DCL-10-122, Response to NRC Letter Dated August 26, 2010, Request for Additional Information Set (20) for License Renewal Application
| ML102700041 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 09/22/2010 |
| From: | Becker J Pacific Gas & Electric Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| DCL-10-122 | |
| Download: ML102700041 (35) | |
Text
PacificGas and Electric Company' James R.Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601 P 0. Box 56 Avila Beach, CA 93424 September 22, 2010 805.545.3462 Internal: 691.3462 Fax: 805.545.6445 PG&E Letter DCL-10-122 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20852 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 Response to NRC Letter dated Auqust 26, 2010, Request for Additional Information (Set 20) for the Diablo Canyon License Renewal Application and LRA Errata
Dear Commissioners and Staff:
By letter dated November 23, 2009, Pacific Gas and Electric Company (PG&E) submitted an application to the U.S. Nuclear Regulatory Commission (NRC) for the renewal of Facility Operating Licenses DPR-80 and DPR-82, for Diablo Canyon Power Plant (DCPP) Units 1 and 2, respectively. The application included the license renewal application (LRA), and Applicant's Environmental Report -
Operating License Renewal Stage.
By letter dated August 26, 2010, the NRC staff requested additional information needed to continue their review of the DCPP LRA.
PG&E's responses to these requests for additional information are provided in Enclosure 1. PG&E has identified additional changes that are required in the LRA submitted in Reference 1. Descriptions of these errata changes are included in Enclosure 2. LRA Amendment 13 resulting from the responses and errata are included in Enclosure 3 showing the changed pages with line-in/line-out annotations.
PG&E makes the following commitment in LRA Table A4-1: The DCPP external surfaces monitoring program will be revised to include visual inspections of the ASW system to inspect for cracking and leakage of the titanium tubing components in scope for license renewal at intervals no longer than once per refueling cycle.
If you have any questions regarding this response, please contact Mr. Terence L. Grebel, License Renewal Project Manager, at (805) 545-4160.
A member of the STARS (Strategic Teaming and Resource Sharing) Atliance Catlaway
- Comanche Peak
- Diablo Canyon
- Palo Verde
- San Onofre
- South Texas Project
- Wotf Creek
Document Control Desk PG&E Letter DCL-10-122 September 22, 2010 Page 2 I declare under penalty of perjury that the foregoing is true and correct.
Executed on September 22, 2010.
pns/50338838 Enclosure cc: Diablo Distribution cc/enc: Elmo E. Collins, NRC Region IV Regional Administrator Nathanial Ferrer, NRC Project Manager, License Renewal Kimberly J. Green, NRC Project Manager, License Renewal Michael S. Peck, NRC Senior Resident Inspector Alan B. Wang, NRC Project Manager, Office of Nuclear Reactor Regulation A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway
- Comanche Peak
- Diablo Canyon
- Palo Verde ° San Onofre
- South Texas Project
- Wolf Creek
Enclosure 1 PG&E Letter DCL-1 0-122 Sheet 1 of 3 PG&E Response to NRC Letter dated August 26, 2010 Request for Additional Information (Set 20) for the Diablo Canyon License Renewal Application RAI B2.1.9 The "detection of aging effects" of the Open-Cycle Cooling Water System Aging Management Programin the GALL Report,Section XI.M20 indicates that the program includes inspections for detecting degradation.
The Diablo Canyon Power Plant Open-Cycle Cooling Water System includes the aging management of cracking for titanium components exposed to raw water. The Open-Cycle Cooling Water System Program describes that it will evaluate cracking found in coatings by visual inspection, but does not discuss how cracking in the titanium components is managed.
Provide additionalinformation on how cracking in titanium components will be managed by the Open-Cycle Cooling Water System Program. If visual inspection will be used, provide details on how the visual inspection will be implemented to take into considerationthe tightness of cracks that can form in titanium.
PG&E Response to RAI B2.1.9 The only titanium components in scope of license renewarare the small instrument tubing and associated valves in the auxiliary saltwater (ASW) system. These components are in scope for pressure boundary. Cracking is not likely to be induced in these components because of the low and constant operating conditions (low constant temperature sea water inside, plant indoor air outside at the intake structure, and low and constant operating pressure). Titanium is well suited for these conditions.
The first indication of cracking would be surface cracking which would be detected by visual inspections.. If surface cracking leads to leaks, such leakage would be visually detected. This leakage would not adversely affect the ability of the ASW system to provide cooling water to the component cooling water heat exchangers because the size of the instrument tubing is very small compared with the main system piping. The Diablo Canyon Power Plant external surfaces monitoring program will be revised to include visual inspections of the ASW system to inspect for cracking and leakage of the titanium tubing components in scope for license renewal at intervals no longer than once per refueling cycle. See revised License Renewal Application Table A4-1 in .
Enclosure 1 PG&E Letter DCL-10-122 Sheet 2 of 3 RAI B2.1.21-5
Background:
LRA Section A 1.21 provides the UFSAR Supplement summary descriptionfor applicant'sAMP B2.1.21, Flux Thimble Tube Inspection Program,and states in part "[t]he inspection frequency may be adjusted based upon items such as operatingexperience and recommendations from the Westinghouse Owners Group."
NRC Bulletin 88-09 permits an applicant for a Westinghouse-design PWR facility to rebaseline the inspection frequency for its flux thimble tubes based on the use of actual plant-specific wear data, which is reflected in the staff's recommended FSAR Supplement in the SRP-LR.
Issue: The staff noted that neitherNRC Bulletin 88-09 nor the SRP-LR account for the possibility that generic vendor or owner's group recommendationsmay be used as an acceptablebasis for rebaseliningthe inspection frequency for a Westinghouse plant's flux thimble tubes. The provision in UFSAR Supplement A 1.21 permitting for thimble tube inspection frequency adjustment based upon items such as operatingexperience and recommendations from the Westinghouse Owners Group does not conform to any of the "monitoringand trending"recommendations for flux thimble tube programsin NRC Bulletin 88-09, the GALL Report, or the SRP-LR.
Request: Justify why the UFSAR Supplement incorporatesa "monitoringand trending" option that would permit the applicant to use Westinghouse Ownders Group recommendations to adjust the inspection frequency criterion for the plant's flux thimble tubes. Justify this option when it does not appearto be consistent with eitherthe staff's recommendations in NRC Bulletin 88-09 or the staff's "monitoringand trending" program element recommendationsin GALL AMP XI.M37.
PG&E Response to RAI B2.1.21-5 PG&E letter DCL-1 0-096 responded to Request for Additional Information Set 8 and provided the plant licensing basis for the existing Thimble Tube Inspection Program developed in response to NRC Bulletin 88-09. PG&E letter DCL-89-280, dated November 10, 1989, indicated that PG&E had established an interim inspection frequency to be every refueling outage. This letter further noted that the inspection program will be revised as appropriate based on industry operating experience, recommendations from the Westinghouse Owners Group, or implementation of a design change to eliminate or greatly reduce thimble tube wear.
License renewal application (LRA) Sections A1.21 and B2.1.21 have been revised to clarify that the examination frequency will be based upon wear predictions that have been technically justified as providing conservative estimates of flux thimble tube wear.
The interval between inspections will be established such that no flux thimble tube is predicted to incur wear that exceeds the established acceptance criteria before the next
Enclosure 1 PG&E Letter DCL-10-122 Sheet 3 of 3 inspection. The examination frequency may be adjusted based on plant-specific wear projections. Rebaselining of the examination frequency will be justified using plant-specific wear-rate data unless prior NRC acceptance for the rebaselining was received.
If design changes are made to use more wear-resistant thimble tube materials (e.g.,
chrome-plated stainless steel), sufficient inspections will be conducted at an adequate inspection frequency, as described above, for new materials. See revised LRA Sections A1.21 and B2.1.21 in Enclosure 3.
PG&E Letter DCL-10-122 Page 1 of 2 PG&E Errata Below is a table of errata identified in the License Renewal Application. The associated changed pages are included in Enclosure 3.
Errata No Section or Table LRA Revision 1 Section 2.3.3.5 Add "turbine building" to the system intended function to indicate a location for potential (a)(2) effects.
2 Section 3.3.2.1.5 Add "polyvinyl chloride" to the list of materials of construction for the makeup water system.
3 Section 3.3.2.1.17 Remove "Lubricating Oil Analysis aging management program from the list of applicable AMPs for the liquid radwaste system 4 Section 3.3.2.1.19 Add "Stainless Steel" to materials of construction.
5 Section 3.3.2.2.7.1 Revised Further Evaluation to discuss treatment for RCP oil.collection components exposed to lubricating oil 6 Section 3.4.2.1.3 Add "wall thinning" as an aging effect requiring management and "Flow Accelerated Corrosion (B2.1.6)" as an aging management program to -
manage the aging effects for the feedwater system.
7 Section 3.4.2.2.8 Revised Further Evaluation to change the "Not applicable" to the conclusion consistent with LRA Table 3.4.1, Item 3.4.1.19.
8 Table 2.3.3-5 Add "eye wash sink" as a new component type for the makeup water system. Add "Structural Integrity (attached)" as an intended function for the "Tubing" component.
9 Table 2.3.3-8 Add "Structural Integrity (attached)" to the pum component type.
10 Table 31.2-2 Change the environments for the "heat exchanger (RCP Seal Cooler)".
11 Table 3.3.1 Revised line 3.3.1.68 to discuss treatment of traps exposed to raw water in the makeup water system.
PG&E Letter DCL-10-122 Page 2 of 2 Errata No Section or Table LRA Revision 12 Table 3.3.2-5 Add rows for the "eye wash sink" components, add rows for "piping", "trap" and "valve" components, and revise intended functions for "valve" and "tubing" components. Add standard note E and plant specific note 5.
13 Table 3.3.2-8 Add "Structural Integrity (attached)" to the "pump" component type. Changed standard note on a row for "heat exchanger (centrifugal charging)".
14 Table 3.3.2-11 Removed a row for the "'heat exchanger (Access Control HVAC)" component.
15 Table 3.3.2-17 Changed the standard note for a "flame arrestor" component, and changed the NUREG-1801 Vol.2 Item and Table 1 Item for a "piping" row.
16 Table 3.3.2-19 Change the material of closure bolting from "Copper Alloy" to "Stainless Steel". Change the material of pump from "Carbon Steel" to "Cast Iron" 17 Table 3.4.2-3 Add rows for "flow element", "heat exchanger (feedwater heater)", "piping", and "valve" components. Changed the standard note on a "heat exchanger (feedwater heater)"
component.
18 Appendix B2.1.8 Revise the OE section to indicate that the material on the new steam generators is "more resistant" to corrosion.
19 Appendix B2.1.9 Added detail to the CCW heat exchanger inspections description 20 Appendix B2.1.30 Revised the OE section to correct some of the I I - test results data.
PG&E Letter DCL-10-122 Page 1 of 28 LRA Amendment 13 LRA Section RAI Section 2.3.3.5 Errata 1 Section 3.3.2.1.5 Errata 2 Section 3.3.2.1.17 Errata 3 Section 3.3.2.1.19 Errata 4 Section 3.3.2.2.7.1 Errata 5 Section 3.4.2.1.3 Errata 6 Section 3.4.2.2.8 Errata 7 Table 2.3.3-5 Errata 8 Table 2.3.3-8 Errata 9 Table 3.1.2-2 Errata 10 Table 3.3.1 Errata 11 Table 3.3.2-5 Errata 12 Table 3.3.2-8 Errata 13 Table 3.3.2-11 Errata 14 Table 3.3.2-17 Errata 15 Table 3.3.2-19 Errata 16 Table 3.4.2-3 Errata 17 Table A4-1 2.1.9 Appendix A1.21 2.1.21-5 Appendix B2.1.8 Errata 18 Appendix B2.1.9 Errata 19 Appendix B2.1.21 2.1.21-5 Appendix B2.1.30 Errata 20 Section 2.3 PG&E Letter DCL-10-122 SCOPING AND SCREENING RESULTS:
Page 2 of 28 MECHANICAL SYSTEMS 2.3.3.5 Makeup Water System System Intended Functions The makeup water system supplies demineralized water to various primary and secondary plant systems. The safety-related portions of the system include the makeup water piping to the auxiliary feedwater system, component cooling water system, spent fuel pool cooling system and fire protection system. Therefore, the makeup water system is within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1).
Portions of the makeup water system located in the turbine, fuel handling and auxiliary buildings have the potential for spatial interaction and as nonsafety affecting safety-related components. Portions of the makeup water system may be used to provide water for long term cooling. Therefore, portions of the system are within scope of license renewal based on the criterion of 10 CFR 54.4(a)(2).
Portions of the makeup water system support fire protection and SBO requirements and are within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(3).
Section 3.3 PG&E Letter DCL-1 0-122 AGING MANAGEMENT OF Page 3 of 28 AUXILIARY SYSTEMS 3.3.2.1.5 Makeup Water System Materials The materials of construction for the makeup water system component types are:
Section 3.3 PG&E Letter DCL-1 0-122 AGING MANAGEMENT OF Page 4 of 28 AUXILIARY SYSTEMS 3.3.2.1.17 Liquid Radwaste System Aging Management Programs The following aging management programs manage the aging effects for the liquid radwaste system component types:
ILubrc*ating goi A*alysi, (132.1.23)
Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF Page 5 of 28 AUXILIARY SYSTEMS 3.3.2.1.19 Oily Water and Turbine Sump System Materials The materials of construction for the oily water and turbine sump system component types are:
0 Stainless Steel Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF Page 6 of 28 AUXILIARY SYSTEMS 3.3.2.2.7.1 Steel Stainless piping and components in the reactor coolant pump oil collection system exposed to lubricating oil The Lubricating Oil Analysis Program(B2.1.23) and the One-Time Inspection program (B2.1.16) will not be used to manage loss of materialdue to general, pitting, crevice, and microbiologicallyinfluenced corrosion and fouling for reactor coolant pump oil collection system carbon steel components exposed to waste lubricatingoil. Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) is credited for reactorcoolant pump oil collection system components exposed to waste lubricatingoil.Tho Lb*ricat;ng Oil Analysis program (B2.1.23) and the One Time In~spoction program (132.1.16) mnanages los6 of material due to general, pitting, and cr*e*v e corrs*i6* for Steel (includig*
galvanized) oxposod to lubricating oil. The- ono tio insect inlues elted compononts at susleptible locatioens whore contaminants SUch as water co4u-l aGGUnumlte.
Section 3.4 PG&E Letter DCL-10-122 AGING MANAGEMENT OF STEAM AND Page 7 of 28 POWER CONVERSION SYSTEM 3.4.2.1.3 Feedwater System Aging Effects Requiring Management The following feedwater system aging effects require management:
0 Wall thinning Aging Management Programs The following aging management programs manage the aging effects for the feedwater system component types:
0 Flow-Accelerated Corrosion (B2.1.6)
Section 3.4 PG&E Letter DCL-1 0-122 AGING MANAGEMENT OF STEAM AND Page 8 of 28 POWER CONVERSION SYSTEM 3.4.2.2.8 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced Corrosion The Lubricating Oil Analysis Program (B2.1.23) and the One-Time Inspection Program (B2.1.16) will manage loss of material due to pitting, crevice corrosion, and MIC for stainless steel components exposed to lubricatingoil. The one-time inspection will include selected components at susceptible locations where contaminantssuch as water could accumulate.Not app,,,ablo. DCPP .han .in
.. OPo stainoss steel cOponontS exposed to ,ub, ail in the stoam and power conVorSion syctems. so the aaalicabiC NUREG 1801 lin9o Woro not used.
Enclosure 3 Section 2.3 PG&E Letter DCL-10-122 SCOPING AND SCREENING RESULTS:
Page 9 of 28 MECHANICAL SYSTEMS Table 2.3.3-5 Makeup Water System Component Type I Intended Function I Eye Wash Sink Leakage Boundary (spatial)
Tubing Leakage Boundary (spatial)
Pressure Boundary Structural Integrity (attached)
Section 2.3 PG&E Letter DCL-1 0-122 SCOPING AND SCREENING RESULTS:
Page 10 of 28 MECHANICAL SYSTEMS Table 2.3.3-8 Chemical and Volume Control System Component Type Intended Function Pump Leakage Boundary (spatial)
Pressure Boundary StructuralIntegrity (attached)
Section 3.1 PG&E Letter DCL-10-122 AGING MANAGEMENT OF REACTOR VESSEL Page 11 of 28 INTERNALS, AND REACTOR COOLANT SYSTEM Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation-Reactor Coolant System Component Intended Material Environment Aging a Effect Aging Management NUREG- Table 1I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 2Item Heat HT, PB Stainless Closed Cycle Loss of material Closed-Cycle Cooling V.A-7 3.2.1.28 B Exchanger Steel Cooling Water Water System (B2.1.10)
(RCP Seal (E-tlnt)
Cooler)
Heat HT, PB Stainless Closed Cycle Reduction of heat Closed-Cycle Cooling V.D1-9 3.2.1.30 B Exchanger Steel Cooling Water transfer Water System (B2.1.10)
(RCP Seal (E-xint)
Cooler)
Heat HT, PB Stainless Treated Borated Loss of material Water Chemistry PG2. 3.4,833.2.1 E, 3 Exchanger Steel Water (B2.1.2) and One-Time 4-5V.D1-30 .49 (RCP Seal (Ext)ReaGtO.- Inspection (B2.1.16)
Cooler) ..... t"" \ ,)
Heat HT, PB Stainless Treated Borated Cracking Water Chemistry l1.C2~ 3.-1..63.2.1 GE, 3 Exchanger Steel Water (B2.1.2) and One-Time 5V. Dl.31 .48 (RCP Seal (Ext)ReaGtor- Inspection Cooler) Geelat(It (82.1.16)ASME Section Xll InsorVIo WInspocionVIV Subsections IWB, IWC, and IWD for Class 1 components, (B21 .1) and Water Chemi~stry (132..
Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 12 of 28 Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG- 1801 for A uxiliary Systems Item Component Type Aging Effect I Mechanism Aging Management Further Discussion Number Program Evaluation I JRecommended 3.3.1.68 Steel oipina, DiDinf Loss of material due to Fire Water System (B2.1.13)
-- -- -- j ..... * .... /
No
Consistent with NUREG-components, and general, pitting, crevice, and 1801 for all components piping elements microbiologically influenced except that a different aging exposed to raw water corrosion, and fouling management programis credited for traps exposed to the raw water environment in the makeup watersystem.
The aging of trap internal component surfaces exposed to the raw water environment in the makeup water system will be managed by Inspection Of InternalSurfaces In MiscellaneousPiping And Ducting Components (B2.1.22).Consiteont with-NUREG 1801 with aging management prFoFram The aging mannagement program(s) with oXveptionn to NUREG 1801 include.: Fir Water System (B2.1.13)
Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 13 of 28 Table 3.3.2-5 Auxiliary Systems - Summary of Aging Management Evaluation - Makeup Water System
]
Component Type 1 Intended Function
_____
Material
__
Pl1
__
Environment
__
1 Aging Effect Requiring Management]1 N
Aging Management Program NUREG-1801 Vol.
2 Item Table I Item Notes Eye Wash Sink ILBS Polyvinyl Plant Indoor Air 'None None None None F Chloride (Ext)
(PVC)
Eye Wash Sink LBS Polyvinyl Plant IndoorAir None None None None F Chloride (Int)
(PVC)
Piping PB Carbon Steel Atmosphere! Loss of material Inspection of Internal VIII.B1-6 3.4.1.30 B Weather (Int) Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Piping PB Carbon Steel Buried (Ext) Loss of material Buried Pipingand Tanks VII. G-25 3.3.1.19 B Inspection (B2.1.18)
Piping LBS CopperAlloy Potable Water (Int) Loss of material Inspection of Internal None None G Surfaces in Miscellaneous Piping and Ducting Components (B2. 1.22)
Trap LBS, PB Cast Iron Atmesphere/L Loss of material Selective Leaching of VII. G- 3.3.1.853734 AB (Gray Cast Weathe Buried Materials 15V4I-9 Iron) (Ext) (B2.1.17)r-xternal Surfarces Monitoring Progr-am (B32. .20)
Trap LBS, PB Cast Iron Buried (Ext) Loss of material Buried Piping and Tanks VII. G-25 3.3.1.19 B (Gray Cast Inspection (B2.1.18)
Iron)
Trap LBS, PB Cast Iron Raw Water (Int) Loss of material Selective Leaching of VII.G- 3.3.1.853-34 AB (Gray Cast Materials(B2.1.17)F4-ie- 14,,V.G 24 M8 Iron) Water System (B2.1.13)
Section 3.3 PG&E Letter DCL-1 0-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 14 of 28 Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Trap LBS, PB Cast Iron Raw Water (Int) Loss of material Inspection of Internal VII.G-24 3.3.1.68 E, 5 (Gray Cast Surfaces in Iron) Miscellaneous Piping and Ducting Components (B2.1.22)
Tubing LBS, PB, Stainless Demineralized Loss of material Water Chemistry VIII.E-29 3.4.1.16 A SIA Steel Water (Int) (B2.1.2) and One-Time Inspection (B2.1.16)
Tubing LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A SIA Steel (Ext)
Valve LBS, PB, Carbon Steel Demineralized Loss of material Water Chemistry VIII.E-34 3.4.1.04 A SIA Water (Int) (B2.1.2) and One-Time Inspection (B2.1.16)
Valve LBS, PB, Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B SIA (Ext) Monitoring Program (B2.1.20)
Valve LBS, PB Cast Iron Demineralized Loss of material Selective Leaching of VII.C2-9 3.3.1.85 A (Gray Cast Water (Int) Materials (B2.1.17)
Iron)
Valve LBS, PB Cast Iron Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B (Gray Cast (Ext) Monitoring Program Iron) (B2.11.20)
Valve LBS, PB Cast Iron Raw Water (Int) Loss of material Selective Leaching of VII.G-14 3.3.1.85 A (Gray Cast Materials (B2.1.17)
Iron)
Valve LBS, PB Cast Iron Raw Water (Int) Loss of material Fire Water System VII.G-24 3.3.1.68 B (Gray Cast (B2.1.13)
Iron)
Valve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A SIA Steel (Ext)
Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 15 of 28 Component Intended Material Environment Aging Effect Aging Management NUREG- Table Item I Notes Type Function Requiring Program 11801 Vol. Item]
_____ _____ _____ Management* __ __ _ ItemJJ Valve LBS Stainless Potable Water C/nt) Loss of material Inspection of Internal None None G Steel Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Notes for Table 3.3.2-5:
Standard Notes:
E Consistent with NUREG-1801 for material,environment, and aging effect, but a different aging management programis credited or NUREG-1801 identifies a plant-specific aging management program.
Plant Specific Notes:
5 NUREG-1801 recommends that the aging of this component, with an internal environment of raw water, be managedby "FireWater System" (B2.1.13). The aging management of the internalsurfaces exposed to raw water for this component would best be managed by "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"(B2.1.22).
Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 16 of 28 Aging Management Evaluation- Chemicaland Volume Control System Aging Effect Aging Management Program NUREG- Table I Notes Requiring 1801 Vol. Item Management 2 Item Heat HT, PB Copper Closed Cycle Loss of material Closed-Cycle Cooling Water VII.E1-2 3.3.1.51 BD Exchanger Alloy (> Cooling Water System (B2.1.10)
(Centrifugal 15% Zinc) (Int)
Charging)
Pump LBS, PB, Carbon Borated Water Loss of material Boric Acid Corrosion (B2.1.4) VII.E1-1 3.3.1.89 A SIA Steel with Leakage (Ext)
Stainless Steel Cladding Pump LBS, PB, Carbon Treated Borated Loss of material Water Chemistry (B2.1.2) and VII.El-17 3.3.1.91 E, 5 SIA Steel with Water (Int) One-Time Inspection (B2.1.16)
Stainless Steel Cladding Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 17 of 28 iHeat- LBS Gesfor [HVAb)
Notes for Tabie 3.3.2-11:
Plant Specific Notes:
4 This NUREG 1801 line is usod to ev3luate duc :tingqi IOS,-er belting.ExternalSurfaces Monitoring Program(B2.1.20) is used to manage the loss of materialfor the ducting closure bolting.
Enclosure 3 Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 18 of 28 Table 3.3.2-17 Auxiliary Systems - Summary of Aging Management Evaluation - Liquid Radwaste System Component Type Intended Function Material Environment 1 Aging Effect Requiring Management Aging Management Program NUREG- Table 1 Item 1801 Vol.
2 Item Notes Flame Arrestor PB Carbon Steel Plant Indoor Air Loss of material Inspection of Internal VII.G-23 3.3.1.71 E-,-7B (Int) Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
I Piping PB Carbon Steel Lubricating Oil (Int) Loss of material Inspection of Internal VII.G-2622 3.3.1.15-14 E, 7 (Galvanized) Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Enclosure 3 Section 3.3 PG&E Letter DCL-10-122 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 19 of 28 Table 3.3.2-19 Auxiliary Systems - Summary of Aging Management Evaluation- Oily Water and Turbine Sumj Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Type Function Requiring Program 1801 Vol.
I Manaaement
- , 2 Item Closur*e Bolting LBS Ceppe- Plant Indoor Air Loss of preload Bolting Integrity (B2.1.7) None AlloyStainles (Ext) s Steel Pump LBS GaFbGR Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B SteelCast (Ext) Monitoring Program Iron (B2.1.20)
Pump LBS Raw Water (Int) Loss of material Inspection of Internal VII.C1 -19 3.3.1.76 E, 2 SteelCast Surfaces in Iron Miscellaneous Piping and Ducting Components (B2.1.22)
Section 3.4 PG&E Letter DCL-10-122 AGING MANAGEMENT OF STEAM AND Page 20 of 28 POWER CONVERSION SYSTEMS Table 3.4.2-3 Steam and Power Conversion System - Summary of Aging Management Evaluation- Feedwater Svstem Component Intended Material Environment Aging Effect Aging Management Type Function Requiring Program Management Flow Element LBS, PB, Carbon Steel Secondary Water Wall thinning Flow-Accelerated TH (Int) Corrosion(B2.1.6)
Heat LBS, SIA Carbon Steel Secondary Water Loss of material Water Chemistry VIII.D1-8 3.4.1.04 CA Exchanger (Int) (B2.1.2) and One-Time (Feedwater Inspection (B2.1.16)
Heater)
Heat LBS, SIA Carbon Steel Secondary Water Wall thinning Flow-Accelerated VIII.D1-9 3.4.1.29 D Exchanger (Int) Corrosion(B2.1.6)
(Feedwater Heater)
Piping LBS, PB, Carbon Steel Secondary Water Wall thinning Flow-Accelerated VIII.D1-9 3.4.1.29 B SIA (Int) Corrosion(B2.1.6)
Valve LBS, PB, Carbon Steel Secondary Water Wall thinning Flow-Accelerated VIII.D1-9 3.4.1.29 B SIA (Int) Corrosion(B2.1.6)
TABLE A4-1 PG&E Letter DCL-1 0-122 LICENSE RENEWAL COMMITMENTS Page 21 of 28 Table A4-1 License Renewal Commitments Item # Commitment LRA Implementation Section Schedule 37 The DCPPexternal surfaces monitoringprogram will be revised to include B2.1.20 Prior to the period visual inspections of the ASW system to inspect for cracking and leakage of of extended the titanium tubing components in scope for license renewal at intervals no operation longer than once per refueling cycle. I Appendix A PG&E Letter DCL-1 0-122 Final Safety Analysis Report Supplement Page 22 of 28 The Flux Thimble A1.21 Flux Thimble Tube Inspection Tube Inspection program manages loss of material by performing wall thickness eddy current testing of all flux thimble tubes that form part of the reactor coolant system pressure boundary. The pressure boundary includes the length of the thimble tube inside the reactor vessel out to the seal fittings outside the reactor vessel. Eddy current testing is performed on the portion of the tubes inside the reactor vessel. The program implements the recommendations of NRC Bulletin 88-09, Thimble Tube Thinning in Westinghouse Reactors.
All flux thimble tubes are currently inspected during each refueling outage. Wall thickness measurements are trended and wear rates are calculated. If the current measured wear exceeds the acceptance criteria or the predicted wear (as a measure of percent through wall) for a given flux thimble tube is projected to exceed the established acceptance criteria for wall thickness prior to the next refueling outage, corrective actions are taken to reposition, cap, or replace the thimble tube. The examination frequency will be based upon wearpredictions that have been technicallyjustified as providing conservative estimates of flux thimble tube wear. The interval between inspections will be established such that no flux thimble tube is predicted to incur wear that exceeds the established acceptance criteria before the next inspection. The examination frequency may be adjusted based on plant-specific wearprojections. Re-baseining of the examination frequency will be justified using plant-specific wear-rate data unless priorNRC acceptance for the re-baseliningwas received. If design changes are made to use more wear-resistantthimble tube materials(e.g., chrome-plated stainless steel) sufficient inspections will be conducted at an adequate inspection frequency, as describedabove, for new materials.
Appendix B PG&E Letter DCL-10-122 AGING MANAGEMENT PROGRAMS Page 23 of 28 B2.1.8 Steam Generator Tube Integrity Operating Experience The Steam Generator Tube Integrity program tube inspection requirements are consistent with NEI 97-06. The program benefits from the industry operating experience available when the initiative was issued as well as the EPRI guidelines it endorses.
NRC Information Notice 97-88, Experiences During Recent Steam Generator Inspections addressed the importance of recognizing the potential for degradation in areas that have not previously experienced tube degradation and the importance of licensees to assess the significance of indications with respect to the qualification of the inspection techniques and the manner in which the indications were detected. The DCPP steam generator Degradation Assessment evaluates industry experience as well as DCPP experience to identify active, relevant and potential tube damage mechanisms. Some of the important features of the Degradation Assessment include:
choosing techniques to test for degradation based on the probability of detection and sizing capability, establishing the number of tubes to be inspected, establishing the structural limits, establishing the flaw growth rate or a plan to establish the flaw growth rate.
DCPP has replaced all four steam generators in each unit with Westinghouse Model Delta 54 steam generators, which contain Alloy 690 thermally treated tubes. The replacements took place during 2R14 in February 2008 for Unit 2 and 1 R15 in February 2009 for Unit 1. A review of industry operating experience indicates that there have been no reported instances of cracking in thermally-treated Alloy 690 tubes at any U.S.
plant. All degradation indications to date are from wear (fretting) due to loose parts, tube supports, anti-vibration bars, and manufacturing or handling anomalies. The tubing and secondary internals in these units are -',, ,SuiGeph
~more resistantto corrosion due to advanced material design.
The DCPP operating experience findings for this program identified no unique plant specific operating experience; therefore DCPP operating experience is consistent with NUREG-1801. As additional Industry and applicable plant-specific operating experience become available, the Operating Experience (OE) will be evaluated and appropriately incorporated into the program through the DCPP Corrective Action and Operating Experience Programs. This ongoing review of OE will continue throughout the period of extended operation, and the results will be maintained on site. This process will confirm the effectiveness of this license renewal aging management program by incorporating applicable OE and performing self assessments of the program.
Appendix B PG&E Letter DCL-1 0-122 AGING MANAGEMENT PROGRAMS Page 24 of 28 B2.1.9 Open-Cycle Cooling Water System Program Description The Open-Cycle Cooling Water (OCCW) System program manages cracking, loss of material, and reduction of heat transfer for components exposed to the raw water of the DCPP OCCW system. The DCPP OCCW system is the auxiliary saltwater (ASW) system.
Components within the scope of the OCCW System program are components of the ASW system and the component cooling water (CCW) heat exchangers that are cooled by the ASW system.
The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in components of the ASW system or structures and components serviced by the ASW system that are within the scope of license renewal. The program also includes periodic visual inspections and non-destructive examinations to detect biofouling, defective coatings and degraded piping and components of, systems and components, and CCW heat exchanger performance testing, to ensure that the effects of aging on components are adequately managed for the period of extended operation. The program is consistent with DCPP commitments established in responses to NRC Generic Letter 89-13, Service Water System ProblemsAffecting Safety-Related Components.
The ASW pump bays are inspected and cleaned once per refueling cycle by divers.
Coatings for equipment in the Intake Structure area are inspected annually. The inspection specifically addresses blistering, cracking, peeling, and rust penetration of coatings. Coatings are not credited in aging management; however, inspection of coating integrity provides a leading indicator of the integrity of the underlying material.
Visual examinations of the ASW System piping are performed every fourth refueling outage to inspect the integrity of the plastic pipe liner and detect indications of corrosion of the base piping material. The extent and type of biofouling observed in the pipe is also evaluated. Periodic performance testing of the CCW heat exchangers is performed prior to each refueling outage to verify their heat transfer capability. Test results are documented, and trended for heat removal capabilities. The CCW heat exchangers are inspected and cleaned during each refueling outage during which time the inlet and outlet waterbox coatings are inspected. Frequencyand percentage of,-and eddy current inspections of the tubes are determined by a documented engineering assessmentpe4eRre4. The acceptance criteria for these activities are specified as appropriate in plant procedures.
The OCCW System program relies on appropriate materials, chemical treatment, flushing and cleaning of system components to mitigate loss of material and fouling in the OCCW system.
Appendix B PG&E Letter DCL-10-122 AGING MANAGEMENT PROGRAMS Page 25 of 28 B2.1.21 Flux Thimble Tube Inspection Program Description The Flux Thimble Tube Inspection program manages loss of material by performing wall thickness eddy current testing of all flux thimble tubes that form part of the reactor coolant system pressure boundary. The pressure boundary includes the length of the tube inside the reactor vessel out to the seal fittings outside the reactor vessel. Eddy current testing is performed on the portion of the tubes inside the reactor vessel. The Flux Thimble Tube Inspection program does not prevent degradation due to aging effects but provides measures for inspection and evaluation to detect the degradation prior to loss of intended function. The program implements the recommendations of NRC Bulletin 88-09, Thimble Tube Thinning in Westinghouse Reactors.
All flux thimble tubes are currently inspected during each refueling outage. Wall thickness measurements are trended and wear rates are calculated. If the current measured wear exceeds the acceptance criteria or the predicted wear (as a measure of percent through wall) for a given flux thimble tube is projected to exceed the established acceptance criteria for wall thickness prior to the next refueling outage, corrective actions are taken to reposition, cap, or replace the tube. Program documentation maintains details regarding the core location, wear location, and the number of times a tube has been previously repositioned or replaced. Any thimble tube exhibiting an abnormally high wear rate is capped or replaced. Design changes are also implemented to use more wear-resistant thimble tube materials (e.g., chrome-plated stainless steel). the examination frequency will be based upon wear predictions that have been technically justified as providing conservative estimates of flux thimble tube wear. The interval between inspections will be established such that no flux thimble tube is predicted to incur wear that exceeds the established acceptance criteria before the next inspection. The examination frequency may be adjusted based on plant-specific wear projections. Re-baselining of the examination frequency will be justified using plant-specific wear-rate data unless priorNRC acceptance for the re-baselining was received. If design changes are made to use more wear-resistantthimble tube materials (e.g., chrome-plated stainless steel) sufficient inspections will be conducted at an adequate inspection frequency, as described above, for new materials.
NUREG-1801 Consistency The Flux Thimble Tube Inspection program is an existing program that is consistent with NUREG-1 801,Section XI.M37, Flux Thimble Tube Inspection.
Exceptions to NUREG-1801 None Appendix B PG&E Letter DCL-1 0-122 AGING MANAGEMENT PROGRAMS Page 26 of 28 Enhancements None Operating Experience In response to NRC Bulletin 88-09, DCPP implemented a flux thimble tube inspection program. Compliance with this inspection program and implemented corrective actions shows that current testing and inspections are effectively managing aging effects of the flux thimble tubes.
A review of the results of these inspections shows that some flux thimble tube loss of material has been identified in each inspection campaign. The DCPP operating experience findings for this program identified no unique plant specific operating experience; therefore DCPP operating experience is consistent with NUREG-1801.
Corrective actions taken at DCPP in response to the results of the inspections have included repositioning 32 thimble tubes, capping six thimble tubes, and replacing 36 thimble tubes. In 2006, a thimble tube in DCPP Unit 2 had a through-wall failure. After the failure, the DCPP Thimble Tube Inspection program was revised to add additional actions to prevent a recurrence of this event. These actions include (1) cap or replace a thimble tube which exhibits a wear rate greater than 25 percent/year, (2) cap or replace a thimble tube which has two wear scars greater than 40 percent through-wall and (3) cap or isolate a thimble tube which is chrome plated and has been repositioned greater than eight inches. These actions have been effective in preventing any new through-wall failures since.
Based on corrective actions taken to identify aging issues discussed above, the Flux Thimble Tube Inspection program is effective at managing loss of material of the flux thimble tubes. The Flux Thimble Tube Inspection program operating experience information provides objective evidence to support the conclusion that the effects of aging will be adequately managed so that the component intended functions will be maintained during the period of extended operation.
Conclusion The continued implementation of the Flux Thimble Tube Inspection program provides 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.
Appendix B PG&E Letter DCL-1 0-122 AGING MANAGEMENT PROGRAMS Page 27 of 28 B2.1.30 10 CFR Part 50, Appendix J Operating Experience The 10 CFR Part 50, Appendix J program performs containment leak rate tests in accordance with DCPP Technical Specification 5.5.16, Containment Leakage Rate Testing Program. A review of 10 years of operating experience has confirmed that the overall leakage total remains within established DCPP Technical Specification limits, well below the acceptance criteria. Individual valves on occasion exceed the leakage acceptance test values and repairs are made in accordance with the program.
The most recent Appendix J test results for both Units are shown below. These results are consistent with results from the past several outages with no negative trends identified.
Most recent test results for Unit 1:
Date of last Type A test: March 17, 2009 As-Found Leakage: O.37950.03798 percent weight per day (%wt/day) (at 95 percent upper confidence limit)
As-Left Leakage: 0.03573 %wt/day (at 95 percent upper confidence limit)
The allowable As-Found limit for Type A test leakage is 0.1 %wt/day Last type B and C test: 15th refueling outage Total Leakage Rate: 76.49975.875 Ibm/Day The allowable limit for the As-Left maximum path Type B and C combined leakage is 455.4 Ibm/day Most recent test results for Unit 2:
Date of Last Type A Test: April 4, 2008 As-Found Leakage: 0.0193 %wt/day (at 95 percent upper confidence limit)
As-Left Leakage: 0.0171 %wt/day (at 95 percent upper confidence limit)
The allowable As-Found limit for Type A test leakage is 0.1 %wt/day Appendix B PG&E Letter DCL-10-122 AGING MANAGEMENT PROGRAMS Page 28 of 28 Date of last type B and C test: 14th refueling outage Total Leakage Rate: 71.33-322 Ibm/day The allowable limit for the As-Left maximum path Type B and C combined leakage is 455.4 Ibm/day The allowable As-Found limit for Type A test leakage is 0.1 %wt/day and the latest results are well below 50 percent of this allowable limit. Type A As-Found leakage test data in %wt/day is as follows: 0.068 %wt/day in 1991 and 0.060 %wt/day in 1994 for Unit 1 and 0.053 %wt/day in 1990, 0.048 %wt/day in 1993 and 0.0193 %wt/day in 2008 for Unit 2.
The allowable limit for the As-Left maximum path Type B and C combined leakage is 455.4 Ibm/day and the latest results represent approximately 16 percent of this value.
Type B and C leakage test data in pounds-mass per day (Ibm/day) is as follows: 56.940 Ibm/day in 2004, 66.94267.172 Ibm/day in 2007, and 7.44975.875 Ibm/day in 2009 for Unit 1 and 65.660 Ibm/day in 2004, 69.770 Ibm/day in 2006, and 74.33271.322 Ibm/day in 2008 for Unit 2.
Type B and C tests are conducted at 24, 30, 60, or 120 month intervals for the penetrations tested. The results of the individual Type B and Type C tests are combined and the total combined leakage is updated after each refueling outage. The Type B and C combined As-Left leakage rate, MXPLR (max path leak rate), acceptance criterion is 0.6 La.