ML14364A262
| ML14364A262 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/22/2014 |
| From: | Pacific Gas & Electric Co |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML14364A259 | List: |
| References | |
| DCL-14-103, FOIA/PA-2016-0438 | |
| Download: ML14364A262 (104) | |
Text
{{#Wiki_filter:Enclosure 1 PG&E Letter DCL-14-103 Page 1 of 4 Diablo Canyon Power Plant LRA Changes Reflected in the Annual LRA Update Amendment 48 Attachment 18 of this enclosure includes a list of acronyms used in the 10 CFR 54.21(b) portion of this submittal. Attachment LRA Section Subject 1 None LR-ISG-2011-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," Revision 1 2 None LR-ISG-2011-02, "Aging Management Program for Steam Generators" 3 Table 3.3.2-3 LR-ISG-2011-03, "Changes to the Generic 15 Table 3.3.2-13 Aging Lessons Learned (GALL) Report Section Al. 18 Revision 2 Aging Management Program Table A4-1 (52) (AMP) XI.M41, 'Buried and Underground Piping and Tanks"'4 Section 3.1.2.1.1 LR-ISG-2011-04, "Updated Aging 15 Section 3.1.2.2.6 Management Criteria for Reactor Vessel Section 3.1.2.2.9 Internal Components for Pressurized Water Section 3.1.2.2.12 Reactors" Section 3.1.2.2.15 Section 3.1.2.2.17 Table 3.1.1 Table 3.1.2-1 Section 4.3.3 Section Al.41 Table A4-1 (22, 72, and 73)Section B1.5 Section B2 Section B2.1.41 5 Section Al LR-ISG-2011-05, "Ongoing Review of 15 Table A4-1 (20) Operating Experience" 6 Table 3.2.2-1 LR-ISG-2012-01, "Wall Thinning Due to 15 Table 3.2.2-3 Erosion Mechanisms" Table 3.3.2-3 Table 3.3.2-8 Table 3.4.2-3 Table 3.4.2-5 Section A1.6 Enclosure 1 PG&E Letter DCL-14-103 Page 2 of 4 Attachment I LRA Section I Subject 7 15 Section 3.2.2.1.1 Section 3.2.2.1.4 Section 3.2.2.1.5 Section 3.2.2.1.9 Table 3.2.2-1 Table 3.2.2-4 Table 3.3.1 Section 3.3.2.1.5 Section 3.3.2.1.9 Section 3.3.2.1.12 Section 3.3.2.1.19 Section 3.3.2.2.10.6 Table 3.3.2.1-19 Table 3.3.2-4 Table 3.3.2-5 Table 3.3.2-9 Table 3.3.2-10 Table 3.3.2-11 Table 3.3.2-12 Table 3.3.2-18 Section 3.4.2.1.5 Table 3.4.2-1 Table 3.4.2-3 Table 3.4.2-5 Section A1.13 Section A1.20 Section A1.22 Table A4-1 (8, 9, and 3)LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Enclosure 1 PG&E Letter DCL-14-103 Page 3 of 4 Attachment LRA Section Subject 8 Section 3.3.2.1.3 Draft LR-ISG-2013-01, "Aging Management of 15 Section 3.3.2.1.4 Loss of Coating Integrity for Internal Service Section 3.3.2.1.5 Level III (Augmented) Coatings" Section 3.3.2.1.8 Section 3.3.2.1.12 Section 3.3.2.1.13 Table 3.3.2-3 Table 3.3.2-4 Table 3.3.2-5 Table 3.3.2-8 Table 3.3.2-12 Table 3.3.2-13 Section 3.4.2.1.4 Table 3.4.2-4 Section A1.9 Section A1.10 Section A1.13 Section A1.22 Table A4-1 (74)9 Section 2.1.2.2 Update to reflect a review of plant equipment 15 Section 2.3.2.4 and editorial corrections. Table 3.3.2-3 Table 3.3.2-5 Table 3.3.2-7 Table 3.3.2-8 Table 3.3.2-9 Table 3.3.2-11 Table 3.3.2-12 Table 3.3.2-18 Table 3.4.2-1 Section Al.18 10 Table 3.4.2-4 Update to remove caustic dilution heat exchanger tubes exposed to secondary water from scope of license renewal.11 Table 4.3-1 Update to reflect WCAP-1 7103 revisions that Table 4.3-6 addressed Regulatory Issues Summary Section 4.9 2011-14 regarding user intervention in Westems TM.12 Section 4.7.4 License Amendments 216 (Unit 1) and 218 Section 4.9 (Unit 2), which revised the reactor coolant pump flywheel inspection interval from 10 to 20 years in accordance with WCAP-15666A. 13 Section A1.6 Flow-Accelerated Corrosion program revision 15 to address NSAC-202L-R4. Enclosure 1 PG&E Letter DCL-14-103 Page 4 of 4 Attachment LRA Section Subject 14 Section 2.1.5 Update to address LR-ISG-201 1-01 through -05; LR-ISG-2012-01; LR-ISG-2012-02, and LR-ISG-2013-01. 15 Section Al All Updates to Final Safety Analysis Report Section A1.2 Supplement. Section A1.6 Section A1.9 Section Al.10 Section Al.12 Section A1.13 Section Al.15 Section Al.16 Section Al.18 Section A1.20 Section A1.22 Section A1.32 Section Al.41 Table A4-1 (3, 8, 9, 20, 22, 32, 48, 52, 64, 66, 68, 72, 73, and 74)16 Section A1.16 One-Time Inspection Program Sample Size 15 Table A4-1 (48)17 Section Al. 15 Reactor Vessel Surveillance Program: 15 PG&E's Participation in EPRI PWR Supplemental Surveillance Program 18 None Acronym List 19 None References Enclosure 1 Attachment 1 PG&E Letter DCL-14-103 Page 1 of 2 LR-ISG-201 1-01, "Aging Management of Stainless Steel Structures and Components in Treated Borated Water," Revision 1 LR-ISG-2011-01 recommends two actions of the licensee to manage the effects of aging during the PEO for stainless steel structures and components exposed to treated borated water within the scope of license renewal. The following identifies the two actions and the results of PG&E's evaluation for impact on its LRA.LR-ISG-201 1-01 Action 1 Add the One-Time Inspection program to verify the effectiveness of the Water Chemistry program to manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking in treated borated water. This revised guidance applies to stainless steel structures and components exposed to treated borated water environments that are not actively controlled to oxygen levels less than 5 ppb.PG&E Evaluation of LR-ISG-2011-01 Action 1 Except for abandoned-in-place components associated with the boric acid evaporator subsystem, the following LRA tables currently specify the Water Chemistry and One-Time Inspection programs to manage aging of stainless steel structures and components exposed to treated borated water: (1) Table 3.1.2-2 (Reactor Coolant System)(2) Table 3.2.2-1 (Safety Injection System)(3) Table 3.2.2-2 (Containment Spray System)(4) Table 3.2.2-3 (Residual Heat Removal System)(5) Table 3.3.2-1 (Cranes and Fuel Handling System)(6) Table 3.3.2-2 (Spent Fuel Pool Cooling System)(7) Table 3.3.2-4 (Component Cooling Water System)(8) Table 3.3.2-6 (Nuclear Steam Supply Sampling System)(9) Table 3.3.2-8 (Chemical Volume and Control System)(10) Table 3.3.2-17 (Liquid Radwaste System), and (11) Table 3.3.2-18 (Miscellaneous Systems In Scope Only for Criterion 10 CFR 54.4(a)(2)) As stated in PG&E Letter DCL-1 1-136, "10 CFR 54.21 (b) Annual Update to the DCPP License Renewal Application and License Renewal Application Amendment Number 45," dated December 21, 2011, (LRA Table 3.3.2-8, Plant-Specific Note 9, and LRA Table 3.3.2-18, Plant-Specific Note 7), abandoned-in-place components associated with the boric acid evaporator subsystem will be managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP. As discussed in LRA Section B2.1.22, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP will provide for periodic Enclosure 1 Attachment 1 PG&E Letter DCL-14-103 Page 2 of 2 inspection of a representative sample of the internal surfaces material and environment combinations for systems within the scope of this program. The internal surfaces inspections will normally be performed through scheduled preventive maintenance and surveillance inspections such that work opportunities will be sufficient to detect aging and provide reasonable assurance that intended functions are maintained. Supplemental inspections not performed concurrently with planned work activities may also be performed. The locations and intervals for these supplemental inspections will be based on assessments of the potential for degradation which could lead to loss of intended function, and on current industry and plant-specific operating experience. In conclusion, PG&E's LRA is consistent with LR-ISG-2011-01, Action 1, except for abandoned-in-place components associated with the boric acid evaporator subsystem as discussed above.LR-ISG-2011-01 Action 2 Add reduction of heat transfer due to fouling as an aging effect for stainless steel heat exchanger tubes exposed to treated borated water, and manage this aging effect with the Water Chemistry and One-Time Inspection programs. As discussed in the ISG, the NRC Staff added reduction of heat transfer due to fouling as an aging effect requiring management with the Water Chemistry and One-Time Inspection programs for stainless steel heat exchanger tubes in the containment spray system, emergency core cooling system, spent fuel pool cooling and cleanup, and chemical and volume control system. The NRC Staff also noted that the current guidance for the containment spray system already includes a reduction of heat transfer item;however, the cited environment is treated water.PG&E Evaluation of LR-ISG-201 1-01 Action 2 As noted in the following LRA tables, stainless steel heat exchanger tubes with a reduction of heat transfer due to fouling aging effect currently require management with the Water Chemistry and One-Time Inspection programs.(1) Table 3.2.2-1 (Safety Injection) (2) Table 3.2.2-3 (Residual Heat Removal System)(3) Table 3.3.2-2 (Spent Fuel Pool Cooling System)(4) Table 3.3.2-4 (Component Cooling Water), and (5) Table 3.3.2-8 (Chemical Volume and Control System)DCPP has no in-scope stainless steel heat exchanger tubes exposed to treated borated water in the containment spray system.In conclusion, PG&E is consistent with LR-ISG-2011-01, Action 2. Enclosure 1 Attachment 2 PG&E Letter DCL-14-103 LR-ISG-2011-02, "Aging Management Program for Steam Generators" LR-ISG-2011-02 evaluates the suitability of using Revision 3 of NEI 97-06 to manage steam generator aging. In addition, the LR-ISG corrects an incorrect revision in NUREG-1 801, Revision 2, to the Steam Generator Integrity Assessment Guidelines. PG&E's licensing basis for DCPP's Steam Generator Tube Integrity program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-122, dated September 22, 2010 The NRC Staff evaluated the DCPP Steam Generator Tube Integrity program in its SER, Section 3.0.3.1.6, dated June 2, 2011.The NRC Staff is recommending that applicants for license renewal follow the guidance provided in Revision 3 of NEI 97-06 when implementing their steam generator AMP, including using Revision 3 of the Steam Generator Integrity Assessment Guidelines. The DCPP Steam Generator Tube Integrity program establishes and maintains the program consistent with NEI 97-06, Revision 3, and the referenced EPRI guidelines. The Steam Generator Tube Integrity program also utilizes EPRI 1019038, "Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 3." In conclusion, PG&E is consistent with LR-ISG-2011-02. Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 1 of 8 LR-ISG-2011-03, "Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 'Buried and Underground Piping and Tanks"'LR-ISG-2011-03 contains recommended inspections, sample sizes, and inspection frequencies for GALL Report AMP XI.M41, "Buried Piping and Underground Piping and Tanks." PG&E's licensing basis for the DCPP Buried and Underground Piping and Tanks program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-097, dated August 2, 2010 (3) PG&E Letter DCL-10-113, dated August 30, 2010 (4) PG&E Letter DCL-10-148, dated November 24, 2010 (5) PG&E Letter DCL-1 1-002, dated January 21, 2011 (6) PG&E Letter DCL-1 1-022, dated March 14, 2011 The NRC Staff evaluated the DCPP Buried and Underground Piping and Tanks program in its SER, Section 3.0.3.2.8, dated June 2, 2011.In order to address the recommendations in LR-ISG-2011-03, PG&E updates its licensing basis for the DCPP Buried Piping and Tanks Inspection and External Surfaces Monitoring programs as follows. The ISG-recommended changes to the Selective Leaching program were evaluated and determined not to be applicable to DCPP since the buried components in-scope of the DCPP Selective Leaching program do not have cathodic protection or coatings.(1) As discussed in PG&E Letter DCL-10-148, PG&E indicated that the in-scope buried piping of the makeup water system consists of asbestos cement pipe and a short segment of in scope, non-cathodically protected carbon steel piping contained inside a valve pit in contact with soil. PG&E Letter DCL-11-002 removed the non-cathodically protected carbon steel piping inside a valve pit in contact with soil from the scope of license renewal. Inspection of the in-scope makeup water asbestos cement pipe will be conducted as defined in LR-ISG-2011-03, Appendix A, Table 4a for cementitious material.As discussed in PG&E Letter DCL-10-097, the in-scope buried makeup water system valves consisted of non-cathodically protected buried copper valves and copper valves in a valve pit in contact with soil. PG&E Letter DCL-1 1-002 removed the valves inside a valve pit in contact with soil from the scope of license renewal. PG&E Letter DCL-1 1-022 noted that the remaining in-scope buried non-cathodically protected makeup water valves were not copper, but cast iron. PG&E will inspect the non-cathodically protected Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 2 of 8 makeup water system cast iron valves buried in soil in accordance with LR-ISG-2011-03, Appendix A, Table 4a. As discussed in SER Section 3.0.3.2.8, "although the cast iron valves are not cathodically protected, the DCPP Buried Piping and Tanks Inspection program will adequately manage aging of them because cast iron valves are thicker than piping or comparable steel valves and have a higher tolerance to general corrosion, and the valves are located in a nonaggressive soil environment." For the purposes of this program the aging management requirements for buried steel will be applied to these cast iron valves.PG&E has evaluated the in-scope makeup water system carbon steel piping and tanks encased in concrete and determined there are no aging effects for these components. See Item (11) below.As discussed in SER Sections 3.0.3.2.8 and 3.0.3.2.18, groundwater testing confirmed that DCPP's groundwater and soil environment was nonaggressive. As discussed in LRA Section B.2.1.32 and Table A4-1, Item 14 of PG&E Letter DCL-09-079, DCPP will monitor groundwater samples every five years for pH, sulfates and chloride concentrations, including consideration for potential seasonal variations. In addition, PG&E will perform a soil analysis prior to entering the PEO to determine the corrosivity of the soil in the vicinity of non-cathodically protected in-scope makeup water cast iron valves. If the initial analysis shows the soil to be non-corrosive, this analysis will be re-performed every ten years thereafter. Item (2) below discusses inspection intervals for steel components in the areas where soil analysis finds the soil to be corrosive. (2) As discussed in PG&E Letter DCL-10-148, PG&E indicated that the in-scope buried ASW piping consists of cathodically protected steel piping and non-cathodically protected steel piping. PG&E committed to installing cathodic protection on a portion of the non-cathodically protected ASW discharge steel piping that is not encased in concrete prior to the PEO. PG&E also indicated that the cathodic protection systems of the ASW piping will be available more than 90 percent of the time.PG&E revises the licensing basis in PG&E Letter DCL-10-148 as follows. If cathodic protection for the ASW steel piping meets the acceptance criteria in LR-ISG-2011-03, Appendix A, Table 4a, Footnote 2.C, including a revised system availability of 85 percent, then inspection of the in-scope cathodically protected ASW steel piping will be conducted consistent with LR-ISG-2011-03, Appendix A, Table 4a, Preventive Action C, with the number of inspections not to exceed 150 percent of the not to exceed values listed in the table. Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 3 of 8 If cathodic protection for the cathodically-protected ASW steel piping does not meet acceptance criteria (LR-ISG-2011-03, Appendix A, Table 4a, Footnote 2.C), PG&E will revise the scope of inspections as defined in LR-ISG-2011-03, Appendix A, Table 4a, Preventive Actions D, E, or F, with the number of inspections not to exceed 150 percent of the not to exceed values listed in the table. As defined in LR-ISG-2011-03, Appendix A, Table 4a, Notes 2E and 7, soil samples will determine which Preventive Action (D, E, or F) is required. These samples will be obtained and tested consistent with LR-ISG-2011-03, Table 4a, Note 7. If the soil is demonstrated not to be corrosive to buried steel piping, the number of inspections will be based on LR-ISG-2011-03, Table 4a, Preventive Action E. If the soil is determined to be corrosive to buried steel piping, then the number of inspections will be based on LR-ISG-2011-03, Table 4a, Preventive Action F.As discussed in PG&E Letter DCL-10-148, ASW system piping that will not be cathodically protected is encased in concrete. The concrete provides a noncorrosive environment for the steel piping such that cathodic protection is not necessary and there are no aging effects. As discussed in PG&E Letter DCL-10-148, DCPP operating experience confirms effectiveness of this design.PG&E has evaluated the in-scope ASW system stainless steel piping encased in concrete and determined there are no aging effects for these components. See Item (11) below.(3) Consistent with LR-ISG-2011-03, Appendix A, Table 2b, the in-scope underground copper piping and piping components in the ASW system are coated. Inspections will be conducted to detect external corrosion in the underground copper piping, and piping components, and PVC piping in the ASW system as defined in LR-ISG-2011-03, Appendix A, Table 4b. Visual inspections of PVC piping will be augmented with manual examinations to detect hardening, softening, or other changes in material properties. (4) The ASW system also contains buried portions of super austenitic stainless steel piping. This piping is in the scope of the Buried Piping and Tanks Inspection program. However, LR-ISG-2011-03, Appendix A, Table 4a, does not require any inspections on buried super austenitic stainless steel.(5) As discussed in PG&E Letters DCL-10-113 and DCL-10-148, the buried diesel fuel oil storage tanks are double walled steel with the exterior surface wrapped in a corrosion resistant fiberglass reinforced plastic. As discussed in PG&E Letter DCL-1 0-113, PG&E indicated that the buried diesel fuel oil storage tanks are equipped to monitor the space between the inner and outer walls for leakage. SER Section 3.0.3.2.8 discusses the acceptability of this Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 4 of 8 monitoring method to adequately manage the aging of the tanks. As allowed by LR-ISG 2011-03, Appendix A, Section 4.d.iv, PG&E will monitor the condition of the buried diesel fuel oil storage tanks by monitoring the space between the inner and outer walls for leakage.As discussed in PG&E Letter DCL-10-148, PG&E indicated that 100 percent of the underground diesel generator fuel oil system piping is visually inspected by an existing plant procedure on a ten-year interval and that this existing plant procedure would be incorporated into the DCPP External Surfaces Monitoring program. To address LR-ISG 2011-03, Appendix E, PG&E will remove the underground diesel fuel oil piping inspections from the scope of the DCPP External Surfaces Monitoring program. The DCPP Buried Piping and Tanks Inspection program will describe this inspection and the associated ten-year frequency. (6) Consistent with the LR-ISG-2011-03, Section titled, "Removal of the Recommendation to Volumetrically Inspect Underground Piping to Detect Corrosion," PG&E revises the commitment in PG&E Letter DCL-10-148 to perform nondestructive examinations during visual inspections of piping to be consistent with LR-ISG-2011-03, Appendix A, Section 4.b.iv, which requires supplemental surface and/or volumetric NDT of buried piping only if significant indications are observed.(7) PG&E will double the initial inspection size following discovery of adverse conditions and will manage subsequent discoveries of adverse conditions as defined in LR-ISG-2011-03, Appendix A, Sections 4.f.iii and 4.f.iv.(8) Consistent with LR-ISG-2011-03, Appendix A, Section 6.b, PG&E will evaluate the extent of condition where damage to the coating is significant and the damage was caused by nonconforming backfill to ensure the as-left condition of backfill in the vicinity of observed damage will not lead to further degradation. In addition, PG&E will qualify personnel performing inspection of coatings on buried piping consistent with LR-ISG-2011-03, Appendix A, Section 6.b.(9) In lieu of visual inspections of the external surface of buried piping requiring excavation, PG&E may perform hydrostatic testing or internal inspections of the pipe consistent with LR-ISG-2011-03, Appendix A, Section 4.b.x.(10) As discussed in PG&E Letter DCL-10-148, PG&E indicated that the 850-mV criteria from NACE SP0169-07, paragraph 6.2.2 are used for the ASW piping cathodic protection test locations where static (native) pipe-to-soil potential data is not available and that the 1 00-mV criteria are used for the ASW pipe test locations where static (native) pipe-to-soil potential data is available. Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 5 of 8 PG&E will use the 850-mV polarized potential relative to a copper sulfate electrode cathodic protection acceptance criteria as defined in LR-ISG-2011-03, Appendix A, Table 6a.(11) Consistent with NUREG-1800, Revision 2, Items 3.3.1-112 and 3.3.1-120, PG&E has evaluated the steel and stainless steel piping, piping components, piping elements, and tanks encased in concrete and determined there are no aging effects for these components. There are floor and equipment drains, piping, and tanks encased in concrete. A majority of the piping and components are within buildings where the potential for water intrusion into the concrete is very low, and therefore the conditional statements associated with NUREG-1800, Revision 2, Item 3.3.1-112 provide a sufficient basis of no aging effects. The remainder of the piping encased in concrete is the ASW discharge. PG&E has previously provided justification for the lack of aging effects for this ASW piping in PG&E Letter DCL-10-148. There has been no DCPP operating experience to show that metallic components embedded in concrete experience any aging effects.(12) As discussed in PG&E Letter DCL-10-148, PG&E committed to inspecting buried PVC and asbestos cement pipe components located in the fire water system (LRA Table A4-1, Item 52). PG&E also committed to subjecting fire mains to a periodic flow test in accordance with NFPA 25, Section 7.3, at a frequency of at least one test in each one-year period. These flow tests will be performed in lieu of excavating buried portions of firewater pipe for visual inspections. SER Section 3.0.3.2.8 discusses the sufficiency of this flow testing to adequately manage the aging of the buried fire water piping.As concluded in SER Section 3.0.3.2.8 and allowed by LR-ISG-2011-03, Appendix A, Section 4.b.ix, in-scope buried fire water piping and components (including PVC and asbestos cement pipe) will be managed by subjecting fire mains to periodic flow tests in accordance with NFPA 25, Section 7.3, at a frequency of at least one test in each one-year period. Although no directed visual inspections of the in-scope buried fire water system piping will be completed through the DCPP Buried Piping and Tanks Inspection program, buried piping will be inspected opportunistically as it is excavated. Additionally, opportunistic internal visual inspections will be conducted through the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program and periodic internal visual inspections will be conducted through the DCPP Fire Water System program.As discussed in SER Sections 3.0.3.2.8 and 3.0.3.2.18, groundwater testing confirmed that DCPP's groundwater and soil environment was nonaggressive. As discussed in LRA Section B.2.1.32 and Table A4-1, Item 14 of PG&E Letter DCL-09-079, DCPP will monitor groundwater Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 6 of 8 samples every five years for pH, sulfates and chloride concentrations, including consideration for potential seasonal variations. In addition, PG&E will perform a soil analysis prior to entering the PEO to determine the corrosivity of the soil in the vicinity of non-cathodically protected steel in-scope buried fire water piping and components. If the initial analysis shows the soil to be noncorrosive, this analysis will be re-performed every ten years thereafter. If the soil is found to be corrosive, the effect on the pipe will be evaluated to determine if aging management of the buried pipe and valves is adequate.LRA Tables 3.3.2-3 and 3.3.2-13 are revised to address LR-ISG-2011-03 as shown in this Attachment. LRA Section Al.18 and Table A4-1, Item 52 are revised to address LR-ISG-2011-03 as shown in Enclosure 1, Attachment
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Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 7 of 8 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-3 Auxiliary Systems -Summary of Aging Management Evaluation -Saltwater and Chlorination System (Continued) Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Piping LBS, PB Copper Alloy Plant Indoor Air Loss of material Buried Piping and Tanks None None H, 3 (Ext) Inspection (B2. 1.18)Piping LBS, SIA Polyvinyl Plant Indoor Air Loss of material Buried Piping and Tanks None None H, 3 Chloride (Ext) Inspection (B2. 1.18)(PVC)Valve LBS, PB Copper Alloy Plant Indoor Air Loss of material Buried Piping and Tanks None None H, 3 Ip(Ext) Inection (B2.1.18) I II _ I Notes for Table 3.3.2-3: Plant Specific Notes: 3 The Buried Piping and Tanks Inspection (B2.1.18) is used to monitor underground copper alloy piping, pipe components, and PVC piping for loss of material. Reference LR-ISG-2011-03, Appendix C, Item VII.l.AP-284 and PG&E Letter DCL-14-1 03, Enclosure 1, Attachment
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Enclosure 1 Attachment 3 PG&E Letter DCL-14-103 Page 8 of 8 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-13 Auxiliary Systems -Summary of A ing Management Evaluation -Diesel Generator Fuel Oil S stem Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Tank PB Carbon Steel Plant Indoor Air Loss of material Etr,,nal Surfacoc, VII.I-8 3.3.1.58 BH, 2 (Ext) Monitwoing ProgrAm (92.1.20,Buried Piping and Tanks Inspection (B2. 1.18)Tank PB Carbon Steel Plant Indoor Air Loss of material In.pection of internal VII.H2-21 3.3.1.71 DH, 2 (Int) SuFfaGes-in MicceIlaneeus Piping(82.1.22)Buried Piping and Tanks Inspection (B2.1.18)Piping PB Carbon Steel Plant Indoor Air Loss of material Buried Piping and Tanks VII.I-8 3.3.1.58 H, 2______________Ex_____ Inspection_(B2. 1.18) __________ Notes for Table 3.3.2-13: Plant Specific Notes: 2 The Buried Piping and Tanks Inspection (B2.1.18) is used to monitor the underground diesel generator fuel oil system piping for loss of material. Reference LR-ISG-2011-03, Appendix C, VII.l.AP-284 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
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Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 1 of 45 LR-ISG-2011-04, "Updated Aging Management Criteria for Reactor Vessel Internal Components of Pressurized Water Reactors" PG&E's licensing basis for the DCPP PWR Vessel Internals program is documented in: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-098, dated August 2, 2010 (3) PG&E Letter DCL-10-121, dated September 22, 2010 (4) PG&E Letter DCL-10-167, dated January 12, 2011 In order to address the recommendations in LR-ISG-2011-04 and NUREG-1 801, Revision 2, for reactor vessel internals, PG&E updates its licensing basis as follows: As discussed in PG&E Letter DCL-09-079, LRA Table A4-1, Item 22, for Reactor Vessel Internals, PG&E previously committed to: (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the PEO, PG&E will submit an inspection plan for reactor internals to the NRC for review and approval. PG&E will validate the schedule for inspection of the baffle and former bolts on a plant-specific basis to ensure that it will appropriately manage the design fatigue analysis.In January 2012, MRP-227-A (EPRI TR-1022863), "Materials Reliability Program: Pressurized Water Reactor (PWR) Internals Inspection and Evaluation Guidelines," was issued. MRP-227-A is the NRC-endorsed version of MRP-227, which incorporates the NRC Staff's SE, Revision 1, on MRP-227. LR-ISG-2011-04 revises the recommendations in the GALL Report, Revision 2, and the NRC Staff's acceptance criteria and review procedures in the SRP-LR to ensure consistency with MRP-227-A. To address the issuance of MRP-227-A and LR-ISG-2011-04, PG&E: (1) Developed LRA Section B2.1.41 consistent with GALL Report, Revision 2, XI.M16A and LR-ISG-2011-04. (2) Developed LRA Section A1.41 to describe the DCPP PWR Vessel Internals program. Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 2 of 45 (3) Deleted LRA Table A4-1, Item 22, for Reactor Vessel Internals. (4) Added LRA Table A4-1, Item 72, to implement the DCPP PWR Vessel Internals program (B2.1.41) prior to the PEO.(5) Added LRA Table A4-1, Item 73, to submit responses to the applicable AMP plant-specific action items, conditions, and limitations identified in the NRC SE, Revision 1, on MRP-227 by December 2015. In addition to developing an AMP, the NRC SE for MRP-227 contains eight action items for applicants/licensees to consider. Responses to the applicable AMP plant-specific action items, conditions, and limitations identified in the NRC SE, Revision 1, on MRP-227 will be submitted to the NRC by December 2015.(6) Incorporated GALL Report, Revision 2, Table IV.B2, for PWR vessel internals and LR-ISG-2011-04 into DCPP reactor vessel internal components' AMR results in revised LRA Tables 3.1.1 and 3.1.2-1, and Sections 3.1.2.1.1, 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17. Revised LRA Tables 3.1.1 and 3.1.2-1, and Sections 3.1.2.1.1, 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, 3.1.2.2.17, 4.3.3, B1.5, B2, and new Section B2.1.41 are shown in this Attachment. New LRA Section A1.41, revised Table A4-1, Item 22, for Reactor Vessel Internals, and new Table A4-1, Items 72 and 73 are shown in Attachment
- 15.
Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 3 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 3.1.2.1.1 Reactor Vessel and Internals Environment
- Neutron flux Aging Management Programs* PWR Vessel Internals (B2.1.41)For R'acto. Vossel internals, PG&E Will: (I in ther,.vwl iv ndl~ nronrm.,for inU etotn ndmnnn nhoefeeo (r anr idpat inanlo the itnltr mn~ema m nnrJ irnafnvestatraonl an *ka inn, ,ean, nranrnrne enr v,, r*c % .7r r i Uric bi~ K 7 cl .At ad Id 4 d iI *r'- UMU V~*t M M Coo4 rS prprcm doS ~S ~~tS3~H r~,I kI #r +kr ran ;t. + i Aiannt.' 11) ! +na nak. klt, + + I,,tsnrn nr.n I.S.al.,i.,,r
.4. , ...... .. ..... .... Lv ,, -v,-,-; 1 , ;;;:;, .--., *S..*S ;.;;.;r v.i. ., Sv ,
- L,,v.,. i,. * ,; ;;less than 241 months before entoring the period of extonded operation, PG&= wil! submnit an plan fbr rpe-actor to the NiRC for re,;ew and appro-al.I I 3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void Swelling Not applicable.
The DCPP PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-22 7-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of selected reactor vessel internal components.Loss of #fratue toughness due to neutron irradiat-on embrittlement and vo id! sen-g for stainless steel internals components exposed to reactor coolant will be managed by (1) pa..i.pating in the indust. ' progr..ams fn g and managing aging effects on reactor internals; (2) evaluating and implementing the results-of the industr; programns as applicable to the reactor interals; and (3) upon completien of these programs, but not less than 24 moenths before entering the period of entended-operation, submitting an inspection plan for reactor internals to the NRC for review and appFeyal.- 3.1.2.2.9 Loss of Preload due to Stress Relaxation Not applicable. The DCPP PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-227-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of selected reactor vessel internal components. Lss Of preload due to s6t.rs relaxation fr Anickel alloy and stainless steel-a4ta .ar fil 4ay. faa1 4. ,f .4 4-- ran far nl i s .MI k~ .~ai A k.,1 * ~ r ---S~V ~ ~ SI 5I reac~tor internals; (2) evaluating and imlmnigthe results of the industr,' programs-as aDolicable to the reactor internals: and (3') upon Gompletion of these F)rOOrams. but+r~ la +kn '),1 + krrnh afer +nar nf tka ;~rr A f a.ta,.an a r4m, Ai + ky, ;++jfln*nt , f- + o+,. I a ,, nal ar nta mm 1+. t t,, a KID .n fa- .4 .in vanv n v a. a, , I 1**--1 5..Sf.po'~ Wa51 5 5%F C21 r5c to5% Ii o*"C *0 RV V. r rv ENV* El" a prV 14. Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 4 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 3.1.2.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress Corrosion Cracking (IASCC)Not applicable. The DCPP PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-227-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of selected reactor vessel internal components.For managing the aging Of cracking due to strs OR cracking and irradiation assisted stress corrosion crackg of "ainss steel reactor internals componcnts exposed to reactor coolant, Water Chemistr,' (132.1.2) is augmented by(1 reactor internals; (2) evaluating and implementing the rcsults of the indusr~y programs as applicable to the reactor internals; and (3) upon completion of these programs, but* a'JL at..,,., La aLa, a S..T a, a,.,, at, at. Lit.at.'a
- t. a.,a at.,. a, a.j La 5t. ~ a'~ t.aLt.a aLa.,,.. t.fJta tAtat.a a, .,t..Ja a aaLLaa a~ ..aa a 4 Vlt, I U i[.peeur-i.uie I eFur iLCJ.C iu Il IG te I -Rn appFeylu.3.1.2.2.15 Changes in dimensions due to Void Swelling Not applicable.
The DCPP PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-22 7-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of selected reactor vessel internal components. G .hang.s in dimensions duo to void swelling for stainless steel react+ka ;...i Aebn + rnaa far; +nn;na+;n An r~~an1 a nann na. an -;a 4-a~ ......r in mqnqr j g~. ~ -. a ... V L.~~aa a~ -...au.. a~ ~aa a--------a aa La a (2) evaluating and implementing the results of the inutyprograms as applicable to the reactor internals; and (3) upon com~pletien of these proegrams, but not less than 24 moneths before entering the period of extended operation, submittin an nseto plan for reactor internals to the NRC for review and aEDEroval-. 3.1.2.2.17 Cracking due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking Not applicable. The DCPP PWR Vessel Intemals program relies on implementation of the inspection and evaluation guidelines in EPRI TR-1022863 (MRP-227-A) and EPRI TR-1016609 (MRP-228) to manage the aging effects of selected reactor vessel internal components. Fo maRnagig the aging Of cacking due to stress corrosion cracking, primnar; water stress corsoGrackinq. and irradiation assisted stress corrosion I I I d r~rnrMInn 0? ~?iIflIr~Ft5~ PSr'0I rr'.~r~tor In?~rn~ii5~t r~nmnnn~nTR nYfl05~rI To r~r~tnr r'nn'in? ~.--.--....----..-..'.--~--............ GrrWinnof staimktrs (R2I e eI Feme iintmannr i 1 GOpnentiinexposin the indi-toF tp'a n an ra rn n fry 113 na ,an ý wall bei a aumnte by aana aaan in an *R ra ther ~ n a-a a- a..-. ~ .~ -~aa a~ -aa~-L- ~aa ~ a a. aL-a. a-..,5 ~r~ ~ *4Ln ..n~a .14,.. aC 41...-. ...,.J. a~4.a... I,..LI.... 4,.a. IL..'.t. V ..Aa'.AY..a La a a~ .a a.., aaaa r at.a a at. a aa.aa a La at. a '.,.,.a at.., '.~ a.. a.... aa a'a.a La ...ata j r a .~ a a..aa a a'.., L4J .Ajfaat...A..,at. a.'., La at.raar'.far gn+prnalo. anti PIN i a ^nn a,^nm1na8a,, ^f +kmcgp nr^ ararat. ai+ ne%+ mýoo +han '7A j 11 11I 11 14 1 a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ T1. a aV. ak.. ,taLataataa ~L t 'aaaLa ~ltaa.t'. .r~ .ttaa .ttaaata il.T WL_.a a aa. t.3;.Jra.a a -a'.a:Ib reau.terimm al lICktG t~e LIN G Hut Fevie.w ii ~p~.m Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 5 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Intemals, and Reactor Coolant System Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.1.1.22 Stainless steel (SS- Loss of fracture toughness due PWR Vessel Internals No Consistent with NUREG-inck.ding GASS; PH to thcr..al aging and neutron (B2.1.41)FSAR supplement 1801, Revision 2, and LR-SS oF martena.iti SS) irradiation embrittlement and commitment to (1) partic;patc ISG-2011-04. ora~d nickel alloy for CASS, martensitic SS, and in industry RVI aging See further evaluat.ion Westinghouse reactor PH SS due to thermal aging program. (2) implement Section 3.1.2.vessel internals embrittlement;T or changes in applicable results (3) submit"Existing Programs" dimensions due to void For NRC approval 24 components exposed swelling or distortion; or loss of months beforc the extended to reactor c.olant and preload due to thermal and period an RVI inspection plan neutren flux irradiation enhanced stress ba-,sed, on relaxation or irradiation recommendatin. enhanced creep; or loss of material due to wear 3.1.1.27 Stainless steel (S$- Loss of fracture toughness due PWR Vessel Internals No Consistent with NUREG-in^luding GASS, PH to neutron irradiation (82.1.41)FSAR supplement 1801, Revision 2, and LR-SS or- mart.nclt, SS) embrittlement and for CASS, commitment to (1) pa"ticipate" ISG-2011-04. oraPd nickel alloy martensitic SS, and PH SS due in RVI aging See further evaluation in Westinghouse reactor to thermal aging embrittlement; programs (2) t Section 3.1.2...vessel internals or changes in dimensions due applicable results (3) submit"Expansion" to void swelling or distortion; or for NRC approval > 24 componentssGFews-, Less-loss of preload due to months befoFe the extended bolts, tie rods, and thermal and irradiation an RVI inspection plan hold down springs enhanced stress relaxation or based en industr,,, irradiation enhanced creep; or recmmendation. loss of material due to wear I I I _I Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 6 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, and Reactor Coolant System Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.1.1.30 Stainless steel or Cracking due to stress Water Chemistry (B2.1.2) and No Consistent with nickel alloy corrosion cracking, irradiation-PWR Vessel Internals NUREG-1801, Revision 2, Westinghouse reactor assisted stress corrosion (B2. 1.41)FSAR .upplm.nt and LR-ISG-2011-04. vessel internals cracking, or fatigue ..mmitment to (1) See futher evaluation in"Primary" components &:n induetr RVI aging Section 3.1.2.2.12.(e.g., Uppcr internals ,PrOgrams (2) implement assembly, RCCA guide applicable results (3) submit tube assemblies, for NRC approval > 24 gaffieffefmef-Fnenft before the extende LeweF an RVI inspection plan 4 nternal assembly-,- based on industy shroud assemblies, reco.mendation. Plenum coere and plenum cylinder, UppeF grid accembly, Ctrogli Fed guide tube (CRGT)assembl, GFe-suppek held-assembly, Core barrel assembly, Lower grid asembly, re!w-distributor assembly, T-hermnal shiekld, Instrumentation:ý I____ 2UPPOrt Structures) _____________ ____________________ ____________ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 7 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, and Reactor Coolant System_Item Component Type Aging Effect I Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.1.1.33 Stainless steel (SF Loss of fracture toughness due PWR Vessel Internals No Consistent with inluding GAS&, PH to neutron irradiation (B2.1.41)FSAR supplement NUREG-1801, Revision 2, S S or- n7a,.o;n. S S) embrittlement and for CASS, "om"mitment to (1) participat and LR-ISG-2011-04. oraPd nickel alloy martensitic SS, and PH SS due in industry RVI aging See fUrther evaluation in Westinghouse reactor to thermal aging embrittlement; programs (2) implmen .ection .1 .2 -15.vessel internals orcGhanges in dimensions results (3) submit"Primary"components due to void swelling or for NRC approval 2 21 distortion; or loss of preload months before the extended due to thermal and irradiation an RVI inspection plan enhanced stress relaxation or based en industry, irradiation enhanced creep; or "ec.mmendatien. loss of material due to wear 3.1.1.37 Stainless steel and-or Cracking due to stress Water Chemistry (B2.1.2) and No Consistent with nickel alloy corrosion cracking, primary PWR Vessel Internals NUREG-1801, Revision 2, Westinghouse reactor water stress corrosion (B2.1.4 ,)FSAR supplement and LR-ISG-2011-04. vessel internals cracking, irradiation-assisted .OMmitment to () participate See futher evaluation in-"Existing Programs" stress corrosion cracking, or i R 3.1.2.2.17. components (e-q., fatigue programs (2) implmen UppeF inte~na~s-applerabie results (3) subi assembly, RCCA guide for NRC app-rval 2 tube assemblies, months, befoe the extended Lower internal-
- perid an RVI inspection plan assembly, CEA shroud based on indust-y assemblies, Core Freommendation.
6hroud assembly, Core assembly, Core barrel assembly, Lowe .grid assemb, ....w-_____distributor assemby ______________ _____________________ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 8 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Intemals, and Reactor Coolant System Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.1.1.63 Steel reactor vessel Cracking or Loss of material Inservice Inspection (IWB, No Consistent with flange, stainless steel due to Wear IWC, and IWD) (B2.1.1) or NUREG-1801, Revision 2, and nickel alloy reactor PWR Vessel Internals and LR-ISG-2011-04 vessel internals (B2.1.41)exposed to reactor coolant (e.g., upper and lower internals assembly,--EA shroud assembly, core support bFel, ppeF gid-assembly, core support shield assembly, lower I Fg-aeeeasseb) 3.1.1.80 Stainless steel Cracking due to stress Water Chemistry (B2.1.2) and No Consistent with Westinghouse reactor corrosion cracking, irradiation-PWR Vessel Intemals NUREG-1801, Revision 2, vessel internal assisted stress corrosion (B2.1.41)ThermFal Aging and. and LR-ISG-2011-04.-for- 'Expansion" cracking, or fatigueLeee-ef Neutron Irradiation naterial, environmnt, and components~ast-
- rrature toughness due to Embrittlement of GASS- aging effect, but a different austenitic stainless therm~al aging and- neutron (B43-3gn aaement program-steel reaGcer vessel iradoati.n embrittlement FSAR supplement internals (e.g., upper ,,mmitment to (1) participate intcrnals assembly, inidustry RVI aging-loweF ii4einaI programs (2) implement assembly, CEA shroud applicable results (3) submi assemblies, control rod for NRC approval >24 guide tube assembly, months before the e-Atend-ed-Gore support shield period an RVI in~spection-assembly, lower grid plan based on is credited.lassembWy I _____________
I_____________ I_______ I___________ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 9 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 10 of 45 Table 3.1.2-1 Reactor\Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM lessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended T Material Environment i Aging Effect Aging Management Program NUREG- Table I f Notes Function i Requiring 1801 Vol. Item_ Management 2 Item RVI Baffle-&-to-SS Stainless IReactor lChanges in PWR Vessel Internals (B2.1.41) IV.B2.RP-13.1.1.33 A, 3 Former Assembly Steel Coolant and dimensions FSAR supplem.ent c..o..mitmcnt 272-4 (Baffle/ Former I neutron flux to (1) participate in indutry RVI Bolts) (Ext) aging prgas (2) imp e.. n -I applicable results (3) submit for-NRC approval >24 mon ths before thc extended peid an________ ________ {RV' inspecto plan 6ased onA_______ -_______ __________indutr emmendation-. __________I_____ RVI Baffle-&--to-IStainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-13.1.1.2-733 3 Former Assembly I iSteel Coolant and preload FSAR supplement
- c. ....mitm'nt 272-5 (Baffle/ Former I neutron flux t9 (1) paticipatG e in indut+, RVm Bolts) ( .leml nt applicable results (3) submit for NRC approyal >24 months-before the extended period an RVI inspection pln based' on -of i~ndustry recommendation.
__________ RVI Baffle-&--to-SS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.2233 A, 3 Former Assembly Steel Coolant and fracture E FSAR supplement commitment 272-6 (Baffle/ Former neutron flux toughness to (1) , RV Bolts) (Ext) aging pro.grams (2)implement applicable results (3) subm-it NRC approval >24 moenths-before the extended period anr inspection plan based on"V.___ _ _ _ _ j_ _ _ _ _ _ _ _ ____RI _ _ ___________ ____ ____ ____ ____ ____ ____ _______ _ _........ ,id sr recomm ndatio..........._ __ _ __ __ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 11 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material I Environment Aging Effect Aging Management Program NUREG- 1 Table I Notes Function Requiring 1801 Vol. Item Management 2 Item RVI Baffle-&--to- !SS !Stainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-1 3.1.1.30 A, 3 Former Assembly Steel Coolant and PWR Vessel Internals 2714-0 (Baffle/ Former I neutron flux (B2.1.41)FSAR supplement 1 Bolts) (Ext) (1) participate in ndustry RVI aigporm (2) implement applicable 4esults (3) submit for NRC approval>i24 months before the exten~ded-period an RVI inspection plan based oni RVI Baffle-to-SS Stainless Reactor 1 Cracking Water Chemistry (B2.1.2) and IV.B2.RP-'-3.1.1.30 IA, 3 Former Assembly Steel Coolant and PWR Vessel Internals (B2.1.41) 275 (Baffle-edge-bolts) neutron flux~(Ext)RVI Baffle-to-SS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.33 A, 3 Former Assembly Steel Coolant and fracture 1354 (Baffle-edge-bolts) !neutron flux toughness Former Assembly Steel Coolant and 1rla 354 (Ba ffle-edge-bo Its) neutron flux! ~(Ext) i RVI Baffle-to-SS Stainless Reactor Changes in PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.33 iA, 3 Former Assembly Steel Coolant and idimension 1354 (Baffle-edge-bolts) neutron flux Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 12 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended -Material Environment 1 Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item Management 2 Item _RVI Control Rod SS Stainless Reactor Ghaege -PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.33 'A, 3 Guide Tube Steel Coolant and dlkensee^s FSAR supplement commitment 296-2-7-Assembly neutron flux Loss of to (1) participate in dustry Ry.(Control Rod Guide (Ext) material "" rams (2) implement Tubes//rube-appl.,.ble .esu.ts (3) submit for'Suppert PinsiGuide NRC approVal > 24 months.Tube BetGuide before the extended period an Plates (cards)) RVI inspection plan basedo________ _ndust.y reGommendation. _ _RVI Control Rod iss I Stainless geete- G*ak § Water Chemity 2) and IV.82 28 13...3-7' A Guide 2 FTube- Steel Geelant-(EA)} ESAR suppleme'nt coMmin Assemnbly te (1) participate iinustry RW eed u t"/.....4+^(Control Ro Gide Iaging programsr (2)imccn Tubesube-applicable results (3) submit for Support Pins!Guide! NRC approva 21 moenth~s Tube Belts) Ibefore the extended period a IRVI inspectio la asdo RVI Contro! Rod 5$ -Stak~ieeeeI ReaeteO- Ghangeesn FSAR supplement commitment W6V~2 29 1A43.113 A Guiide Tb-u Steel Coolant (4) 1 dimfensions Ito (1) partc~ipateinndsrRI Asemenbly agn rgas (2) implcmen (Control Rod Guide wplibl euts (3) submitfr Tubes~Fube-N.RC approval >21 months-Support Pins/Guide-I before the extended perioda Tube Belts) I RVI inspection plan based en______________ _______ ________ ___________iondustr; recommendation._____ _____ _____ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 13 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended 1 Material Environment T Aging Effect Aging Management Program NUREG- Table I Notes Function I Requiring 1801 Vol. Item 1 Management __2 Item _RVI Control Rod ISS IStainless IReactor 'Cracking JWater Chemistry (B2.1.2) and lIV.B2.RP-13.1.1.30 lA, 3 Guide Tube Steel Coolant and PWR Vessel Internals 298-30 Assembly Guideneutron flux (B2.1.41)F.SAR supplement (Contr.ol Red Guide i (Ext) I Gmmitmnt to (1) p .ti.ipatei Twbes~iube-I nutyRVI 3igporm/ 1(2) implement applicable Fesults Guide Tube- (3)e soolant an fatue B(efLower Flange ý24 umitxt for R prl Welds) period an RI based on industry_____ ____ _____ ________ _______ _____ ____ ___________ ecomm~endation-._ _ _ __ _____RVI Control Rod DSS I Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-' 3.1.1.33 A, 3 Guide Tube Steel Coolant and fracture 297 Assembly neutron flux toughness (Lower Flange (Ext)Weld~s)-)opnn RVI Centio Red DF, SLD, Stainless Reactor Loss of Water Chemistry (132.1.2) IV.B2-32 3.1.1.83 A Guide Tube- SS Steel Coolant and material Assembly neutron flux (Cotrol od Guide (Ext)Tube&LewreF Flange Wodiube Support PinsiGuideI Tube Belts, Guide p~ales-( GaFGW)-}Component 1 RVI Control Rod ISS Stainless 1Reactor 1 rcig A SME Section X1 nservice IV.82.BP-13.1.1.63 !A, 3 Guide Tube Steel 'Coolant and I Inspection, Subsections IWE, 382 Assembly (Guide jneutron flux iIWC, and IWD (B2. 1.1)Tube Bolts) i (Ext) ________________________ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 14 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol.. Item Management 2 Item _RVI Control Rod SS Stainless Reactor Loss of I ASME Section Xl Inservice IV.B2.BP-3.1.1.63 A, 3 Guide Tube Steel Coolant and material Inspection, Subsections IWB, 382 Assembly (Guide neutron flux IWC, and IWD (B2.1.1)Tube Bolts) (Ext Q RVI oe- DF, SLD), Stainless Reactor Changes in PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.3327 IA, 3 Bar-elBaffle-to-SS Steel Coolant and dimensions FSAR .uppl.m.nt com-mitment 274-7 FormerAssembly neutron flux 4o (1) patiip t- -in..nd... .RV.(Barrel-to-Former (Ext) aging programs (2) implem..nt BoltsRV4-Ge~e- .pli.able (3) submit for Barrcl, Core Barrel NRC appreval > 24 mont Outlet Nozzes, and lbefore the extended period ;;n Core Barrel Flange) IRV! inspection plan based on. ._________~~~~~~ _____________nductr; recommcndation-. RVI Baffle-to-ISS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.27 A, 3 Former Assembly Steel Coolant and Preload 274 (Barrel-to-Former neutron flux Bolts) _ _ _ (Ext) _ _RVI Baffle-to-IDF, SLD, Stainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-13.1.1.3,80 iA, 3 Forme g,e e-Bar-Fe ISS Steel Coolant and PWR Vessel Internals 1273-8 Assembly neutron flux t(B21.141)FSAR (Barrel-to-Former (Ext) i mmitment to (1) participate in BoltsRV!1-ee I.industry RVI aging programs BaFrel, Core Barrel (2) implement applicable results Outlet Nozesan (3) submit for NRC approval>Core BaFrrel Flnge) 124 months befere the extended period an RVI inspection plan based en industry______________ ________- -__ _______ _ ___________ r-eGGommendation-._____ _ _ _ __ _ _ _ _ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 15 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table 1 Notes Function Requiring 1801 Vol. Item iManagement __2 Item I RVI Baffle-to-DF-, SLD, Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.2-227 A, 3 FormerG~pe-Safrel SS Steel Coolant and Ifracture FSAR supplement com.mitment 274-9 Assembly I neutron flux Itoughness to. (1) participate in indust, y RVI , (Barrel-to-Former j(Ext) gs (2) imp"ement BoltsRVI-1 eFe- appl.c.bl r .ult (3) submit for I.arel, Core Bairrell 1 NRC approal > 24 Outlet Nozl, n before the exte-nded period a ,re Barrel FRVI inspection plan based_____________ _______ _______ __________ _________ I ndustr; Frae mmendation ____ ______-_____ RVI Core Barrel jDF, SLD, Stainless Reactor fLoss of IASME Section X1 Inservice IV.B2.RP-13.1.1.63 !A, 3 Assembly SS Steel Coolant and material Inspection, Subsections IWB, 382 (Core Barrel neutron flux IWC, and IWD (B2.1.1)Flange) I_ _ (Ext) Q__ _RVI Core Barrel DF, SLD, Stainless 1Reactor Cracking ASME Section XI Inservice IV.B2.RP-3.1.1.63 !A, 3 Assembly (Core SS Steel Coolant and Inspection, Subsections IWB, 382 Barrel Outlet I neutron flux IWC, and IWD (B2.1.1)Nozzles) _ _ _ (Ext)__ __ _ _RVI Core Barrel DF, SLD, Stainless Reactor Loss of ASME Section XI Inservice IIV.B2.RP-13.1.1.63 A, 3 Assembly (Core SS Steel Coolant and material i Inspection, Subsections IWB, 382 Barrel Outlet neutron flux IWC, and IWD (B2. 1. 1)Nozzles) ____(Ext) _ _ _RVI Core Barrel DF, SLD, Stainless Reactor I Cracking Water Chemistry (B2.1.2) and I IV.B2.RP-3.1.1.80 A, 3 Assembly SS Steel Coolant and PWR Vessel Internals (82.1.41) 278 (Core Barrel Outlet neutron flux Nozzle Welds) _ _(Ext)_____ _ ___RVI Core Barrel DF, SLD, Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.27 A, 3 Assembly SS Steel Coolant and fracture 1278a (Core Barrel Outlet neutron flux toughness Nozzle Welds) _ (Ext) Q__ _ _ i Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Page 16 of 45 Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect -Aging Management Program NUREG- Table I .Notes Function Requiring 1801 Vol. Item__ _ _ _Management __2 Item _RVI Core Barrel DF, SLD, 'Stainless I Reactor Cracking I Water Chemistry (B2.1.2) and IV.B2.RP-3.1.1.30 A, 3 Assembly SS Steel Coolant and PWR Vessel Internals (B2.1.41) 387 (Upper and Lower I neutron flux Core Barrel Girth (Ext)Welds) ( .RVI Core Barrel DF, SLD, Stainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-3.1.1.80 A, 3 Assembly SS Steel 'Coolant and PWR Vessel Internals (B2.1.41) 387a (Upper and Lower i neutron flux Core Barrel Axial (Ext)Welds) _ _ _RV Cr BrrlIV.B2.RP-3. 1.127 A, 3 RVl Core Barrel DF, SLD, Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) ..-.Assembly SS Steel Coolant and fracture 388a (Upper and Lower neutron flux toughness Core Barrel Axial (Ext)Welds) _ _ _RVI Core Barrel 1 DF, SLD, Stainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-3.1.1.30 A, 3 Assembly iSS Steel Coolant and PWR Vessel Internals (B2.1.41)1280 (Lower Core Barrel neutron flux Flange Weld) (Ext) _ _RVI Core Barrel DF, SLD, Stainless Reactor Cracking I Water Chemistry (B2.1.2) and IV.B2.RP-13.1.1.30 A, 3 Assembly SS Steel Coolant and PWR Vessel Internals (B2.1.41)1276 (Upper Core Barrel neutron flux I Flange Weld) (Ext) _ .__ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 17 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Function Material Environment Aging Effect Requiring Aging Management Program NUREG-1801 Vol.2 Item Assemby (RVI Core Barrel, Corc Barrel Outlet Nozzles, and Coee Bar~eb FaRne mnate~oa RVI Hold Down Spring (RVI Hold Down Spring)Loss of preload Steel Coolant and neutron flux (Ext)Changes in dimensions Spring (RVI Hold Down Spring)Steel Coolant and neutron flux (Ext)300-44 aging rogras (2)imlen applicable prc-ult (3) submit for INRC approval >24 menths before the extended period an-RVI ipetoplnbased on. Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 18 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item Management 2 Item I RVI Hold Down SS Stainless Reactor Loss of Water Chemistr y (82.4.2) IV.B2.RP-13.1.1.3G33 !A, 3 Spring I Steel Coolant and materialG-a1G4 PWR Vessel Internals (B2.1.41) 300-4Q (RVI Hold Down neutron flux A9 FSAR supplement ..mmitm.nt Spring) (Ext) t+ (1) pa-ticipate in industr.,y RI aging progr3am (2) implement applicable results (3) submit fort NRC approval >24 months-I before the extended period an R"I inspcction plan based on_________ ________ ___________ ___________remmendation. I____ _____Bottom-mounted SS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-13.1.1.3327 IA, 3 instrumentation I Steel Coolant and fracture FSAR supplement commitment 292-4-system: bottom- neutron flux toughnessGha to (1) participate in industy+RVI mounted (Ext) es aging pogra (2) implement-instrumentation I ..,.,,..,;applicable re.ults (3) submi.t fo (BMI) column NRC approval 1 U month bodiesRVI- ,,forp the, extended ,crd an RVI plan based on Support StructureS I ndustry recoAmmend~ation1. and Belts, TheFMOGOUPle-I Instrumentation GGI4F f/ I............ __ _ __I _ __ __ __ __ _ __ ___/_____ ______________I __ __ _ ._____ __ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 19 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals 1J Aging Management Program NUREG-1801 Vol. Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 20 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Intemals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function I Requiring 1801 Vol. Item_ _ Management 2 Item RVI Lower Core !SS Nickel Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.2-722 A, 3 Support Structure Alloys Coolant and preload FSAR supplement commitment 1285-44 (Clevis Insert Bolts-, neutron flux to (1) participate i inductry RYI Radial Keys, Clevis (Ext) is (2) i c I;Ge4- Keyways) I applicablo Fesults (3) submit for NRC approval > 24 monthrs beforo the cxtended perfiod-an:ý RVI inc6pcction plan based o-_d uctry remmendation-. RVI Lower Core SS Nickel Reactor Loss of PWR Vessel Internals (B2.1.4 1) IV.B2.RP-3.1.1.3322 A, 3 Support Structure 'Alloys Coolant and imaterialGha"g ESAR supplement commitment 285-46 (Clevis Insert Boltsr- neutron flux es-e to (,) participate in indutry RVI Radial Keys, C levis (Ext) d*Fienens aging programas (2) implement Clevi IKeyways) applicable results (3) submit for'NRC approval >214onh before the extended period-an 1RV! inspectiOn plan based on I-_____________ _______ _______ _________ _________ idustry recommendation. ____ _____ ____RVI Lower Core SS Nickel Reactor Cracking Water Chemistry (2.1.2) and IV.B2.RP-3.1.1.37 A, 3 Support Structure Alloys Coolant and PWR Vessel Internals (82.141) 399 (Clevis Insert Bolts) neutron flux RVI Lower Core SS 1Nickel IReactor Cracking A SME Section Xl Inservice JIV.B2.RP-: 3.1.1.63 1C, 3 Support Structure 'Alloys Coolant and Inspection, Subsections IWB, 382 (Radial Keys, i neutron flux I IWC, and IWD (B2.1.1)Clevis Insert I (Ext) , Kevyways) _ _ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 21 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item Management 2 Item RVI Lower Core SS Nickel Reactor Loss of ASME Section Xl Inservice IV.B2- 3.1.1.63 IC, 3 Support Structure Alloys Coolant and material Inspection, Subsections IWB, 34RP-382 (Cleyvs !,scrt 1o3ts, neutron flux IWC, and IWD (B2.1.1) I Radial Keys, Clevis (Ext)Insert Keyways) ____ _RVI Lower Core SS IStainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2 RP-I3.1.1.3-7-80 A, 3 Support Structure Steel Coolant and PWR Vessel Intemals 286-46 (Clevis !nsct Bofts, 4-Alleys neutron flux (B2.1.41)F.SAR supplement Radial Keys, C levis (Ext) commitm~ent to (1) participate in inset ..industry RVI aging programs KeywaysCore (2) implement appli-able results Support Column '(3) submit for NCapproval >Bolts) 214 months before the extend-ed period an RVI inpcinplan-based on indusr__________________________________ ecomm~endation-. RVI Lower Core SS , Stainless Reactor Loss of PPWR Vessel Internals (B2.1.41)AIV.B2RP-13.1.1.2227 A, 3 Support Structure SteelNiske Coolant and fracture FSAR supplemen"t commitm,,ent 287-4-7 (Core Support 4-Alleys neutron flux toughness Lo (1) participate in i R,. RI Column (Ext) aging progrm s (2) implemen insert Bolts, Radial applicable results (3) submto Keys, Clevis Insert NRC approVal 214onh lKeyays) bfore the extended period an-RVI inspcctin plan based on ,__Iindustry Grecmmendai-on R__' Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 22 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material I Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item_ Management __2 Item _RVI Lower Core SS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.3327 A, 3 Support Structure SteelNieke Coolant and preloadGba-^g FSAR supplement commitment 287-49 (Core Support ,-Alloys neutron flux es-lwto (1) participate in indu"try RVI Column BoltsQe'.4- (Ext) eams (2) imp.ement lns,`t Bol9ts, Radial applicable results (3) s. ubmit for Keys, Clevis, Insert NRC approval > 24 monnthýs.Keyways) before the ex;endcd period anR RVI inspection plan based-on-_ _indutrY reo...mmendation. RVI Lower Core SS Stainless Reactor 1Cracking Water Chemistry (B2.1.2) and IV.B2.RP-3.1.1.3-780 A, 3 Support Structure SteelN4eke Coolant and PWR Vessel Internals 294-2, (Lower Support 1-Alleys neutron flux (B2.1.41)FSAR supplement Column Bodies (Ext) commitment to (1) participate n (non-cast)Gleyis-d .ustry RVI aging programs insert Bol1ts, Radial i(2) implement applicable resultsI Keys, levi,;- Insert -(3) submit fo'r NC appMoyýal Keyways) 124 months before the eotndedan R'.'! inspection plan" based en industry_______ _______ _________ _________ eGommendation ____-_____ RVI Lower Core SS iStainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.3,327 A, 3 Support Structure Steel Coolant and fracture FSAR supplement commitment 295-5-1 (FuelAigment-neutron flux toughnessGha to (1) participate in industry+RVI 1 (Ext) Figes-+ agnrgams (2) implement Support Column d'me.i.ns app.esults (3) submit for Bodies (non-cast)-& NRC appro.al -24 months.t, Ce Spr--4 before the e .ended period an IRV' inspection plan based o..-r iePlate inutr ecommendation.(U2), UppeF i Plate (U2), Manwa', "_'__\_ lllI___\ __________ ____11 _;______________ £,I,-___ __-_____ _______ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 23 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type un Intended I Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Functo Requiring 181VI 1801Vol. Item RVI Lower Core SSSto Management 2 Item SS tainless Reactor Cracking Water Chemistry (B2.1.2) and IlV.B2.RP-3.1.1.80 A,3 Support Structure i Steel Cast i Coolant and PWR Vessel Intemals (B2.1.41)1291 (Lower Support Austenitic neutron flux Column Bodies Atit (Ext)(cast)) _ _ _RVI Lower Core SS Stainless Reactor Loss of PWR Vessel Intemals (B2.1.41) IV. B2.RP- 3.1.1.27 A, 3 Support Structure Steel Cast Coolant and fracture 290 (Lower Support Austenitic neutron flux toughness Column Bodies (Ext)(cast)) I _ _RVI Lower Core [5S Stainless ReaeteF- G..GI. .Water Chemistr. (324..2) Wn 132 16 12. 1...37- A I Steel Geelant (fEd) FSAR supplement commf.itment I to (1) participate in n trRVII Pins, Core u;grs (2) implement ColumnR & Bolts applicable results (3) submit for GeFe Supp- i 'NRC approval >24 months-eIgnh 2)-,before the tended an Lower Tie Plate RVI inspecto plan based on (U2), P~eF Tie- Industry recommendaton Plate (I2)\, ManwayI,-RVI Lower Core 185 IStainless-ReaGte- Less-of- ESAR supplement commitment .42-47 13.1.22 JA Su&ppea- StFuGtuwe [Steel Geelant (Ed) Iftrat~e~ Ito (1) participateinndsrRY (Fuael Aligmenit-teughess aging programs (2)imlen Pins, Core Support applicable results (3) submit forF Column & Bolts, NRC approal >24 monh Ge~e SippeG- be~fore the extended period an Fering(W2ý-,RVl inspection plan basedo Lower Tie Plate industr' recommendation. Plate (U2), Manway 1 GGeve}_ __ __ _ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 24 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item Management 2 Item _RVI Lower Core SS Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-13.1.1.22 'A, 3 Support Structure Steel Coolant and Ifracture FSAR supplement commitment 288-48 (Lower Core Plate) neutron flux toughness to (1) participate in indutry RVI (Ext) aging pogr.ams (2) implement applicable results (3) submit for NRC approval >24 months-before the W~ended period an RVI incpection plan based-eon RVI Lower Core QF IStainless-ReaGWtF I ess-of- fzsR cupm t co-mmimn ~W 12 8 &13.1..22 [C Suppe~Stiuetuwe Steel e4n4~4 fate to (1) participate iindustryRV (Flew Diffu ser Plate 4oughness agn rgam~s (2 mpent-(Unit 1)) applicsable results (3) submit for INRC approval >24 months before the eode;nded period a IRV! inspecstion plan based oný________ ________ __________ idustryremmendation. ______________ RVI Lower Core "-'SS Stainless Reactor Loss of PWR Vessel Internals (82.1.41) IV.B2.RP-3.1.1.22 'A, 3 Support Struucture Steel Coolant and fraetUwe-FSAR supplement coSmmitment 12884-8 (Lower Core Plate) I neutron flux ýteughessrnat Ito (1) participate in industr"R"-W-(Ext) erial aging programs (2)imlen applicable results (3) submit for NRC approval >24 moenthws ebfefoe the extonded period an RVI inspection plan based en______ ______ _ ________ _______ ___________industng recmmn;A Pdatio._ __ _ _ _ _ _ _ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 25 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Function Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 26 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Intemals Component Type i Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item Management 2 Item RVI Lower Core SS Stainless Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-13.1.1.37 JA, 3 Support Structure Steel Coolant and PWR Vessel Internals 28940 (Lower Core Plate) neutron flux (B2.1.41)FSAR supplement (Ext) .emmitmont to (1) participate in industry RVI aging programs I (2) implement applicable , .sult (3) submit for NRC approval>24 months befoee the extended period an RVI inspection plan baed on *industr;_______ indcmmendationdat__n.__ _RVI Lower Core Stainless ReaGt9F !GaGkin Watefr heiste (132.4.2) and lnVB2 29 1.1- A tFUekwe Steel GGGIa{(E) FSAR supplement Gcommitme (Lower Core Plate) to (1) participate iinutyRVI aging programs (2)iplmn applicable results (3) submit for NGapproval > 21 months befGre the extended period an-IRV! inspection plan based-Gon RVI Lower Core iFStainless-Reaate- IG~arking Water Chemistry (132.1.2) and- WVB2-20 13.11.37-G SUPP~t tFU~U~el~eeantPd)FSAR supplement (Flow DiffiuserF Plate~ to (1) participat nidsr agngprgams (2) implement-applieable results (3) submit for!N.RC approval >24 moenths-bfGre the extended period-an-RVI inspection plan based-on-______________ _______ _______ __________I __________ ndustr; recom~mendation. _____L_____ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 27 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 28 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 29 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- I Table I Notes Function Requiring 1801 Vol. Item Fuoncrt ion -Management 2 ItemA RVI GG Iss StainlessReaGte" Chie;-es OF; FSAR supplement commitment !V. B2 23 3-4.---33 IA l()p tcpaci industr' rc Redalcn Support Structure steel Gast 1 Coolant (End)I PWRnre Vese l ()ptInteml 29a-4 (GeFe-LSopper Austenitic aging programs (2) implement GSstor FrU4n applicablc Fesults (3) submit for NRC approval >24 moenths-before the cxtendcd period an RVI inspection plan bascd on;______ -industr'; ommndato-n........ RVI Lower Core 'SS Stainless Reactor Cracking Water Chemistry (132.1.2) and IV.B32.RP-13.1.1.3080 ýA, 3 Support Structure ýSteel Cast Coolant and PWR Vessel Internals 291la-24 (Ge~e Lower jAustenitic neutron flux (B2. 1.41)F-SAR supplem *ent Support Forgiing or (Ext) commitment to (1) participate in Casting-{U4) industry Ryl aging programs.(2) implement applicable results I (3) submit for NRC approval-24 months before the c~tcnded perid an RVI inspection plan based on indust.y._______ _______ _________ _________ ecommendation. ____ _____ ____RVI Thermal & iSLQ stainlessI Reariw Ghagesin FSAR supplement commitment IV B2 7 A NeUtrn Sh Steel Geela(nt (Ev) dimensiens to (1) participate in RVI (Thealai progrms (2) implement mU)Nurn (UJ2) applicable result6 (3) submit forj Shield and Botig NRC approval 21U months before the exedd eid a;n RVI inpcin plan based on-_____________ _______ _______ __________ __________ ndustry recommendationm____ _____ ____ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 30 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 31 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Intemals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I I Notes Function Requiring 1801 Vol. Item Management 2 Item RVI Upper Core SS Stainless Reactor 'Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP. 3.1.1.27 JA, 3 Support Structure Steel Coolant and materialwpeloa FSAR supplement commitment 290b-38 i (Upper Core Plate-, neutron flux d to (1) participate in industy RVI UppeF ppeA- (Ext) aging programs (2) ;"plment Plate, U-pef- applic.able results (3) submit for Support ColuRs NRC approval 24 2 months igeRt- efore the extended period an P-ins) RVI in~spection plan basedo I _________ i~~~ndustr'; reco~mmendation. _____-_____ RVI UpperCoeFe SS Stainless Reactor Crhacnges ^i- S ARsupplementGcmmitmnt t,,,4B239 3\-.-.33 A Support StFruture Steel Coeelant aEn) dension to (1) pWrticipate in indust( 1 29l 4 (Upper Core Plate, ngntrgns (2) implement ,P .S.PPe-t- .ppli.able results (3) submt for.Pae \ NRC approval 2 21 mont SUP~et C9UMASbefore the extended period an Belts, Al n .RV. inspection plan based on Pndustr'y recommendation. _RVI Upper Core SS Stainless Reactor 1Cracking AlateF Chemistry (B2.1.2 and ýIV.B2.RP-3.1.1.780 ýA, 3 Support Structure iSteel Coolant and PWR Vessel Internals (B2. 1.41) 291b-4G (Upper Core Plateý- neutron flux FSAR supplement coemmitment UpeFSUPGt-(EI)to (1) participate in idsr V Plate Upefging programs (2)imlen Supprt eWFns pplicable reksut (3) submit for Belts Aligment RC approval >24 months before the extended perioda RVI inspeetion plan based-on-_____ _____ ___ _ _____ ____ ___ _ _____ ___ _ _____ ___ ndust'r ; r-#-rre m mendation. _ _ _ _ _ _ _ _ _ _ _ _ _ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 32 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Internals Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Function Requiring 1801 Vol. Item___ _Management _ 2 Item RVI Upper Core 5 Stainless Reactor Loss of PWR Vessel Internals (B2.1.41) IV.B2.RP-3.1.1.3322 A, 3 Support Structure Steel Coolant and materialGhaP~g FSAR supplement commitment , 299-44 (Upper Core Plate-, neutron flux les-on to (1) participate in indust, y RVI (Ext) dimensios ..gn I prams (2) impl.ment Plate,-44ppeI-applicable results (3) submit for Suppor Columh NRC approval -24 month.9 Alignment ,,,befFethe, an Pins) RVI inspec tio plan based on_____ ____ ____ ____ ___ _______ _________ __________;indstr; remmendation-. ____ _ _ _RVI Upper Core SS Stainless I Reactor Cracking Water Chemistry (B2.1.2) and IV.B2.RP-13.1.1.3037 A, 3 Support Structure Steel Coolant and PWR Vessel Internals 301-4-2 (Upper Core Plate.- neutron flux (B2.1.41)FSAR supplement 1JP~eI: S4UPPGe (Ext) Gommitment to (1) participate in PlateUppef I ndustry RVI aging pmrgFams Support Columns (2) implement applicable results B Alignment (3) submitfF Pins) '24 months before the extended perod an RVI ispect\on plan RVI Jpper CeFe S tainless Reator r Ghacnges WSAR supplement commitment a V.B2.3- 3.1.1.37 "A,3 Suppot StFuGtue Steel Coolant diaenien to es(1) participate iR2. 34 (UppF SuPG~tr Astent* aingprograms (2) implement (UppemAs) apprable results (3) submit forx NRC approral >)24 mtnths before the e*ene peid an a RVI inspectoG lnbsdo______________ _______ _______ __________ ___________ ndustr'; recommensdation ______ ______RVI Upper Core SS Stainless Reactor Cracking Water Chemistry (B2.1.2) and ~IVB,2.RP-13.1.1.37 A, 3 Support Structure ISteel Coln and PWR Vessel Internals (B2. 1.41); 346 (Upper Support ~neutron flux Ring or Skirt) _ _ _ _. (Ext)_______ _ _ _ _ _ _ _ _ _ _ _ _ _____ _ _ _ __ ____ Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 33 of 45 Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -Reactor Vessel and Intemals Notes for Table 3.1.2-1: Plant Specific Notes: 3. The commitment to implement the RVI inpe~tin plan will manage this aging effect. Line item was revised to align with NUREG-1801, Revision 2, and LR-ISG-2011-04. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 4.4. The commnitment to implement the R, I inpctian plan PWR Vessel Internals (B2. 1.41) will manage fatigue of the Baffle-Former Bolts in the Reactor Vessel Internals Baffle and Former Assembly Enclosure 1 Section 4 Attachment 4 TIME-LIMITED AGING ANALYSES PG&E Letter DCL-14-103 Page 34 of 45 4.3.3 Fatigue Analyses of the Reactor Pressure Vessel Internals Summary Description The structural adequacy of the reactor internals is discussed in FSAR Section 3.9.3.4.1. The reactor internal components are not ASME code components. The reactor internals were designed and built prior to the implementation of Subsection NG of the ASME Boiler and Pressure Vessel Code, Section III, for reactor vessel internals. Therefore, no plant-specific ASME Code stress report was written during the initial design. However, these components were originally designed to meet the intent of the 1971 Edition of Section III of the ASME Boiler and Pressure Vessel Code with addenda through the Winter 1971. The structural integrity of the reactor internals design has been ensured by analyses performed on both generic and DCPP-specific bases.Analysis The qualification of the reactor vessel internals was first performed by Westinghouse on a generic basis for 40 years of operation. Some DCPP internal components were subsequently analyzed on a DCPP-specific basis.Tavg Operating Range Reactor Vessel Internals Analysis In support of the modification to the Tavg operating range, all of the core support structures, except for the upper core plate, lower core plate, and baffle bolts, were qualified based on analyzing the most limiting internal components [Reference 23]. From the four-loop generic stress report, for the applicable components, the most highly stressed due to cyclic thermal loads are: 1. Lower support plate 2. Lower support columns 3. Core barrel nozzles These components therefore have the highest fatigue usage factors and were used to demonstrate compliance of the DCPP reactor internals with the intent of ASME Code, Section III, Subsection NG. The remaining internal components within the scope of the DCPP-specific analysis are bounded by the results of the limiting components and have sufficient margin in the stress and fatigue usage factors to accommodate any expected increases in stress range or number of cycles.The enhanced DCPP Fatigue Management Program will monitor the 50-year design basis number of transients used in the Tavg operating range analysis to ensure it will remain valid for the period of extended operation. Upper Core Plates The Unit 2 upper core plate (UCP) was analyzed to support the 2005 Unit 2 upflow conversion modification [Reference 24]. The numbers of transients used in the analysis are bound by the numbers of transients in the current 50-year design basis. Enclosure 1 Section 4 Attachment 4 TIME-LIMITED AGING ANALYSES PG&E Letter DCL-14-103 Page 35 of 45 The results of the four-loop generic stress report qualify the Unit 1 UCP for 40 years of operation. However, the results of the DCPP-specific analysis performed for the Unit 2 UCP can be applied to the Unit 1 component, since these components are of similar design[Reference 19].The enhanced DCPP Fatigue Management Program will monitor the 50-year design basis number of transients used in the Unit 2 upflow conversion modification for the Unit 1 and 2 UCPs to ensure it will remain valid for the period of extended operation. Lower Core Plates The Unit 1 lower core plate (LCP) was analyzed for the increase in heat generation seen by the lower core plate due to power uprate [Reference 25]. The numbers of transients used in the analysis are bound by the numbers of transients in the current 50-year design basis.The results of the four-loop generic stress report qualify the Unit 2 LCP for 40 years of operation. However, the results of the DCPP-specific analysis performed for the Unit 1 LCP can be applied to the Unit 2 component, since these components are of similar design[Reference 19].The enhanced DCPP Fatigue Management Program will monitor the 50-year design basis number of transients used in the Unit 1 power uprate for the Unit 1 and 2 LCPs to ensure it will remain valid for the period of extended operation. Baffle-Former Bolts The fatigue usage factor of the baffle-former bolts was originally shown to be less than 1.0 based on evaluation of test data which demonstrated acceptable performance for a set of bolt displacements. The adequacy of baffle-former bolts is an industry issue and their extended operation is addressed by participation in industry lev.el initiatives as described beo!:the PWR Vessel Internals program, which is summarized in Section B2.1.41.Flow Induced Vibration in the Reactor Vessel Internals FSAR Section 3.9.1 and the original SER for DCPP discuss the design and vibration test programs for the reactor vessel internals performed as part of preoperational and startup testing. The dynamic behavior of reactor internals has been studied using experimental data obtained from prototype plants along with results of model tests and static and dynamic tests.Indian Point Nuclear Generating Unit 2 was the prototype for the DCPP Unit 1 internals verification program. Trojan Nuclear Plant data provide additional internals verification for Unit 2 (Unit 1 lower internals are similar to Indian Point Unit 2; Unit 2 lower internals are similar to Trojan). The tests indicated that no unexpected large vibration amplitudes existed in the internal structure during operation. The licensing basis does not describe any time limited effects for a licensed operating period associated with flow-induced vibration. Therefore there are no TLAAs, in accordance with 10 CFR 54.3(a) Criteria 2 and 3. Enclosure 1 Section 4 Attachment 4 TIME-LIMITED AGING ANALYSES PG&E Letter DCL-14-103 Page 36 of 45 f : i A ffatb'C. 111." 01 _11~ 0 P- y,"e KOF 041GO "&Be! 1**-* *PGE 1l (1) pa~ticipate in idutr_,' programRs foinestgtn and manaaging the aging effect OR the reactor Vessel internals; (2' evlut and imnp~cent the reWSults of the indusr.tr; programs6 as applic--hAbl t-o tthe rean-tor internals6; (3) upon cmltoof those program~s, but not lees than 241 months prorF to entering the period of extended operation, PG&E will submnit an inspection plan to the NRC for review and approva!; and (4) in accordanc~e with RIS 2011 07, PG&E= will sbubmilt Information requested in the safety evaluation for RARP-2-27 "Pressurized W~ater R'eaco (PWVR) Internals Inspecntion-and-Ev~aluation Guidelne," date Ju-no 2:2,2011 to the NIRC for 4 ,ai-nr n r ia m aa.*an+ a+k-ftrlom,,nan ha0na.aI iRona n na ia r 01l ... -- -*.4-- -**-2 vearw before the plant enters PEGm. hwmv r cormnet firm. m F" .......Disposition: Aging Management, 10 CFR 54.21E(1)(iii) The design basis number of transients will be managed for the period of extended operation by the DCPP Metal Fatigue of Reactor Coolant Pressure Boundary program, which is summarized in Sections 4.3.1 and B3.1. Action limits will permit completion of corrective actions before the design basis number of events is exceeded. The continued implementation provides reasonable assurance that fatigue in the reactor vessel internals will be managed for the period of extended operation in accordance with 10 CFR 54.21 E(1)(iii). The integrity of the reactor vessel internals and baffle and former bolts will be managed by the ReaGeoePWR Vessel Internals Aging Management program, which --2DC committ*ed to hmplementis summarized in LRA Table A4 1, Commitment 22Section B2.1.41. The implementation of the PWR Vessel Internals program provides assurance that fatigue in the reactor vessel internals and baffle and former bolts will be managed for the period of extended operation in accordance with 10 CFR 54.21 E(1)(iii). Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 37 of 45 B1.5 AGING MANAGEMENT PROGRAMS 0 PWR Vessel Internals (Section B2.1.41)B2 AGING MANAGEMENT PROGRAMS NUREG- EXlSTIN APPENDIX 1801 NUREG-1 801 EITNB 181 NRE-81 PLANT PROGRAM G ORB NUMBE PROGRAM NEW REFERENC R E XI.M16 PWR Vessel Net GredatePWR N/Anew NIAB2.1.41 Internals Vessel Internals B2.1.41 PWR Vessel Internals Program Description The PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in Electric Power Research Institute (EPRI) Technical Report (TR)No. EPRI 1022863, "Materials Reliability Program: Pressurized Water Reactor (PWR)Internals Inspection and Evaluation Guidelines," (MRP-22 7-A) and EPRI TR- 1016609,"Materials Reliability Program: Inspection Standard for PWR Internals," (MRP-228) to manage the aging effects on the reactor vessel internal components. The recommended activities in MRP-227-A and additional plant-specific activities not defined in MRP-227-A are implemented in accordance with Nuclear Energy Institute (NEI) 03-08, "Guideline for the Management of Materials Issues." Plant procedures align with the augmented inspection and evaluation (M&E) criteria for PWR reactor vessel internals components specified in NRC Safety Evaluation (SE), Revision 1, on MRP-227.The PWR Vessel Internals program is used to manage: (a) cracking, including stress corrosion cracking (SCC), primary water stress corrosion cracking (PWSCC), irradiation-assisted stress corrosion cracking (IASCC), and cracking due to fatigue/cyclical loading; (b) loss of material induced by wear, (c) loss of fracture toughness due to either thermal aging, neutron irradiation embrittlement, or void swelling; (d) dimensional changes due to void swelling or distortion; and loss of preload due to thermal and irradiation-enhanced stress relaxation or irradiation-enhanced creep.The DCPP PWR Vessel Internals program applies the guidance in MRP-227-A for inspecting, evaluating, and, if applicable, dispositioning non-conforming reactor vessel internals components at the facility. These examinations provide reasonable assurance that the effects of age-related degradation mechanisms will be managed during the period of extended operation. The program includes expanding periodic examinations Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 38 of 45 and other inspections, if the extent of the degradation identified exceeds the expected levels.The DCPP PWR Vessel Internals program uses MRP-227-A guidance for selecting reactor vessel internals components for inclusion in the inspection sample is based on a four-step ranking process. Through this process, the DCPP reactor vessel internals were assigned to one of the following four groups: "Primary," "Expansion," "Existing Programs," and "No Additional Measures." The result of the four-step sample selection process is a set of "Primary" internals component locations that are inspected because they are expected to show the leading indications of the degradation effects, with another set of "Expansion" internals component locations that are specified to expand the sample should the indications be more severe than anticipated. The degradation effects in a third set of internals locations are deemed to be adequately managed by "Existing Programs," such as American Society of Mechanical Engineers (ASME) Code, Section Xl, Examination Category B-N-3, examinations of core support structures. A fourth set of internals locations are deemed to require "No Additional Measures." Element 1 -Scope of Program The DCPP PWR Vessel Internals Program provides guidelines to adequately manage the aging effects of selected DCPP reactor vessel intemals components, both non-bolted and bolted. The DCPP reactor vessel internals consist of three basic assemblies: (1) the upper core support structure that is removed during each refueling operation to obtain access to the reactor core, (2) the lower core support structure that can be removed, if desired, following a complete core off-load, and (3) the incore instrumentation support structures. The scope does not include fuel assemblies, control rod drive assemblies, nuclear instrumentation, bottom mounted instrumentation flux thimble tubes, and attachments welded to the reactor vessel. Fuel assemblies are periodically replaced (i.e., short lived), and therefore, are not subject to aging management review. Control rod drive assemblies are active components and therefore, are not subject to aging management review. Nuclear Instrumentation (i.e., incore neutron flux detectors) are active electrical components, and therefore, are not subject to aging management review. Bottom mounted instrumentation flux thimble tubes are managed by the Flux Thimble Tube Inspection program (B2.1.21). Welded attachments to the reactor vessel interior are subject to examination in accordance with the ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD program (B2. 1.1) and are therefore excluded from the scope of this program. Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 39 of 45 The DCPP PWR Vessel Internals program will be focused on managing age related degradation mechanisms by performing inspections intended to identify crack initiation and growth due to irradiation-assisted stress corrosion cracking and cracking due to fatigue/cyclical loading, loss of material induced by wear, primary water stress corrosion cracking, and stress corrosion cracking; reduction of fracture toughness due to irradiation embrittlement, thermal embrittlement, and void swelling; changes in dimensions due to void swelling; and loss of preload due to thermal and irradiation-enhanced stress relaxation or irradiation-enhanced creep, in reactor vessel internals components. The DCPP PWR Vessel Internals program applies the guidance in MRP-227-A, which identifies and provides the basis for required augmented inspections, inspection techniques to permit detection and characterization of aging effects of interest, prescribed frequency of inspections, and examination acceptance criteria for assuring the functional integrity of Westinghouse reactor vessel internals. The program scope includes the Westinghouse plants "Primary" components listed in Table 4-3 of MRP-227-A and Westinghouse plants "Expansion" components listed in Table 4-6 of MRP-227-A. The aging effects of a third set of reactor vessel internals locations, consistent with those listed in Table 4-9 of MRP-227-A, are adequately managed by the existing DCPP programs. Those reactor vessel internals components for which the effects of all aging mechanisms were determined by MRP-227-A to be below the screening criteria were placed in the "No Additional Measures" group. No additional aging management is necessary for the reactor vessel internals components in the No Additional Measures group. In no case does the No Additional Measures determination supersede the ASME Section X1 Inservice Inspection requirements for components in this group.Element 2 -Preventive Measures The DCPP PWR Vessel Internals program does not prevent degradation due to aging effects; rather, it provides measures for monitoring to detect the degradation prior to loss of intended function. Preventive measures to mitigate aging effects such as loss of material and cracking in the primary water system are established and implemented in accordance with the DCPP Water Chemistry program (B2.1.2), as described in GALL AMP Xl.M2, Water Chemistry. Element 3 -Parameters Monitored or Inspected The DCPP PWR Vessel Internals program monitors the following aging effects by inspection, in accordance with the guidance of MRP-227-A orASME Code Section X1, Category B-N-3: Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 40 of 45 (1) Cracking Cracking is due to stress corrosion cracking (SCC), primary water stress corrosion cracking (PWSCC), irradiation assisted stress corrosion cracking (IASCC), or fatigue Icyclical loading. Cracking is monitored with a visual inspection for evidence of surface-breaking linear discontinuities or a volumetric examination. Surface examinations may also be used to supplement visual examinations for detection and sizing of surface-breaking discontinuities. (2) Loss of Material Loss of material is due to wear. Loss of material is monitored with a visual inspection for gross or abnormal surface conditions. (3) Loss of Fracture Toughness Loss of fracture toughness is due to thermal aging embrittlement (TE) or neutron irradiation embrittlement (IE). The impact of loss of fracture toughness on component integrity is indirectly managed by monitoring for cracking by using visual or volumetric examination techniques and by applying applicable reduced fracture toughness properties in flaw evaluations if any detected cracking is determined to be extensive enough to necessitate a supplemental flaw growth or flaw tolerance evaluation. (4) Changes in Dimension Changes in dimension are due to void swelling or distortion. The program supplements visual inspection with physical measurements to monitor for any dimensional changes due to void swelling or distortion. (5) Loss of Preload Loss of preload is due to thermal and irradiation-enhanced stress relaxation (ISR) or irradiation-enhanced creep. Loss of preload is monitored with a visual inspection for gross surface conditions that may be indicative of loosening in applicable bolted, fastened, keyed, or pinned connections. The DCPP PWR Vessel Internals program manages the aging effects noted above consistent with the guidance designated for the Westinghouse-designed Primary components included in Table 4-3 of MRP-227-A and the Westinghouse-designed Expansion components included in Table 4-6 of MRP-227-A. Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 41 of 45 Element 4 -Detection of Aging Effects The DCPP PWR Vessel Internals program detects the aging effects listed in Element 3 through performance of examinations of the parameters specified in MRP-227-A, Table 4-3 for Westinghouse-designed Primary components and for parameters specified in MRP-227-A, Table 4-6 for Westinghouse-designed Expansion components. The DCPP PWR Vessel Internals program provides both examination acceptance criteria (See Element 6) for conditions detected during inspection of Westinghouse-designed Primary components, as well as criteria that are applied to determine if scope expansion of examinations is required. When the examination acceptance criteria for the Westinghouse designed Primary components included in MRP-227-A, Table 4-3 are not met, the program requires expanding the scope of examinations to include the additional Westinghouse-designed Expansion components included in MRP-227-A, Table 4-6.MRP-227-A also identifies Existing Program components whose aging is managed through implementation of other programs. The DCPP PWR Vessel Internals program manages these Westinghouse designed components included in MRP-227-A, Table 4-9 through implementation of the ASME Code Section X1 Inservice Inspection, Subsections IWB, IWC, and IWD program (B2. 1.1) and the Flux Thimble Tube Inspection program (B2.1.22). MRP-227-A includes a fourth group of components designated as requiring No Additional Measures. The aging of these components was determined to be negligible relative to other reactor intemals, and therefore the program does not include any measures to monitor for effects of aging degradation in these components. The inspections of the DCPP PWR Vessel Internals program are conducted as recommended in MRP-227-A. The program standards for examination methods, procedure content, and personnel qualifications are consistent with the requirements specified in MRP-228.Volumetric (UT) and visual (VT-3, EVT-1) examinations are used for detecting aging effects including general conditions, surface breaking discontinuities, and cracking caused by SCC, IASCC, and fatigue.VT-3 examinations are applied to detection of cracking only when the flaw tolerance of the component or affected assembly, as evaluated for reduced fracture toughness, has been shown to be tolerant of easily detectable large flaws, even under reduced fracture toughness conditions. VT-3 examinations may also be used to inspect for loss of material that is induced by wear, and other aging effects such as gross distortion caused by void swelling and irradiation growth, and aging effects of loss of preload that is caused by thermal and irradiation-enhanced stress relaxation and creep. Enclosure 1 Appendix B Aftachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 42 of 45 Surface measurements may be used to supplement visual examinations required by this program to reject or accept relevant indications. The impact of loss of fracture toughness (due to TE or IE) on component integrity is indirectly managed by monitoring for cracking using visual or volumetric examination techniques and by applying applicable reduced fracture toughness properties in the flaw evaluations after cracking is determined to be extensive enough to warrant a supplemental flaw growth or flaw tolerance evaluation. One hundred percent of the accessible volume/area of each component will be examined for the Primary and Expansion components inspection category components. The minimum examination coverage for primary and expansion inspection categories is 75 percent of the component's total (accessible plus inaccessible) inspection area/volume be examined. When addressing a set of like components (e.g. bolting), the minimum examination coverage for primary and expansion inspection categories is 75 percent of the component's total population of like components (accessible plus inaccessible). If conditions are detected during the examination, DCPP will enter the information into the corrective action program and evaluate whether the results of the examination ensure that the component (or set of components) will continue to meet the intended function under all licensing basis conditions of operation until the next scheduled examination. Engineering evaluations that demonstrate the acceptability of a detected condition will be performed consistent with WCAP-I 7096-NP.Element 5 -Monitoring and Trending The methods for monitoring, recording, evaluating, and trending the data that result from the DCPP PWR Vessel Internals program's inspections are in accordance with the evaluation methodologies detailed in MRP-227-A, Section 6. This includes the recommended evaluation methodologies for flaw depth sizing and crack growth determinations as well as for performing applicable limit load, linear elastic and elastic-plastic fracture analyses of relevant flaw indications. The DCPP PWR Vessel Internals program applies applicable fracture toughness properties, including reductions for thermal aging or neutron embrittlement, in the flaw evaluations of the components in cases where cracking is detected in a reactor vessel internals component and is extensive enough to warrant a supplemental flaw growth or flaw tolerance evaluation. In accordance with MRP-227-A, the DCPP PWR Vessel Internals program includes criteria to evaluate the aging effects in the inaccessible portions of the components and the resulting impact on the intended function(s) of the components. For redundant components, the program includes criteria to evaluate the aging effects in the Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 43 of 45 population of components that are inaccessible to the applicable inspection technique and the resulting impact on the intended function(s) of the assembly containing the components. Examination and re-examinations are implemented in accordance with MRP-227-A, together with the criteria specified in MRP-228 for inspection methodologies, inspection procedures, and inspection personnel, provide timely detection, reporting, and corrective actions with respect to the effects of age related degradation mechanisms within the scope of the program.Element 6 -Acceptance Criteria The DCPP PWR Vessel Internals program acceptance criteria for the Westinghouse-designed Primary and Expansion component examinations are consistent with MRP-22 7-A, Section 5A. For the Westinghouse-designed Expansion components, ASME Code, Section Xl, Section IWB-3500 acceptance criteria apply. The DCPP PWR Vessel Internals program establishes acceptance criteria for any physical measurement monitoring methods that are credited for aging management of particular reactor vessel internals components. Element 7- Corrective Actions Any detected conditions that do not satisfy the examination acceptance criteria are required to be dispositioned through the DCPP corrective action program. The disposition will ensure that licensing and design basis functions of the reactor internals will continue to be fulfilled. The following corrective actions are suggested for the disposition of detected conditions that exceed the examination acceptance criteria: (a) Supplemental examinations to further characterize and potentially dispose of a detected condition;(b) Engineering evaluation that demonstrates the acceptability of a detected condition;(c) Repair, in order to restore a component with a detected condition to acceptable status; or (d) Replacement of a component with an unacceptable detected condition If an engineering evaluation is used to disposition an examination result that does not meet the examination acceptance criteria, the engineering evaluation shall be conducted per an NRC-approved evaluation methodology. Enclosure 1 Appendix B Attachment 4 AGING MANAGEMENT PROGRAMS PG&E Letter DCL-14-103 Page 44 of 45 DCPP quality assurance (QA) procedures and review and approval processes are implemented in accordance with the requirements of 10 CFR 50 Appendix B and include: administrative controls as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to verify that corrective actions are effective and those implemented to address significant conditions adverse to quality are effective in preventing recurrence of the condition. Element 8 -Confirmation Process DCPP QA procedures and review and approval processes are implemented in accordance with the requirements of 10 CFR 50 Appendix B and include: administrative controls as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to verify that corrective actions are effective and those implemented to address significant conditions adverse to quality are effective in preventing recurrence of the condition. The implementation of the guidance in MRP-227-A, in conjunction with the requirements of NEl 03-08 and other guidance documents, reports, or methodologies referenced in this AMP, provides an acceptable level of quality and an acceptable basis for confirming the quality of inspection, flaw evaluation, and other elements of aging management of the DCPP PWR Vessel Internals. Element 9- Administrative Controls See Element 8.Element 10- Operating Experience The systematic and ongoing review and assessment of relevant DCPP-specific and industry operating experience for its impact to the program are governed by Nuclear Energy Institute (NEI) 03-08, "Guideline for the Management of Materials Issues," and MRP-227-A, Appendix A.Based on industry operating experience, DCPP proactively replaced the originally installed Alloy X-750 guide tube support pins (split pins) with strain hardened (cold worked) 316 stainless steel pins in 1999 for Unit I and 2006 for Unit 2 to reduce the susceptibility for stress corrosion cracking in the support pins.Relatively few incidents of PWR internals aging degradation have been reported in operating U.S. commercial PWR plants, and a summary of observations is maintained in Appendix A of MRP-227-A. With exception of the ASME Section Inservice Inspection portions, the DCPP PWR Vessel Internals program will be a new program. A key element of the program defined in MRP-227-A is the requirement for utilities to continue to report aging effects of PWR vessel internal components identified during Enclosure 1 Attachment 4 PG&E Letter DCL-14-103 Page 45 of 45 Appendix B AGING MANAGEMENT PROGRAMS examination. DCPP, through its participation in PWR Owners Group and EPRI-MRP activities, will continue to benefit from the reporting of examination information and results, and will share its own operating experience with the industry through those groups.NUREG-1801 Consistency The PWR Vessel Internals program is a new program that, when implemented, will be consistent with the recommendations of XI.M16A, "PWR Vessel Internals," specified in NUREG-1801, Revision 2, and LR-ISG-2011-04. Exceptions to NUREG-1801 None Enhancements None Conclusion The implementation of the PWR Vessel Internals program will provide reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation. Enclosure 1 Attachment 5 PG&E Letter DCL-14-103 LR-ISG-2011-05, "Ongoing Review of Operating Experience" LR-ISG-2011-05 was issued by the NRC Staff to establish a framework for the consideration of operating experience concerning aging management and age-related degradation during the term of a renewed operating license. It also clarifies the NRC Staff's acceptance criteria and review procedures with respect to the ongoing review of operating experience. PG&E's licensing basis for the review of applicable industry and plant-specific operating experience is documented LRA Table A4-1, Item 20. Reference PG&E Letter DCL-09-079, dated November 23, 2009. PG&E committed to perform an ongoing review of industry and applicable plant-specific operating experience throughout the PEO pertaining to the following AMPs: (1) Steam Generator Tube Integrity (B2.1.8)(2) One-Time Inspection (B2.1.16)(3) Selective Leaching of Materials (B2.1.17)(4) Buried Piping and Tanks Inspection (B2.1.18)(5) External Surfaces Monitoring (B2.1.20)(6) Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)(7) Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.14)(8) Fuse Holders (B2.1.34). This program was deleted in PG&E Letter DCL-13-119, dated December 23, 2013.(9) Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.35)(10) Metal Enclosed Bus (B2.1.36)The license renewal SER evaluated LRA Table A4-1, Item 20 as documented in SER Appendix A, Item Number 20.In order to address the recommendations in LR-ISG-2011-05, PG&E updates its licensing basis as shown in LRA Section Al and Table A4-1, Item 20. Upon receipt of the renewed operating licenses, ongoing reviews of operating experience will apply to all DCPP AMPs following the process described in LRA Section Al.Refer to markups of LRA Section Al and Table A4-1, Item 20, in Attachment
- 15.
Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 1 of 9 LR-ISG-2012-01, "Wall Thinning Due to Erosion Mechanisms" LR-ISG-2012-01 contains recommendations to address wall thinning due to erosion mechanisms such as cavitation, flashing, droplet impingement, and solid particle impingement. Changes have been made to the GALL Report and the SRP for review of LRAs.PG&E's licensing basis for the DCPP FAC program is documented in PG&E Letter DCL-09-079, dated November 23, 2009.The NRC evaluated the DCPP FAC program in its SER, Section 3.0.3.2.2, dated June 2, 2011.In order to address the recommendations in LR-ISG-2012-01, PG&E updates its licensing basis for the FAC program as follows: (1) The expanded definition of "wall thinning" including erosion mechanisms such as cavitation, flashing, droplet impingement, and solid particle impingement will be incorporated into the DCPP FAC program, LRA Section A1.6.(2) The ISG-revised definition of "flow-accelerated corrosion" currently aligns with the DCPP FAC program. The DCPP FAC program will be updated to reflect the specific forms of erosion described in the ISG.(3) PG&E will include the ISG-recommended activities to monitor wall thinning due to erosion mechanisms by updating the DCPP FAC program to: (a) Identify susceptible locations based on the extent-of-coridition reviews from corrective actions in response to plant-specific and industry operating experience.(b) Periodically verify the effectiveness of corrective actions for which design changes have been implemented to eliminate the source of the erosion mechanism. Periodic wall thickness measurements will be taken until the effectiveness of the corrective actions has been confirmed.(c) Review periodic wall thickness measurements as the basis to ensure functionality during the PEO will be maintained.(d) Remove the term "high-energy" from the scope of the DCPP FAC program. Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 2 of 9 (e) Align with the changes outlined in LR-ISG-2012-01, Appendix D,"Mark-up Showing Changes to the GALL Report." (4) The ISG revised SRP-LR and GALL Report Tables aging management review items to align with the changes made to the scope of GALL Report AMP XI.M17.Refer to revised LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-8, 3.4.2-3, and 3.4.2-5 in this Attachment. Refer to revised LRA Section A1.6 in Attachment
- 15. Section A1.6 also revises NSAC-202L from Revision 3 to Revision 4 as described in Attachment
- 13.
Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 3 of 9 Section 3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES Table 32.2-1 Enaineered Safety Features -Siimmani nf Ariinn Manar,~mi~nt Fvaliatir~n -SafAtv lnip~'tinn !~v.~t~m Tal -nieee evFaue -Smavofnn annmn Eauto -Safetv nci a Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Class 1 PB Stainless Treated Borated Wall thinning Flow-Accelerated Corrosion None None H, 5 Piping < 4in Steel Water (Int) due to erosion (B2.1.6)Orifice PB, TH Stainless Treated Borated Wall thinning Flow-Accelerated Corrosion None None H, 5 Steel Water (Int) due to erosion (B2.1.6)Piping LBS, PB, Stainless Treated Borated Wall thinning Flow-Accelerated Corrosion None None H, 5 SIA Steel Water (Int) due to erosion (B2.1.6)Valve LBS, PB, Stainless Treated Borated Wall thinning Flow-Accelerated Corrosion None None H, 5 SIA Steel Water (Int) due to erosion (B2.1.6)Valve LBS, PB, Stainless Treated Borated Wall thinning Flow-Accelerated Corrosion None None H, 5 SIA Steel Cast Water (Int) due to erosion (B2.1.6)1_ _ __ Austenitic I Plant Specific Notes: 5. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item V.D.E-407 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Section 3.2 Attachment 6 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES PG&E Letter DCL-14-103 Page 4 of 9 Table 3.2.2-3 Engineered Safety Features -Summary of Aging Management Evaluation -Residual Heat Removal System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Orifice PB, TH Stainless Treated Borated Wall thinning due Flow-Accelerated None None H, 6 Steel Water (Int) to erosion Corrosion (B2.1.6)Piping LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated None None H, 6 SIA Steel Water (Int) to erosion Corrosion (B2.1.6)Valve LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated None None H, 6 SIA Steel Water (Int) to erosion Corrosion (B2.1.6)Valve PB Stainless Treated Borated Wall thinning due Flow-Accelerated None None H, 6 Steel Cast Water (Int) to erosion Corrosion (B2.1.6)I _ _ Austenitic Plant Specific Notes: 6. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item V.D.E-407 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 5 of 9 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-3Auxiliary Systems -Summary of Aging Management Evaluation -Saltwater and Chlorination System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Orifice LBS Carbon Steel Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Orifice LBS Stainless Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 Steel to erosion Corrosion (B2.1.6)Piping LBS, PB Carbon Steel Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Piping LBS Cast Iron Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 (Gray Cast to erosion Corrosion (B2.1.6)Iron)Piping LBS, PB Copper Alloy Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Piping LBS Nickel Alloys Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Piping LBS, PB, Stainless Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 SIA Steel to erosion Corrosion (B2.1.6)Valve LBS, PB Carbon Steel Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Valve LBS, PB Cast Iron Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 (Gray Cast to erosion Corrosion (B2.1.6)Iron)Valve LBS, PB Copper Alloy Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Valve PB Copper Alloy Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 (Aluminum > to erosion Corrosion (B2.1.6)8%)Valve LBS, PB Nickel Alloys Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 to erosion Corrosion (B2.1.6)Valve LBS, PB, Stainless Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 SIA Steel to erosion Corrosion (B2.1.6)Valve LBS, PB, Stainless Raw Water (Int) Wall thinning due Flow-Accelerated None None H, 3 SIA Steel Cast to erosion Corrosion (B2.1.6)I________ __Austenitic I I I I Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 6 of 9 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-3Auxiliary Systems -Summary of Aging Management Evaluation -Saltwater and Chlorination System Plant Specific Notes: 3. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item VII. CI.A-409 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Section 3.3 Attachment 6 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 7 of 9 Tnhlc. .'q 9' 5-R Aivili~av .'Zv.c~fpm~ -F~,immr.~ri, nf Anina M~n~n~mAnf FvQIw~tk~n -Oh~micRl Rnd VAIIImA (Thntrnl Sv.'tRm Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Orifice LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated Corrosion None None H, 10 SIA, TH Steel Water (Int) to erosion (B2.1.6)Piping LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated Corrosion None None H, 10 SIA Steel Water (Int) to erosion (B2.1.6)Valve LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated Corrosion None None H, 10 SIA Steel Water (Int) to erosion (B2.1.6)Valve LBS, PB, Stainless Treated Borated Wall thinning due Flow-Accelerated Corrosion None None H, 10 SIA Steel Cast Water (Int) to erosion (B2.1.6)Austenitic Plant Specific Notes: 10. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item VII. El.A-407 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 8 of 9 Table 3.4.2-3 Steam ar Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM 7d Power Conversion System -Summary of Aging Management Evaluation -Feedwater System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Orifice LBS Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 Steel (Int) to erosion Corrosion (B2.1.6)Piping LBS, PB, Carbon Steel Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA (Int) to erosion Corrosion (B2.1.6)Piping LBS Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 Steel (Int) to erosion Corrosion (B2.1.6)Valve LBS, PB, Carbon Steel Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA (Int) to erosion Corrosion (B2.1.6)Valve LBS, PB Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 Steel (Int to erosion Corrosion (B2.1.6)Plant Specific Notes: 2. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item VIII.D1. S-408 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Attachment 6 PG&E Letter DCL-14-103 Page 9 of 9 Table 3.4.2-5 Steam ar Section 3.4 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM d Power Conversion System -Summary of Aging Management Evaluation -Auxiliary Feedwater System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Orifice LBS, PB, Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA, TH Steel (Int to erosion Corrosion (B2.1.6)Piping LBS, PB, Carbon Steel Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA Itto erosion Corrosion (B2.1.6)Piping LBS, PB, Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA Steel (Int) to erosion Corrosion (B2.1.6)Valve LBS, PB, Carbon Steel Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA nt to erosion Corrosion (B2.1.6)Valve LBS, PB, Stainless Secondary Water Wall thinning due Flow-Accelerated None None H, 2 SIA Steel (Int) to erosion Corrosion (B2.1.6)Plant Specific Notes: 2. Program provisions for wall thinning due to erosion apply. Refer to LR-ISG-2012-01, Appendix B, Line Item VIII.DI.S-408 and PG&E Letter DCL-14-103, Enclosure 1, Attachment
- 6.
Enclosure 1 Attachment 7A, PG&E Letter DCL-14-103 Page 1 of 10 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section A, Recurring Internal Corrosion LR-ISG-2012-02, Section A, provides recommendations to augment existing AMPs to address RIC.Following the changes discussed below, DCPP will be consistent with the recommendations in LR-ISG-2012-02, Section A.LR-ISG-2012-02, Section A, revised the SRP for engineered safety features systems, auxiliary systems, and steam and power conversion systems to require a review of the plant's CAP to identify RIC. Consistent with the methodology outlined in LR-ISG-2012-02, Section A, PG&E conducted a review of the past ten years of DCPP OE to identify internal corrosion events that are consistent with the definition of RIC in LR-ISG-2012-02. Based on this review, PG&E has identified RIC in the following systems: (1) Makeup Water System (System 16)(2) Saltwater and Chlorination (System 17)(a) Saltwater (System 17A)(b) Auxiliary Saltwater (System 17B)(c) Chlorination (System 17C)(3) Fire Protection (System 18)(4) Oily Water and Turbine Sump System (System 27)Makeup Water System (System 16)During a search of DCPP OE from November 23, 2009, to September 30, 2014, PG&E identified internal corrosion of copper components exposed to potable water in the DCPP makeup water system. Consistent with LR-ISG-2012-02, Section A, the internal corrosion is considered RIC because of the frequency of occurrence and significance of aging effect. The internal surfaces of copper makeup water system components exposed to potable water are managed by the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. Consistent with LR-ISG-2012-02, Appendix G, following a failure of the copper components exposed to potable water due to RIC, this program will be used to either: (a) replace the component with a material that is more corrosion-resistant; (b) take corrective actions to prevent recurrence of the RIC; (c) perform augmented inspections to detect aging before a loss of function occurs, or; (d) credit mitigating actions in accordance with Enclosure 1 Attachment 7A, PG&E Letter DCL-14-103 Page 2 of 10 NEI 95-10, Appendix F. Copper components exposed to potable water in the makeup water system that are currently in-scope for 10 CFR 54.4 (a)(2) may be re-evaluated to potentially further refine the scope of 10 CFR 54.4 (a)(2).Saltwater and Chlorination (System 17)In the original OE search performed and documented in the LRA (PG&E Letter DCL-09-079), PG&E identified microbiologically-induced corrosion in its ASW system, for which aging management is performed by the OCCW System program. Consistent with LR-ISG-2012-02, Section A, this is considered RIC because of the frequency of occurrence and significance of aging effect. This aging effect has been managed with the OCCW System program by continuous chlorination and periodic system inspections to verify effectiveness of continuous chlorination, as documented in PG&E Letter DCL-09-079, LRA Section B2.1.9, and SER Section 3.0.3.1.7. To ensure effectiveness, the OCCW System program performs visual examinations of the ASW system piping every fourth refueling outage to inspect the integrity of the plastic pipe liner and detect indications of corrosion of the base piping material. The examinations look for visible lining holes, lining cracks, or any loss of the internal lining that would expose the piping base material. If the acceptance criteria for the internal lining are not met, a corrective action document is written to repair the internal lining and piping if necessary, and an engineering evaluation is completed to determine the effect of the piping corrosion on system operability. Some of the piping in the ASW system is located below ground; these visual inspections are conducted remotely with robot inspection devices equipped with video cameras.The heat removal capability of heat exchangers in the CCW system is also currently tested prior to each refueling outage to ensure that it is greater than or equal to 100 percent of its design basis, through the testing of heat transfer effectiveness and flow testing. Test results are documented, trended, and validated for heat removal capabilities. If the results of the testing indicate any parameter outside of established acceptance criteria, deficiencies are resolved via DCPP's CAP.SER Section 3.0.3.1.7 concluded that, based on the operating experience, the OCCW System program can adequately manage the detrimental effects of aging on SSCs within the scope of the program and implementation of the program has resulted in the applicant taking corrective actions.Fire Protection System (System 18)PG&E has identified RIC in portions of the fire protection system that contain carbon steel components exposed to raw water. The DCPP Fire Water System program will be enhanced as described in LRA Section B2.1.13 (PG&E Letter DCL-09-079, dated November 23, 2009), PG&E Letter DCL-10-057, dated June 3, 2010, and PG&E Letter Enclosure 1 Attachment 7A, PG&E Letter DCL-14-103 Page 3 of 10 DCL-10-101, dated August 17, 2010 (RAI Responses B2.1.13-2, B2.1.13-3), and SER Section 3.0.3.2.6 to perform additional volumetric examinations and visual inspections of above-ground fire water system piping. The DCPP Fire Water System program will also be revised to address the changes to GALL Report AMP XI.M27 made by LR-ISG-2012-02, Section C, as discussed in Enclosure 1, Attachment 7C of this letter.The revisions that are sufficient to manage RIC identified in the fire protection system are summarized below: (1) Internal and external visual inspections are performed on accessible exposed portions of fire water piping during plant maintenance activities, or at least once every 18 months for external visual inspections, and every 5 years for internal visual inspections. Consistent with LR-ISG-2012-02, Section C.iii.b, volumetric examination will not be used in lieu of prescribed visual examinations of the internal surface of piping. The inspections detect loss of material due to corrosion, ensure that aging effects are managed, and detect surface irregularities that could indicate wall loss below nominal pipe wall thickness. When surface irregularities are detected, follow-up volumetric wall thickness examinations are performed. (2) Augmented volumetric wall thickness inspections are performed on 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect in each five-year interval prior to the PEO. The 20 percent of piping inspected in each 5-year interval shall be in different locations than previously inspected piping.DCPP's acceptance criteria for inspections of fire water piping are: (1) ability of the fire protection system to maintain required pressure and flow rates, (2) minimum design wall thickness is maintained, (3) no fouling exists in the sprinkler system that could cause corrosion in the sprinkler heads.Oily Water and Turbine Sump System (System 27)During a search of DCPP OE from November 23, 2009, to September 30, 2014, PG&E identified internal corrosion of stainless steel components exposed to raw water in the DCPP oily water and turbine sump system. Consistent with LR-ISG-2012-02, Section A, the internal corrosion is considered RIC because of the frequency of occurrence and significance of aging effect. However, these components are located in an out-of-scope portion of the oily water and turbine sump system, in a raw water Enclosure 1 Attachment 7A, PG&E Letter DCL-14-103 Page 4 of 10 environment considerably more harsh than that seen by in-scope components. This portion of the system is located in the turbine building sump, where the raw water environment has the potential to include seawater, caustics, and acids. The in-scope portions of the oily water and turbine sump system are constructed of carbon steel, carbon steel (galvanized), cast iron (gray cast iron), and copper, and are located in the 12-kV cable spreading rooms, the component cooling water heat exchanger rooms, and the diesel generator rooms within the turbine building. The raw water that the in-scope piping is exposed to consists of groundwater or used potable water, and is only used intermittently. Because RIC has only occurred in a material/environment combination that is separate from the in-scope portions of the oily water and turbine sump system, no actions to manage RIC are required.LRA Sections 3.3.2.1.5 and 3.3.2.1.12, and Tables 3.3.2-5 and 3.3.2-12 are revised to incorporate loss of material due to recurring internal corrosion as an aging effect in the fire protection system.The NRC Staff also revised the criteria for the use of GALL Report AMP XI.M38 to emphasize that the program should not be used to manage RIC. Consistent with LR-ISG-2012-02, Section A, the DCPP Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program will state that an aging effect is considered as RIC if it has occurred over three or more sequential or nonsequential cycles for a ten-year OE search of aging effects with the same aging mechanism and for which the aging effect resulted in the component not meeting plant-specific acceptance criteria, or experiencing a reduction in wall thickness greater than 50 percent regardless of the minimum wall thickness. If the criteria for RIC are met, use of the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program is allowed if augmented requirements are included to adequately manage the aging. Refer to revised LRA Section A1.22 in Attachment
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Enclosure 1 Section 3.3 Attachment 7A AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 5 of 10 3.3.2.1.5 Makeup Water System Aging Effects Requiring Management The following makeup water system aging effects require management: 0 Loss of material from recurring internal corrosion Enclosure 1 Attachment 7A PG&E Letter DCL-14-103 Page 6 of 10 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-5 Auxiliary Systems -Summary of Aging Management Evaluation -Makeup Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Flow Element LBS Copper Alloy Potable Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring internal Surfaces in corrosion Miscellaneous Piping and Ducting Components (B2.1.22)Heater LBS Copper Alloy Potable Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring internal Surfaces in corrosion Miscellaneous Piping and Ducting Components (B2.1.22)Piping LBS Copper Alloy Potable- Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring internal Surfaces in corrosion Miscellaneous piping and Ducting Components (B2.1.22)Tank LBS Copper Alloy Potable Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring internal Surfaces in corrosion Miscellaneous Piping and Ducting Components (B2.1.22)Trap LBS Copper Alloy Potable Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring internal Surfaces in corrosion Miscellaneous Piping and Ducting Components (B2.1.22)Valve LBS Copper Alloy Potable Water (Int) Loss of material; Inspection of Internal None None G, 6 recurring intemal Surfaces in corrosion Miscellaneous Piping and Ducting Components (B2.1.22) Enclosure 1 Attachment 7A PG&E Letter DCL-14-103 Page 7 of 10 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Notes for Table 3.3.2-5: Plant Specific Notes: 6 The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (82.1.22) is used to manage recurring internal corrosion in the makeup water system. Reference LR-ISG-2012-02, Section A, and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7A. Enclosure 1 Attachment 7A PG&E Letter DCL-14-103 Page 8 of 10 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.12 Fire Protection System Aging Effects Requiring Management The following fire protection system aging effects require management: 0 Loss of material from recurring intemal corrosion Enclosure 1 Attachment 7A PG&E Letter DCL-14-103 Page 9 of 10 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems -Summary of Aging Management Evaluation -Fire Protection System Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. 2 Item Management Item Loss of material;Bellows PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Flow Element PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Flow Indicator PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Hose Station PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Hydrant PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Piping LBS, PB, Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 SS corrosion Carbon Steel Loss of material;Piping PB Canized) Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 (Galvanized) corrosion Cast Iron Loss of material;Piping PB (Gray Cast Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 Iron) corrosion Cast Iron Loss of material;Pump PB, SS (Gray Cast Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 Iron) corrosion Enclosure 1 Attachment 7A PG&E Letter DCL-14-103 Page 10 of 10 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems -Summary of Aging Management Evaluation -Fire Protection System Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table 1 Notes Type Function Requiring 1801 Vol. 2 Item Management Item Loss of material;Strainer PB Carbon Steel Raw Water (Int) recurring intemal Fire Water System (B2.1.13) None None H, 5 corrosion Cast Iron Loss of material;Strainer PB (Gray Cast Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 Iron) corrosion Loss of material;Tank PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Test Connection PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Loss of material;Valve PB Carbon Steel Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 corrosion Cast Iron Loss of material;Valve PB (Gray Cast Raw Water (Int) recurring internal Fire Water System (B2.1.13) None None H, 5 Iron) corrosion Notes for Table 3.3.2-12: Plant Specific Notes: 5 The Fire Water System program (B2.1.13) is used to monitor for recurring internal corrosion in the Fire Protection system. Reference LR-ISG-2012-02, Appendix C, Line VII. G.A-400 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7A. Enclosure 1 Attachment 7B PG&E Letter DCL-14-103 Page 1 of 2 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section B, "Representative Minimum Sample Size for Periodic Inspections in GALL Report AMP XI.M38, 'Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"' LR-ISG-2012-02, Section B, contains recommended inspection sample sizes, population, and frequency for GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." PG&E's licensing basis for the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-105, dated August 18, 2010 (4) PG&E Letter DCL-10-147, dated November 24, 2010 The NRC evaluated the DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program in its SER, Section 3.0.3.2.11, dated June 2, 2011.In order to address the recommendations in LR-ISG-2012-02, Section B, PG&E updates its licensing basis for the Inspection of Internal Surfaces program as follows.(1) The DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program will inspect 20 percent of each population of in-scope components with the same material, environment, and aging effect, with a maximum sample size of 25 components, in each 10-year period during the PEO.(2) Where practical, the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program will select inspection locations from bounding or lead components (e.g., low or stagnant flow) most susceptible to aging because of time in service, severity of operating conditions, and lowest design margin.(3) The minimum sample size specified above does not override the opportunistic inspection basis of the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program. Opportunistic inspections will still be conducted, even though the sample size specified above may have already been inspected in a ten-year period. Enclosure 1 Attachment 7B PG&E Letter DCL-14-103 Page 2 of 2 (4) Inspections conducted on a component in a more severe environment may be credited as an inspection in a less severe similar environment for the same material and aging effect. Alternatively, similar environments for the same material can be combined into a larger group as long as the inspections occur on components located in the more severe environment. (5) LRA Table A4-1, Item 9, is revised to reflect the updated implementation schedule for the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program, as described in LR-ISG-2012-02, Appendix B, Table 3.0-1.LRA Section A1.22 and Table A4-1, Item 9, are revised to address LR-ISG-2012-02, Section B. Refer to Attachment
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Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 1 of 14 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section C, "Flow Blockage of Water-Based Fire Protection System Piping, GALL Report AMP XI.M27, 'Fire Water System"'PG&E's licensing basis for the DCPP Fire Water System, XI.M27 program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-057, dated June 3, 2010 (3) PG&E Letter DCL-10-101, dated August 17, 2010 (4) PG&E Letter DCL-10-128, dated October 12, 2010 (5) PG&E Letter DCL-10-134, dated October 27, 2010 The NRC Staff evaluated the DCPP Fire Water System program in its SER, Section 3.0.3.2.6, dated June 2, 2011.In order to address the recommendations in LR-ISG-2012-02, Section C, PG&E updates its licensing basis for the Fire Water System program as follows.Based on the recommendations in LR-ISG-2012-02, Section C, PG&E will inspect and test in-scope fire water system components within the scope of license renewal consistent with guidance of LR-ISG-2012-02, Section C and the NFPA-25 (2011 Edition) sections listed in LR-ISG-2012-02, Appendix D, Table 4a, with the following exceptions: (1) NFPA-25, Section 5.2.1.1 specifies inspecting sprinklers from the floor annually.Exception PG&E inspects sprinklers outside containment from the floor every 18 months as required by ECG 18.4. By NRC letter dated January 13, 1993, "Issuance of Amendments for Diablo Canyon Nuclear Power Plant, Unit Nos. 1 and 2 (License Amendments 75 and 74, respectively) the NRC approved DCPP's request to relocate the fire protection Technical Specifications and associated bases to the ECGs. Therefore, DCPP testing frequencies are in compliance with the licensing basis previously approved by NRC.Basis An 18-month inspection frequency reduces exposure of personnel to safety considerations such as those raised by continuous process operations, and radiological dose, and does not exceed the plant refueling outage interval. Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 2 of 14 The majority of sprinkler systems are located in areas that are frequented by plant personnel during operator rounds and other work activities. These activities have identified sprinkler system degradation such as leaks, mechanical damage, obstruction of sprinkler spray patterns, and loose pipe hangers. Upon discovery, these issues are entered into the CAP for evaluation, increasing the likelihood that degradation will be identified outside of procedure-driven sprinkler system inspections. A review of plant operating experience since 1997 has not revealed age-related degradation occurring at such a rate that would warrant increasing the procedure-driven sprinkler system visual inspection from 18 months to annually.Conclusion PG&E will continue to inspect sprinklers outside containment from the floor every 18 months.(2) NFPA-25, Section 6.3.1.1 specifies that flow tests will be conducted every five years at the hydraulically most remote hose connection of each zone of an automatic standpipe system. NFPA-25, Section 6.3.1.5 specifies that a test shall be performed on all standpipe systems with automatic water supplies in accordance with the requirements of Chapter 13. NFPA-25, Section 13.2.5 specifies the test of the automatic water supply shall be performed annually at each water based fire protection system riser.Exception Instead of flow testing each zone of an automatic standpipe system and testing the automatic water supply on each riser of the fire water system annually, PG&E will rely on redundant water supplies and system pressurization sources as described in the DCPP FSAR Update, Section 9.5.1.2.1, and the following tests to ensure adequate flow capability: (a) flow testing three hose station locations where flow test results bound other locations in the system, (b) flow testing fire main supply lead-ins to each building at least every 18 months, (c) hose station functional testing, and (d) water supply valve position verification Basis Flow testing of automatic standpipe systems increases risk due to the potential for water contacting critical equipment in the area. In addition, flow in the radiologically-controlled areas increases the amount of liquid radwaste.NFPA-25 specifies that flow testing is performed to verify the fire water supply still provides the design pressure at the required flow. Similarly, NFPA-25 indicates the primary purpose of the Section 13.2.5 test is to identify major Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 3 of 14 reductions in water flow due to significant obstructions to flow such as a failed or mispositioned valve. The DCPP Fire Water System program will rely on the following activities to demonstrate unobstructed flow of the automatic standpipe system at design pressure and verify the fire main supply to each building is unobstructed. The DCPP fire water system is normally supplied through the yard fire water loop, which is supplied and gravity-pressurized by the RWSR. There are two fire water supply lead-ins from the fire water loop to the auxiliary building (which includes the fuel handling building), and four to the turbine building. A seismically qualified water system within the turbine building, auxiliary building, and containment structures provides uninterrupted water supply to hose stations servicing safety related areas of the plant. The qualified system consists of the FWST, two electric pumps, fire mains, and piping. The system is designed to provide redundant flow paths, with the ability to align any of six water supply lead-ins to the hose station or sprinkler systems inside the auxiliary building, turbine building and containment structures. Two fire water pumps in the fuel handling portion of the auxiliary building will auto-start on low fire water system pressure, drawing water from the FWST to pressurize the system within the auxiliary and turbine buildings, and the containment structures. Check valves on the mains into these buildings from the yard loop ensure that system pressure developed by the fire pumps is not lost due to backflow to the yard loop.Every five years, PG&E will flow test at least three remote firewater hose station locations in accordance with NFPA-25, Section 6.3.1, to demonstrate the standpipe system can supply design pressure at required flow.The intake structure fire water is supplied by a branch line off of the yard loop.Adequate pressure is ensured, as hose station connections in the intake are 300 feet below the minimum RWSR level. The availability of adequate flow to the intake structure automatic standpipe system and sprinklers is verified by flow testing the hydrant just outside of the intake structure in accordance with NFPA-25, Section 7.3.2. During the flow test, the static and residual pressure are recorded and trended. In addition, all of the hose stations within the scope of license renewal are functionally tested at least every three years. Functional testing consists of verifying: (a) the hose station valve is functional, (b) there is flow through the valve and connection, and (c) the absence of any indication of obstruction or other undue restriction of water flow.NFPA-25, Section 13.2.5 testing is prescribed to identify major reductions in waterflow to the fire water system that can be caused by obstructions such as mispositioned valves. PG&E verifies that valves that are normally open in the fire water system are not mispositioned by sealing them open and, with the exception of those in containment, by walkdown every 31 days. The isolation valves in Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 4 of 14 containment are verified open during operational testing of containment hose station connections every refueling outage.NFPA-25, Section 13.2.5 states that a test shall be conducted annually at each fire protection system riser to determine if there has been a change in the condition of the water supply. Appendix A of NFPA-25, Section Al 3.2.5, clarifies that "The test for standpipe system should be done at the low-point drain for each standpipe or the main drain test connection where the supply main enters the building." PG&E will perform a flow test of all the fire water supply mains that enter the auxiliary building, turbine building, and the radwaste storage facility every 18 months to verify the design is being maintained. If there is a ten percent reduction in full flow pressure when compared to previously performed tests, the deficiency will be entered into the CAP.The auxiliary building and the intake structure have combined standpipe and sprinkler systems such that the flow testing of the automatic standpipe verifies the supply to the sprinkler systems is unobstructed. Every 18 months, the absence of blockage in sprinkler branch lines and the associated supply mains is demonstrated during fire water flow alarm testing by opening a flushing connection or drain valve at the end of branch lines.Conclusion (a) PG&E will enhance the Fire Water System program to flow test at least three firewater hose station locations in accordance with NFPA-25, Section 6.3.1 to demonstrate the system is capable of providing design pressure at required flow.(b) PG&E will continue to flow test the fire hydrant outside the intake structure in accordance with NFPA-25, Section 7.3.2, and record the static and residual pressures during the test and trend the results.(c) PG&E will continue the functional test of all the hose stations within the scope of license renewal at least every three years.(d) PG&E will continue to seal open valves that are normally open in the fire water system and verify they are not mispositioned, with the exception of those in containment, by a walkdown every 31 days.(e) PG&E will continue to open a flushing connection or drain valve at the end of sprinkler branch lines every 18 months.(f) PG&E will enhance the Fire Water System program to perform a flow test of the fire water supply mains that enter the auxiliary building, turbine building, and radwaste storage facility every 18 months to verify the Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 5 of 14 design is being maintained. If there is a ten percent reduction in full flow pressure when compared to previously performed tests, the deficiency will be entered into the CAP.(3) NFPA-25, Section 9.2.5.5 specifies performing an annual inspection of the exterior surface of fire water tanks.Exception A diver will inspect the external surface of the FWST every five years.Basis Typically, the inspection of the exterior surface of a fire water tank is conducted via walkdown and visual inspection of the tank. The DCPP FWST is inside of the transfer tank and is coated with vinyl paint for corrosion protection. The transfer tank contains makeup water. A diver will inspect the internal surface of the transfer tank and the internal and external surfaces of the FWST every five years. The five year inspection interval is consistent with the frequency requirement in NFPA-25, Section 9.2.6.1.2, for the internal inspection of tanks with corrosion protection. Conclusion PG&E will enhance the DCPP Fire Water System program to inspect the internal and external surface of the FWST by diver every five years.(4) NFPA-25, Section 13.4.3.2.2 specifies annually trip testing each deluge valve system at full flow, incorporating full functionality of the system including automatic detection. Exception PG&E performs a combination of trip testing of the outdoor deluge systems at full flow and reduced flow, and verifies water supply to the system is available, but does not include automatic detection. The hydrogen seal oil cooler deluge system is trip tested at minimal flow and will be tested with air, smoke, or other medium.Basis Automatic actuation of the DCPP deluge systems is provided by pilot lines.Utilizing automatic detection of the deluge system through actuation of one of the pilot line sprinklers requires replacement of the pilot line sprinkler head.Actuation of the deluge system is with a manual pull box that depressurizes the pilot system causing the deluge valve to open without requiring replacement of a pilot sprinkler. Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 6 of 14 The deluge system nozzles are visually inspected every 18 months to verify the spray patterns are unobstructed and the nozzle openings are not blocked.Opening the deluge valve and allowing water flow out of the sprinkler nozzles in critical equipment areas is considered a risk significant activity. The deluge systems that protect electric transformers are trip tested at full flow every three years and annually at a reduced flow through a system drain. The reduced flow test ensures the deluge valves are operational while avoiding the risks associated with spraying water on the transformers. Every 18 months, the deluge system strainer flush valves are fully opened, the flow is observed verifying sufficient flow is available to the system, that there is no blockage, and the static and residual pressures are recorded.The only other deluge system within the scope of license renewal is for the hydrogen seal oil cooler. Actuation of the hydrogen seal oil cooler deluge valves is performed every 18 months at minimal flow through a system drain, to prevent water from flowing to the spray nozzles. Dry piping downstream of the deluge valve will be flow tested with air, smoke, or other medium to ensure the piping and nozzles are clear every second visual inspection of the spray nozzles (i.e., every three years). Past visual inspections have found the hydrogen seal oil cooler deluge system to be clean and free of corrosion. The benefit of the nozzle testing at shorter intervals is negated by the risk of introducing foreign material while breaking open and closing the spray piping to perform the test.Conclusion (a) PG&E will continue to visually inspect the deluge system nozzles every.18 months to verify the spray patterns are unobstructed and the nozzle openings are not blocked.(b) PG&E will continue to trip test the outdoor deluge systems at full flow every three years and at reduced flow annually.(c) PG&E will continue to flush the outdoor deluge systems every 18 months by fully opening strainer flush valves. Flow will be observed during the test to verify that sufficient flow is available to the system, that there is no blockage, and the static and residual pressures are recorded.(d) PG&E will continue to actuate the hydrogen seal oil cooler deluge valves every 18 months at minimal flow through a system drain to prevent water from flowing to the spray nozzles.(e) PG&E will enhance the Fire Water System program to flow test dry piping downstream of the hydrogen seal oil cooler deluge valve with air, smoke, Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 7 of 14 or other medium to ensure the piping and nozzles are clear every second visual inspection (i.e., every three years) of the spray nozzles.(5) Steel tanks will be inspected in accordance with NFPA-25, Section 9.2.6. An exception is being taken to Section 9.2.6.4 in that any degradation, such as described in LR-ISG-2012-02, Appendix D, Table 4a, Note 4, will be entered into the CAP and an engineering evaluation of the inspection results will be performed to determine whether further actions are required. Follow-up actions will be in accordance with either NFPA-25 Section 9.2.7 or 4.6.(6) NFPA-25 sections referenced in this Attachment specify frequencies. An exception is being taken regarding inspection periodicity in that, in accordance with NFPA-25, Section 4.6, subject to the authority having jurisdiction, frequencies may be adjusted based on testing and inspection results.Further Enhancements to be Consistent with LR-ISG-2012-02, Section C PG&E will also make the following enhancements to the DCPP Fire Water System program. Following these enhancements, and with the exceptions stated above, the DCPP Fire Water System program will be consistent with LR-ISG-2012-02, Section C.(1) Consistent with NFPA-25, Section 5.2.1.1, PG&E will include the acceptance criteria for sprinkler visual inspection. (2) Consistent with LR-ISG-2012-02, Appendix D, Table 4a, Note 5, PG&E will inspect sprinklers inside containment every refueling cycle for each Unit.(3) Consistent with LR-ISG-2012-02, Appendix D, Table 4a, Note 1, for those NFPA-25 sections referenced in this Attachment, the inspection scope and periodicity will be consistent with the 2011 Edition, with the exception listed in (6) above.(4) PG&E will flow test fire water supply piping in the yard and hydrants consistent with NFPA-25, Sections 7.3.1 and 7.3.2.(5) PG&E will inspect the FWSTs internally, consistent with NFPA-25, Section 9.2.6, with the exception to Section 9.2.6.4 listed above.(6) PG&E will inspect, repair, and replace strainers every five years consistent with NFPA-25, Sections 10.2.1.7 and 10.2.7.1. Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 8 of 14 (7) Consistent with NFPA-25, Section 10.3.4.3.2, PG&E will clean deluge system nozzles and retest the system when obstructions are identified during flow testing.(8) Consistent with LR-ISG-2012-02, Section C.iii.d, PG&E will identify any portions of the fire water deluge system piping that are normally dry and periodically subject to flow, but are unable to be drained. During the five year period prior to the PEO, PG&E will perform either: (a) a flow test or flush sufficient to detect potential flow blockage, or (b) an inspection of 100 percent of the internal surface on those portions unable to be drained.Every 5 years thereafter, 20 percent of the portion will be volumetrically tested so that after 25 years, 100 percent has been volumetrically tested.If and when the hydrogen seal oil cooler deluge system spray piping becomes wetted, an inspection will be conducted to determine if any portions of the spray piping cannot be drained or allows water to collect, and the flow testing and inspection criteria for normally dry wet sprinkler systems above will be applied.(9) Consistent with NFPA-25 Section 14.2, PG&E will internally inspect wet sprinkler systems using a method capable of detecting flow blockage due to fouling in addition to loss of material.(10) PG&E will perform obstruction investigations as required by and consistent with NFPA Section 14.3.(11) Consistent with LR-ISG-2012-02, Section C.iii.b, volumetric examination will not be used in lieu of prescribed visual examinations of the internal surface of piping.(12) Consistent with LR-ISG-2012-02, Section C.iii.c, following detection of irregularities identified during visual inspections that could indicate wall loss below nominal wall thickness, follow-up volumetric examination will be performed. (13) Consistent with LR-ISG-2012-02, Section C.iii.p, DCPP Fire Water System program references to biofouling will be revised to the general term fouling.LRA Sections 3.3.2.1.12 and 3.3.2.2.10.6 and LRA Tables 3.3.1 and 3.3.2-12 are revised to address LR-ISG-2012-02, Section C, as shown in this Attachment. LRA Section A1.13 and Table A4-1, Item 3 are revised to address LR-ISG-2012-02, Section C, as shown in Attachment
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Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 9 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.12 Fire Protection System Aging Effects Requiring Management The following fire protection system aging effects require management:
- Loss of material* Loss of material, cracking and changes in material properties
- Loss of preload* Flow blockage due to fouling 3.3.2.2.10.6 Copper alloy piping and components exposed to internal condensation The Fire Water System AMP (B2.1.13) manages loss of material due to general pitting, and crevice corrosion for fire water system copper alloy internal surfaces exposed to internal condensation and moisture.Thea inncAn inf inharn=I eiur~nies On~ m4i rIn*-lineo Pining and fltitinn Gempenent's.....
..- ........i III 4 ..C.n~'.r- ; a .4 4; A f-nn-nann,-ataa
- ~AI I ..* I *~~% J 11 M I I BVI coIPper alley interna su~faces exposed to irnernlal cOnaensation and moeisture Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 10 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary Systems (Continued)
Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.3.1.28 Copper alloy fire Loss of material due to pitting A plant-specific aging Yes Consistent with protection piping, and crevice corrosion management program is to be NUREG-1801. piping components, evaluated. The plant-specific aging and piping elements management program(s) exposed to used to manage the aging condensation (internal) include: Fire Water System (B2.1.13)lFispeti f-Intcrnal Surfaces in Mliccellancous Piping and Ducting Comnponents (B2.1.22). See further evaluation in Section 3.3.2.2.10.6. Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 11 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems -Summary of Agring Management Evaluation -Fire Protection System (Continued) Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Bellows PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Flow Element PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Flow Element PB Stainless Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 7 Steel Flow Indicator PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Hose Station PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Hydrant PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Hydrant PB Ductile Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Orifice PB Stainless Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 7 Steel Piping LBS, PB, Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 SS Piping PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 (Galvanized) Piping PB Cast Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 (Gray Cast Iron)Piping PB Ductile Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Piping PB Carbon Steel Atmosphere! Loss of material Fire Water System (B2.1.13) None None H, 9 Weather (Int)Piping PB Carbon Steel Plant Indoor Air Loss of material Fire Water System (B2.1.13) None None H, 9 1(Int)I Piping PB Carbon Steel Atmosphere/ Flow blockage Fire Water System (B2.1.13) None None H, 9 Weather (Int) if, 9:: Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 12 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems -Summary of Agfing Management Evaluation -Fire Protection System (Continued) Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Piping PB Carbon Steel Plant Indoor Air Flow blockage Fire Water System (B2.1.13) None None H, 9 (Int)Piping LBS, PB Stainless Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 7 Steel Pump PB, SS Cast Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 (Gray Cast Iron)Pump PB, SS Aluminum Plant Indoor Air None None V.F-2 3.2.1.50 A, 2 (Int)Spray Nozzle SP Copper Alloy Atmosphere! Flow blockage Fire Water System (B2.1.13) None None H, 11 Weather (Int)Spray Nozzle SP Copper Alloy Atmosphere! Flow blockage Fire Water System (B2.1.13) None None H, 11 Weather (Ext)Spray Nozzle SP Copper Alloy Plant Indoor Air Flow blockage Fire Water System (B2.1.13) None None H, 11 (Ext)Spray Nozzle SP Copper Plant Indoor Air Flow blockage Fire Water System (B2.1.13) None None H, 11 Alloyl (Int)Strainer PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Strainer PB Cast Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 (Gray Cast Iron)Strainer PB Copper Alloy Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 8 Tank PB Carbon Steel Raw Water (Ext) Flow blockage Fire Water System (B2.1.13) None None H, 10 Tank PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 10 T Test Connection PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Tubing LBS, PB Stainless Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 7 Steel Enclosure 1 Attachment 7C PG&E Letter DCL-14-103 Page 13 of 14 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-12 Auxiliary Systems -Summary of Aging Management Evaluation -Fire Protection System (Continued) Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Valve PB Carbon Steel Plant Indoor Air Flow blockage Fire Water System (B2.1.13) None None H, 12 (Int)Valve PB Carbon Steel Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Valve PB Cast Iron Plant Indoor Air Flow blockage Fire Water System (B2.1.13) None None H, 12 (Gray Cast (Int)Iron)Valve PB Cast Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 (Gray Cast Iron)Valve PB Copper Alloy Plant Indoor Air Loss of material Fire Water System VII.G-9 3.3.1.28 E, 5 (Int) (B2.1. 13),.spectin ef intc..al Surfaccs in Miscellaneous-Piping and Ducting Valve LBS, PB Copper Alloy Raw Water (Int) Flow blockage Fire Water System (82.1.13) None None H, 8 Valve PB Copper Alloy Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 8 (> 15% Zinc)Valve PB Ductile Iron Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 6 Valve PB Stainless Raw Water (Int) Flow blockage Fire Water System (B2.1.13) None None H, 7 Steel Plant Specific Notes: 2 This line represents priming pumps associated with the portable diesel driven fire pumps that are not normally connected to the fire water system when the pumps are stored. The aging effect of flow blockage from LR-ISG 2012-02, Appendix C, Item VII. G.A-403 is not applicable because this line is not normally connected to the Fire Water system so there is no upstream corrosion products that may accumulate in this pump. Reference PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C. Enclosure 1 Section 3.3 Attachment 7C AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-14-103 Page 14 of 14 5 The Fire Water System program (B2.1.13) is used to monitor copper alloy piping, piping components and piping elements exposed to condensation (internal) for loss of material in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VII.G.A-143 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.6 The Fire Water System program (B2.1.13) is used to monitor steel piping, piping components, and piping elements exposed to raw water for fouling that leads to corrosion and flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VlI G.A-33 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.7 The Fire Water System program (B2.1.13) is used to monitor stainless steel piping, piping components, and piping elements exposed to raw water for fouling that leads to corrosion, and flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VlI.G.A-55 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.8 The Fire Water System program (B2.1.13) is used to monitor copper alloy piping, piping components and piping elements exposed to raw water for fouling that leads to corrosion, and flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line Vl1 G.A-197 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.9 The Fire Water System program (B2.1.13) is used to monitor steel piping, piping components, and piping elements exposed to moist air or condensation (intemal)for fouling that leads to corrosion and flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VII.G.A-23 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.10 The Fire Water System program (B2.1.13) is used to monitor steel tanks exposed to soil or concrete, air indoor uncontrolled, raw water, treated water, waste water, or condensation for fouling that leads to corrosion, and flow blockage due to fouling in the fire protection system.Reference LR-ISG-2012-02, Appendix C, Line V1l. G.A-402 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.11 The Fire Water System program (B2.1.13) is used to monitor copper alloy sprinklers exposed to air indoor controlled, air indoor uncontrolled, air outdoor, moist air, condensation, raw water, or treated water for flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VI. G.A-403 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C.12 The Fire Water System program (B2.1.13) is used to monitor steel, stainless steel, copper alloy or aluminum fire water system piping, piping components, and piping elements exposed to air indoor uncontrolled (internal), air outdoor (internal), or condensation (internal) for fouling that leads to corrosion, and flow blockage due to fouling in the fire protection system. Reference LR-ISG-2012-02, Appendix C, Line VI. G.A-404 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C. Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 1 of 8 LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" Section D, "Revisions to the Scope and Inspection Recommendations of Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.M29, 'Aboveground Metallic Tanks"'LR-ISG-2012-02, Section D, provides scope and inspection recommendations for AMP XI.M29, "Aboveground Metallic Tanks." PG&E did not credit the Aboveground Metallic Tanks AMP during the preparation of DCPP LRA. The aging of in-scope aboveground metallic tanks is managed by the Water Chemistry program (B2.11.2), One Time Inspection program (B2.1.16), Close Cycle Cooling Water program (B2.1.9), Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program (B2.1.22) and the External Surfaces Monitoring Program (B2.1.20). PG&E's licensing basis for the DCPP Water Chemistry program is documented in PG&E Letter DCL-09-079, dated November 23, 2009.PG&E's licensing basis for the DCPP One-Time Inspection program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-1 0-134, dated October 27, 2010 (4) PG&E Letter DCL-1 3-119, dated December 23, 2013 PG&E's licensing basis for the DCPP Open-Cycle Cooling Water System program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-1 0-122, dated September 22, 2010 (3) PG&E Letter DCL-1 0-151, dated November 24, 2010 PG&E's licensing basis for the DCPP Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-073, dated July 7, 2010 (3) PG&E Letter DCL-10-105, dated August 18, 2010 (4) PG&E Letter DCL-10-147, dated November 24, 2010 Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 2 of 8 PG&E's licensing basis for the DCPP External Surfaces Monitoring program is documented in the following letters: (1) PG&E Letter DCL-09-079, dated November 23, 2009 (2) PG&E Letter DCL-10-130, dated October 12, 2010 The NRC evaluated the DCPP Water Chemistry, One-Time Inspection, Open-Cycle Cooling Water, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and External Surfaces Monitoring programs in its SER, Sections 3.0.3.1.2, 3.0.3.1.10, 3.0.3.1.7, 3.0.3.2.11, and 3.0.3.2.10, respectively, dated June 2, 2011.LR-ISG-2012-02, Section D, revised XI.M29, Program Element 1, "Scope of Program," to include indoor large-volume tanks that meet all of the following criteria: (a) have a large volume (i.e., greater than 100,000 gallons); (b) are designed to near-atmospheric internal pressures; (c) sit on concrete; and (d) are exposed internally to water. DCPP does not have any indoor large-volume tanks that meet these criteria.DCPP has the following outdoor tanks in the scope of license renewal: (1) Refueling water storage tanks (LRA Table 3.2.2-1 Safety Injection System)(2) Component cooling water surge tanks, (LRA Table 3.3.2-4 Component Cooling Water System)(3) Condensate storage tanks, (LRA Table 3.3.2-5 Makeup Water System)(4) Transfer storage tank, (LRA Table 3.3.2-5 Makeup Water System)(5) Backup air supply accumulator tanks, (LRA Table 3.3.2-7 Compressed Air System)(6) Steam generator blowdown tanks, (LRA Table 3.4.2-1 Turbine Steam Supply System)Following the enhancements described below, DCPP will be consistent with the recommendations provided in LR-ISG-2012-02, Section D.The RWSTs are stainless steel tanks encased in concrete. These tanks sit on concrete foundations with an internal environment of treated water and plant indoor air. The AMR lines for these tanks are shown on LRA Table 3.2.2-1. The internal surfaces of these tanks exposed to treated water are managed by the Water Chemistry program (B2.1.2) and the One Time Inspection program (B2.1.16). The internal surfaces of these tanks exposed to plant indoor air are managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22). The exterior surfaces of these tanks are encased in concrete and are not exposed to condensation; therefore, there are no aging effects that require managing. To address the recommendations in LR-ISG-2012-02, Section D, a new AMR line to perform Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 3 of 8 volumetric examinations of the tank bottom from the inside has been added to LRA Table 3.2.2-1. The volumetric examinations will be performed from inside the tank each ten-year period starting ten years before entering the PEO to confirm the absence of loss of material due to corrosion. These volumetric examinations will be performed using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22). The CCW surge tanks are carbon steel tanks with an internal environment of closed cycle cooling water and dry gas. These tanks are not exposed to soil or concrete. The AMR lines for these tanks are shown on LRA Table 3.3.2-4. The internal surfaces of these tanks are managed by the Closed Cycle Cooling Water program (B2.1.10). The external surfaces of these tanks are managed by the External Surfaces Monitoring program (B2.1.20). The external surfaces will be visually inspected every refueling outage interval by the External Surfaces Monitoring program (B2.1.20). No revisions to the AMR lines are required to address the recommendation from LR-ISG-2012-02, Section D.The condensate storage tanks and the transfer storage tank are carbon steel tanks encased in concrete. These tanks sit on a concrete foundation with an internal environment of demineralized water and plant indoor air. The AMR lines for these tanks are shown on LRA Table 3.2.2-5. The internal surfaces exposed to demineralized water are managed by the Water Chemistry program (B2.1.2) and One Time Inspection program (B2.1.16). The internal surfaces exposed to plant indoor air are managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.11.22). The exterior surfaces of these tanks are encased in concrete and are not exposed to condensation; therefore, there are no aging effects that require managing. To address the recommendation from LR-ISG-2012-02 Section D a new AMR line to perform volumetric examinations of the tank bottom from the inside is added to LRA Table 3.2.2-5. The volumetric examinations will be performed from inside the tank each ten-year period starting ten years before entering the PEO to confirm the absence of loss of material due to corrosion. These volumetric examinations will be performed using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22). The backup air supply accumulator tanks are carbon steel tanks with an internal environment of dry gas. These tanks are not exposed to soil or concrete. The AMR lines for these tanks are shown on LRA Table 3.3.2-7. Since the internal surface of these tanks is exposed to dry gas there are no aging effects that require managing.The external surfaces of these tanks are managed by the External Surfaces Monitoring program (B2.1.20). The external surfaces will be visually inspected every refueling outage interval by the External Surfaces Monitoring program (B2.1.20). No revisions to the AMR lines are required to address the recommendation from LR-ISG-2012-02, Section D. Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 4 of 8 The steam generator blowdown tanks are insulated carbon steel tanks with an internal environment of secondary water. These tanks are not exposed to soil or concrete. The AMR lines for these tanks are shown on LRA Table 3.4.2-1, with the external environment listed as Plant Indoor Air. The external environment of these tanks is Atmosphere/Weather, and is revised in Attachment
- 9. The internal surfaces exposed to secondary water are managed by the Water Chemistry program (B2.1.2) and One Time Inspection program (B2.1.16).
The external surfaces beneath insulation will be visually inspected every refueling outage interval by the External Surfaces Monitoring program (B2.1.20), in accordance with the recommendations of LR-ISG-2012-02, Section E.No revisions to the AMR lines are required to address the recommendations from LR-ISG-2012-02, Section D.LRA Sections 3.2.2.1.1 and 3.3.2.1.5, and Tables 3.2.2-1, 3.3.2-5, and A4-1, Item 9, are revised as shown in this Attachment to address the changes in LR-ISG-2012-02, Section D recommendations. LRA Sections A1.22 and Table A4-1, Item 9, are revised as shown in Attachment
- 15.
Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 5 of 8 Section 3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES 3.2.2.1.1 Safety Injection System Environment The safety injection system components are exposed to the following environments: 0 0 S S 0 0 S S S S S Borated Water Leakage Closed-Cycle Cooling Water Concrete Demineralized Water Dry Gas Encased in Concrete Lubricating Oil Plant Indoor Air Reactor Coolant Treated Borated Water Ventilation Atmosphere Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 6 of 8 Section 3.2 AGING MANAGEMENT OF ENGINEERED SAFETY FEATURES Table 3.2.2-1 Engineered Safety Features -Summary of Aging Management Evaluation -Safety Injection System Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item Tank PB Stainless Concrete Loss of material Inspection of Internal Surfaces of None None G, 5 Steel Miscellaneous Ducting and Piping I_ I Components (B2.1.22)G 5.Environment not in NUREG-1801 for this component and material.The Inspection of Internal Surfaces of Miscellaneous Ducting and Piping Components (B2.1.22) is used to inspect tanks in the scope of XI.M29 from the internal surface. Reference LR-ISG-2012-02, Appendix C, Line V.DI.E-402 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7D. Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 7 of 8 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS 3.3.2.1.5 Makeup Water System Environment The makeup water system components are exposed to the following environments: S S S S S S S S S S Atmosphere/ Weather Buried Concrete Demineralized Water Encased in Concrete Lubricating Oil Plant Indoor Air Potable Water Raw Water Sodium Hydroxide Sulfuric Acid Enclosure 1 Attachment 7D PG&E Letter DCL-14-103 Page 8 of 8 Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS Table 3.3.2-5 Auxiliary Systems -Summary of Aging Management Evaluation -Makeup Water System Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.Management 2 Item Tanks PB Carbon Steel Concrete Loss of material Inspection of Internal None None G, 6 Surfaces of Miscellaneous Ducting and Piping Components (82.1.22)9. The Inspection of Internal Surfaces of Miscellaneous Ducting and Piping Components (B2.1.22) is used to inspect tanks in the scope of XI.M29 from the internal surface. Reference LR-ISG-2012-02, Appendix C, Line VII.C3.A-401 and PG&E Letter DCL-14-103, Enclosure 1, Attachment 7D.}}