectiveness of the Wate r Chemistry Program in managing loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow conditions. The staff
 
concludes that these AMPs will adequately manage loss of material due to general, pitting, and
 
crevice corrosion for steel piping, piping components, piping elements, tanks, and heat
 
exchanger components exposed to treated water and for steel piping, piping components, and
 
piping elements exposed to steam. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.4.2.2.2.1 for further evaluation.
In LRA Section 3.4.2.2.2.2, the applicant addressed loss of material due to general, pitting, and crevice corrosion for steel piping, piping components, and piping elements exposed to lubricating
 
oil or steam.
3-380 SRP-LR Section 3.4.2.2.2.2 states that loss of material due to general, pitting, and crevice corrosion can occur in steel piping, piping components, and piping elements exposed to
 
lubricating oil. The existing AMP relies on periodic sampling and analysis of lubricating oil to
 
maintain contaminants within acceptable limits, thereby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be adequate
 
to preclude corrosion. Therefore, the effectiveness of lubricating oil contaminant control should
 
be verified to ensure that corrosion does not occur. The GALL Report recommends further
 
evaluation of programs to manage corrosion to veri fy the effectiveness of the lube oil chemistry control program. A one-time inspection of selected components at susceptible locations is an
 
acceptable method to ensure that corrosion does not occur and that the component's intended
 
function will be maintained during the period of extended operation.
LRA Section 3.4.2.2.2.2 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectiveness of the Lubricating Oil Monitoring Activities
 
Program to manage the loss of material due to general, pitting, and crevice corrosion for steel
 
piping, piping components, and piping elements expos ed to a lubricating oil internal environment in the condensate system, condensate transfer syst em, feedwater system, main steam system, main turbine and auxiliary system, ESW sy stem, RBCCW system, and heating and process steam system. The Lubricating Oil Monitoring Activities Program manages the physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear
 
mechanisms, contamination, and oil degradation that could affect intended functions. Observed
 
conditions with potential impact on an intended function are evaluated or corrected in
 
accordance with the corrective action process.
The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it includes appropriate activities to manage the loss of material due to general, pitting, and
 
crevice corrosion for steel piping, piping components, and piping elements exposed to a
 
lubricating oil internal environment. The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.4.2.2.2.2 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.2. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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 (MIC), and Fouling In LRA Section 3.4.2.2.3, the applicant stated that loss of material due to general, pitting, and crevice corrosion and MIC, and fouling of steel components exposed to raw water in a PWR
 
auxiliary feedwater system, with reference to the further evaluation in SRP-LR Section 3.4.2.2.3, is applicable to PWRs only. The staff finds acceptable the applicant's evaluation of this aging
 
effect as not applicable to OCGS because it is a BWR plant.
3-381 3.4.2.2.4  Reduction of Heat Transfer Due to Fouling The staff noted that the applicant did not credit the GALL Report AMR for reduction of heat transfer due to fouling for stainless steel or copper alloy heat exchanger tubes exposed to
 
treated water, with reference to the further evaluation in SRP-LR Section 3.4.2.2.4.1.
The staff reviewed LRA Tables 3.4.2.1.1 through 3.4.2.1.7 and noted that this component group and environment combination was not identified as within the scope of license renewal.
 
Therefore, the staff finds acceptable the applicant's assessment and concludes that this further
 
evaluation is not applicable.
The staff noted that the applicant did not credit the GALL Report AMR for reduction of heat transfer due to fouling for steel, stainless steel, and copper alloy heat exchanger tubes exposed
 
to lubricating oil, with reference to the further evaluation in SRP-LR. This new AMR was not in
 
the January 2005 draft GALL Report.
The staff reviewed LRA Tables 3.3.2.1.13, 3.3.2.1.15, and 3.3.2.1.29 and noted that the applicant identified copper alloy components exposed to lubricating oil for which the Lubricating
 
Oil Monitoring Activities Program was credit ed to manage reduction of heat transfer. Generic Note G was cited, indicating that the environment was not in the GALL Report for that
 
component and material; therefore, these AMR line items were identified as not consistent with
 
the GALL Report and are addressed in SER Section 3.4.2.3.
3.4.2.2.5  Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced Corrosion The staff reviewed LRA Section 3.4.2.2.5.2 against the criteria in SRP-LR Section 3.4.2.2.5.
 
In LRA Section 3.4.2.2.5.2, the applicant addressed loss of material due to general, pitting, and crevice corrosion and MIC in steel components exposed to soil.
SRP-LR Section 3.4.2.2.5.1 states that loss of material due to general, pitting, and crevice corrosion and MIC can occur in steel (with or without coating or wrapping) piping, piping
 
components, piping elements, and tanks exposed to soil. The Buried Piping Inspection Program
 
relies on industry practice, frequency of pipe excavation, and operating experience to manage
 
the effects of loss of material from general, pitting, and crevice corrosion and MIC. The
 
effectiveness of the buried piping and tanks inspection program should be verified to evaluate an
 
applicant's inspection frequency and operating experience with buried components, ensuring that
 
loss of material does not occur.
LRA Section 3.4.2.2.5.2 states that a Buried Piping Inspection Program will be implemented to manage the loss of material in steel piping exposed to soil in the heating and process steam
 
system. The Buried Piping Inspection Program includes preventive measures to mitigate corrosion and periodic inspection to manage the effects of corrosion on the pressure-retaining
 
capacity of buried steel piping, piping components, and piping elements. Observed conditions
 
with potential impact on an intended function are evaluated or corrected in accordance with the
 
corrective action process.
3-382 The staff reviewed the applicant's Buried Piping Inspection Program and verified that it includes inspections to detect loss of material in steel piping, piping components, and piping elements
 
due to general, pitting, and crevice corrosion and MIC. The staff confirmed that, for each of the
 
material and environment combinations for which the Buried Piping Inspection Program will be
 
credited, at least one inspection (opportunistic or focused) has been or will be performed prior to
 
the period of extended operation, and a focused inspection will be performed within the first 10
 
years of the period of extended operation. The staff finds that, based on the programs identified
 
above, the applicant has met the criteria of SRP-LR Section 3.4.2.2.5.1 for further evaluation.
The staff noted that the applicant did not credit the GALL Report AMR for loss of material due to general, pitting, and crevice corrosion and MIC in steel heat exchanger components exposed to
 
lubricating oil, with reference to the further evaluation in SRP-LR Section 3.4.2.2.5.2. The staff
 
reviewed LRA Tables 3.4.2.1.1 through 3.4.2.1.7 and noted that other GALL Report AMR line
 
items that address the same material and environment combinations are appropriately credited.
 
Therefore, the staff concludes that this further evaluation is not applicable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.5. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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 (SCC)
 
The staff reviewed LRA Section 3.4.2.2.6.1 against the criteria in SRP-LR Section 3.4.2.2.6.
 
In LRA Section 3.4.2.2.6.1, the applicant addressed cracking due to SCC for stainless steel components exposed to treated water or steam.
SRP-LR Section 3.4.2.2.6 states that cracking due to SCC can occur in the stainless steel piping, piping components, piping elements, tanks, and heat exchanger components exposed to treatedwater greater than 60 &deg;C (>140 &deg;F), and for stainless steel piping, piping components, and piping
 
elements exposed to steam. The existing AMP moni tors and controls water chemistry to manage the effects of cracking due to SCC. However, high concentrations of impurities at crevices and
 
locations of stagnant flow conditions can cause SCC. Therefore, the GALL Report recommends
 
that the effectiveness of the Water Chemistry Program be verified to ensure that SCC does not
 
occur. A one-time inspection of selected components at susceptible locations is an acceptable
 
method to ensure that SCC does not occur and that the component's intended function will be
 
maintained during the period of extended operation.
LRA Section 3.4.2.2.6.1 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage SCC of stainless steel piping, piping components, piping elements, and coolers exposed to treated water >140 &deg;F or exposed to a steam environment in the feedwater system, heating and process steam system, main steam system, isolation condenser system, shutdown cooling system, and 3-383 main turbine auxiliary system. Observed conditi ons with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it includes activities that will mitigate cracking due to SCC. In addition, the staff reviewed the applicant's One-Time
 
Inspection Program and verified that it includes inspections of the stainless steel steam and
 
power conversion system components to detect cracking and verify the effectiveness of the Water Chemistry Program. The staff finds that these AMPs will adequately manage cracking due
 
to SCC for stainless steel heat exchanger components in the steam and power conversionsystems.Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.6. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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 Sections 3.4.2.2.7 and 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.7.
In LRA Section 3.4.2.2.7.1, the applicant addressed loss of material due to pitting and crevice corrosion 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.SRP-LR Section 3.4.2.2.7.1 states that loss of material due to pitting and crevice corrosion can occur in stainless steel, aluminum, and copper alloy piping, piping components, and piping
 
elements and in stainless steel tanks and heat exchanger components exposed to treated water.
 
The existing AMP monitors and controls water chemistry to manage the effects of loss of
 
material due to pitting, and crevice corrosion. However, control of water chemistry does not
 
preclude corrosion at locations of stagnant flow conditions. Therefore, the GALL Report
 
recommends that the effectiveness of the Water Chemistry Program be verified to ensure that
 
corrosion does not occur. A one-time inspection of select components at susceptible locations is
 
an acceptable method to ensure that corrosion does not occur and that the component's
 
intended function will be maintained during the period of extended operation.
LRA Section 3.4.2.2.7.1 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in stainless steel, piping components, piping elements, tanks, and heat
 
exchanger shell-side components exposed to a treated water environment in the condensate system, feedwater system, ma in steam system, main turb ine and auxiliary system, and RWCU system. Observed conditions with potentia l impact on intended function are evaluated or corrected in accordance with the corrective action process.
3-384 The staff reviewed the applicant's Water Chemistry Program and verified that it will mitigate cracking due to SCC. In addition, the staff reviewed the applicant's One-Time Inspection
 
Program and verified that this AMP includes inspections of the stainless steel, aluminum, and
 
copper alloy steam and power conversion system components to detect cracking and verify the effectiveness of the Water Chemistry Program. The staff determined that these AMPs will
 
adequately manage cracking due to SCC for stainless steel, piping components, piping
 
elements, tanks, and heat exchanger shell-side components exposed to a treated water
 
environment in the steam and power conversion sy stems. The staff concludes that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.4.2.2.7.1 for
 
further evaluation.
In LRA Section 3.4.2.2.7.2, the applicant addressed loss of material due to pitting and crevice corrosion for stainless steel piping, piping components, and piping elements exposed to soil.
SRP-LR Section 3.4.2.2.7.2 states that loss of material due to pitting and crevice corrosion can occur in stainless steel piping, piping components, and piping elements exposed to soil. The
 
GALL Report recommends further evaluation of a plant-specific AMP to ensure adequate
 
management of this aging effect.
LRA Section 3.4.2.2.7.2 states that a Buried Piping Inspection Program will be implemented to manage the loss of material in stainless steel piping exposed to soil in the heating and process
 
steam system. The Buried Piping Inspection Program includes preventive measures to mitigate corrosion and periodic inspection to manage the effects of corrosion on the pressure-retaining
 
capacity of buried stainless steel piping. Observed conditions with potential impact on an
 
intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Buried Piping Inspection Program and verified that it includes inspections to detect loss of material of stainless steel piping due to pitting and crevice corrosion.
 
The staff confirmed that, for each of the material and environment combinations for which the
 
Buried Piping Inspection Program will be credited, at least one inspection (opportunistic or
 
focused) has been, or will be performed prior to the period of extended operation, and a focused
 
inspection will be performed within the first 10 years of the period of extended operation. The
 
staff concludes that, based on the program identified above, the applicant has met the criteria of
 
SRP-LR Section 3.4.2.2.7.2 for further evaluation.
In LRA Section 3.4.2.2.9, the applicant addressed loss of material due to pitting and crevice corrosion for copper alloy components exposed to lubricating oil SRP-LR Section 3.4.2.2.7.3 states that loss of material due to pitting and crevice corrosion can occur in copper alloy piping, piping components, and piping elements exposed to lubricating oil.
 
The existing AMP relies on the periodic sampling and analysis of lubricating oil to maintain
 
contaminants within acceptable limits, ther eby preserving an environment not conducive to corrosion. However, control of lube oil contaminants may not always be adequate to preclude
 
corrosion. Therefore, the effectiveness of lubricating oil contaminant control should be verified to
 
ensure that corrosion does not occur. The GALL Report recommends further evaluation of
 
programs to manage corrosion to verify the e ffectiveness of the Lubricating Oil Monitoring Activities Program. A one-time inspection of selected components at susceptible locations is an 3-385 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.
LRA Section 3.4.2.2.9 states that this line item is not used, that there are no in-scope copper alloy piping, piping components, and piping elements in a lubricating oil environment in the
 
steam and power conversion systems.
The staff reviewed LRA Tables 3.4.2.1.1 through 3.4.2.1.7 and verified that no copper alloy piping, piping components, or piping elements are within the scope of license renewal.
 
Therefore, the staff finds acceptable the applicant's conclusion that this further evaluation is not
 
applicable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.7. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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.
 
In LRA Section 3.4.2.2.8, the applicant addressed loss of material due to pitting and crevice corrosion and MIC in stainless steel piping, piping components, piping elements, and heat
 
exchanger components exposed to lubricating oil.
SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion and MIC can occur in stainless steel piping, piping components, piping elements, and heat exchanger
 
components exposed to lubricating oil. The existing AMP relies on periodic sampling and
 
analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving
 
an environment not conducive to corrosion. However, control of lube oil contaminants may not
 
always be adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil
 
contaminant control should be verified to ensure that corrosion does not occur. The GALL Report
 
recommends further evaluation of programs to manage corrosion to verify the effectiveness of the Lubricating Oil Monitoring Activities Program. 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.
LRA Section 3.4.2.2.8 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectiveness of the Lubricating Oil Monitoring Activities
 
Program to manage the loss of material in stainless steel piping, piping components, and piping
 
elements exposed to a lubricating oil internal environment in the main turbine and auxiliary system. The Lubricating Oil Monitoring Activi ties Program manages physical and chemical properties of lubricating oil by sampling, testing, and trending to identify specific wear
 
mechanisms, contamination, and oil degradation that could affect intended functions. Observed 3-386 conditions with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Lubricating Oil Monitoring Activities Program and determined that it includes sampling, testing, and trending activities adequate to manage the loss of material
 
in stainless steel piping, piping components, and piping elements exposed to a lubricating oil
 
internal environment. The staff finds this program adequate to manage the aging effect for which
 
it is credited.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.8. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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).
3.4.2.2.9  Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion
 
The staff reviewed LRA Section 3.4.2.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.9.
 
In LRA Section 3.4.2.2.2.1, the applicant addressed loss of material due to general, pitting, and crevice corrosion of steel and aluminum piping, piping components, and piping elements
 
exposed to treated water.
SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, and galvanic corrosion can occur in steel heat exchanger components exposed to treated water. The
 
existing AMP monitors and controls water chemistry to manage the effects of loss of material due
 
to general, pitting, and crevice corrosion. However, control of water chemistry does not preclude
 
loss of material due to general, pitting, and crevice corrosion at locations of stagnant flow
 
conditions. Therefore, the effectiveness of the Water Chemistry 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 Wa ter Chemistry Program. A one-time inspection of select components and 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.
LRA Section 3.4.2.2.2.1 states that the One-Time Inspection Program will be implemented for susceptible locations to verify the effectivene ss of the Water Chemistry Program to manage the loss of material in steel and aluminum pipi ng, piping components, and piping elements exposed to a treated water environment, steel heat exc hanger components exposed to a steam or treated water environment, and steel piping, piping components, and piping elements exposed to a
 
steam environment in the condensate system, c ondensate transfer system, feedwater system, main steam system, main turbine and auxilia ry system, ESW syst em, RBCCW system, and heating and process steam system. The One-Time In spection Program also will be used to verify the effectiveness of the Water Chemistry Program to manage the loss of material in steel shell
 
and shell side components exposed to a treated water environment in the isolation condenser 3-387 system. Observed conditions with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process.
The staff reviewed the applicant's Water Chemistry Program and verified that it will manage loss of material due to general, pitting, crevice, and galvanic corrosion of steel heat exchanger
 
components. In addition, the staff reviewed the applicant's One-Time Inspection Program and
 
verified that it includes inspections to detect cracking and verify the effectiveness of the Water
 
Chemistry Program. The staff concludes that these AMPs will adequately manage loss of
 
material for steel heat exchanger components exposed to a treated water environment in the
 
steam and power conversion systems.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.4.2.2.9. For those LRA line items that apply to this SRP-LR section, the staff determined that the applicant is consistent with the GALL Report and 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 quality assurance program for safety-related and nonsafety-related components.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant had claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determines that the applicant has adequately
 
addressed the issues that required further evaluation. 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).3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.4.2.1.1 through 3.4.2.1.7, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL Report.
In LRA Tables 3.4.2.1.1 through 3.4.2.1.7, 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 the aging effects
 
will be managed. Specifically, Note F indicates t hat 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, materi al, 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 3-388 that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
Staff Evaluation. 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 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 discussed in the following sections.
3.4.2.3.1  Condensate System Summary of Aging Management Evaluation -
LRA Table 3.4.2.1.1 The staff reviewed LRA Table 3.4.2.1.1, which summarizes the results of AMR evaluations for the condensate system component groups.
LRA Table 3.4.2.1.1 states that the AMRs for the condensate system either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this
 
table are consistent with the GALL Report. The staff's evaluation for AMR items that are
 
consistent with the GALL Report is documented in SER Sections 3.4.2.1 and 3.4.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the condensate system 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).
3.4.2.3.2  Condensate Transfer System Su mmary of Aging Management Evaluation -
LRA Table 3.4.2.1.2 The staff reviewed LRA Table 3.4.2.1.2, which summarizes the results of AMR evaluations for the condensate transfer system component groups.
LRA Table 3.4.2.1.2 states that loss of material of buried aluminum piping and fittings in an external soil environment will be managed by the Buried Piping Inspection Program.
The staff's review of LRA Table 3.4.2.1.2 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.4-1 dated March 30, 2006, the staff requested that the applicant provide the following additional information about the management of the aging effects:  (a)the type of loss of material expected (pitting, cracking, general corrosion etc.)  (b)operating experience with this material in this environment (c)type of external coatings and wrappings used and preventive measures to keep them in place 3-389 In its response dated April 28, 2006, the applicant stated:  (a)Buried aluminum piping at Oyster Creek is coated to preclude loss of material. Deterioration of the protective coating of aluminum piping at
 
Oyster Creek resulted in loss of material due to pitting and galvanic
 
corrosion.  (b)Operating experience for the buried Condensate Transfer aluminum piping adjacent to the Condensate Transfer pump house has shown previous
 
loss of material subsequent to protective coatings failure. The loss of
 
material was attributed to galvanic corrosion and resulted in leakage of the
 
piping. The galvanic mechanism was primarily due to interaction between
 
aluminum pipe and a large copper grounding grid at the same location. A
 
significant portion of the underground piping is no longer in contact with
 
soil. Piping was relocated aboveground or routed in precast concrete
 
trenches. The remaining run of buried pipe was replaced and coated with
 
the Polykin coating system. Also, a short run of aluminum pipe between the turbine building and reactor building is buried. This piping is located at
 
a different location on site not near the grounding grid. Operating
 
experience and soil samples at this piping location did not identify any
 
leakage.  (c)Replaced piping is coated with Polykin 1029 pipeline primer then 3 layers of Polykin 910 Oil Field utility tape with 50% overlap are applied.
 
Preventive measures to keep them in place include tape termination points
 
sealed with a double wrap of tape around the pipe. The short run of pipe
 
between the turbine building and reactor building is protected by a coal tar
 
enamel. It has a felt wrap and waterproof exterior finish system.
The staff finds the applicant's response acceptable because it identified the type of loss of material expected and the coating specifications.
 
LRA Table 3.4.2.1.2 states that loss of material of aluminum tanks in an air (internal and
 
external) and external soil environments w ill be managed by the Aboveground Outdoor Tanks Program. The staff determined that the LRA had insufficient information on the adequacy of the
 
aging management of the tanks.
In RAI 3.4-2 dated March 30, 2006, the staff requested that the applicant provide the following information regarding the tanks:  (1)specific alloy composition of the tank material  (2)description of the tank supports (3)aging management of the sealant or coatings on the tank bottom, if any (4)operating experience 3-390  (5)purpose of the tanks (including a description of the services performed) and any other material in contact with its internal and external surfaces like expansion joints, piping
 
connections, etc.  (6)specific tests, wall thickness measurements, and inspections to assure that the leak tightness is maintained in the internal and external outdoor air and soil environments In its response dated April 28, 2006, the applicant stated:
The one aluminum tank included in the Aboveground Outdoor Tanks Program, B.1.21 is the Condensate Storage Tank (CST).  (1)The tank shell plates are made from type 5086-H34 aluminum. The bottom plates are constructed from type 5086-H1116 aluminum. The materials are identified in
 
the tank specification and drawings.  (2)The tank is supported by a concrete ring and soil foundation. The tank is connected to the pad by 12 anchor brackets as specified in the tank specification
 
and drawings.  (3)Caulking is applied to tank/concrete seam on the exterior of the tank base to prevent water intrusion underneath the tank. Caulking will be inspected on the
 
external surfaces of the tank.  (4)The tank bottom was inspected in 1980 and localized patch plate repairs were made. Water seepage was discovered during the refueling outage in March 1991.
 
Subsequent inspection found through wall corrosion and thinning of the bottom
 
plates. The tank bottom was then replaced. A layer of clean, washed "low iron" silica sand was installed under the bottom of the new tank plates to inhibit
 
corrosion as detailed in the tank repair specification.  (5)The in scope aluminum tank is the site Condensate Storage Tank. The purpose of the Condensate Storage Tank as discussed in LRA section 2.3.4.2 is to provide
 
for bulk storage of condensate, surge volume capability for the Condensate
 
system and condensate supply for the Condensate Transfer system. Aluminum
 
supply and return piping connect to the aluminum tank. Additionally, overflow and
 
instrument lines and a vent, containing component materials other than aluminum, are connected to the tank. As specified in the Oyster Creek Line List and
 
Specifications, aluminum piping systems are insulated and electrically isolated from ferrous materials.  (6)Aging management of external tank surfaces exposed to air will be performed by visual inspections every five years. The internal surfaces exposed to outdoor air
 
are subcomponents of the tank vent and will be inspected along with the external
 
tank inspection. The external tank surface in contact with soil is inspected by UT
 
measurements of the bottom plates prior to the period of extended operation. A
 
corrosion rate of the bottom plates is determined from thickness measurements
 
and original plate thickness. The results of these inspections are monitored and
 
trended and the tank bottom inspection frequency set such that component 3-391 intended function is ensured. Note, the internal surfaces of the tank are managed by the Water Chemistry and One-Time Inspection aging management programs.
The staff finds the applicant's response acceptable because it provided the inspection methods for both the internal and external surfaces as well as other pertinent information as to the tank as
 
requested. The staff's concerns described in RAI 3.4-2 are resolved.
In RAI 3.4-3 dated March 30, 2006, the staff noted that LRA Table 3.4.2.1.2 states that loss of material in stainless steel tanks in inte rnal and external environments is managed by the Aboveground Outdoor Tanks Program. The staff requested that the applicant provide the
 
following information:  (1)description of the tanks including supports and other connecting piping  (2)specific tests and inspections (including wall thickness measurements) in the Aboveground Outdoor Tanks Program, which are performed relative to these tanks to
 
assure structural integrity  (3)operating history In its response dated April 28, 2006, the applicant clarified that there are no stainless steel tanks in the Aboveground Outdoor Tanks Program. The stainless steel listed in LRA Table 3.4.2.1.2 is
 
a screen frame sub-component of the aluminum condensate storage tank roof vent. Recurring visual inspections of this stainless steel subcomponent are included in this program. Operating
 
history of this tank was included in the above response to RAI 3.4-2. The staff's concern
 
described in RAI 3.4-3 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the condensate transfer system 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).
3.4.2.3.3  Feedwater System Summary of Ag ing Management Evaluation - LRA Table 3.4.2.1.3 The staff reviewed LRA Table 3.4.2.1.3, which summarizes the results of AMR evaluations for the feedwater system component groups.
LRA Table 3.4.2.1.3 states that carbon and low alloy steel piping and fittings in containment atmosphere (external) have no aging effects. According to the applicant the aging effect in the
 
GALL Report for this component, material, and environment combination is not applicable (Note I). The applicant cited a previous evaluation in which the staff concluded that loss of
 
material is not an aging effect for carbon steel components in a containment nitrogen
 
environment because of negligible amounts of fr ee oxygen (less than 4 percent by volume) during normal operation.
The staff's review of LRA Table 3.4.2.1.3 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
3-392 The staff believes that due to the leakage of moisture and the presence of oxygen during plant shutdown the potential for degradation of carbon steel components cannot be ruled out over an extended period of time. Therefore, there is a need for a one-time inspection prior to the period
 
of extended operation unless the applicant can provide additional assurance in support of its
 
position (e.g., monitored data from the containm ent nitrogen environment to indicate that free oxygen levels have been and would continue to be continuously maintained below threshold
 
levels during the period of extended operation).
In RAI 3.4-4 dated March 30, 2006, the staff requested that the applicant justify its position or, alternately, commit to a one-time inspection of these components prior to the period of extended
 
operation.
In its response dated April 28, 2006, the applicant committed (Commitment No. 31) to perform a one-time inspection of carbon steel feedwater system piping located inside containment. The
 
one-time inspection will be a visual inspection of the carbon steel piping external surface for loss
 
of material due to corrosion. This inspection will be prior to period of extended operation.
The applicant further stated:
This one-time inspection is intended to confirm that there is no significant age related degradation occurring on the external carbon steel surfaces of the
 
feedwater system located inside containment. If aging degradation is identified, the condition will be documented on an Issue Report and evaluated for corrective
 
actions including additional feedwater system piping and component inspection
 
locations.
The staff finds the applicant's response acceptable because the applicant agreed to the one-time inspection as suggested. The staff's concern described in RAI 3.4-4 is resolved.
LRA Table 3.4.2.1.3 states that there are no AERMs for carbon and low alloy steel valve bodies in external containment air and treated water environments.
In RAI 3.4-5 dated March 30, 2006, the staff requested that the applicant address the same issues previously discussed under RAI 3.4-4 as they are also applicable to carbon and low alloy
 
steel valve bodies. The staff also requested that the applicant justify and provide the basis for its
 
response.In its response dated April 28, 2006, the applicant stated:
As stated in the response to RAI 3.4-4, AmerGen will perform a one-time inspection of carbon steel feedwater system piping located inside containment.
 
The one-time inspection will be a visual inspection of the carbon steel piping
 
external surface for loss of material due to corrosion. This inspection will be
 
performed prior to entering the period of extended operation. This one-time
 
inspection is intended to confirm that there is no significant age related
 
degradation occurring on the external carbon steel surfaces of the feedwater 3-393 system located inside containment. Since the piping and valves are carbon steel, and the environment is the same, results of the one-time inspection of the piping
 
surface will also be applicable to the carbon steel valve external surfaces. If aging
 
degradation is identified, the condition will be documented on an Issue Report and
 
evaluated for corrective actions including additional feedwater system piping and
 
component inspection locations.
The staff finds the applicant's response acceptable because the applicant agreed to a one-time inspection with adequate remedial measures. The staff's concerns described in RAI 3.4-5 are
 
resolved.On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the feedwater system 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).
3.4.2.3.4  Main Condenser Summary of Aging Management Evaluation - LRA Table 3.4.2.1.4
 
The staff reviewed LRA Table 3.4.2.1.4, which summarizes the results of AMR evaluations for the main condenser component groups.
LRA Table 3.4.2.1.4 states that there are no AERMs for the following main condenser subcomponents:
* carbon and low alloy steel main condenser shell in indoor air (external) and steam (internal) environments
* titanium main condenser tubes in a raw salt water (internal) and steam (external) environment
* aluminum/bronze tubesheet in a raw salt water (internal) and steam (external) environment The applicant further stated that aging management of the main condenser is not based on analysis of materials, environments and aging effects. Condenser integrity required for the
 
post-accident intended function (holdup and plate out of MSIV leakage) is continuously
 
confirmed by normal plant operation. Therefore, the applicant stated that no traditional AMR or
 
aging management is required.
The staff's review of LRA Table 3.4.2.1.4 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
 
In RAI 3.4-6 dated March 30, 2006, the staff requested that the applicant provide the following
 
information about the main condenser or justify why this information does not apply:  (1)Operational and maintenance history of the main condenser, summarizing the significant abnormal conditions or events which may have occurred in the past. This summary 3-394 should include a brief discussion of the root cause determination and evaluation of these events, if available. The staff is particularly interested in events related to fouling, insulation failure, tube ruptures or major leaks, expansion joint failures, condenser air
 
in-leakage, and condenser tube MIC.  (2)Any concerns related to condenser capacity under power uprate conditions.
In its response dated April 28, 2006, the applicant stated:  (1)The main condenser is a critical balance-of-plant component for power generation. The main condenser is required to continuously maintain vacuum
 
pressure integrity to support normal power operation of the station. Condenser
 
tubes can become fouled or corroded as a result of normal plant operation, and
 
these issues are addressed by tube cleaning or tube plugging during refueling and
 
maintenance outages. Tube corrosion, tube fouling or insulation failure does not
 
immediately prevent continued plant operation, and does not prevent the main
 
condenser from performing its intended function of post accident holdup and
 
plateout of main steam isolation valve (MSIV) bypass leakage. Significant
 
condenser air in-leakage would prevent the main condenser from maintaining
 
normal vacuum and would require immediate corrective action or plant shutdown
 
for repair. Air in-leakage does not prevent the main condenser from performing its
 
intended function of post-accident holdup and plateout of MSIV bypass leakage.
 
Under post accident conditions, condenser vacuum is lost and the condenser is at
 
atmospheric pressure.
Major leaks including tube leaks and expansion joint failure would result in immediate shutdown for repair. Such failures would not be expected when
 
the condenser is performing its post-accident intended function because
 
the condenser is not under vacuum conditions and is at atmospheric
 
pressure. The intended function of the main condenser is to provide a
 
post-accident holdup and plateout volume for MSIV bypass leakage. This
 
intended function is not a pressure boundary function. The approach for
 
aging management of the Main Condenser is to demonstrate adequate
 
post-accident structural integrity of the Main Condenser, based on the fact
 
that the condenser is operating prior to the accident and that the
 
conditions, for the condenser are more severe during power operations
 
than they are post-accident, when the MSIVs will be closed and vacuum
 
will be lost. The structural integrity of the main condenser components
 
during power operation will not immediately change post accident, and no
 
aging effects will cause a loss of intended function in the short time that
 
the main condenser is credited following the accident. Since no aging
 
effects can cause a loss of intended function, no aging management is
 
required. Assurance that the main condenser will be available to perform
 
its post-accident intended function is continuously demonstrated by its
 
ability to support normal plant operation. This demonstration is not
 
dependent on the operational and maintenance history of the main
 
condenser. Although the Oyster Creek main condenser has performed
 
well, as demonstrated by reliable plant operation, it is not necessary to 3-395 consider the detailed operation and maintenance history to support the license renewal conclusion that an aging management program is not
 
required.  (2)AmerGen has no plans to implement power uprate at Oyster Creek. Therefore, the main condenser will not be subject to power uprate conditions.
The staff finds the applicant's response acceptable because the applicant provided an adequate justification demonstrating that the condenser's intended function of post-accident holdup and
 
plateout of MSIV bypass leakage would be maintained. The staff's concerns described in
 
RAI 3.4-6 are resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the main condenser 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).
3.4.2.3.5  Main Generator and Auxiliary Syst em Summary of Aging Management Evaluation -
LRA Table 3.4.2.1.5 The staff reviewed LRA Table 3.4.2.1.5, which summarizes the results of AMR evaluations for the main generator and auxiliary system component groups.
LRA Table 3.4.2.1.5 states that the AMRs for the main generator and auxiliary system are either consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results
 
presented in this table are consistent with the GALL Report. The staff's evaluation for AMR items
 
that are consistent with the GALL Report is documented in SER Sections 3.4.2.1 and 3.4.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the main generator and auxiliary system
 
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).
3.4.2.3.6  Main Steam System Summary of Aging Management Evaluation - LRA Table 3.4.2.1.6 The staff reviewed LRA Table 3.4.2.1.6, which summarizes the results of AMR evaluations for the main steam system component groups.
The staff's review of LRA Table 3.4.2.1.6 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAIs as discussed below.
LRA Table 3.4.2.1.6 states that there are no AERMs for carbon and low alloy steel expansion joints, flow element and thermowells in an internal and external containment atmosphere
 
environment. As discussed in RAI 3.4-4, the staff considers a one-time inspection prior to the
 
period of extended operation appropriate for these components.
3-396 In RAI 3.4-7 dated March 30, 2006, the staff requested that the applicant respond to these concerns about the main steam system and justify its position.
In its response dated April 28, 2006, the applicant stated:
As stated in the response to RAI 3.4-8, AmerGen will perform a one-time inspection of carbon steel main steam system piping located inside containment.
 
The one-time inspection will be a visual inspection of the carbon steel piping
 
external surface for loss of material due to corrosion. This inspection will be
 
performed prior to entering the period of extended operation. This onetime
 
inspection is intended to confirm that there is no significant age related
 
degradation occurring on the external carbon steel surfaces of the main steam
 
system located inside containment. Since the piping, valves, expansion joints, flow elements and thermowells are carbon steel, and the environment is the
 
same, results of the one-time inspection of the piping surface will also be
 
applicable to these other carbon steel component external surfaces. If aging
 
degradation is identified, the condition will be documented on an Issue Report and
 
evaluated for corrective actions including additional main steam system piping
 
and component inspection locations.
The staff finds the applicant's response acceptable because the applicant agreed to a one-time inspection of the carbon steel piping external surface for loss of material due to corrosion. The
 
staff's concern described in RAI 3.4-7 is resolved.
LRA Table 3.4.2.1.6 states that no AERMs were identified for carbon and low alloy steel piping and fittings and valve bodies in internal and external containment air and internal treated water
 
environments. As discussed in RAI 3.4-4, the staff considers a one-time inspection prior to the
 
period of extended operation appropriate for these components.
In RAI 3.4-8 dated March 30, 2006, the staff requested that the applicant respond to its concerns about the main steam system and justify its position.
In its response dated April 28, 2006, the applicant stated:
AmerGen will perform a one-time inspecti on of carbon steel main steam system piping located inside containment. The one-time inspection will be a visual
 
inspection of the carbon steel piping external surface for loss of material due to
 
corrosion. This inspection will be performed prior to entering the period of
 
extended operation. This one-time inspection is intended to confirm that there is
 
no significant age related degradation occurring on the external carbon steel
 
surfaces of the main steam system located inside containment. Since the piping
 
and valves are carbon steel, and the environment is the same, results of the
 
one-time inspection of the piping surface will also be applicable to the carbon
 
steel valve external surfaces. If aging degradation is identified, the condition will
 
be documented on an Issue Report and evaluated for corrective actions including
 
additional main steam system piping and component inspection locations.
3-397 The staff finds the applicant's response acceptable because the applicant agreed to one-time inspection of carbon steel main steam system piping located inside containment in accordance
 
with the staff position. The staff's concern described in RAI 3.5-8 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated wi th the main steam system 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).
3.4.2.3.7  Main Turbine and Auxiliary System Summary of Aging Management Evaluation -
LRA Table 3.4.2.1.7 The staff reviewed LRA Table 3.4.2.1.7, which summarizes the results of AMR evaluations for the main turbine and auxiliary system component groups.
LRA Table 3.4.2.1.7 states that the AMRs for t he main turbine and auxiliary system either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results
 
presented in this table are consistent with the GALL Report. The staff's evaluation for AMR items
 
that are consistent with the GALL Report is documented in SER Sections 3.4.2.1 and 3.4.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the main turbine and auxiliary system
 
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).
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERMs, and AMP combinations that are 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 had provided sufficient information to demonstrate that the effects of aging for the steam and power conver sion system components, that are 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).
 
===3.5 Aging===
Management of Containmen t, Structures, Component Supports, and Piping and Component Insulation This section of the SER documents the staff's review of the applicant's AMR results for the containment, structures, component supports, and piping and component insulation components
 
and component groups of the following structures, and commodity groups:
* primary containment 3-398
* reactor building
* chlorination facility
* condensate transfer building
* dilution structure
* emergency diesel generator building
* exhaust tunnel
* fire pond dam
* fire pumphouses
* heating boiler house
* intake structure and canal
* miscellaneous yard structures
* new radwaste building
* office building
* oyster creek substation
* turbine building
* ventilation stack
* component supports commodity group
* piping and component insulation commodity group3.5.1  Summary of Technical Information in the Application In LRA Section 3.5, the applicant provided AMR results for the containment, structures, component supports, and piping and component insulation components and component groups.
 
In LRA Table 3.5.1, "Summary of Aging Management Evaluations in Chapters II and III of
 
NUREG-1801 for Structures and Component Supports," the applicant provided a summary
 
comparison of its AMRs with those evaluated in the GALL Report for the containment, structures, component supports, and piping and component insulation components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of 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 had provided sufficient information to demonstrate that the effects of aging for the containment, structures, component
 
supports, and piping and component insulation components within the scope of license renewal
 
and subject to an AMR will be adequately managed so that the intended function(s) will be
 
maintained consistent with the CLB for the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs during the weeks of October 3-7, 2005, January 23-27, 2006, February 13-17, 2006, and April 19-20, 2006, to confirm the applicant's
 
claim that certain identified AMRs were consistent with the GALL Report. The staff did not repeat 3-399 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 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 the Audit and Review
 
Report and summarized in SER Section 3.5.2.1.
In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.5.2.2. The staff's
 
audit evaluations are documented in the Audit and Review Report and summarized in SER
 
Section 3.5.2.2.
The staff also conducted a technical review of the remaining AMRs that were not consistent with, or not addressed in, the GALL Report. The technical review included evaluating whether all
 
plausible aging effects were identified, and whether the aging effects listed were appropriate for
 
the combination of materials and environments specified. The staff's evaluations are
 
documented in SER Section 3.5.2.3.
For AMRs that the applicant identified as not applicable or not requiring aging management, the staff conducted a review of the AMR line items and the plant's operating experience, to verify the
 
applicant's claims. Details of these reviews are documented in the Audit and Review Report.
Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the containment, structures, component supports, and piping and component insulation
 
components.
Table 3.5-1, provided below, includes a summary of the staff's evaluation of components, aging effects and mechanisms, and AMPs listed in LRA Section 3.5 and addressed in the GALL
 
Report.Table 3.5-1  Staff Evaluation for Containment, Structures, Component Supports, and Piping and Component Insulation in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation BWR Concrete and Steel (Mark I, II, and III) Containments Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-400 Concrete elements:walls, dome, basemat, ring girder, buttresses, containment (as applicable).
(Item 3.5.1-1)
Aging of accessible and inaccessible
 
concrete areas due
 
to aggressive
 
chemical attack, and
 
corrosion of
 
embedded steelISI (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.Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Concrete elements; All (Item 3.5.1-2)
Cracks and distortion due to
 
increased stress
 
levels from
 
settlement Structures Monitoring Program.
 
If a de-watering system
 
is relied upon for
 
control of
 
settlement, then the
 
licensee is to ensure
 
proper functioning of the de-watering system through the
 
period of extended
 
operation.Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Concrete elements:
foundation, sub-foundation (Item 3.5.1-3)
Reduction in foundation strength, cracking, differential
 
settlement due to
 
erosion of porous
 
concrete subfoundation Structures Monitoring Program If a de-watering system is relied
 
upon to control
 
erosion of cement
 
from porous
 
concrete subfoundations, then the licensee is
 
to ensure proper
 
functioning of the de-watering system
 
through the period
 
of extended
 
operation.Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-401 Concrete elements:dome, wall, basemat, ring girder, buttresses, containment, concrete fill-in
 
annulus (as applicable)
(Item 3.5.1-4)
Reduction of strength and
 
modulus of concrete
 
due to elevated
 
temperature A plant-specific aging management
 
program is to be
 
evaluatedNot ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Steel elements:Drywell; torus; drywell head;
 
embedded shell and
 
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)
(Item 3.5.1-5)
Loss of material due to general, pitting
 
and crevice
 
corrosion ISI (IWE) and10 CFR Part 50, Appendix JASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29);
 
Protective Coatings (B.1.33)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.1)
Steel elements:
steel liner, liner
 
anchors, integral
 
attachments (Item 3.5.1-6)
Loss of material due to general, pitting
 
and crevice
 
corrosion ISI (IWE) and10 CFR Part 50, Appendix JASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.1)
Prestressed containment
 
tendons (Item 3.5.1-7)
Loss of prestress due to relaxation, shrinkage, creep, and elevated
 
temperatureTLAA, evaluated inaccordance with 10 CFR 54.21(c)Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Steel and stainless steel elements: vent
 
line, vent header, vent line bellows; downcomers; (Item 3.5.1-8)
Cumulative fatigue damage (CLB fatigue analysis
 
exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.5.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-402 Steel, stainless steel elements, dissimilar metal welds:
 
penetration sleeves, penetration bellows;
 
suppression pool
 
shell, unbraced downcomers (Item 3.5.1-9)
Cumulative fatigue damage (CLB fatigue analysis
 
exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)TLAAThis TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.5.2.2.1)
Stainless steel penetration sleeves, penetration bellows, dissimilar metal welds (Item 3.5.1-10)
Cracking due to stress corrosion
 
cracking ISI (IWE) and10 CFR Part 50, Appendix J, and
 
additional
 
appropriate
 
examinations/
 
evaluations for bellows assemblies
 
and dissimilar metal welds.ASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.1)
Stainless steel ventline bellows, (Item 3.5.1-11)
Cracking due to stress corrosion
 
cracking ISI (IWE) and10 CFR Part 50, Appendix J, and
 
additional
 
appropriate
 
examination/
 
evaluation for bellows assemblies
 
and dissimilar metal welds.ASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.1)
Steel, stainless steel elements, dissimilar metal welds:
 
penetration sleeves, penetration bellows;
 
suppression pool
 
shell, unbraced downcomers (Item 3.5.1-12)
Cracking due tocyclic loading ISI (IWE) and10 CFR Part 50, Appendix J, and
 
supplemented to
 
detect fine cracksTLAA (CLB fatigueanalysis exists);
 
covered by
 
Item 3.5.1-9This TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.5.2.2.1)
Steel, stainless steel elements, dissimilar metal welds: torus;
 
vent line; vent
 
header; vent line bellows; downcomers (Item 3.5.1-13)
Cracking due tocyclic loading ISI (IWE) and10 CFR Part 50, Appendix J, and
 
supplemented to
 
detect fine cracksTLAA (CLB fatigueanalysis exists);
 
covered by
 
Item 3.5.1-8This TLAA is evaluated in Section
 
4.3.
(See SER Section
 
3.5.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-403 Concrete elements:dome, wall, basemat
 
ring girder, buttresses, containment (as applicable)
(Item 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).Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Concrete elements:walls, dome, basemat, ring girder, buttresses, containment, concrete fill-in
 
annulus (as applicable).
(Item 3.5.1-15)
Cracking due to expansion and reaction with
 
aggregate; increase in porosity, 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.Not ApplicableNot Applicable; Steel containment (See SER Section
 
3.5.2.2.1)
Seals, gaskets, and moisture barriers (Item 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) and10 CFR Part 50, Appendix JASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29)Consistent with GALL.
(See SER Section
 
3.5.2.1)Personnel airlock, equipment hatch
 
and CRD hatch
 
locks, hinges, and
 
closure mechanisms (Item 3.5.1-17)
Loss of leak tightness in closed
 
position due to mechanical wear of
 
locks, hinges and
 
closure mechanisms10 CFR Part 50, Appendix J and Plant Technical
 
Specifications10 CFR Part 50, Appendix J (B.1.29) and Plant Technical
 
SpecificationsConsistent with GALL.
(See SER Section
 
3.5.2.1)Steel penetration sleeves and
 
dissimilar metal welds; personnel
 
airlock, equipment
 
hatch and CRD
 
hatch (Item 3.5.1-18)
Loss of material due to general, pitting, and crevice
 
corrosion ISI (IWE) and10 CFR Part 50, Appendix JASME Section XI,Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29)Consistent with GALL.
(See SER Section
 
3.5.2.1)Steel elements:
stainless steel
 
suppression
 
chamber shell (inner
 
surface)
(Item 3.5.1-19)
Cracking due to stress corrosion
 
cracking ISI (IWE) and10 CFR Part 50, Appendix JNot applicableNot applicable; carbon steel
 
suppression
 
chamber Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-404 Steel elements:
suppression
 
chamber liner (interior surface)
(Item 3.5.1-20)
Loss of material due to general, pitting, and crevice
 
corrosion ISI (IWE) and10 CFR Part 50, Appendix JNot applicableNot applicable; carbon steel
 
suppression
 
chamber; no liner.
Steel elements:drywell head and downcomer pipes (Item 3.5.1-21)Fretting or lock up due to mechanical wearISI (IWE)ASME Section XI,Subsection IWE (B.1.27)Consistent with GALL.
(See SER Section
 
3.5.2.1)Prestressed containment:
 
tendons and
 
anchorage components (Item 3.5.1-22)
Loss of material due to corrosionISI (IWL)Not ApplicableNot Applicable; Steel containmentSafety-Related and Other Structures; and Component Supports All Groups except Group 6: interior and
 
above grade exterior
 
concrete (Item 3.5.1-23)
Cracking, loss of bond, and loss of
 
material (spalling, scaling) due to
 
corrosion of
 
embedded steel Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL (See SER Section
 
3.5.2.2.2)
All Groups except Group 6: interior and
 
above grade exterior
 
concrete (Item 3.5.1-24)
Increase in porosityand permeability, cracking, loss of
 
material (spalling, scaling) due to
 
aggressive chemical
 
attack Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL (See SER Section
 
3.5.2.2.2)
All Groups except Group 6: steel
 
components: all
 
structural steel (Item 3.5.1-25)
Loss of material due to corrosion Structures Monitoring Program.
 
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.
Structures Monitoring Program (B.1.31)Consistent with GALL (See SER Section
 
3.5.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-405 All Groups except Group 6: accessible
 
and inaccessible
 
concrete: foundation (Item 3.5.1-26)
Loss of material (spalling, scaling)
 
and cracking due to
 
freeze-thaw Structures Monitoring Program.
 
Evaluation is
 
needed for plants
 
that are located in
 
moderate to severe weathering
 
conditions (weathering index
> 100 day-inch/yr)
(NUREG-1557).
Structures Monitoring Program (B.1.31)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
All Groups except Group 6: accessible
 
and inaccessible interior/exterior
 
concrete (Item 3.5.1-27)
Cracking due to expansion due to reaction with
 
aggregates Structures Monitoring Program.
 
None for inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in
 
ACI 201.2R-77.
Structures Monitoring Program (B.1.31)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Groups 1-3, 5-9: All (Item 3.5.1-28)
Cracks and distortion due to
 
increased stress
 
levels from
 
settlement Structures Monitoring Program.
 
If a de-watering system
 
is relied upon for
 
control of
 
settlement, then the
 
licensee is to ensure
 
proper functioning of the de-watering system through the
 
period of extended
 
operation.
Structures Monitoring Program (B.1.31)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Groups 1-3, 5-9:
foundation (Item 3.5.1-29)
Reduction in foundation strength, cracking, differential
 
settlement due to
 
erosion of porous
 
concrete subfoundation Structures Monitoring Program.
 
If a de-watering system
 
is relied upon for
 
control of
 
settlement, then the
 
licensee is to ensure
 
proper functioning of the de-watering system through the
 
period of extended
 
operation.Not applicableNot applicable; no porous concrete
 
subfoundation or de-watering system (See SER Section
 
3.5.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-406 Group 4: Radialbeam seats in BWR drywell; RPV
 
support shoes for PWR with nozzle
 
supports; Steam
 
generator supports (Item 3.5.1-30)Lock-up due to wearISI (IWF) or Structures
 
Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.1)Groups 1-3, 5, 7-9:below-grade
 
concrete components, such as exterior walls below grade and
 
foundation (Item 3.5.1-31)
Increase in porosityand permeability, cracking, loss of
 
material (spalling, scaling)/aggressive
 
chemical attack;
 
Cracking, loss of
 
bond, and loss of
 
material (spalling, scaling)/corrosion of
 
embedded steel Structures monitoring Program;
 
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.
Structures Monitoring Program (B.1.31);
Examination of
 
representative
 
samples of below-grade
 
concrete, and
 
periodic monitoring of groundwater (non-aggressive
 
environment).Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Groups 1-3, 5, 7-9:
exterior above and below grade
 
reinforced concrete
 
foundations (Item 3.5.1-32)
Increase in porosityand permeability, and loss of strength
 
due to leaching of calcium hydroxide Structures Monitoring Program
 
for accessible areas.
 
None for inaccessible areas if concrete was
 
constructed in accordance with the
 
recommendations in
 
ACI 201.2R-77.
Structures Monitoring Program (B.1.31)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Groups 1-5:
concrete (Item 3.5.1-33)
Reduction of strength and
 
modulus due to
 
elevated temperature A plant-specific aging management
 
program is to be
 
evaluated Structures Monitoring Program (B.1.31) with a 2-year inspection frequency and a
 
quantitative criterion for crack widthConsistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-407 Group 6: Concrete; all (Item 3.5.1-34)
Increase in porosityand permeability, cracking, loss of
 
material due to
 
aggressive chemical
 
attack; cracking, loss of bond, loss of
 
material due to
 
corrosion of
 
embedded steel Inspection of Water-Control
 
Structures or
 
FERC/US 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.
RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Group 6: exterior above and below
 
grade concrete
 
foundation (Item 3.5.1-35)
Loss of material (spalling, scaling)
 
and cracking due to
 
freeze-thaw Inspection of Water-Control
 
Structures or
 
FERC/US 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).
RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-408 Group 6: all accessible/
 
inaccessible
 
reinforced concrete (Item 3.5.1-36)
Cracking due to expansion/reaction with aggregates Accessible areas:
Inspection of
 
Water-Control
 
Structures or
 
FERC/US 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.
RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)
Group 6: exterior above and below
 
grade reinforced
 
concrete foundation
 
interior slab (Item 3.5.1-37)
Increase in porosityand permeability, loss of strength due
 
to leaching of calcium hydroxide For accessible areas, Inspection of
 
Water-Control
 
Structures or
 
FERC/US 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.
RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
3.5.2.2.2)Groups 7, 8: Tank liners (Item 3.5.1-38)
Cracking due to stress corrosion
 
cracking; loss of
 
material due to
 
pitting and crevice
 
corrosion A plant-specific aging management
 
program is to be
 
evaluatedNot ApplicableNot applicable; Theonly stainless steel
 
lined concrete tank at Oyster Creek is
 
the spent fuel pool
 
skimmer surge tank.
 
Aging effects of the
 
stainless steel tank
 
liner are evaluated with the mechanical auxiliary systems.
(See SER Section
 
3.5.2.2.2)
Support members;welds; bolted
 
connections;
 
support anchorage
 
to building structure (Item 3.5.1-39)
Loss of material due to general and
 
pitting corrosion Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL (See SER Section
 
3.5.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-409 Building concrete at locations of
 
expansion and
 
grouted anchors;
 
grout pads for
 
support base plates (Item 3.5.1-40)
Reduction in concrete anchor capacity due to local
 
concrete degradation/
 
service-induced
 
cracking or other
 
concrete aging
 
mechanisms Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL (See SER Section
 
3.5.2.2.2)
Vibration isolation elements (Item 3.5.1-41)
Reduction or loss of isolation function/radiation
 
hardening, temperature, humidity, sustained vibratory loading Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.2.2)
Groups B1.1, B1.2, and B1.3: support
 
members: anchor bolts, welds (Item 3.5.1-42)
Cumulative fatigue damage (CLB fatigue analysis
 
exists)TLAA, evaluated inaccordance with 10 CFR 54.21(c)
Not applicable; no CLB fatigue analyses)Not applicable; no CLB fatigue analyses.
(See SER Section
 
3.5.2.2.2)
Groups 1-3, 5, 6: allmasonry block walls (Item 3.5.1-43)
Cracking due to restraint shrinkage, creep, and
 
aggressive
 
environmentMasonry Wall ProgramMasonry Wall Program (B.1.30)Consistent with GALL.
(See SER Section
 
3.5.2.1)Group 6 elastomer seals, gaskets, and
 
moisture barriers (Item 3.5.1-44)
Loss of sealing due to deterioration of
 
seals, gaskets, and
 
moisture barriers (caulking, flashing, and other sealants)
Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.1)Group 6: exterior above and below
 
grade concrete
 
foundation; interior
 
slab (Item 3.5.1-45)
Loss of material due to abrasion, cavitation Inspection of Water-Control
 
Structures or
 
FERC/US Army
 
Corps of Engineers
 
dam inspections and
 
maintenance RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent with GALL.
(See SER Section
 
3.5.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-410Group 5: Fuel pool liners (Item 3.5.1-46)
Cracking due to stress corrosion
 
cracking; loss of
 
material due to
 
pitting and crevice
 
corrosion Water Chemistry and monitoring of
 
spent fuel pool water level in accordance with
 
technical specifications and
 
leakage from the
 
leak chase
 
channels.Water Chemistry (B.1.2) and
 
monitoring of spent fuel pool water level in accordance with
 
technical specifications Consistent with GALL.
(See SER Section
 
3.5.2.1)Group 6: all metal structural members (Item 3.5.1-47)
Loss of material due to general (steel only), pitting and
 
crevice corrosion Inspection of Water-Control
 
Structures or
 
FERC/US 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.RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.32)Consistent with GALL.
(See SER Section
 
3.5.2.1)Group 6: earthenwater control
 
structures - dams, embankments, reservoirs, channels, canals, and ponds (Item 3.5.1-48)
Loss of material, loss of form due to
 
erosion, settlement, sedimentation, frost action, waves, currents, surface
 
runoff, Seepage Inspection of Water-Control
 
Structures or
 
FERC/US Army
 
Corps of Engineers
 
dam inspections and
 
maintenance
 
programs RG 1.127, Inspection of
 
Water-Control
 
Structures Associated with Nuclear Power
 
Plants (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.1)Support members;welds; bolted
 
connections;
 
support anchorage
 
to building structure (Item 3.5.1-49)
Loss of material/general, pitting, and crevice
 
corrosion Water Chemistryand ISI (IWF)
Water Chemistry (B.1.2) and ASME
 
Section XI, Subsection (IWF)
(B.1.28) for Treated Water EnvironmentConsistent with GALL.
(See SER Section
 
3.5.2.1)Groups B2, and B4:
galvanized steel, aluminum, stainless
 
steel support members; welds;
 
bolted connections;
 
support anchorage
 
to building structure (Item 3.5.1-50)
Loss of material due to pitting and crevice
 
corrosion Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-411 Group B1.1: highstrength low-alloy
 
bolts (Item 3.5.1-51)
Cracking due to stress corrosion
 
cracking; loss of
 
material due to
 
general corrosionBolting IntegrityNot applicableNot applicable; no high strength low-alloy bolts used
 
in Group B1.1
 
supports.Groups B2, and B4:
sliding support
 
bearings and sliding
 
support surfaces (Item 3.5.1-52)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loads Structures Monitoring Program Structures Monitoring Program (B.1.31)Consistent with GALL.
(See SER Section
 
3.5.2.1)Groups B1.1, B1.2, and B1.3: support members: welds;
 
bolted connections;
 
support anchorage
 
to building structure (Item 3.5.1-53)
Loss of material due to general and
 
pitting corrosionISI (IWF)ASME Section XI,Subsection (IWF)
(B.1.28)Consistent with GALL.
(See SER Section
 
3.5.2.1)Groups B1.1, B1.2, and B1.3: Constant
 
and variable load
 
spring hangers;
 
guides; stops; (Item 3.5.1-54)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loadsISI (IWF)ASME Section XI,Subsection (IWF)
(B.1.28)Consistent with GALL.
(See SER Section
 
3.5.2.1)Groups B1.1, B1.2, and B1.3: Sliding
 
surfaces (Item 3.5.1-56)
Loss of mechanical function due to
 
corrosion, distortion, dirt, overload, fatigue due to vibratory and cyclic
 
thermal loadsISI (IWF)ASME Section XI,Subsection (IWF)
(B.1.28)Consistent with GALL.
(See SER Section
 
3.5.2.1)Groups B1.1, B1.2, and B1.3: Vibration
 
isolation elements (Item 3.5.1-57)
Reduction or loss of isolation function/
 
radiation hardening, temperature, humidity, sustained vibratory loadingISI (IWF)ASME Section XI,Subsection (IWF)
(B.1.28)Consistent with GALL.
(See SER Section
 
3.5.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-412 Galvanized steel and aluminum
 
support members; welds; bolted
 
connections;
 
support anchorage
 
to building structure
 
exposed to
 
air - indoor
 
uncontrolled (Item 3.5.1-58)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.5.2.1)Stainless steel support members; welds; bolted
 
connections;
 
support anchorage
 
to building structure (Item 3.5.1-59)NoneNoneNoneConsistent with GALL.
(See SER Section
 
3.5.2.1)The staff's review of the containment, structures, component supports, and piping and component insulation component groups followed one of several approaches. One approach, documented in SER Section 3.5.2.1, discusses the staff's review of the 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, discusses the staff's
 
review of the 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, discusses the staff's review of the AMR results for components that the
 
applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's
 
review of AMPs credited to manage or monitor aging effects of the containment, structures, component supports, and piping and component insulation components is documented in SER
 
Section 3.0.3.3.5.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the effects of aging related to the containment, structures, component
 
supports, and piping and component insulation components:
* Water Chemistry (B.1.2)
* One-Time Inspection (B.1.24)
* ASME Section XI, Subsection IWE (B.1.27)
* ASME Section XI, Subsection IWF (B.1.28)
* 10 CFR Part 50, Appendix J (B.1.29) 3-413
* Masonry Wall Program (B.1.30)
* RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants (B.1.32)
* Structures Monitoring Program (B.1.31)
* Protective Coating Monitoring and Maintenance Program (B.1.33)
 
Staff Evaluation. In LRA Tables 3.5.2.1.1 through 3.5.2.1.19, the applicant provided a summary of AMRs for the containment, structures, component supports, and piping and component
 
insulation components and identified which AMRs it considered to be consistent with the GALL
 
Report.For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report 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 that the AMR is 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 AMP
 
identified in the GALL Report. 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. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant is 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 com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component that was under review. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the AMR
 
line item of the different component was applicable to the component under review and whether
 
the AMR was valid for the site-specific conditions.
3-414 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. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. The staff verified whether
 
the identified exceptions to the GALL 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 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review Report. The staff did not repeat its review of the matters described in the
 
GALL Report; however, the staff did verify that the material presented in the LRA was applicable
 
and that the applicant identified the appropriate GALL Report AMRs.
The staff 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
 
containment, structures, component supports, and piping and component insulation components
 
subject to an AMR. On the basis of its audit and review, the staff determined 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.
Conclusion. 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes that the applicant has demonstrated that the effects of aging for these components will
 
be adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report, for the containment, structures, component supports, and piping and component insulation components.
 
The applicant provided information about how it will manage the following aging effects:
PWR and BWR Containment:
3-415
* aging of inaccessible concrete areas
* cracks and distortion due to increased stress levels from settlement; reduction of foundation strength, cracking and differential settlement due to erosion of porous
 
concrete subfoundations, if not covered by 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 stress corrosion cracking
* cracking due to cyclic loading
* loss of material (scaling, cracking, and spalling) due to freeze-thaw
* cracking due to expansion and reaction with aggregate and increase in porosity and permeability due to leaching of calcium hydroxide Safety-Related and Other Structures and Component Supports:
* aging of structures not covered by structures monitoring program
* aging management of inaccessible areas
* reduction of strength and modulus of concrete structures due to elevated temperature
* aging management of inaccessible areas for Group 6 structures
* cracking due to stress corrosion cracking and loss of material due to pitting and crevice corrosion
* aging of supports not covered by structures monitoring program
* cumulative fatigue damage due to cyclic loading Quality Assurance for Aging Management of Nonsafety-Related Components
 
Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL Report recommends
 
further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether
 
it adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria in SRP-LR Section 3.5.2.2. Details of the staff's
 
audit are documented in the Audit and Review Report. The staff's evaluation of the aging effects
 
is discussed in the following sections.
3.5.2.2.1  PWR and BWR Containments
 
The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which addresses several areas discussed below.
3-416 Aging of Inaccessible Concrete Areas. In LRA Section 3.5.2.2.1.1, the applicant stated that aging of inaccessible areas of concrete containments, with reference to the further evaluation in
 
SRP-LR Section 3.5.2.2.1.1, is not applicable because OCGS has a Mark I steel containment.
 
The staff finds acceptable the applicant's evaluation that this aging effect is not applicable.
Cracks and Distortion Due to Increased Stress Levels from Settlement; Reduction of Foundation Strength, Cracking and Differential Settlement Due to Erosion of Porous Concrete Subfoundations, If Not Covered by Structures Monitoring Program. In LRA Section 3.5.2.2.1.2, the applicant stated that cracks and distortion of concrete subfoundations, with reference to the
 
further evaluation in SRP-LR Section 3.5.2.2.1.2, are not applicable because OCGS has a Mark I
 
steel containment. The staff finds acceptable the applicant's evaluation that this aging effect is
 
not applicable.
Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.
In LRA Section 3.5.2.2.1.3, the applicant addressed reduction of strength and modulus of concrete due to elevated temperatures.
SRP-LR Section 3.5.2.2.1.3 states that reduction of strength and modulus of concrete due to elevated temperatures could occur in PWR and BWR concrete and steel containments. The implementation of 10 CFR 50.55a and ASME Code Section XI, Subsection IWL would not be
 
able to identify the reduction of strength and modulus of concrete due to elevated temperature.
 
Subsection CC-3400 of ASME Code Section III, Division 2, specifies the concrete temperature
 
limits for normal operation or any other long-term period. The GALL Report recommends further
 
evaluation of a plant-specific AMP if any portion of the concrete containment components
 
exceeds specified temperature limits (i.e., general area temperature greater than 66 &deg;C (150 &deg;F)and local area temperature greater than 93 &deg;C (200 &deg;F)).
LRA Section 3.5.2.2.1.3 states that the normal operating temperature inside the primarycontainment drywell varies from 139 &deg;F (at elevation 55') to 256 &deg;F (at elevation 95'). The
 
containment structure is a BWR Mark I steel containment, which is not affected by general area temperature of 150 &deg;F and local area temperature of 200 &deg;F. Concrete for the reactor pedestal
 
and the drywell floor slab (fill slab) are located below elevation 55' and are not exposed to the
 
elevated temperature. The biological shield wall ex tends from elevation 37' 3" to 82' 2" and isexposed to a temperature range of 139 &deg;F to 184 &deg;F. The wall is a composite steel-concrete
 
cylinder surrounding the reactor vessel framed with 27 inches deep wide flange columns covered
 
with steel plate on both sides. The area between the plates is filled with high-density concrete to
 
satisfy the shielding requirements. The steel columns provide the intended structural support
 
function and the encased high-density concrete provides shielding requirements. The encased
 
concrete is not accessible for inspection. The elevated drywell temperature concern was
 
evaluated as a part of the Integrated Plant A ssessment Systematic Evaluation Program (SEP)
Topic III-7.B. The evaluation concluded that the te mperature would not adversely affect the structural and shielding functions of the wall. The elevated drywell temperature was also
 
identified as a concern for the reactor building drywell shield wall. Further evaluation for this wall
 
is discussed in SER Section 3.5.2.2.2.
3-417 The staff finds acceptable the applicant's further evaluation because the existing elevated temperature condition in the drywell will not impair the intended functions of the steel
 
containment shell or the shielding concrete of the biological shield wall.
Based on the above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.1.3. For those LRA line items that apply to this SRP-LR section, the staff
 
determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
Loss of Material Due to General, Pitting and Crevice Corrosion. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4.
In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to general, pitting, and crevice corrosion in steel elements of accessible and inaccessible areas for BWR containment.
SRP-LR Section 3.5.2.2.1.4 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 the ASME Section XI, Subsection
 
IWE, and 10 CFR Part 50, Appendix J Programs, 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.
LRA Section 3.5.2.2.1.4 states the potential for loss of material, due to corrosion, in inaccessible areas of the containment drywell shell was first recognized in 1980 when water was discovered
 
coming from the sand bed region drains. Corrosion was later confirmed by UT measurements
 
taken during the 1986 refueling outage. As a result, several corrective actions were initiated to
 
determine the extent of corrosion, evaluate the integrity of the drywell, mitigate accelerated
 
corrosion, and monitor the condition of containment surfaces. The corrective actions include
 
extensive UT measurements of the drywell shell thickness, removal of the sand in the sand bed
 
region, cleaning and coating of exterior surfaces in areas where sand was removed, and an
 
engineering evaluation to confirm the drywell structural integrity. In 1987, a corrosion monitoring
 
process was established for the drywell shell above the sand bed region to ensure that the
 
containment vessel is capable of performing its intended functions. Elements of the program have been incorporated into the ASME Section XI, Subsection IWE Program and provide the
 
following:
* periodic UT inspections of the shell thickness at critical locations
* calculations which establish conservative corrosion rates
* projections of the shell thickness based on the conservative corrosion rates
* demonstration that the minimum required shell thickness is in accordance with ASME Code 3-418 Additionally, the staff was notified of this potential generic issue that later became the subject of IN 86-99 and GL 87-05.
The applicant provided the following summary of the operating experience, monitoring activities, and corrective actions taken to ensure that the primary containment will perform its intended
 
functions:
Drywell Shell in the Sand Bed Region. The drywell shell is fabricated from ASTM A-212-61T Grade B steel plate. The shell was coated on the inside surface with an inorganic zinc (carboline
 
carbozinc 11) and on the outside surface with "red lead" primer identified as TT-P-86C Type I.
 
The red lead coating covered the entire exterior of the vessel from elevation 8' 11.25" (fill slab
 
level) to elevation 94' (below drywell flange).
The sand bed region was filled with dry sand as specified by ASTM 633. Leakage of water from the sand bed drains was observed during the 1980 and 1983 refueling outages. The applicant
 
performed a series of investigations to identify the source of the water and its leak path and
 
concluded that the source of water was from the reactor cavity, which is flooded during refueling
 
outages.With the presence of water in the sand bed region, the applicant took extensive UT thickness measurements of the drywell shell to determine whether degradation had occurred. These
 
measurements corresponded to known water leaks and indicated that wall thinning had occurred
 
in this region.
With reduced thickness readings, the applicant obtained additional thickness measurements to determine the vertical profile of the thinning. A trench was excavated inside the drywell, in the
 
concrete floor, in the area where thinning was most severe. Measurements taken from the
 
excavated trench indicated that thinning of the embedded shell in concrete were no more severe
 
than those taken at the floor level and became less severe at the lower portions of the sand bed
 
region. Conversely, measurements taken in areas with no floor level thinning showed no significant thinning in the embedded shell. Aside fr om UT thickness measurements by plant staff, an independent analysis by the EPRI NDE Center, and the GE Ultra Image III "C" scan
 
topographical mapping system confirmed the UT re sults. The GE ultra image results were used as baseline profile to track continued corrosion.
To validate UT measurements and characterize the form of damage and its cause (i.e., due to the presence of contaminants, microbiological species, or both) core samples of the drywell shell
 
were obtained at seven locations. The core samples validated the UT measurements and
 
confirmed that the corrosion of the drywell was due to the presence of oxygenated wet sand and
 
exacerbated by chloride and sulfate in the sand bed region. Contaminate concentration due to
 
alternate wetting and drying of the sand also may have contributed to the corrosion. Therefore, the applicant concluded that the optimum method to mitigate the corrosion was by removal of the
 
sand to break up the galvanic cell, removal of the corrosion product from the shell, and
 
application of a protective coating.
Removal of sand was initiated during 1988 by the removal of sheet metal from around the vent headers to provide access to the sand bed from the torus room. During operating cycle 13 some 3-419 sand was removed and access holes cut into the sand bed region through the shield wall. The work was finished in December 1992. After sand removal, the applicant found the concrete
 
surface below the sand unfinished with improper provisions for water drainage. Corrective
 
actions taken in this region during 1992 included (1) cleaning of loose rust from the drywell shell
 
followed by application of epoxy coating and (2) removal of the loose debris from the concrete
 
floor followed by rebuilding and reshaping of the floor with epoxy to allow drainage of any water
 
that may leak into the region. UT measurements taken from the outside after cleaning verified
 
loss of material projections that had been made based on measurements taken from the inside
 
of the drywell. There were, however, some areas thinner than projected, but in all cases
 
engineering analysis determined that the drywell shell thickness satisfied ASME Code
 
requirements. The protective coating monitoring and maintenance program was revised to
 
include monitoring of the coatings of exterior surfaces of the drywell in the sand bed region.
The coated surfaces of the former sand bed region were inspected during refueling outages of 1994, 1996, 2000, and 2004. These inspections showed no coating failure or signs of
 
deterioration. Therefore, the applicant concluded that corrosion in the sand bed region had been
 
arrested and expected no further loss of material. Monitoring of the coating in accordance with
 
the protective coating monitoring and maintenance program will continue to ensure that the
 
containment drywell shell maintains its intended function during the period of extended operation.
The staff reviewed the applicant's operating experience and proposed aging management activities to address degradation of the primary containment drywell area in the former sand bed
 
region as part of its evaluation of the ASME Subsection IWE Program. The staff identified five
 
OIs and found that the applicant had not provided sufficient information to conclude that the
 
effects of aging for the primary containment in the former sand bed region will be adequately
 
managed so that the intended functions will be maintained during the period of extended
 
operation, as required by 10 CFR 54.21(a)(3). The staff's evaluation is documented in SER
 
Section 4.7.2.
Drywell Shell Above Sand Bed Region. The UT investigation phase (1986 through 1991) also identified loss of material due to corrosion in the upper regions of the drywell shell. These
 
regions were handled separately from the sand bed region because of the significant difference
 
in corrosion rate and physical difference in design. Corrective action for these regions provided a
 
corrosion allowance by demonstrating, through analysis, that the original drywell design pressure
 
was conservative. Amendment 165 to the OCGS technical specifications reduced the drywell
 
design pressure from 62 psig to 44 psig. The new design pressure coupled with measures to
 
prevent water intrusion into the gap between the drywell shell and the concrete will allow the
 
upper portion of the drywell to meet ASME Code requirements.
Originally, the knowledge of the extent of corrosion was based on UT measurements completely around the inside of the drywell at several elevations. At each elevation, a belt-line sweep took
 
readings on as little as 1-inch centers wherever thickness changed between successive nominal
 
6-inch centers. 6" by 6" grids that exhibited the worst metal loss around each elevation were
 
established by this approach and included in the drywell corrosion inspection program.
As experience increased with each data collection campaign, only grids showing evidence of a change were retained in the inspection program. Additional assurance of the adequacy of this 3-420 inspection plan was obtained by a completely randomized inspection of 49 grids showing that all inspection locations satisfied ASME Code require ments. Evaluation of UT measurements taken through 2000 concluded that corrosion no longer occurs at two (2) elevations, the third elevation
 
undergoes a corrosion rate of 0.6 mils per year, and the fourth 1.2 mils per year. The recent UT
 
measurements (2004) confirmed that the corrosion rate continues to decline. The 2 elevations
 
that previously exhibited no increase in corrosion continue the trend to no corrosion increase.
 
The rate of corrosion for the third elevation decreased from 0.6 to 0.4 mils per year. The rate of
 
corrosion for the fourth elevation decreased from 1.2 to 0.75 mils per year. After each UT
 
examination campaign, an engineering analysis is performed to ensure the required minimum
 
thickness through the period of extended operation. Thus, corrosion of the drywell shell is
 
considered a TLAA further described in SER Section 4.7.2.
The applicant concluded that the corrective actions taken and continued monitoring of the drywellfor loss material through the ASME Section XI, Subsection IWE, Protective Coating Monitoring
 
and Maintenance, and 10 CFR Part 50, Appendix J Programs provide reasonable assurance that
 
loss of material in inaccessible areas of the drywell will be detected prior to a loss of an intended
 
function. Observed conditions with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process. The ASME Section XI, Subsection
 
IWE, Protective Coating Monitoring and Maintenance, and 10 CFR Part 50, Appendix J
 
Programs are evaluated in SER Section 3.0.
The staff noted that the applicant had not addressed aging management of the portion of the drywell shell embedded in the drywell concrete floor. This area is inaccessible for inspection but
 
potentially subject to wetting on both inside and outside surfaces. During the audit, the staff
 
requested that the applicant submit its AMR for this inaccessible portion of the drywell shell.
The applicant stated that the embedded portion of the drywell shell is exempt from visual examination in accordance with IWE-1232. Pressure testing in accordance with 10 CFR Part 50, Appendix J, Type A test is credited for managing aging effects of inaccessible portions of the
 
drywell shell consistent with the GALL Report.
The applicant identified that the GALL Report, Volume 2, item II.B1.1-2, AMP column states that loss of material due to corrosion is not significant if the following conditions are satisfied:
* concrete meeting the specifications of ACI 318 or 349 and use of the guidance of 201.2R for containment shell or liner
* concrete monitoring to ensure that it is free of cracks providing paths for water seepage to the surface of the containment shell or liner
* aging management of the moisture barrier, at the junction where the shell or liner becomes embedded, is subject to aging management in accordance with ASME Section XI, Subsection IWE requirements
* prompt clean-up of water ponding on the containment concrete floor when detected If any of these conditions cannot be satisfied a plant-specific AMP for corrosion is necessary.
3-421 The applicant indicated that its AMR results satisfy these requirements and that a plant-specific AMP is not required for corrosion of the embedded drywell shell. The concrete meets the
 
recommendations of ACI 318 and the guidance of ACI 201.2R. The drywell concrete floor will be
 
monitored for cracks under the Structures Monitoring Program. OCGS design does not include a
 
moisture barrier; however, the design provides a 9-inch high curb (minimum) around the entire drywell floor (except at two trenches) to prevent any contact between water accumulated on the
 
floor and the drywell shell. The curb is considered part of the drywell concrete floor and
 
inspected for cracking under the Structures Monitoring Program. The drywell floor is designed to
 
slope away from the drywell shell towards the drywell sump for proper drainage. The sump level
 
is monitored in the main control room in accordance with technical specifications, and actions are
 
taken to ensure that technical specifications limits are not violated. If the sump fills and the
 
overflow leak rate cannot be monitored, a plant shutdown will be required to regain leak rate
 
monitoring capability and to determine the source of the leak.
The applicant further stated that during the investigation period to determine the extent of corrosion in the exterior surfaces of the sand bed region two trenches were excavated in the
 
drywell concrete floor to expose the embedded dryw ell shell so that UT thickness measurements could be taken from inside the drywell in the sand bed region. Visual inspection and UT
 
measurements did not identify corrosion as a concern on the exposed embedded drywell shell
 
inside the drywell within the excavated trenches. The two trenches were sealed with an
 
elastomer to prevent water intrusion into the embedded shell. Prior to the period of extended
 
operation a one-time visual inspection of the embedded drywell shell within the two trenches will
 
be performed by removal of the sealant and exposure of the embedded shell. Inspection and
 
acceptance criteria will be in accordance with IWE. If visual inspection reveals corrosion that
 
could impact drywell integrity, corrective actions will be initiated in accordance with the corrective
 
action process to ensure that the drywell remains capable of performing its intended function.
 
Following these inspections, the trenches will be resealed for continued protection of the
 
embedded shell. In addition, one-time UT measurements will be taken and corrective actions
 
initiated in accordance with the corrective action process to ensure that the drywell is capable of
 
performing its intended function.
In its letter dated April 4, 2006, the applicant committed (Commitment No. 27) to the following: A visual examination of the drywell shell in the drywell floor inspection access trenches will be
 
performed to assure that the drywell steel remains intact. If degradation is identified, the drywell
 
shell condition will be evaluated and corrective actions taken as necessary. These surfaces will either be inspected as part of the scope of the ASME Section XI, Subsection IWE Program, or
 
they will be restored to the original design configuration with concrete or other suitable material to prevent moisture collection in these areas.
In addition to its previous commitment to perform one-time visual examinations of the drywell shell in the areas exposed by the trenches in the bottom of the drywell, in its letter dated
 
May 1, 2006, the applicant committed (Commitment No. 27) to taking one-time UT
 
measurements to confirm the adequacy of the shell thickness in these areas, providing further
 
assurance that the drywell will remain capable of performing its intended function. This
 
commitment will be performed prior to the period of extended operation.
3-422 The applicant also noted that the inaccessible drywell shell in the sand bed region became accessible (from the outside surface) after removal of sand in 1992. The interface of the shell
 
and the sand bed floor was cleaned, coated, and sealed with silicon sealant. The periodic
 
coating inspection has not identified any coating degradation at the shell-concrete interface
 
indicating corrosion in the embedded portion of the shell.
The staff concludes that the applicant will determine, based on the results of the inspection of the two trenches, the condition of the inaccessible portion of the drywell shell embedded in the
 
drywell concrete floor prior to the period of extended operation, and that corrective actions will be
 
taken as necessary if degradation is found. The staff finds the applicant's approach to aging
 
management of the inaccessible portion of the drywell shell embedded in the drywell concrete
 
floor acceptable.In its evaluation of the applicant's ASME Section XI, Subsection IWE Program the staff evaluated the degradation history of the applicant's containment and the adequacy of its aging
 
management commitments for the period of extended operation. Five OIs are documented in
 
SER Section 4.7.2. After this review and evaluation of the containment corrosion history and the
 
applicant's proposed aging management activities for the period of extended operation, the staff
 
finds that the applicant has not met the criteria of SRP-LR Section 3.5.2.2.1.4 for further
 
evaluation and not demonstrated that the effects of aging will be adequately managed so that the
 
intended functions will be maintained during the period of extended operation, as required by
 
10 CFR 54.21(a)(3).
Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA Section 3.5.2.2.1.5 states that loss of prestress of concrete containments is not applicable since
 
OCGS has a Mark I steel containment. The staff finds acceptable the applicant's evaluation that
 
this aging effect is not applicable since OCGS has a Mark I steel containment.
Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER
 
Section 4.6 documents the staff's review of the applicant's evaluation of this TLAA.
Cracking Due to Stress Corrosion Cracking (SCC). The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7.
In LRA Section 3.5.2.2.1.7, the applicant addressed cracking of stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds due to SCC.
SRP-LR Section 3.5.2.2.1.7 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. Cracking due to SCC also could occur in stainless steel vent line bellows for BWR containments. The existing program relies on the ASME Section XI, Subsection IWE and
 
10 CFR Part 50, Appendix J Programs to manage this aging effect. The GALL Report
 
recommends further evaluation of additional appropr iate examinations and evaluations to detect these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar
 
metal welds, and stainless steel vent line bellows.
3-423 LRA Section 3.5.2.2.1.7 states that cracking of containment penetrations (including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading is considered
 
metal fatigue and addressed as a TLAA in LRA Section 4.6. SCC is an aging mechanism that
 
requires the simultaneous action of a corrosive environment, sustained tensile stress, and a
 
susceptible material. Elimination of any one of these elements eliminates susceptibility to SCC.
 
Stainless steel elements of primary containment and the containment vacuum breakers system, including dissimilar welds, are susceptible to SCC. However these elements are located inside
 
the containment drywell or outside the drywell in the reactor building and are not subject to a
 
corrosive environment as discussed below. The drywell is made inert with nitrogen to render the
 
primary containment atmosphere non-flammable by maintaining the oxygen content below
 
4 percent by volume during normal operation. The normal operating average temperature inside the drywell is less than 139 &deg;F and the relative humidity range is 20 to 40 percent. The reactor building normal operating temperature range is 65 &deg;F to 92 &deg;F except in the trunnion room where the temperature can reach 140 &deg;F. The relative humidity is 100 percent maximum. Both the
 
containment atmosphere and indoor air environments are noncorrosive (chlorides <150 ppb, sulfates <100 ppb, and fluorides <150 ppb). Thus, SCC is not expected to occur in the
 
containment penetration bellows, penetration sleeves, and containment vacuum breakers
 
expansion joints, piping and piping components, and dissimilar metal welds. A review of plant
 
operating experience identified no cracking of the components and primary containment leakage
 
has not been identified as a concern. Therefore, the existing 10 CFR Part 50, Appendix J Program leak tests and the ASME Section XI, Subsection IWE Program are adequate to detect
 
cracking. Observed conditions with potential impact on an intended function are evaluated or corrected in accordance with the corrective action process. The ASME Section XI, Subsection
 
IWE and 10 CFR Part 50, Appendix J Programs are described in SER Section 3.0.
The staff requested that the applicant address whether the problems encountered at Dresden and Quad Cities Power Plants with cracking of expansion bellows apply to OCGS. The applicant
 
stated that the problems were unique to the Dresden and Quad Cities Power Plant and do not
 
apply to OCGS. On the basis that the environment conducive to SCC exists at OCGS, the staff
 
finds the applicant's further evaluation for cracking due to SCC acceptable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.1.7. For those line items that apply to LRA Section 3.5.2.2.1.7, the staff determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
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. In LRA Section 3.5.2.2.1.7, the applicant stated that cracking due to cyclic loading is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in
 
accordance with 10 CFR 54.21(c)(1). SER Section 4.6 documents the staff's review of the
 
applicant's evaluation of this TLAA.
Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. In LRA Section 3.5.2.2.1.8, the applicant stated that loss of material due to freeze-thaw of concrete
 
containments is not applicable since OCGS has a Mark I steel containment. The staff finds 3-424 acceptable the applicant's evaluation that this aging effect is not applicable since OCGS has a Mark I steel containment.
Cracking Due to Expansion and Reaction with Aggregate, and Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide. In LRA Section 3.5.2.2.1.8, the applicant stated that cracking due to expansion and reaction with aggregates of concrete containments is
 
not applicable since OCGS has a Mark I steel containment. The staff finds acceptable the
 
applicant's evaluation that this aging effect is not applicable since OCGS has a Mark I steel
 
containment.
 
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, which addresses several areas discussed below.
Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.
In LRA Section 3.5.2.2.2.1, the applicant addressed further evaluations in accordance with the January 2005 draft SRP-LR. The applicant provided its reconciliation to the further evaluations
 
listed in the September 2005 SRP-LR in Attachment 3, items T-04, T-06, and T-11 of its
 
reconciliation document. The staff reviewed the reconciliation document against the criteria in the
 
September 2005 SRP-LR Section 3.5.2.2.2.1, for items (1), (2), and (3). Based on its review of
 
LRA Section 3.5.2.2.2.1, the staff determined that the applicant's reconciliation also applies to
 
items (4), (5), and (6) in SRP-LR Section 3.5.2.2.2.1. Item (7) is not applicable to OCGS.
SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of certain structure and aging effect combinations 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, 9 structures (T-04), (2) increase in porosity and
 
permeability, cracking, loss of material (spalling, scaling) due to aggressive chemical attack for
 
Groups 1-5, 7, 9 structures (T-06), (3) loss of material due to corrosion for Groups 1-5, 7, 8
 
structures (T-11), (4) loss of material (spalling, scaling) and cracking due to freeze-thaw for
 
Groups 1-3, 5, 7-9 structures, (5) cracking due to expansion and reaction with aggregates for
 
Groups 1-5, 7-9 structures, (6) cracks and distortion due to increased stress levels from
 
settlement for Groups 1-3, 5-9 structures, and (7) reduction in foundation strength, cracking, and
 
differential settlement due to erosion of porous concrete subfoundation for Groups 1-3, 5-9
 
structures. The GALL Report recommends further evaluation only for structure and aging effect
 
combinations not within the Structures Monitoring Program.
The SRP-LR further states that lock-up due to wear could occur for Lubrite radial beam seats in BWR drywell, RPV support shoes for PWR with nozzle supports, steam generator supports, and
 
other sliding support bearings and sliding support surfaces. The existing program relies on the Structures Monitoring or ASME Section XI, Subsection IWF Programs to manage this aging
 
effect. The GALL Report recommends further evaluation only for structure/aging effect combinations not within the ASME Section XI, Subsection IWF or Structures Monitoring
 
Programs.
3-425 In Attachment 3, item T-04, of its reconciliation document, the applicant stated that this item change requires no change the LRA. The wording for further evaluation was changed from "not
 
required if within the scope of the applicant's structures monitoring program" to "required if not
 
within the scope of the applicant's structures monitoring program." This item is within the scope
 
of the Structures Monitoring Program; therefore, no further evaluation is required.
In Attachment 3, item T-06, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The environment for this item, concrete: interior and
 
above grade exterior, changed from "aggressive environment" to "air - indoor uncontrolled or air - outdoor." The wording for further evaluation was changed from "not required if within the
 
scope of the applicant's structures monitoring program" to "required if not within the scope of the
 
applicant's structures monitoring program." Each instance of use of this item is within the scope
 
of the Structures Monitoring Program; therefore, no further evaluation is required.
In Attachment 3, item T-11, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The wording for further evaluation was changed from
 
"not required if within the scope of the applicant's structures monitoring program" to "required if
 
not within the scope of the applicant's structures monitoring program." This item is within the
 
scope of Structures Monitoring Program; therefore, no further evaluation is required.
The staff finds acceptable the applicant's determination that no further evaluation is required on the basis that the Structures Monitoring Program is credited for aging management.
Based on the program above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.1. For those LRA line items that apply to this SRP-LR section, the staff
 
determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
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. The staff reviewed LRA Section 3.5.2.2.2.2 and  of the applicant's reconciliation document against the criteria in SRP-LR
 
Section 3.5.2.2.2.2.
In Attachment 3, item T-01, of its reconciliation document, the applicant addressed cracking due to freeze-thaw in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures (T-01). The staff reviewed the reconciliation document against the criteria in SRP-LR
 
Section 3.5.2.2.2.2.1 SRP-LR Section 3.5.2.2.2.2.1 states that 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 (T-01). The GALL Report recommends further evaluation of this aging effect for
 
inaccessible areas of these groups of structures for plants located in moderate to severe
 
weathering conditions.
In Attachment 3, item T-01, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. For inaccessible areas, as described in UFSAR 3-426 Section 3.8.4.6, "Materials, Quality Control and Special Construction Techniques," concrete is designed consistent with ACI 318 recommendations to be workable with homogeneous structure
 
which, when hardened, will have durability, impermeability, and the specified strength. Testing of
 
concrete was in accordance with ASTM standards specified in ACI 318 to ensure that the
 
desired quality of concrete was furnished. The strength quality of the concrete was established
 
by tests by a maximum slump of 4 inches in advance of the beginning of operations. Specimens
 
were tested and cured in accordance with ASTM C39.
Review of design and construction documents indicated that the specified air content is 4 to 6 percent. The water-to-cement ratio was based on the strength required by the design considering
 
the maximum slump of 4 inches. Curves representing the relation between the water content and
 
the average 28-day compressive strength were established for a range of values including the
 
compressive strengths specified. The curves were established by at least three points, each
 
representing average values from at least four test specimens. The maximum allowable water
 
content for each class of concrete was determined from the curves and corresponded to a
 
compressive strength of 15 percent greater than that specified. A review of documentation for a
 
sample of Class 4LA (4000 psi) concrete cylinder tests shows that the 28-day strength meets or exceeds the specified 4000 psi compressive strength. Inspections conducted in accordance with
 
the Structures Monitoring Program have identified minor loss of material (spalling, scaling) and
 
cracking which could be attributed to freeze-thaw in accessible areas. Engineering evaluation
 
concluded that the loss of material and cracking had no significant impact on the intended
 
function of the affected structure. From this evaluation, the applicant concluded that loss of
 
material and cracking due to freeze-thaw is not significant for inaccessible areas. Thus, no
 
plant-specific AMP is required.
In Attachment 3, item T-03, of its reconciliation document, the applicant addressed cracking due to expansion and reaction with aggregates in below-grade inaccessible concrete areas for
 
Groups 1-5 and 7-9 structures (T-03). The staff reviewed the reconciliation document against the
 
criteria in SRP-LR Section 3.5.2.2.2.2.2.
SRP-LR Section 3.5.2.2.2.2.2 states that cracking due to expansion and reaction with aggregates could occur in below-grade inaccessible concrete areas for Groups 1-5 and 7-9
 
structures (T-03). The GALL Report recommends further evaluation of inaccessible areas of
 
these groups of structures if concrete was not constructed in accordance with the ACI 201.2R-77
 
recommendations.
In Attachment 3, item T-03, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The wording for further evaluation was changed from
 
"not required if within the scope of the applicant's structures monitoring program and stated
 
conditions are satisfied for inaccessible areas" to "required if not within the scope of the
 
applicant's structures monitoring program, or concrete was not constructed as stated for
 
inaccessible areas." This item is within the scope of the Structures Monitoring Program;
 
therefore, no further evaluation is required. The staff finds this acceptable because the item has
 
been included within the scope of the program.
In Attachment 3, item T-08, of its reconciliation document, the applicant addressed cracks and distortion due to increased stress levels from settlement and reduction of foundation strength, 3-427 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 (T-08).
SRP-LR Section 3.5.2.2.2.2.3 states 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 could occur in below-grade inaccessible concrete
 
areas of Groups 1-3, 5, and 7-9 structures (T-08). The existing program relies on the Structures
 
Monitoring Program to manage these aging effects. Some plants may rely on a de-watering
 
system to lower the site ground water level. If the plant's CLB credits a de-watering system, the
 
GALL Report recommends verification of the continued functionality of the de-watering system
 
during the period of extended operation. The GALL Report recommends no further evaluation if
 
this activity is included within the scope of the applicant's Structures Monitoring Program.
In Attachment 3, item T-08, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. OCGS does not rely on a de-watering system for control
 
of settlement. The wording for further evaluation was changed from "not required if within the
 
scope of the applicant's structures monitoring program" to "required if not within the scope of the
 
applicant's Structures Monitoring Program." This item is within the scope of the Structures
 
Monitoring Program; therefore, no further evaluation is required. The staff finds this acceptable
 
because the item has been included within the scope of the program.
In LRA Section 3.5.2.2.2.2, the applicant addressed 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 in
 
below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures.
SRP-LR Section 3.5.2.2.2.2.4 states that 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 could occur in below-grade
 
inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends
 
further evaluation of plant-specific programs to manage these aging effects in inaccessible areas
 
of these groups of structures if their environment is aggressive.
LRA Section 3.5.2.2.2.2 states that recent groundwater analysis results (pH: 5.6 to 6.4, chlorides: 3 to 138 ppm, and sulfates: 7 to 73 ppm) show that the groundwater is not aggressive
 
for Groups 2-3, 8-9 structures. Therefore, further evaluation of below-grade inaccessible
 
concrete areas for Groups 2, and 8-9 structures is not required. Similarly, inaccessible areas of
 
Group 3 structures are not exposed to aggressive environments except for fire water
 
pump-houses (fresh water pump-house only), so further evaluation of Group 3 structures other
 
than the fresh water pump-house is not required. The fresh water pump-house reinforced
 
concrete is subject to slightly aggressive water from the fire pond dam (pH: 4.8, chlorides: 12 ppm, and sulfates: 6 ppm). Inaccessible areas will be inspected if excavated for any
 
reason or if observed conditions in accessible areas exposed to the same environment show that significant concrete degradation has occurred. The Structures Monitoring Program will be
 
enhanced to include periodic groundwater monitoring in order to demonstrate that the below
 
grade environment remains nonaggressive. (Commitment No. 31). Observed conditions with 3-428 potential impact on an intended function are evaluated or corrected in accordance with the corrective action process.
The staff determined that the applicant's approach to aging management for the freshwater pump-house and the service water seal well is appropriate. The need to inspect more frequently
 
than every 4 years will be determined prior to the period of extended operation.
The staff concludes that for inaccessible areas the recommendations of SRP-LR Section 3.5.2.2.2.2.4 is achieved by performing: (1) opportunistic inspection of normally
 
inaccessible areas if exposed for any reason, and (2) inspection of inaccessible areas of
 
structures if observed conditions in accessi ble areas exposed to the same environment show that significant concrete degradation has occurred. The need for periodic inspection of
 
inaccessible areas of the freshwater pump-house and the service water seal well will be
 
determined prior to the period of extended operation. The staff finds that, based on the programs
 
identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.2.4 for further
 
evaluation.
In Attachment 3, item T-02, of its reconciliation document, the applicant addressed 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.
SRP-LR Section 3.5.2.2.2.2.5 states that 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. The GALL Report recommends further evaluation of
 
this aging effect for inaccessible areas of these groups of structures if concrete was not
 
constructed in accordance with ACI 201.2R-77 recommendations.
In Attachment 3, item T-02, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. Further evaluation is required only for inaccessible areas
 
with concrete not constructed as stated (in accordance with ACI 201.2R-77 recommendations).
 
In the LRA, the use of this line item is not for inaccessible areas. Accessible areas inspections
 
are performed in accordance with the Structures Monitoring Program.
The staff concludes that for inaccessible areas the recommendations of SRP-LR Section 3.5.2.2.2.2.5 can be achieved perform: (1) opportunistic inspection of normally
 
inaccessible areas if exposed for any reason and (2) inspection of inaccessible areas of
 
structures if observed conditions in accessi ble areas exposed to the same environment show that significant concrete degradation has occurred. The staff finds that, based on the information
 
identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.2.5 for further
 
evaluation.
The staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.2. For those LRA line items that apply to this SRP-LR section, the staff determined that the LRA is
 
consistent with the GALL Report and that the applicant has demonstrated that the effects of
 
aging will be adequately managed so that the intended function(s) will be maintained consistent
 
with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-429 Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.3.
In LRA Section 3.5.2.2.2.1, item (8), the applicant addressed reduction of strength and modulus of concrete due to elevated temperatures in BWR Groups 1-5 concrete structures.
SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due to elevated temperatures could occur in PWR and BWR Groups 1-5 concrete structures. For any
 
concrete elements that exceed specified te mperature limits, further evaluations are recommended. Appendix A of ACI 349-85 specifies the concrete temperature limits for normal
 
operation or any other long-term period. The temperatures shall not exceed 150 &deg;F except forlocal areas allowed to have increased temperatures not to exceed 200 &deg;F. The GALL Report
 
recommends further evaluation of a plant-specific program if any portion of the safety-related and other concrete structures exceeds specified temperature limits (i.e., general area temperaturegreater than 66 &deg;C (150 &deg;F) and local area temperature greater than 93 &deg;C (200 &deg;F)). The
 
acceptance criteria are described in Branch Technical Position RLSB-1 (SRP-LR Appendix A.1).
LRA Section 3.5.2.2.2.1, states that for loss of strength and modulus of concrete structures due to elevated temperatures in Groups 2-5, the GALL Report recommends a plant-specific AMP and further evaluation if the general temperature is greater than 150 &deg;F or if the local temperature is greater than 200 &deg;F. For OCGS, the Structures Monitoring Program manages cracking of
 
concrete structures exposed to elevated temperat ures. Concrete temperature limits specified in the GALL Report are exceeded only in a section of the reactor building (Group 2) drywell shield
 
wall that encloses the containment drywell head. Thermocouples mounted on the head, in the general area of the shield wall, indicated a maximum temperature of 285 &deg;F. Engineering
 
analysis predicted that the average temperature through the 5-feet thick concrete wall could be in the range of 180 to 215 &deg;F with a worst case thermal environment inside the containment of 340 &deg;F. As a result, an investigation evaluated the impact of the elevated temperature on the
 
structural integrity of the shield wall. The initial inspection of the shield wall identified concrete
 
cracking in the area subject to high temperature. A map of the cracked area including crack
 
length and width was developed for future monitoring.
Subsequently, the applicant conducted an engineering evaluation to assess the impact of the elevated temperature on the drywell shield wall. For this purpose, a finite element model was
 
created based on the geometry of the shield wall and connecting structural elements. The analysis was based on a temperature of 285 &deg;F and a reduced concrete compressive strength
 
that accounts for temperature-induced reduction. The results concluded that concrete and rebar
 
stress limits are in accordance with ACI 349 criteria with an adequate safety margin. In the
 
May 1994 SER, the staff found the analysis acceptable and concluded that the wall is capable of
 
performing its intended function. The staff also recommended condition monitoring of the drywell
 
shield wall to ensure its continued intended function.
During the audit, the staff noted that the wall has been included within the scope of the Structures Monitoring Program and inspected periodically to ensure its continued intended
 
function. Observed conditions with potential impact on intended function are evaluated or
 
corrected in accordance with the corrective action process.
3-430 In order to facilitate its AMR review, the staff asked the applicant for additional information related to the elevated temperature condition in the reactor building drywell shield wall. In its
 
response, the applicant stated that the drywell shield wall elevated temperature became a
 
concern in the early to mid-1980s. The issue was evaluated as part of NUREG-0822, "Integrated
 
Plant Safety Assessment, Systematic Evaluati on Program, Oyster Creek Nuclear Generating Station," January 1983, Topic III-7.B.
The applicant further stated that a review of the CLB information did not identify documents that provide details on the extent of the cracked region when it was first discovered in mid-1980's.
 
The applicant stated that the condition of the wall was monitored once it was discovered.
 
However, specific criteria such as distribution, width, and length of cracks were not identified.
 
The earliest document that provides this information is an inspection report prepared in 1994 by
 
the applicant. This report has been used since 1994 as a benchmark against which subsequent
 
observed shield wall condition is evaluated.
Observed cracks on the outside of drywell shield wall documented in a 1994 inspection report show that the entire shield wall above elevation 95' 3" may be affected by the elevated
 
temperature. Distribution of the cracks is gener ally random. Crack widths are generally hairline with no cracks wider than 1/32 inch. Staff evaluation of information submitted by GPUN on the
 
drywell shield wall elevated temperature began in 1986. In its SER dated October 24, 1986 (Letter, J. Zwolinsky, NRC, to P. Fiedler, GPUN, with Safety Evaluation 4.12, SEP Topic III-7.B, NRC Information Request Form of NUREG-0822, Design Codes, Design Criteria and Load
 
Combinations, dated October 29, 1986), the staff required further investigation to complete its
 
evaluation. GPUN transmitted the requested information in several correspondences between
 
1990 through 1993. The staff completed its review of the submitted information and concluded in
 
an SER dated May 11, 1994, that the drywell shield wall is capable of performing its intended
 
function (Letter from Alexander W. Dromerick, Jr., NRC, to J. Barton, GPUN, "Oyster Creek
 
Nuclear Generating station - Evaluation of Effects of High Temperature on Drywell Shield Wall
 
and Biological Shield Wall, SEP Topic III-7.B, Design Codes, Design Criteria, Load
 
Combinations, and Reactor Cavity Criteria," (TAC No. M76879) dated May 11, 1994). The
 
May 11, 1994, SER did not specify that the conclusion was based on the remaining OCGS
 
operating life.
As recommended by the staff in its SER dated May 11, 1994, the applicant implemented a periodic crack monitoring program consisting of visual inspection of the drywell shield wall above
 
elevation 95' 3" every refueling outage (Letter from R.W. Keaten to U.S. NRC, "Oyster Creek
 
Nuclear Generating Station (OCNGS) Docket 50-219 SEP Topic III-7B, Drywell Shield Wall
 
Integrity," dated April 19, 1994). The benchmark inspection was conducted in April 1994 to
 
record the surface condition of the drywell shield wall, including the crack patterns, crack length, and width. In October 1996, during the refueling outage, the applicant performed a second
 
inspection in which it assessed the condition of the drywell shield wall with the reactor cavity
 
flooded with water. No changes to the cracks or water stain were observed. In similar inspections
 
during the 1996 and 1998 refueling outages the structural engineer who performed them
 
concluded that the drywell shield walls are structurally adequate to perform their intended
 
functions.
3-431 The applicant's 2002 inspection report noted that the structural condition of the shield walls was the same as that observed in 1998, that cracks observed were minor, and that the walls were
 
adequate for their intended functions. The 2005 inspection report noted that the shield walls were
 
in good and sound condition and capable of performing their intended function. The minor
 
hairline cracks and rust stains were the same as noted in previous inspections.
The applicant further stated that, as evident from operating experience discussed above, the extent of the elevated temperature region and the extent of the cracked region have not significantly changed since the benchmark report of 1994. Additional minor cracks and stains
 
have been observed since that time but not considered so significant as to impact the intended
 
function of the drywell shield wall. A reanalysis for GPUN by ABB Impell Corporation (Report #0037-00196-0) was transmitted to NRC in November 19, 1993 (Letter, R. Keaton, GPUN, to NRC, "Response to Request for Additional Information on Drywell Temperature (SEP
 
Topic III-7.B)," dated November 19, 1993). There has been no need for repairs. The license
 
renewal commitment (Commitment No. 31) under the Structures Monitoring Program is equal to
 
the condition monitoring activities conducted under the current term to satisfy staff
 
recommendations.
As a followup to the applicant's response, the staff reviewed the May 11, 1994, letter from A. Dromerick and the November 19, 1993, letter from R. Keaton along with ABB Impell
 
Corporation Report #03-0370-1341, "Oyster Creek Nuclear Generating Station Structural
 
Evaluation of the Spent Fuel Pool," Revision 0, June 29, 1992.
The staff reviewed the applicant's responses and concluded that the applicant's program to manage concrete cracking in the drywell shield wall, the biological shield wall, and the spent fuel
 
pool supporting structural elements is adequate based on the 2-year inspection frequency, the
 
inclusion of a quantitative acceptance criterion for crack width consistent with the staff
 
recommendations, and the apparent stability of the existing crack patterns and crack widths.
Based on the information identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.3. For those LRA line items that apply to this SRP-LR
 
section, the staff determined that the LRA is consistent with the GALL Report and 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 of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA Section 3.5.2.2.2.4, and Attachment 3 of the applicant's reconciliation document against the
 
criteria in SRP-LR Section 3.5.2.2.2.4.
In Attachment 3, items T-18 and T-19, of its reconciliation document, the applicant addressed increase in porosity and permeability, cracking, loss of material (spalling, scaling) - aggressive
 
chemical attack; and cracking, loss of bond, and loss of material (spalling, scaling) - corrosion of
 
embedded steel in below-grade inaccessible concrete areas of Group 6 structures (T-18, T-19).
SRP-LR Section 3.5.2.2.2.4.1 states that increase in porosity and permeability, cracking, loss of material (spalling, scaling) - aggressive chemical attack; and cracking, loss of bond, and loss of 3-432 material (spalling, scaling) - corrosion of embedded steel could occur in below-grade inaccessible concrete areas of Group 6 structures (T-18, T-19). The GALL Report recommends
 
further evaluation of plant-specific programs to manage these aging effects in inaccessible areas
 
if their environment is aggressive. The acceptance criteria are described in Branch Technical
 
Position RLSB-1 (SRP-LR Appendix A.1).
In Attachment 3, item T-18, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The LRA states that inaccessible areas of structures in
 
the scope of license renewal exposed by exca vation for any reason will be inspected and groundwater sampled and tested periodically during the period of extended operation. This line
 
item has been invoked for water control structures. The applicant has committed (Commitment
 
No. 31) to a baseline inspection of submerged water control structures prior to the period of
 
extended operation with a second inspection 6 years after the baseline inspection and a third 8
 
years after the second. Following each inspection, the identified degradations will be evaluated
 
to determine whether more frequent inspections are warranted or there is a need for corrective
 
actions to ensure adequate management of age-related degradations. Inspections will be
 
conducted in accordance with the RG 1.127, Inspection of Water-Control Structures Associated
 
with Nuclear Power Plants Program. The review of design and construction documents indicated
 
that the specified air content is 4 to 6 percent. Water-to-cement ratio was based on the strength
 
required by the design considering the maximum slump of 4 inches. Curves representing the relation between the water content and the average 28-day compressive strength were
 
established for a range of values including the compressive strengths specified. The curves were
 
established by at least three points, each representing average values from at least four test
 
specimens. The maximum allowable water content for each class of concrete was determined
 
from the curves and corresponded to a compressive strength of 15 percent greater than that
 
specified for that class of concrete. A review of documentation for a sample of class 4LA (4000
 
psi) concrete cylinder tests shows that the 28-day strength meets or exceeds the specified 4000 psi compressive strength.
The applicant stated that inspections in accordance with the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program have identified
 
cracking, change in material properties, and loss of material (spalling, scaling) which could be
 
attributed to corrosion of embedded steel in accessible areas. Engineering evaluation of these
 
aging effects concluded that they are not so significant as to impact the intended function of the
 
affected structure, and the applicant concluded that they are not significant for accessible and
 
inaccessible areas and that the RG 1.127, Inspection of Water-Control Structures Associated
 
with Nuclear Power Plants Program will adequately manage them. Thus, no plant-specific AMP
 
is required.
The staff finds acceptable the applicant's assessment that the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will adequately
 
manage aging effects caused by corrosion of embedded steel and that no plant-specific program
 
is necessary.
In Attachment 3, item T-19, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The applicant stated that it will inspect inaccessible
 
areas of structures within the scope of license renewal exposed by excavation for any reason, 3-433 and to sample and test groundwater periodically during the period of extended operation. This line item has been invoked for water control structures. The applicant has committed (Commitment No. 31) to a baseline inspection of submerged water control structures prior to the
 
period of extended operation with a second inspection 6 years after the baseline inspection and
 
a third 8 years after the second. Following each inspection, the identified degradations will be
 
evaluated to determine whether more frequent inspections are warranted or there is a need for
 
corrective actions to ensure adequate management of age-related degradations. Inspections will
 
be conducted in accordance with the RG 1.127, Inspection of Water-Control Structures
 
Associated with Nuclear Power Plants Program. The inspections conducted in accordance with
 
the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants
 
Program have identified concrete degradation which could be attributed to aggressive chemical
 
attack in accessible areas. Engineering evaluation of the identified increase in porosity and
 
permeability, cracking, and loss of material concluded that they are not so significant as to
 
impact the intended function of the affected structure. Based on this evaluation, change in
 
material properties, cracking, and loss of material (spalling, scaling) due to aggressive chemical
 
attack is not significant for accessible and inaccessible areas, and the RG 1.127, Inspection of
 
Water-Control Structures Associated with Nuclear Power Plants Program will adequately
 
manage these aging effects. Thus, no plant-specific AMP is required.
The staff finds acceptable the applicant's assessment that the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will adequately
 
manage aging effects that may be caused by aggressive chemical attack and that no
 
plant-specific program is necessary.
The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4.1 for further evaluation.
In Attachment 3, item T-15, of its reconciliation document, the applicant addressed loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete
 
areas of Group 6 structures (T-15).
SRP-LR Section 3.5.2.2.2.4.2 states that loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in below-grade inaccessible concrete areas of Group 6 structures (T-15). The GALL Report recommends further evaluation of this aging effect for inaccessible
 
areas for plants located in moderate to severe weathering conditions.
In Attachment 3, item T-15, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The applicant stated that for inaccessible areas, as
 
described in UFSAR Section 3.8.4.6, "Materials, Quality Control and Special Construction
 
Techniques," concrete is designed consistent with ACI 318 requirements to be workable with
 
homogeneous structure which, when hardened, will have durability, impermeability, and the
 
specified strength. Testing of concrete was performed in accordance with ASTM standards
 
specified in ACI 318 to ensure that the desired quality of concrete was furnished. The strength
 
quality of the concrete was established by tests by a maximum slump of four inches made in
 
advance of the beginning of operations. Specimens were tested and cured in accordance with
 
ASTM C39.
3-434 The applicant further stated that inspections conducted in accordance with the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program have
 
identified loss of material (spalling, scaling) and cracking which could be attributed to
 
freeze-thaw in accessible areas. Engineering evaluation of the identified loss of material and
 
cracking concluded it is not so significant as to impact the intended function of the affected
 
structure. Therefore, loss of material and cracking due to freeze-thaw is not significant in
 
inaccessible concrete areas of Group 6 structures, and no plant-specific AMP is required.
The staff noted that the applicant credited the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program for managing loss of material, cracking, and
 
change in material properties in both accessible and inaccessible (submerged) concrete areas of
 
Group 6 structures regardless of the aging mechanism. Any degradation caused by freeze-thaw
 
will be identified. The staff finds acceptable the applicant's conclusion that a plant-specific
 
program is not needed. The staff finds that, based on the programs identified above, the
 
applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4.2 for further evaluation.
In Attachment 3, items T-16 and T-17, of its reconciliation document, the applicant addressed cracking due to expansion and reaction with aggregates, as well as increase in porosity and
 
permeability, and loss of strength due to leaching of calcium hydroxide in below-grade
 
inaccessible reinforced concrete areas of Group 6 structures (T-16, T-17).
SRP-LR Section 3.5.2.2.2.4.3 states that cracking due to expansion and reaction with aggregates and 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 (T-16, T-17). The GALL Report recommends further evaluation of inaccessible areas if
 
concrete was not constructed in accordance with ACI 201.2R-77 recommendations.
In Attachment 3, items T-16 and T-17, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The LRA commitment (Commitment No. 31) to
 
perform inspections in accordance with RG 1.127 does not change. As described in UFSAR
 
Section 3.8.4.6, "Materials, Quality Control and Special Construction Techniques," the cement
 
used was an approved brand of Portland Cement conforming to ASTM Specification C-150, Type
 
II, low alkali. Alkali content is limited to 0.6 percent total alkali. The low alkali requirement for the
 
cement was waived provided petrographic tests in accordance with ASTM C295 and C227
 
demonstrated no potential alkali reactivity for all aggregates proposed for use, providing
 
reasonable assurance that aggregates will not react with reinforced concrete. The aggregate
 
used on the project was from approved sources and consisted of clean, hard, durable particles
 
conforming to the requirements of concrete specifications. Tests were performed as necessary to
 
determine that the proposed aggregate would produce concrete of acceptable quality and
 
durability meeting ACI requirements.
The staff finds acceptable the applicant's assessment of cracking due to expansion and reaction to with aggregates. The staff also noted that the applicant's RG 1.127, Inspection of
 
Water-Control Structures Associated with Nuclear Power Plants Program is credited for
 
managing loss of material, cracking, and change in material properties in both accessible and
 
inaccessible (submerged) concrete areas of Group 6 structures regardless of the aging
 
mechanism. Any degradation that may be caused by these aging mechanisms will be identified.
3-435 The staff finds that, based on the programs identified above, the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4.3 for further evaluation.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4. For those LRA line items that apply to this SRP-LR
 
section, the staff determined that the LRA is consistent with the GALL Report and that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended 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. The staff noted that the applicant had not provided a further evaluation for cracking of stainless steel tank liners, with reference to the further evaluation in SRP-LR Section 3.5.2.2.2.5;
 
however, LRA Table 3.5.1, item number 3.5.1-30, addresses this aging effect.
SRP-LR Section 3.5.2.2.2.5 states that cracking due to SCC and loss of material due to pitting and crevice corrosion could occur for Group 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.
LRA Table 3.5.1, item number 3.5.1-30, states that cracking due to SCC or loss of material due to pitting and crevice corrosion for Group 7 and 8 stainless steel tank liners is not applicable. The
 
only stainless steel lined concrete tank is the spent fuel pool surge tank. Aging effects of the
 
stainless steel tank liner are evaluat ed with the mechanical auxiliary systems.
The staff reviewed LRA Tables 3.5.2.1.1 through 3.5.2.1.19 and noted that the only stainless steel tank liner listed is the fuel pool skimmer surge tank liner, in LRA Table 3.5.2.1.2. The AMR
 
for this tank references GALL Report Table 2 item VII.A4-11 and Table 1 item 3.3.1-22 in
 
auxiliary systems. The Water C hemistry and One-Time Inspection Programs are credited for aging management. The staff concludes that the applicant's AMP for the stainless steel tank liner
 
is acceptable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.5. For those LRA line items that apply to this SRP-LR
 
section, the staff determined that the LRA is consistent with the GALL Report and that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended 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 of Supports Not Covered by Structures Monitoring Program. The staff reviewed  of the applicant's reconciliation document against the criteria in SRP-LR
 
Section 3.5.2.2.2.6.
In Attachment 3, items T-29, T-30, and T-31, of its reconciliation document, the applicant addressed aging management of component support and aging effect combinations not covered
 
by the Structures Monitoring Program.
3-436 SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation of certain component support and aging effect combinations not covered by the Structures
 
Monitoring Program, including (1) loss of material due to general and pitting corrosion for Groups
 
B2-B5 supports (T-30), (2) reduction in concrete anchor capacity due to degradation of the
 
surrounding concrete for Groups B1-B5 supports (T-29), and (3) reduction/loss of isolation
 
function due to degradation of vibration isolation elements for Group B4 supports (T-31). Further
 
evaluation is necessary only for structure and aging effect combinations not covered by the
 
Structures Monitoring Program.
In Attachment 3, item T-29, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The wording for further evaluation was changed from
 
"not required if within the scope of the applicant's structures monitoring program" to "required if
 
not within the scope of the applicant's structures monitoring program." This item is within the
 
scope of the applicant's Structures Monitoring Program; therefore, no further evaluation is
 
required.The staff verified that this item is within the scope of the Structures Monitoring Program; therefore, no further evaluation is required. The staff finds this assessment acceptable.
In Attachment 3, item T-30, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The wording for further evaluation was changed from
 
"not required if within the scope of the applicant's structures monitoring program" to "required if
 
not within the scope of the applicant's structures monitoring program." This item is within the
 
scope of the Structures Monitoring Program; therefore, no further evaluation is required.
The staff verified that this item is within the scope of the Structures Monitoring Program; therefore, no further evaluation is required. The staff finds this assessment acceptable. , item T-31, of its reconciliation document, the applicant stated that this item change requires no change to the LRA. The wording for further evaluation was changed from "not
 
required if within the scope of the applicant's structures monitoring program" to "required if not
 
within the scope of the applicant's structures monitoring program." This item is within the scope
 
of the Structures Monitoring Program, therefore, no further evaluation is required.
The staff verified that this item is within the scope of the Structures Monitoring Program; therefore, no further evaluation is required. The staff finds this assessment acceptable.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.6. For those LRA line items that apply to this SRP-LR
 
section, the staff determined that the LRA is consistent with the GALL Report and that the
 
applicant has demonstrated that the effects of aging will be adequately managed so that the
 
intended 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 LRA Section 3.5.2.2.3 (2), the applicant stated that fatigue of 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.
3-437 TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). At OCGS, there are no fatigue analyses applicable to Groups B1.1 and B1.2 component supports in the CLB. Therefore, cumulative fatigue damage for Groups B1.1 and B1.2 component supports is not a TLAA as
 
defined in 10 CFR 54.3. The CLB includes fatigue analysis for certain Group B1.3 ASME Class
 
MC component supports. For these supports (torus support columns and sway braces)
 
cumulative fatigue damage is a TLAA evaluated in accordance with 10 CFR 54.21(c) in LRA
 
Section 4.6.1.
The evaluation of this TLAA is documented in SER Section 4.6.
 
3.5.2.2.3  Quality Assurance for Aging Management of Nonsafety-Related Components
 
SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program for safety-related and nonsafety-related components.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant had claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determines that the applicant has adequately
 
addressed the issues that were further evaluated, except for the primary containment (drywell).
Five OIs were identified and are documented in SER Section 4.7.2. Based upon this review and
 
evaluation of the containment corrosion history and the applicant's proposed aging management
 
activities for the period of extended operation, the staff fins, contingent upon resolution of the
 
OIs, that the applicant has demonstrated that the effects of aging will be adequately managed so
 
that the intended functions will be maintained during the period of extended operation, as
 
required by 10 CFR 54.21(a)(3). 3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.5.2.1.1 through 3.5.2.1.19, the staff reviewed additional details concerning the results of the AMRs for material, environment, AERM, and AMP combinations not consistent with or not addressed in the GALL
 
Report.In LRA Tables 3.5.2.1.1 through 3.5.2.1.19, 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 Repor
: t. 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.
Staff Evaluation. For component type, material, and environment combinations not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether the 3-438 applicant had 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 discussed in the following sections.
3.5.2.3.1  Primary Containment Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.1 The staff reviewed LRA Table 3.5.2.1.1, which summarizes the results of AMR evaluations for the primary containment component groups.
The staff's review of LRA Table 3.5.2.1.1 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.5-1 dated March 20, 2006, the staff identified that LRA Table 3.5.2.1.1 indicates that fretting and lockup of suppression pool downcomers will be managed by the ASME Section Xl, Subsection IWE Program. Directly, the downcomers are not parts of the pressure boundary.
 
Subsection IWE does not provide examinati on requirements and acceptance criteria for downcomers; however, as a convenience, the examinations of downcomers can be included in Subsection IWE requirements with special provis ions for examining the downcomers for fretting or lockups in the plant-specific procedures. The staff requested that the applicant provide (1) the
 
operating experience with downcomers fretting or lockups and (2) the ISI provisions incorporatedin the plant-specific ASME Section Xl, Subsection IWE Program.
In its response dated April 18, 2006, the applicant stated as to item (1) that OCGS operating experience has not identified fretting or lockups of the downcomers. Visual inspections in accordance with ASME Section Xl, Subsection IWE have been limited to downcomer surfaces
 
above water level in the torus. Areas potentially susceptible to fretting or lockup are submerged
 
in torus water and scheduled for inspection at the end of the current 10-year interval in
 
accordance with Table IWE-2500-1. Consequently, OCGS has no operating experience with
 
fretting or lockups of the downcomers. As to item (2), the applicant explained that the ASME Section Xl, Subsection IWE Program includes exam ination of downcomers with the vent system, examination category E-A, item number E1.20 in accordance with Table IWE-2500-1. The
 
examination method is visual, VT-3, in accordance with IWE. Parameters monitored are loss of
 
material due to corrosion and fretting or lockup at clamps that connect adjacent downcomers.
 
The inspection frequency is every 10 years with 100 percent inspection at the end of the interval
 
in accordance with Table IWE-2500-1.
The staff agreed with the applicant that the examination of downcomers for fretting and lock-upsis part of implementation of the ASME Section Xl, Subsection IWE Program and that these types
 
of degradation will be managed by the applicant during the period of extended operation. The
 
staff's concerns described in RAI 3.5-1 are resolved.
 
In RAI 3.5-2 dated March 20, 2006, the staff noted that LRA Table 3.5.2.1.1 credits the
 
10 CFR Part 50, Appendix J Program for management of loss of material in downcomers. It is
 
not apparent how the leak testing requirement of Appendix J will detect loss of material in 3-439 downcomers. The staff requested that the applicant discuss the use of the10 CFR Part 50, Appendix J Program for managing loss of material in downcomers.
In its response dated April 18, 2006, the applicant explained that the primary containment leakage rate testing program is performed in accordance with 10 CFR Part 50, Appendix J, Option B, RG 1.163, NEI 94-01, ANSI/ANS 56.8, and approved plant program documents and procedures. Appendix J of 10 CFR Part 50, paragraph III.A, Type A pretest requirements, requires a general inspection of the accessible interior and exterior surfaces of the containment
 
structure and component prior to any Type A test to uncover any evidence of deterioration which may affect the containment structural integrity or leak-tightness. The general inspection detects
 
loss of material due to corrosion on accessible surfaces of the containment including downcomers. However, the ASME Section Xl, Subsection IWE Program is the primary AMP
 
credited for managing loss of material of the downcomers.
The staff finds the applicant's procedure acceptable because it incorporates the examination of downcomers as part of its Appendix J, Type A te st pre-service examination requirements. The staff's concern described in RAI 3.5-2 is resolved.
In RAI 3.5-3 dated March 20, 2006, the staff noted under component types "Reactor Pedestal" and "R.C. Floor Slab" a reference to GALL Report Table 1, item 3.5.1-29, where the discussion
 
indicates that the concrete temperatures in the upper part of the drywell could be as high as 259 &deg;F. As a result, the reactor building drywell shield concrete experienced significant cracking.
 
However, the cause of the high temperature is not indicated. In light of that discussion, the staff
 
requested that the applicant provide the following information:  (a)type and adequacy of the cooling system used to control the temperatures in the drywell  (b)operating experience with the reliability of the cooling system (c)actions taken to reduce the high temperatures in the upper part of the drywell (d)a summary of the results of the last inspection of the reactor pedestal, R.C. floor slabs, drywell lateral supports, and sacrificial shield wall, including the date of the inspection and
 
frequency of inspection during the period of extended operation In its response dated April 18, 2006, the applicant explained that the GALL Report Table 1,item 3.5.1-29 discussion paragraph states that the temperatures limits of 150 &deg;F and 200 &deg;F are
 
exceeded only in the upper elevation of the drywell. The reactor pedestal and the reinforced
 
concrete floor slab are not subject to elevated temperature inside the drywell. These structures
 
are located below elevation 55' where the maximum drywell temperature during plant operation is 139 &deg;F. For this reason LRA Table 3.5.2.1.1 indicates "none" for the aging effect associated
 
with GALL Report Table 2, item III.A4-1 (T-10), which rolls up to GALL Report Table 1, item 3.5.1-29. A plant-specific Note 7 was added to LRA Table 3.5.2.1.1 for these components
 
for a technical basis for the aging, "none." The plant-specific note states "Reduction of strength
 
and modulus due to elevated temperature is not an aging effect requiring management."
 
Furthermore, the applicant points to the additional evaluation in LRA Section 3.5.2.2.1.3, which
 
essentially states "Concrete for the reactor pedestal, and the drywell floor slab (fill slab) are
 
located below elevation 55' and are not exposed to the elevated temperature." Additionally, the 3-440 applicant explained that, as discussed in LRA Section 3.5.2.2.1, item 3, the temperature insidethe drywell during plant operation varies from 139 &deg;F at elevation 55' to more than 256 &deg;F in the
 
upper elevations of the drywell, above elevation 95'. Thus, the temperature in the upper
 
elevations of the drywell exceeds local and general limits for concrete in accordance with
 
ACI 349. The affected concrete structure is the drywell shield walls above elevation 95'. The
 
effect of elevated temperature on the drywell shield wall is discussed in detail in LRA
 
Section 3.5.2.2.2, item 8. The applicant provided the following additional information as
 
requested by the staff:  (a)The drywell cooling system, consisting of the drywell recirculating fan cooler units and the drywell temperature detection system, is a ventilation system designed to maintain temperature, humidity, and mixing in the drywell to control drywell pressure and protect
 
the drywell and equipment inside from excessive heat by circulating the drywell
 
atmosphere (inerted nitrogen environment) through the drywell fan cooler units cooling
 
coils and transferring heat from the drywell fan cooler units cooling coils to the reactor
 
building closed cooling water system.
The drywell cooling system is comprised of five recirculation fan cooler units including supply fans, demisters, supply and return ductwork, dampers, registers, instrumentation, and controls. In normal operation, four fans (20,000 cfm each) are sufficient for cooling.
 
From the fans, cooled nitrogen is fed to a supply/distribution ring header at elevation 54'
 
and delivered to the air space within the drywell:
* 52,800 cfm is distributed through 5 supply air ducts to Zone I toward the lower part of the drywell for cooling of the recirculation pump motors.
* 16,800 cfm is distributed through 9 supply registers to the remaining portions of Zone I.
* 8,800 cfm is distributed through 5 supply air ducts to Zone II for cooling of the RPV surface and biological shield.
* 1,600 cfm is distributed through a single supply air duct to Zone lIl for cooling the RPV bottom cavity.
The supply/distribution ring header at elevation 54' does not directly provide cooling to the space above the reactor vessel head. A total of 1,600 cfm is transferred through 8
 
ventilation hatches from Zone II to the space above the reactor vessel head. Return
 
nitrogen is collected by a return duct ring header at elevation 91' 7":
* 54,400 cfm is returned to the return duct ring header through 5 return ducts in the lower part of the drywell.
* 24,000 cfm is returned to the return duct ring header through 5 return ducts located directly on the return duct ring header.
* 1,600 cfm is returned from the space above the reactor vessel head to the return duct ring header through 3 return ducts.
3-441 The return duct ring header at elevation 91' 7" does not directly collect flow from the Zone IlI RPV bottom cavity area. Nitrogen in this area exits Zone IlI through access openings
 
and is collected by the return ducts in the lower part of the drywell (Zone I).
The drywell temperature detection system prov ides information to the operators in the control room to monitor and record the drywell atmosphere temperature at various
 
locations and to determine the drywell bulk temperature during normal plant operation.
 
The drywell temperature detection system is comprised of local drywell temperature instrumentation and includes duct-mounted temperature elements located in the supply
 
and return portions of the recirculation fan ducts. The drywell temperatures are monitored
 
by the plant computer system and recorded on control room and local panel recorders in the reactor building. The drywell cooling system is designed to maintain the drywell bulk temperature below 150 &deg;F as discussed in paragraph (c). The system performs this function adequately.  (b)The cooling system is maintained to maximize reliability. Drywell fan motors on 4 fans were replaced in the mid-'90s with direct drive motors. This change eliminated the
 
possibility of belt breakage or slippage. The fifth fan, which has the original belt-driven
 
motor, is maintained as a spare and used during periods of peak drywell temperature.
 
During refueling outages, maintenance is performed on all fans and motors. Cooling coils
 
are cleaned, bearings greased, and vibration data obtained on all bearings. Belts are
 
replaced on the one belt-driven fan. In recent years there have been no significant
 
component failures that have rendered one train inoperable.  (c)There have been no actions to reduce temperature in the upper elevations. The drywell cooling system has functioned within design bases to cool the drywell adequately.
Drywell bulk temperature is maintained under the 150 &deg; limit even during the highest heat
 
periods. The drywell bulk temperature value is calculated from a weighted average of all
 
the thermocouples. It is the single value used for such action levels as EOP entry, plant
 
shutdown, etc.  (d)Structures inside the drywell were last inspected October 16, 2002, under the Structures Monitoring Program. The reactor pedestal, drywell R.C. floor slab, and liner plate for the
 
sacrificial shield wall were found structurally sound and able to perform their intended functions. Inspection of the drywell lateral supports is included in the ASME Section Xl, Subsection IWE Program as nonmandatory augmented inspections during the current
 
term. The last inspection was during the refueling outage in 2004. The inspection report
 
identified no degradations that would impact the intended function of the supports. The
 
reactor pedestal and the R.C. floor slab will be monitored on a frequency of every
 
refueling outage during the period of extended operation under the Structures Monitoring
 
Program. The sacrificial (biological) shield wall carbon steel liner has previously
 
experienced cracking. The cracking was evaluated and determined not to impact the
 
intended function of the wall. This carbon steel liner is monitored under the CLB every
 
refueling outage consistent with an existing NRC commitment and will continue to be
 
monitored every refueling outage during the period of extended operation as part of the
 
Structures Monitoring Program.
3-442 The drywell lateral supports are included in Class MC component supports and will bemonitored under the ASME Section Xl, Subsection IWF Program during the period of
 
extended operation. Inspection frequency is every 10 years in accordance with ASME Code Section Xl, Subsection IWF as required by 10 CFR 50.55a.
The staff finds that with the operation of the cooling system as described in responses to paragraphs (a) and (b) and the inspection of structural components as described in response to
 
paragraph (d) there is reasonable assurance that the structures affected by high temperatures
 
will be adequately managed during the period of extended operation. The staff's concerns
 
described in RAI 3.5-3 are resolved.
In RAI 3.5-4 dated March 20, 2006, the staff noted that component type "Shielding Blocks and Plates" uses patented material "Permali," for which no aging effects are indicated in LRA
 
Table 3.5.2.1.1. The staff requested that the applicant briefly describe the material and the AMR
 
results that justified no need for aging management during the period of extended operation.
In its response dated April 18, 2006, the applicant explained that Permali consists of vacuum-impregnated material based on wood veneers (rosewood) and phenolic resin. The material was
 
provided in the OCGS original design in combination with steel blocks to provide neutron
 
shielding around recirculation piping nozzles at biological shield wall penetrations. The material
 
is designed for its operating environment and aging management reviews identified no AERMs
 
during the period of extended operation.
The hydrogen content in wood veneers would make the material susceptible to neutron radiation, and high temperatures around the penetration could affect the stability of phenolic resin. The
 
staff requested from the applicant a detailed justification in its AMR for this material concluding
 
that no aging management is required for this material.
In its supplemental response dated July 10, 2006, the applicant stated:
AmerGen stated during the conference call that the material was provided in the original plant design specifically for shielding purposes around penetrations in the
 
biological shield wall. Industry and plant specific operating experience have not
 
identified any aging effects requiring management. Also, available vendor data, not specific to Oyster Creek, shows that the material is designed for neutron
 
attenuation in a high temperature environment. But it is unlikely that Oyster Creek
 
will be able to produce specific material test reports for the original material.
AmerGen therefore has elected to monitor the "Permali" material associated with the penetration shielding blocks for potential aging effects that could impact their
 
intended function. The blocks will be monitored for loss of material and cracking
 
through the Structures Monitoring aging management program. The inspection frequency will coincide with the ASME Section XI inspection of reactor vessel
 
nozzles, where the material is applied.
3-443 In addition, the applicant revised the Structures Monitoring Program to include inspection and degradation monitoring of Permali. The staff finds this acceptable because it ensures aging
 
management of this material. The staff's concern described in RAI 3.5-4 is resolved.
In RAI 3.5-5 dated March 20, 2006, the staff noted that for all component types described in Table 3.5.2.1.1, the Water Chemistry Program is vital, in addition to the programs noted in the
 
individual component types, for components fully or partially submerged in water. The staff requested that the applicant provide reasons for not including a Water Chemistry Program to
 
manage the aging degradation of these components.
In its response dated April 18, 2006, the applicant recognized that water chemistry is vital for mitigating loss of material due to corrosion of carbon and stainless steel components and
 
cracking of stainless steel components exposed to treated water environments. Torus water
 
chemistry is monitored in accordance with industry guidelines (BWRVIP-130) as described in the
 
Water Chemistry Program. The Water Chemistr y Program was not credited for managing the effects of aging of the torus and structural components subject to torus water because the ASME Section Xl, Subsection IWE, the 10 CFR Part 50, Appendix J, and the Protective Coating
 
Monitoring and Maintenance Programs are deemed adequate to manage their aging effects. The
 
applicant stated that this position is consistent with the January 2005 draft GALL Report which credits only the ASME Section Xl, Subsection IWE and 10 CFR Part 50, Appendix J Programs.
 
However, the applicant recognized that the September 2005 GALL Report added treated water
 
environment to steel elements of the containment (II.B1.1-2 (C-19), but that this line item does not credit water chemistry aging management for any of the components subject to treated
 
water. Based on this discussion, the applicant concluded that, while torus water chemistry is vital
 
and maintained in accordance with BWRVIP-130, the Water Chemistry Program need not be
 
credited to provide reasonable assurance that aging effects of structural components exposed to treated water are adequately managed, that the credited ASME Section Xl, Subsection IWE, 10 CFR Part 50, Appendix J, and Protective Coating Monitoring and Maintenance Programs are
 
adequate.
The staff recognized that maintaining the protective coating would eliminate any need for a water chemistry program. However, because the torus coatings and the protected steel of a number of
 
Mark 1 containments degrade, it is essential that the torus water be periodically checked and
 
maintained in accordance with BWRVIP-130 as stated in the UFSAR supplement. Although the
 
applicant does not credit a Water Chemistry Program explicitly, it recognizes a need to maintain
 
the water quality in accordance with the recommendations in the BWRVIP report. The staff's
 
concern described RAI 3.5-5 is resolved.
In RAI 3.5-6 dated March 20, 2006, the staff stated that the through-wall cracking of the Fitzpatrick Nuclear Power Plant torus indicates a need for closer examination of the highly
 
restrained and structurally discontinuous areas subject to operational cyclic loads. The prime AMP for managing degradation of the primary containment structure is the ASME Section XI, Subsection IWE Program. The program is focused towards detecting loss of material. The staff
 
requested that the applicant discuss how the program would detect initiation of such cracking in
 
the primary containment.
3-444In its response dated April 18, 2006, the applicant explained that the ASME Section Xl, Subsection IWE Program is not credited for managing crack initiation and growth. The program
 
is based on visual examinations that may not detect cracking experienced at Fitzpatrick.
 
However, the applicant noted that the crack initiation and growth mechanism experienced at
 
Fitzpatrick is not applicable to OCGS:
The initial review (2005) of the Fitzpatrick torus leak operating experience determined that the crack was related to design and operating conditions that are
 
not applicable to Oyster Creek. Analysis performed by Fitzpatrick indicated that
 
the most likely cause for the initiation and propagation of the crack was the
 
hydrodynamic loads of the turbine exhaust pipe during HPCI operation coupled
 
with the highly restrained condition of the torus shell at the torus column support.
 
The cracking occurred in the heat-affected zone of the lower gusset plate of the
 
ring girder at the torus column support. Fitzpatrick concluded that the crack was
 
initiated by cyclic loading due to condensation oscillation during HPCI operation.
 
The condensation oscillations induced on the torus shell may have been
 
excessive due to lack of a HPCI pipe sparger. The combined operation of the
 
HPCI system and safety relief valve (S RV) discharges during the northeast grid blackout disturbance of August 2003 may have initiated the crack. The HPCI
 
system operated approximately 14.5 hours and SRVs lifted five times over a period of 28 hours following the grid disturbance.
The applicant had explained that OCGS does not have a high-pressure coolant injection (HPCI) system and was not subject to such events. Furthermore, the applicant recognized that since the
 
initial review the NRC had issued IN 2006-01, "Torus Cracking in BWR Mark I Containment," on
 
January 12, 2006, to alert licensees of the Fitzpatrick condition. After reviewing the impact of the
 
Fitzpatrick experience on OCGS, the applicant will initiate corrective actions if it determines that
 
the condition described in the IN applies to OCGS.
The staff recognized that the major cause of the torus cracking at Fitzpatrick was the condensation oscillation loads generated during the HPCI operation. However, such loads are
 
also generated during SRV discharges in Mark I containments. The staff requested from the
 
applicant the results of its evaluation of the event.
In its supplemental response dated July 10, 2006, the applicant stated:
AmerGen's final review of the NRC Information Notice 2006-01, "Torus Cracking in BWR Mark I Containment", issued on January 12, 2006 concluded that the
 
torus crack identified by the Fitzpatrick Operating Experience is not applicable to
 
Oyster Creek. The crack was considered event driven, caused by design
 
configuration of the HPCI discharge line into the torus with no spargers. Oyster
 
Creek does not have a HPCI system or a steam discharge line to the torus with
 
the same design configuration as the Fitzpatrick HPCI system.
The SRV discharges won't be a concern for Oyster Creek because unlike the Fitzpatrick event driven HPCI discharges, Mark I containment SRV discharges
 
into the torus are design basis events evaluated in accordance with the Oyster 3-445 Creek Plant Unique Analysis Report (PUAR). Oyster Creek has five-safety relief valves (EMRVs) installed in the main steam system. When opened, steam
 
discharge from each EMRV is through piping routed inside the vent lines that
 
enter the torus from penetrations in the vent header. The steam lines are then
 
routed to a Y-quencher that discharges underwater. The SRV discharge pipes do
 
not penetrate the torus shell directly.
The Y-Quenchers were provided as a part of the Mark I containment hydrodynamics loads assessment to minimize the consequences of loads that
 
result from blowdown of SRV lines into the torus. Components of the torus that
 
are affected by the cyclic loads, due to blowdowns, were analyzed as described in
 
Oyster Creek PUAR for the current term. The analysis was determined to be a
 
TLAA for the period of extended operation and evaluated as described in LRA
 
Section 4.6.1. Thus, the concern with SRV discharge cycles and their impact on
 
the torus have been addressed in the LRA.
Based on operating experience and the review of Mark I containment information, the staff believes that OCGS is not likely to have the type of the event described in IN 2006-01. The
 
staff's concern described in RAI 3.5-6 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated wi th the primary containment 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).
3.5.2.3.2  Reactor Building Summary of Aging Management Evaluation - LRA Table 3.5.2.1.2
 
The staff reviewed LRA Table 3.5.2.1.2, which summarizes the results of AMR evaluations for the reactor building component groups.
The applicant stated that the Structures Monitoring Program manages the aging effect of loss of material for carbon and low alloy steel liners for sumps subject to raw water. The program
 
description states that steel components are inspected for loss of material due to corrosion every
 
4 years. The staff agreed that the Structures Monitoring Program is an acceptable AMP because
 
it can detect the corrosion of steel liners for sumps and that the inspection frequency of every
 
4 years is adequate.
The applicant stated that the Structures Monitoring Program manages the aging effect of cracking of concrete grout. The program description states that concrete structures are inspected
 
for cracking every 4 years. The staff agreed that the Structures Monitoring Program is an
 
acceptable AMP because it can detect the cracking of grout and that the inspection frequency of
 
every 4 years is adequate.
The applicant stated that this program is also used to manage the aging effect of change in material properties for the roofing material. The staff agrees with the applicant that periodic visual
 
inspections for roofing material degradation by qualified personnel is a proper way to manage
 
aging effects of the roofing material.
3-446 On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the reactor building 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).
3.5.2.3.3  Chlorination Facility Summary of Aging Management Evaluation - LRA Table 3.5.2.1.3
 
The staff reviewed LRA Table 3.5.2.1.3, which summarizes the results of AMR evaluations for the chlorination facility component groups.
LRA Table 3.5.2.1.3 states that the AMRs for the chlorination facility either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this
 
table are consistent with the GALL Report. The staff's evaluation for AMR items that are
 
consistent with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the chlorination facility 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).
3.5.2.3.4  Condensate Transfer Building Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.4 The staff reviewed LRA Table 3.5.2.1.4, which summarizes the results of AMR evaluations for the condensate transfer building component groups.
LRA Table 3.5.2.1.4 states that the AMRs for the condensate transfer building either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results
 
presented in this table are consistent with the GALL Report. The staff's evaluation for AMR items
 
that are consistent with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the condensate transfer building
 
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).
3.5.2.3.5  Dilution Structure Summary of Aging Management Evaluation - LRA Table 3.5.2.1.5
 
The staff reviewed LRA Table 3.5.2.1.5, which summarizes the results of AMR evaluations for the dilution structure component groups.
LRA Table 3.5.2.1.5 states that the AMRs for the dilution structure either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this table
 
are consistent with the GALL Report. The staff's evaluation for AMR items that are consistent
 
with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
3-447 On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the dilution structure 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).
3.5.2.3.6  Emergency Diesel Generator Building Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.6 The staff reviewed LRA Table 3.5.2.1.6, which summarizes the results of AMR evaluations for the EDG building component groups.
The staff's review of LRA Table 3.5.2.1.6 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.5-8 dated March 20, 2006, the staff stated that LRA Tables 3.5.2.1.6, 3.5.2.1.15, 3.5.2.1.16, and 3.5.2.1.17 identify loss of preload as the AERM for structural bolts and the
 
Structures Monitoring Program as its AMP.
The Structures Monitoring Program states that exposed surfaces of bolting are monitored for indications of loss of preload and that the program
 
relies on procurement controls and installation practices, defined in plant procedures, to ensure
 
that only approved lubricants and proper torque are applied consistent with the GALL Report AMP XI.M18. LRA Section B.1.12 states that the Bolting Integrity Program takes exception to the
 
GALL Report and that the aging management of structural bolting is addressed by the Structures
 
Monitoring Program. The staff requested that the applicant:  (a) Resolve the apparent inconsistencies that the Structures Monitoring Program states that the proper torque for bolts is applied consistent with the GALL Report bolting integrity
 
program while the Bolting Integrity Program takes exception to the GALL Report and
 
refers the aging management of structural bolting back to the Structures Monitoring
 
Program.    (b) Clarify whether the loss of preload of structural bolts is identified by visual inspection or by application of a torque wrench and if by visual inspection how the loss of preload can
 
be estimated.  (c) Explain how the Structures Monitoring Program relies on bolt procurement controls and installation practices. LRA Section B.1.31 states that the Structures Monitoring Program
 
relies on procurement controls and installation practices, defined in plant procedures, to
 
ensure that only approved lubricants and proper torque are applied. The staff believes
 
that bolt procurement controls and installation practices supposedly were used before, during, or immediately after installation of the bolts.  (d) Clarify whether there are any structural bolts or fasteners with a yield strength equal to or greater than 150 ksi managed by the Structures Monitoring Program and, if so, justify not
 
using the Bolting Integrity Program as the AMP for structural bolts.
In its response dated April 18, 2006, the applicant stated:
3-448  (a) The exception to the GALL Report referred to in the Bolting Integrity Program is that coverage of NSSS component support and structural bolting in the GALL Report is by the
 
Bolting Integrity Program but that instead coverage is by the Structures Monitoring Program for structural bolting, ASME Section Xl, Subsection IWE Program for primary containment pressure bolting, and ASME Section XI, Subsection IWF Program for ASME Code Section Xl Classes 1, 2, and 3 and Class MC support members. The same
 
procurement and installation procedures credited in the Bolting Integrity Program are also
 
applicable to the structural bolting.  (b) Structural bolting applications at OCGS do not require any specific predetermined bolting preload to assure that structural intended functions are maintained. Structural bolting is
 
assembled by approved bolting materials and lubricants. Bolted connections are
 
assembled by vendor-recommended methods, turn-of-the-nut methods, or standard
 
torque values for the applicable bolt size and material. For structural bolting, loss of
 
preload will not impact the bolted connection intended function unless the bolts become
 
so loose that they affect the integrity and geometry of the bolted connection. This aging
 
effect is managed by visual inspection for loose or missing nuts and bolts.  (c) The same procurement and installation procedures credited in the Bolting Integrity Program are also applicable to the structural bolting. The Structures Monitoring Program
 
is credited because it provides for visual in spections of the structural bolted connections.  (d) Structural bolts with yield strength greater than or equal to 150 ksi are used in limited structural applications, but those bolts are not subject to significant preload stress;
 
therefore, cracking would not be expected. The Structures Monitoring Program includes
 
structural bolting inspections for loss of material due to corrosion and visual inspections
 
for loose nuts, missing bolts, or other indications of loss of preload.
The applicant clarified that the aging effect of structural bolts in managed by visual inspection for loose or missing bolts as specified in the Structures Monitoring Program and that there is no
 
physical check on the preload loss in the bolts or bolt connections. The issue of structural bolts
 
that have yield strength greater than or equal to 150 ksi was resolved in the Audit and Review
 
Report. The staff's concern described in RAI 3.5-8 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the EDG building 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).
3.5.2.3.7  Exhaust Tunnel Summary of Aging Management Evaluation - LRA Table 3.5.2.1.7
 
The staff reviewed LRA Table 3.5.2.1.7, which summarizes the results of AMR evaluations for the exhaust tunnel component groups.
The staff's review of LRA Table 3.5.2.1.7 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
3-449 In RAI 3.5-10 dated March 20, 2005, the staff noted that LRA Table 3.5.2.1.7 lists aluminum material embedded in concrete and states that there is no aging effect and that no AMP is
 
required. The staff stated that the ACI Building Code prohibits the use of aluminum in structural
 
concrete unless coated or covered to prevent al uminum-concrete reaction or electrolytic action between aluminum and steel. The staff requested that the applicant justify the use of aluminum
 
material in concrete and explain why there is no aging effect and why no AMP is required.
In its response dated April 18, 2006, the applicant stated that, as required by ACI, the concrete is not in direct contact with aluminum. The OCGS s pecification for placement of concrete requires that where aluminum will contact concrete the contact surface of the metal shall have not less
 
than one coat of zinc chromate primer and one heavy coat of aluminum-pigmented asphalt paint.
The applicant's response indicated that it complied with the ACI Code requirement that aluminum not be in direct contact with concrete. The staff's concern described in RAI 3.5-10 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the exhaust tunnel 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).
3.5.2.3.8  Fire Pond Dam Summary of Aging Management Evaluation - LRA Table 3.5.2.1.8
 
The staff reviewed LRA Table 3.5.2.1.8, which summarizes the results of AMR evaluations for the fire pond dam component groups.
LRA Table 3.5.2.1.8 states that the AMRs for the fire pond dam either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this table
 
are consistent with the GALL Report. The staff's evaluation for AMR items that are consistent
 
with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the fire pond dam 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).
3.5.2.3.9  Fire Pumphouses Summary of Aging Management Evaluation - LRA Table 3.5.2.1.9
 
The staff reviewed LRA Table 3.5.2.1.9, which summarizes the results of AMR evaluations for the fire pumphouses component groups.
LRA Table 3.5.2.1.9 states that the AMRs for the fire pumphouses either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this table
 
are consistent with the GALL Report. The staff's evaluation for AMR items that are consistent
 
with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
3-450 On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the fire pumphouses 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).
3.5.2.3.10  Heating Boiler House Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.10 The staff reviewed LRA Table 3.5.2.1.10, which summarizes the results of AMR evaluations for the heating boiler house component groups.
LRA Table 3.5.2.1.10 states that the AMRs for the heating boiler house either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this
 
table are consistent with the GALL Report. The staff's evaluation for AMR items that are
 
consistent with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the heating boiler house 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).
3.5.2.3.11  Intake Structure and Canal (Ultimate Heat Sink) Summary of Aging Management Evaluation - LRA Table 3.5.2.1.11 The staff reviewed LRA Table 3.5.2.1.11, which summarizes the results of AMR evaluations for the intake structure and canal component groups.
LRA Table 3.5.2.1.11 states that the AMRs for the intake structure and canal either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results
 
presented in this table are consistent with the GALL Report. The staff's evaluation for AMR items
 
that are consistent with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
 
On the basis of its review, as discussed above, the staff concludes that the applicant has
 
demonstrated that the aging effects associated with the intake structure and canal 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).
3.5.2.3.12  Miscellaneous Yard Structures Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.12 The staff reviewed LRA Table 3.5.2.1.12, which summarizes the results of AMR evaluations for the miscellaneous yard structures component groups.
The applicant stated that no aging effects are considered applicable to polyvinyl chloride (PVC) conduits embedded in concrete. Based on the available information, the staff finds that PVC
 
conduits embedded in concrete will not have aging effects of concern during the period of
 
extended operation. Therefore, the staff concludes that there are no applicable AERMs for PVC
 
conduits embedded in concrete.
3-451 The applicant stated that no aging effects are considered applicable to gravel and sand under tank foundations. Based on the available information, the staff agrees that the gravel and sand
 
under tank foundations have no aging effects.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the miscellaneous yard structures
 
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).
3.5.2.3.13  New Radwaste Building Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.13 The staff reviewed LRA Table 3.5.2.1.13, which summarizes the results of AMR evaluations for the new radwaste building component groups.
LRA Table 3.5.2.1.13 states that the AMRs for the new radwaste building either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in
 
this table are consistent with the GALL Report. The staff's evaluation for AMR items that are
 
consistent with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the new radwaste building 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).
3.5.2.3.14  Office Building Summary of Aging Management Evaluation - LRA Table 3.5.2.1.14
 
The staff reviewed LRA Table 3.5.2.1.14, which summarizes the results of AMR evaluations for the office building component groups.
LRA Table 3.5.2.1.14 states that the AMRs for the office building either are consistent with the GALL Report or have no AERM. The staff confirmed that the AMR results presented in this table
 
are consistent with the GALL Report. The staff's evaluation for AMR items that are consistent
 
with the GALL Report is documented in SER Sections 3.5.2.1 and 3.5.2.2.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the office building 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).
3.5.2.3.15  Oyster Creek Substation Summary of Aging Management Evaluation -
LRA Table 3.5.2.1.15 The staff reviewed LRA Table 3.5.2.1.15, which summarizes the results of AMR evaluations for the OCGS substation component groups.
3-452 The applicant stated that the Structures Monitoring Program manages the aging effect of loss of preload for structural bolts. The staff evaluation of loss of preload is documented in SER
 
Section 3.5.2.3.6.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the OCGS substation 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).
3.5.2.3.16  Turbine Building Summary of Aging Management Evaluation - LRA Table 3.5.2.1.16
 
The staff reviewed LRA Table 3.5.2.1.16, which summarizes the results of AMR evaluations for the turbine building component groups.
The applicant stated that the Structures Monitoring Program manages the aging effect of change in material properties for the roofing material. The staff agreed with the applicant that periodic
 
visual inspections for roofing material degradation by qualified personnel properly manage aging
 
effects of roofing material.
The applicant stated that the Structures Monitoring Program manages the aging effect of loss of preload for structural bolts. The staff evaluation of loss of preload is documented in SER
 
Section 3.5.2.3.6.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the turbine building 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).
3.5.2.3.17  Ventilation Stack Summary of Aging Management Evaluation - LRA Table 3.5.2.1.17
 
The staff reviewed LRA Table 3.5.2.1.17, which summarizes the results of AMR evaluations for the ventilation stack component groups.
The applicant stated that aluminum embedded in concrete has no aging effect. The staff review of this subject is documented in SER Section 3.5.2.3.7.
The applicant stated that the Structures Monitoring Program manages the aging effect of cracking for concrete grout. The program description states that concrete structures are
 
inspected for cracking every 4 years. The staff agreed that the Structures Monitoring Program is
 
an acceptable AMP because it can detect the cracking of grout and that the inspection frequency
 
of every 4 years is adequate.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the ventilation stack 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).
3-453 3.5.2.3.18  Component Supports Commodity Gr oup Summary of Aging Management Evaluation
- LRA Table 3.5.2.1.18 The staff reviewed LRA Table 3.5.2.1.18, which summarizes the results of AMR evaluations for the component supports commodity group component groups.
The staff's review of LRA Table 3.5.2.1.18 identified an areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant responded to the
 
staff's RAI as discussed below.
In RAI 3.5-7 dated March 20, 2006, the staff noted that LRA Table 3.5.3.1.18 indicates that theaging of Class MC component supports is managed by ASME Section Xl, Subsection IWF
 
Program during the CLB. However, review of the enhancements in LRA Section B.1.28 indicated
 
that the program will be enhanced during the period of extended operation to include additional
 
MC supports and underwater structures in the torus. The staff requested from the applicant
 
clarification of the inspection of Class MC supports during the CLB and the period of extended
 
operation.
In its response dated April 18, 2006, the applicant noted that the reference to LRA Table 3.5.3.1.18 is a typographical error and should read "LRA Table 3.5.2.1.18." LRA
 
Table 3.5.2.1.18 is for AMR of Class MC component supports during the period of extended
 
operation, not during the CLB. The table reflects enhancements described in the ASME Section XI, Subsection IWF Program.
For the current period, the applicant explained that inspection of some Class MC componentsupports is conducted under the ASME Section Xl, Subsection IWF Program, and others are under the ASME Section Xl, Subsection IWE Program. Those included under nonmandatory IWE
 
augmented inspections are vent header supports, downcomer bracing, and drywell stabilizers.
Other supports are within the scope of IWF. Supports submerged in torus water are treated as
 
inaccessible under the current term and not included in the inspection plan for either IWF or IWE.
For license renewal, all Class MC component supports are included within the scope of IWF.
Submerged supports inside the torus will be monitored under IWF and inspected by
 
divers when the torus shell is submerged or when the torus is dewatered.
The staff finds the applicant's AMP enhancement to include the examinations of all Class MC component supports within the scope of IWF during the period of extended of operation
 
acceptable. The staff's concern described in RAI 3.5-7 is resolved.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the component supports commodity group
 
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).
3-454 3.5.2.3.19  Piping and Component Insulation Commodity Group Summary of Aging Management Evaluation - LRA Table 3.5.2.1.19 The staff reviewed LRA Table 3.5.2.1.19, which summarizes the results of AMR evaluations for the piping and component insulation commodity group component groups.
The applicant stated that no aging effects are considered applicable to insulations fabricated from asbestos, calcium silicate, fiberglass, and NUKON. Based on the available information, the
 
staff agreed that these insulations will not cause aging of concern during the period of extended
 
operation. Therefore, the staff concludes that there are no applicable AERMs for these
 
insulations.
On the basis of its review, as discussed above, the staff concludes that the applicant has demonstrated that the aging effects associated with the piping and component insulation
 
commodity group 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).
Conclusion. On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR results involving material, environment, AERMs, and AMP combinations that are 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).
 
====3.5.3 Conclusion====
The staff concludes that, pending resolution of the OIs, the applicant has provided sufficient information to demonstrate that the effects of aging for the containment, structures, component
 
supports, and piping and component insulation components, that are 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.
 
===3.6 Aging===
Management of Electrical Components This section of the SER documents the staff's review of the applicant's AMR results for the
 
electrical components and component groups of the following:
* insulated cables and connections
* electrical penetrations
* high voltage insulators
* transmission conductors and connections
* fuse holders
* wooden utility poles
* cable connections (metallic parts)
* uninsulated ground conductors 3-4553.6.1  Summary of Technical Information in the Application In LRA Section 3.6, the applicant provided AMR results for the electrical components and component groups. In LRA Table 3.6.1, "Summary of Aging Management Programs for the
 
Electrical Components Evaluated in Chapter VI of NUREG-1801," the applicant provided a
 
summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical components and component groups.
The applicant's AMRs incorporated applicable operating experience in the determination of AERMs. These reviews included evaluation of plant-specific and industry operating experience.
 
The plant-specific evaluation included reviews of 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.
 
====3.6.2 Staff====
Evaluation The staff reviewed LRA Section 3.6 to determine whether the applicant had provided sufficient information to demonstrate that the effects of aging for the electrical components within the
 
scope of license renewal and subject to an AMR will be adequately managed so that the
 
intended function(s) will be maintained consistent with the CLB for the period of extended
 
operation, as required by 10 CFR 54.21(a)(3).
The staff conducted an onsite audit of AMRs, during the weeks of October 3-5, 2005, January 23-27, 2006, and February 13-17, 2006, 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 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 the Audit and Review Report and summarized in SER
 
Section 3.6.2.1.
In the onsite audit, the staff also selected AMRs that were 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 acceptance criteria in SRP-LR Section 3.6.2.2. The staff's
 
audit evaluations are documented in the Audit and Review Report and summarized in SER
 
Section 3.6.2.2.
The staff also conducted a technical review of the remaining AMRs not consistent with or not addressed in the GALL Report. The technical review included evaluating whether all plausible
 
aging effects had been identified and whether the aging effects listed were appropriate for the
 
combination of materials and environments specified. The staff's evaluations are documented in
 
SER Section 3.6.2.3.
For AMRs that the applicant identified as not applicable, or not requiring aging management, the staff conducted a review of the AMR line items, and the plant's operating experience, to verify
 
the applicant's claims. Details of these reviews are documented in the Audit and Review Report.
3-456 Finally, the staff reviewed the AMP summary descriptions in the UFSAR supplement to ensure that they provided an adequate description of the programs credited with managing or monitoring aging for the electrical components.
Table 3.6-1, provided below, includes a summary of the staff's evaluation of components, aging effects and mechanisms, and AMPs listed in LRA Section 3.6 and addressed in the GALL
 
Report.Table 3.6-1  Staff Evaluation for Electrical Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation Electrical equipment subject to 10 CFR 50.49
 
environmental
 
qualification (EQ)
 
requirements (Item 3.6.1-1)
Degradation due to various aging
 
mechanisms Environmental Qualification of
 
Electrical
 
ComponentsTLAA Environmental Qualification (B.3.2)Consistent withGALL, which
 
recommends further
 
evaluation (See SER Section
 
4.4)Electrical cables, connections and
 
fuse holders (insulation) not
 
subject to 10 CFR 50.49
 
EQ requirements (Item 3.6.1-2)
Reduced insulation resistance and
 
electrical failure due to various physical, thermal, radiolytic, photolytic, and
 
chemical mechanisms Electrical Cables and Connections
 
Not Subject to 10 CFR 50.49
 
EQ Requirements Electrical Cables and Connections
 
Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements
 
program, (B.1.34).Consistent with GALL.
(See SER Section
 
3.6.2.1)Conductor insulation for electrical cables
 
and connections
 
used in instrumentation
 
circuits not subject to 10 CFR 50.49
 
EQ requirements
 
that are sensitive to
 
reduction in
 
conductor insulation
 
resistance (IR)
(Item 3.6.1-3)
Reduced insulation resistance and
 
electrical failure due to various physical, thermal, radiolytic, photolytic, and
 
chemical mechanisms Electrical Cables And Connections
 
Used In Instrumentation
 
Circuits Not Subject To 10 CFR 50.49
 
EQ Requirements Electrical Cables and Connections
 
Not Subject to 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Used
 
In Instrumentation
 
Circuits program, (B.1.35)Consistent with GALL.
(See SER Section
 
3.6.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-457 Conductor insulation for inaccessible
 
medium voltage
 
(2 kV to 35 kV)
 
cables (e.g., installed in
 
conduit or direct
 
buried) not subject to 10 CFR 50.49
 
EQ requirements (Item 3.6.1-4)
Localized damageand breakdown of
 
insulation leading to
 
electrical failure due
 
to moisture intrusion, water
 
trees Inaccessible Medium Voltage
 
Cables Not Subject to 10 CFR 50.49
 
EQ Requirements Inaccessible Medium Voltage
 
Cables Not Subject To 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements
 
program, (B.1.36)Consistent with GALL.
(See SER Section
 
3.6.2.1)Fuse Holders (Not Part of a Larger Assembly): Fuse
 
holders - metallic
 
clamp (Item 3.6.1-6)Fatigue due to ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical
 
contamination, corrosion, and
 
oxidationFuse HoldersNot ApplicableNot Applicable-GALL Report aging
 
effect is not
 
applicable to OCGS.
(See SER Section
 
3.6.2.3)Metal enclosed bus -
Bus/connections (Item 3.6.1-7)
Loosening of bolted connections due to thermal cycling and
 
ohmic heatingMetal Enclosed BusNot ApplicableNot Applicable.
OCGS has no
 
phase buses in the
 
scope of license renewal.Metal enclosed bus -
Insulation/insulators (Item 3.6.1-8)
Reduced insulation resistance and
 
electrical failure due to various physical, thermal, radiolytic, photolytic, and
 
chemical mechanismsMetal Enclosed BusNot ApplicableNot Applicable.
OCGS has no
 
phase buses in the
 
scope of license renewal.Metal enclosed bus - Enclosure
 
assemblies (Item 3.6.1-9)
Loss of material due to general corrosion Structures Monitoring ProgramNot ApplicableNot Applicable.
OCGS has no
 
phase buses in the
 
scope of license renewal.Metal enclosed bus - Enclosure
 
assemblies (Item 3.6.1-10)
Hardening and loss of strength due to
 
elastomers
 
degradation Structures Monitoring ProgramNot ApplicableNot Applicable.
OCGS has no
 
phase bus in the
 
scope of license renewal.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation 3-458 High voltage insulators (Item 3.6.1-11)
Degradation of insulation quality
 
due to presence of any salt deposits
 
and surface
 
contamination; Loss
 
of material caused by mechanical wear due to wind blowing
 
on transmission
 
conductors A plant-specific aging management
 
program is to be
 
evaluated Periodic Monitoring of Combustion Turbine Power Plant
 
Electrical Program (B.1.37)Consistent withGALL which
 
recommends further
 
evaluation (See SER Section
 
3.6.2.2.2)Transmission conductors and
 
connections; switchyard bus and
 
connections (Item 3.6.1-12)
Loss of material dueto wind induced
 
abrasion and
 
fatigue; loss of
 
conductor strength
 
due to corrosion;
 
increased resistance
 
of connection due to
 
oxidation or loss of
 
preload A plant-specific aging management
 
program is to be
 
evaluatedNot ApplicableNot Applicable-GALL Report aging
 
effect is not
 
applicable to OCGS.
(See SER Section
 
3.6.2.2.3)
Cable Connections -
Metallic parts (Item 3.6.1-13)
Loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical
 
contamination, corrosion, and
 
oxidation Electrical Cable Connections Not Subject To 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements Electrical Cable Connections Not Subject To 10 CFR 50.49
 
Environmental
 
Qualification
 
Requirements
 
Program (B.1.40)
Not Applicable-GALL Report aging
 
effect is not
 
applicable to OCGS.
(See SER Section
 
3.6.2.3)Fuse Holders (Not Part of a Larger Assembly)
Insulation material (Item 3.6.1-14)NoneNoneNoneConsistent with GALL. (See SER
 
Section 3.6.2.1)
The staff's review of the electrical components and component groups followed one of several approaches. One approach, documented in SER Section 3.6.2.1, discusses the staff's review of
 
the 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 3.6.2.2, discusses the staff's review of the 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 3.6.2.3, discusses the staff's review of the AMR results
 
for components that the applicant indicated are not consistent with, or not addressed in, the
 
GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the
 
electrical components is documented in SER Section 3.0.3.
3-4593.6.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicant identified the materials, environments, and AERMs. The applicant identified the following
 
programs that manage the effects of aging related to the electrical components:
* Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements (B.1.34)
* Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrument Circuits (B.1.35)
* Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements (B.1.36)
* Periodic Monitoring of Combustion Turbine Power Plant Electrical (B.1.37)
* Wooden Utility Pole Program (B.2.6)
* Periodic Monitoring of Combustion Turbine Power Plant (B.2.7)
In its response to RAI 2.5.1.19-1, which is documented in AmerGen Letter 2130-05-20214 titled "Response to NRC Request for Additional Information (RAI 2.5.1.19-1), dated
 
September 28, 2005, Related to Oyster Creek G enerating Station License Renewal Application (TAC No. MC7624)," dated October 12, 2005, the applicant stated that it had revised its
 
approach to aging management for the SBO system co mbustion turbine power plant. As a result, the Periodic Monitoring of Combustion Turbine Power Plant Program was deleted. Therefore, the
 
staff did not review this program.
Staff Evaluation. In LRA Tables 3.6.2.1.1 and 3.6.2.1.2, the applicant provided a summary of AMRs for the electrical components and identified which AMRs it considered to be consistent
 
with the GALL Report.
For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report 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 that the AMR is 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 AMP
 
identified in the GALL Report. The staff audited these line items to verify consistency with the
 
GALL Report and the validity of the AMR for the site-specific conditions.
3-460 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. The staff verified that the identified exceptions to the GALL AMPs had been
 
reviewed and accepted by the staff. The staff also determined whether the AMP identified by the
 
applicant is 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 com ponents in the GALL Report; however, the applicant identified a different component in the GALL Report that has the same material, environment, aging effect, and AMP as the component that was under review. The staff audited these line
 
items to verify consistency with the GALL Report. The staff also determined whether the AMR
 
line item of the different component was applicable to the component under review and whether
 
the AMR was valid for the site-specific conditions.
Note D indicates that the component for the AMR line item, although different from, is consistent with the GALL Report for material, environment, and aging effect. In addition, the AMP takes
 
some exceptions to the AMP identified in the GALL Report. The staff audited these line items to
 
verify consistency with the GALL Report. The staff verified whether the AMR line item of the
 
different component was applicable to the component under review. The staff verified whether
 
the identified exceptions to the GALL 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 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 conducted an audit and review of the information provided in the LRA, as documented in the Audit and Review Report. The staff did not repeat its review of the matters described in the
 
GALL Report; however, the staff did verify that the material presented in the LRA was applicable
 
and that the applicant identified the appropriate GALL Report AMRs.
The staff 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
 
electrical components subject to an AMR. On the basis of its audit and review, the staff
 
determined that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, the
 
applicant's references to the GALL Report are acceptable and no further staff review is required.
Conclusion. 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 3-461 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 indeed consistent with the AMRs in the GALL Report. Therefore, the staff
 
concludes that the applicant has demonstrated that the effects of aging for these components will
 
be adequately managed so that their intended function(s) will be maintained consistent with the
 
CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2  AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation is Recommended Summary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicant provided further evaluation of aging managemen t, as recommended by the GALL Report, for the electrical components. The applicant provided in formation about how it will manage the following aging effects:
* electrical equipment subject to environmental qualification
* degradation of insulator quality due to presence of any salt deposits and surface contamination, and loss of material due to mechanical wear
* loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due to corrosion, and increased resistance of connection due to oxidation or loss of pre-load
* quality assurance for aging management of nonsafety-related components Staff Evaluation. For component groups evaluated in the GALL Report, for which the applicant has claimed consistency with the GALL Report and for which the GALL Report recommends
 
further evaluation, the staff audited and reviewed the applicant's evaluation to determine whether
 
it adequately addressed the issues that were further evaluated. In addition, the staff reviewed the
 
applicant's further evaluations against the criteria in SRP-LR Section 3.6.2.2. Details of the staff's
 
audit are documented in the Audit and Review Report. The staff's evaluation of the aging effects
 
is discussed in the following sections.
3.6.2.2.1  Electrical Equipment Subject to Environmental Qualification
 
In LRA Section 3.6.2.2.1, the applicant stated that environmental qualification is a TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with
 
10 CFR 54.21(c)(1). SER Section 4.4 documents the staff's review of the applicant's evaluation
 
of this TLAA.
3.6.2.2.2  Degradation of Insulator Quality Due to Presence of Any Salt Deposits and Surface Contamination, and Loss of Material Due to Mechanical Wear The staff reviewed LRA Section 3.6.2.2.5 against the criteria in SRP-LR Section 3.6.2.2.2.
 
In LRA Section 3.6.2.2.5, the applicant addressed degradation of insulator quality due to presence of any salt deposits and surface contamination, and loss of material due to mechanical
 
wear.
3-462 SRP-LR Section 3.6.2.2.2 states that degradation of insulator quality due to presence of any salt deposits and surface contamination could occur in high-voltage insulators. The GALL Report
 
recommends further evaluation of a plant-specific AMP where the potential exists for salt
 
deposits or surface contamination (e.g., in the vicinity of salt water bodies or industrial pollution).
 
Loss of material due to mechanical wear caused by wind blowing on transmission conductors
 
could occur in high-voltage insulators. The GALL Report recommends further evaluation of a
 
plant-specific AMP to ensure adequate management of this aging effect. Acceptance criteria are
 
described in Branch Technical Position RLSB-1 (SRP-LR Appendix A.1)
Aging Effects. LRA Section 3.6.2.1.3 lists the materials of construction for the high-voltage insulators as:
* aluminum
* cement
* galvanized steel
* malleable iron
* porcelain The applicant stated that high-voltage insulator components are exposed to an outdoor air environment. The applicant also stated that the high-voltage insulators have no AERMs. LRA
 
Table 3.6.1 identifies degradation of insulation quality due to the presence of any salt deposit, surface contamination, and loss of material caused by mechanical wear due to wind blowing on
 
transmission conductors as the aging effects and mechanisms.
Salt Deposits. The applicant stated that on September 18, 2003, arcing was observed on 230 kV insulators in the OCGS switchyard. The arcing was not severe enough to cause
 
ground faults. No protective relaying was actuated (CAP No. 02003-1925). The
 
observations made in the switchyard are consistent with salt spray on the insulators and
 
resulted from the unusual weather conditions during the passing of Hurricane Isabel. The
 
high winds and waves deposited wind blown salty spray on the insulators. The electrical
 
conductivity of the salty moisture on the insulators caused the observed flashing.
The subsequent rains washed the salt from the insulators and eliminated the problem.
OCGS has not experienced any arcing leading to loss of offsite power attributable to salt
 
contamination. Salt spray deposits on high-voltage insulators are a temporary condition
 
and not an aging effect. They are external to the insulator and do not degrade the
 
electrical or mechanical properties of the porcelain insulating material or its support
 
structure. Therefore, no aging management for salt deposits is required for the period of
 
extended operation.
The staff's review of LRA Section 3.6.2.2.5 identified an area in which additional information was necessary to complete the review of the applicant's AMR results. The
 
applicant responded to the staff's RAI as discussed below.
In RAI 3.6.2.2.5 dated April 20, 2006, the staff requested that the applicant provide an AMP to manage the aging effects of insulator surface contamination due to salt deposit or
 
further justify not having an AMP.
3-463 In its response dated May 9, 2006, the applicant stated that it will implement visual inspections of high-voltage insulators to manage the aging effects of salt build-ups. These
 
inspections will be incorporated as a revision to the Periodic Monitoring of Combustion
 
Turbine Power Plant Electrical Program. Inspections will be by binoculars to a determined
 
threshold for implementing corrective actions. Corrective actions include subsequent
 
cleaning (i.e., washing) of a contaminated insulator. The visual inspections will be twice
 
per year beginning prior to the period of extended operation. The staff finds that the
 
applicant had adequately addressed the staff's concern. The staff identified this response
 
as a revision to Commitment No. 43.
The applicant stated that this inspection will be incorporated as a revision to the Periodic Monitoring of Combustion Turbine Power Plant Electrical Program. The purpose of this
 
AMP will be to demonstrate, for high-voltage insulators subject to an AMR, that the aging
 
effects of insulator surface contamination caused by salt deposit will be adequately
 
managed for reasonable assurance that high-voltage insulators will perform their
 
intended function(s) consistent with the CLB during the period of extended operation.
In its May 9, 2006, letter the applicant modified the Periodic Monitoring of Combustion Turbine Power Plant Electrical Program. In order to determine whether the applicant's
 
AMP was still adequate to manage the effect of aging to maintain the intended function
 
consistent with the CLB for the period of extended operation, the staff reevaluated the
 
following seven program elements: (1) "scope of program," (2) "preventive actions," (3)
"parameter monitored or inspected," (4) "detection of aging effects," (5) "monitoring and
 
trending," (6) "acceptance criteria," and (10) "operating experience." The staff's evaluation
 
of the applicant's "corrective action," "confirmation process," and "administrative controls"
 
is provided separately SER Section 3.0.4.  (1)Scope of Program - The scope of this program includes in-scope high-voltage insulators above 34.5 kV. This scope is acceptable to the staff because the
 
program will include all high-voltage (greater than 35 kV) insulators within the
 
scope of license renewal.  (2)Preventive Actions - The inspection and washing of in-scope high-voltage insulators above 34.5 kV under this AMP assist in preventing faults on
 
high-voltage circuits. These preventive actions are acceptable to the staff because
 
the inspection and washing will provide assurance that the insulators are free from
 
contamination and thus prevent faults on high-voltage circuits.    (3)Parameters Monitored and Inspected - Visual inspection of the in-scope high-voltage insulators above 34.5 kV will be performed by the applicant for signs
 
of salt build-ups. The first inspection will be prior to the period of extended
 
operations with an inspection frequency of at least twice per year. The staff finds
 
that the visual inspection of insulators will indicate salt build-ups and that
 
inspection frequency of at least twice per year is adequate.  (4)Detection of Aging Effects - In-scope high-voltage insulators above 34.5 kV will be checked for salt build-ups by visual inspections. If contamination is identified, the 3-464 inspections will distinguish between slight, medium, and heavy levels of contamination based on the lack of a shiny surface appearance (slight), build-ups
 
of contamination at the base of the insulators or indications of dripping (medium),
or an audible noise or visible corona (heavy). Inspections will begin prior to the
 
period of extended operation and occur twice per year thereafter. The staff finds
 
that inspection frequency of twice per year is adequate to preclude salt deposit on
 
high-voltage insulators.  (5)Monitoring and Trending - Monitoring of electrical commodities involves visual inspection by qualified individuals at specified intervals to determine whether there
 
are salt build-ups on the insulators. The staff finds this monitoring acceptable
 
because it will be performed by qualified individuals at specified intervals.    (6)Acceptance Criteria - High-voltage insulators are to be free from salt build-ups. If contamination is identified, the inspections will distinguish between slight, medium, and heavy levels of contamination based on the lack of a shiny surface
 
appearance (slight), build-ups of contamination at the base of the insulators or
 
indications of dripping (medium), or an audible noise or visible corona (heavy).
 
Subsequent corrective actions will be aligned with the level of contamination. The
 
staff finds the acceptance criterion (insulators to be free from salt build-ups)
 
acceptable.  (10)Operating Experience - On September 18, 2003, arcing was observed on 230 kV insulators in the OCGS switchyard. This event was entered and evaluated in the
 
corrective action process (CAP No. 02003-1925). The arcing was not severe
 
enough to cause ground faults. No protective relaying was actuated. There was
 
no associated loss of offsite power to OCGS. The observations made in the
 
switchyard are consistent with salt spray on the insulators. This occurrence was
 
the result of unusual weather conditions during the passing of Hurricane Isabel.
 
The high winds and waves deposited wind-blown salt spray on the insulators. The
 
electrical conductivity of the salty moisture on the insulators caused the observed
 
flashing. OCGS has not experienced any arcing leading to loss of offsite power
 
events attributable to salt contamination. The staff finds that the proposed
 
program will provide reasonable assurance that the high-voltage insulators will be
 
free from salt build-ups.
Contamination. The applicant stated that other external substances, including dust or animal contamination, could temporarily contaminate an insulator and cause an electrical
 
path to be formed. Such deposits are temporary and not an aging effect because they are
 
external to the insulator and do not degrade the electrical or mechanical properties of the
 
porcelain insulating material or its support structure. The buildup of surface contamination
 
is gradual. This contamination is washed away by rain or snow; the glazed insulator
 
surface aids this contamination removal. Surface contamination can be a problem in
 
areas with great concentrations of airborne particles as near facilities that discharge soot.
 
OCGS is located in an area where industrial airborne particle concentrations are
 
comparatively low, not in a heavily industrialized area. Minor contamination is washed
 
away by rainfall or snow, and cumulative buildup has not been experienced and is not 3-465 expected to occur. Therefore, no aging management activities for surface contamination are required for the period of extended operation.
On the basis of its review, the staff finds that surface contamination is not a problem for OCGS because it is not located in a heavily industrialized area. Therefore, the staff
 
agreed that no aging management activities for surface contamination are required for
 
the period of extended operation.
Wear. The applicant stated that mechanical wear applies to strain and suspension type insulators if they are subject to significant movement. Movement of the insulators can be
 
caused by wind blowing on the supported transmission conductor, causing it to swing
 
from side to side. If frequent enough, this swinging could cause wear in the metal contact
 
points of the insulator string and between an insulator and the supporting hardware.
 
Although this mechanism is possible, experience has shown that the transmission
 
conductors do not normally swing significantly. When they do swing due to a substantial
 
wind, they do not continue to swing for very long after the wind has subsided. Wind
 
loading that can cause a transmission line and insulators to sway is considered in the
 
design and installation. Therefore, the loss of material due to wear is not considered an
 
aging effect that will cause a loss of intended function of the insulators. Therefore, loss of
 
material due to wear is not an applicable aging effect for insulators.
On the basis of its review, the staff finds that the high-voltage insulators are not subject to significant movement and concluded that loss of material due to wear is not an applicable
 
aging effect for insulators.
Based on the programs identified above, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.6.2.2.2. For those line items that apply to LRA Section 3.6.2.2.5, the
 
staff determined that the LRA is consistent with the GALL Report and that the applicant has
 
demonstrated that the effects of aging will be adequately managed so that the intended
 
function(s) will be maintained, consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.6.2.2.3  Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of Conductor Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss of
 
Pre-Load The staff reviewed LRA Section 3.6.2.2.6 against the criteria in SRP-LR Section 3.6.2.2.3.
 
In LRA Section 3.6.2.2.6, the applicant addressed loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due to corrosion, and increased resistance of connection
 
due to oxidation or loss of pre-load.
SRP-LR Section 3.6.2.2.3 states that loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due to corrosion, and increased resistance of connection due to
 
oxidation or loss of pre-load could occur in transmission conductors and connections and in
 
switchyard bus and connections. The GALL Report recommends further evaluation of a
 
plant-specific AMP to ensure adequate management of this aging effect.
3-466 Aging Effects. LRA Section 3.6.2.1.4 lists the materials of construction for transmission conductors and connections as aluminum and steel.
The applicant stated that transmission conductors and connections are exposed to an outdoor air environment and that the transmission conductors and connections have no AERMs. LRA
 
Table 3.6.1 identifies loss of material due to wind-induced abrasion and fatigue, loss of
 
conductor strength due to corrosion, and increased resistance of connection due to oxidation or
 
loss of pre-load as the aging effects and mechanisms.
Loss of Conductor Strength and Wind-Induced Abrasion and Fatigue. The applicant stated that tests by Ontario Hydroelectric showed a 30-percent loss of composite
 
conductor strength of an 80-year old aluminum conductor-steel reinforced (ACSR)
 
conductor due to corrosion. Using the example of a 4/0 ACSR conductor, EPRI 1003057
 
shows the ultimate strength and the National Electrical Safety Code (NESC) heavy load
 
tension requirements of 4/0 ACSR as 8350 and 2761 pounds, respectively. The margin
 
between the NESC heavy load and the ultimate strength is 5589 pounds (67 percent of
 
ultimate strength margin). The Ontario Hydroelectric study showed a 30-percent loss of
 
composite conductor strength in an 80-year old conductor. In the case of the 4/0 ACSR
 
transmission conductor, a 30-percent loss of ultimate strength would mean that there still
 
would be a 37 percent ultimate strength margin between what is required by the NESC
 
and the actual conductor's strength.
There is a set percentage of composite conductor strength established at which a transmission conductor is replaced. NESC recommends that tension on installed
 
conductors be limited to a maximum of 60 percent of the ultimate conductor's strength.
 
The NESC also sets the maximum tension a conductor must be designed to withstand
 
under various load requirements considering ice, wind, and temperature. Therefore, for a
 
typical transmission conductor, there is an ample design margin to offset the loss of
 
strength due to corrosion and maintain the transmission conductor's intended function
 
through the period of extended operation.
The staff's review of LRA Section 3.6.2.2.6 identified areas in which additional information was necessary to complete the review of the applicant's AMR results. The applicant
 
responded to the staff's RAIs as discussed below.
In RAI 3.6.2.2.6-2 dated April 20, 2006, the staff requested that the applicant explain why the Ontario Hydroelectric study applies to OCGS. In its response dated May 9, 2006, the
 
applicant stated that in-scope transmission conductors have a minimum size of
 
397.5 ACSR and are specified and installed in accordance with NESC. It is conservative
 
to assume the same 80-year 30-percent loss of composite conductor strength for the
 
transmission conductors because the Ontario Hydr oelectric tests were for a conservative heavy loading zone. A 397.5 ACSR conductor has a minimum ultimate strength of 9900
 
pounds. Applying NESC requirements for maximum design line loading accounting for
 
wind and ice (< 60 percent) and initial unloaded tension limits (< 35 percent) the 397.5
 
ACSR conductors have a minimum heavy load tension ratio of 65 percent. If the
 
conservatively assumed 30-percent loss of composite conductor strength is deducted, the
 
bounding ultimate resulting strength margin is 35 percent. This minimum strength margin 3-467 for the transmission conductors is sufficient and wind loading and fatigue are not applicable aging mechanisms affecting the intended function of transmission conductors.
 
Based on its review, the staff's concern described in RAI 3.6.2.2.6-2 is resolved.
Corrosion of a steel core caused by loss of zinc coating or aluminum strand pitting corrosion is a very slow-acting aging effect even slower for areas with fewer suspended
 
particles and sulphur dioxide concentrations in the air than in urban or industrial areas.
 
OCGS transmission conductors do not have air particulate or contaminants as in urban or
 
heavy industrial areas. Therefore, corrosion is not an aging mechanism for their intended
 
function. EPRI 1003057 discusses the aging of high-voltage transmission conductors and
 
concludes that the potential aging mechanism of vibration has no significant effects of
 
concern for their intended function. Wind-loading induced vibration is considered in the
 
design and installation. Aging effects of loss of material and fatigue from transmission
 
conductor vibrations or sways would cause no loss of intended function for the period of
 
extended operation. Experience shows that the transmission conductors do not normally
 
swing significantly. When they do swing due to a substantial wind, they do not continue to
 
swing for very long after the wind has subsided. Wind loading that can cause a
 
transmission line to sway is considered in the design and installation. Therefore, wind-loading induced vibration and fatigues are not credible aging mechanisms, and will
 
not cause a loss of intended function of the conductors.
On the basis of its review, the staff finds that outdoor air on aluminum and steel will not result in aging of concern during the period of extended operation. Corrosion is a slow
 
process. Operating experience has found no failure of transmission conductors due to
 
vibration. Therefore, the staff concludes that there are no applicable AERMs for
 
transmission conductors.
Loss of pre-load. The applicant stated that pre-load of bolted connections is maintained by the appropriate design and the use of lock and Belleville washers that absorb vibration
 
and prevent loss of pre-load.
The staff's review found that torque relaxation for bolted connections is a concern for transmission conductor connections. An electrical connection must be designed to remain
 
tight and maintain good conductivity through a wide temperature range. This design
 
requirement is difficult to meet if the materials specified for the bolt and conductor differ
 
and therefore have different rates of thermal expansion. For example, copper or
 
aluminum bus/conductor materials expand faster than most bolting materials. If thermal
 
stress is added to stresses inherent at assembly, the joint members or fasteners can
 
yield. If plastic deformation occurs during thermal loading (i.e., heat up) the joint will be
 
loose when the connection cools.
EPRI TR-104213, "Bolted Joint Maintenance & Application Guide," recommends inspection of bolted joints for evidence of overheating, signs of burning or discoloration, and indications of loose bolts.
In RAI 3.6.2.2.6-1 dated April 20, 2006, the staff requested that the applicant discuss why torque relaxation for bolted connection was not a concern. In its response on 3-468 May 9, 2006, the applicant stated that the connections at switchyard equipment, transformers (including the in-scope startup and SBO transformers), the startup
 
transformer regulators, and disconnect switches are also periodically evaluated via
 
thermography as preventive maintenance.
From the design in accordance with EPRI-104213, periodic monitoring through existing preventive maintenance, and no
 
adverse operating experience, the applicant concluded that there are no additional
 
evaluations or actions required to address the aging mechanism of torque relaxation for
 
bolted connections for transmission conductors. On June 2, 2006, the applicant clarified
 
"periodic" as at least twice per year. The staff's concern described in RAI 3.6.2.2.6-1 is
 
resolved.
Based on the Preventive Maintenance Program identified above to verify the bolted connections, the staff concludes that the applicant has met the criteria of SRP-LR Section 3.6.2.2.3. For those
 
line items that apply to LRA Section 3.6.2.2.3, the staff determined that the LRA is consistent
 
with the GALL Report and that the applicant has demonstrated that the effects of aging will be
 
adequately managed so that the intended function(s) will be maintained, consistent with the CLB
 
during the period of extended operation, as required by 10 CFR 54.21(a)(3).
3.6.2.2.4  Quality Assurance for Aging Management of Nonsafety-Related Components
 
SER Section 3.0.4 provides the staff's evaluation of the applicant's quality assurance program for safety-related and nonsafety-related components.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report, for which the applicant had claimed consistency with the GALL Report and for which the GALL
 
Report recommends further evaluation, the staff determines that the applicant has adequately
 
addressed the issues that required further evaluation. 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).3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL Report Summary of Technical Information in the Application. In LRA Tables 3.6.2.1.1 and 3.6.2.1.2, the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and
 
AMP combinations not consistent with or not addressed in the GALL Report.
In LRA Tables 3.6.2.1.1 and 3.6.2.1.2, 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.
3-469 Note J indicates that neither the component nor the material and environment combination for the line item is evaluated in the GALL Report.
Staff Evaluation. For component type, material, and environment combinations that are not evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine whether
 
the applicant had 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 discussed in the following sections.
3.6.2.3.1  Electrical Commodity Groups}}

Latest revision as of 07:19, 15 January 2025

Safety Evaluation Report with Open Items Related to the License Renewal of Oyster Creek Generating Station
ML062300330
Person / Time
Site: Oyster Creek
Issue date: 08/18/2006
From: Ashley D
NRC/NRR/ADRO/DLR/RLRA
To: Rausch T
AmerGen Energy Co
Ashley D, NRR/DLR/RLRA, 415-3191
References
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Download: ML062300330 (900)
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