ML110270135
| ML110270135 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 01/20/2011 |
| From: | Gambhir S Energy Northwest |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| G02-11-018 | |
| Download: ML110270135 (53) | |
Text
Sudesh K.
ENJERGY Vice President, Engineering P.O. Box 968, Mail Drop PE04.
NORTHW EST Richland, WA 99352-0968 Ph. 509-377-8313 F. 509-377-2354 sgambhir@energy-northwest.com January 20, 2011 G02-11-018 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001
Subject:
COLUMBIA GENERATING STATION, DOCKET NO. 50-397 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION
References:
- 1) Letter, G02-10-11, dated January 19, 2010, WS Oxenford (Energy Northwest) to NRC, "License Renewal Application"
- 2) Letter dated December 3, 2010, NRC to SK Gambhir (Energy Northwest), "Request for Additional Information for the Review of the Columbia Generating Station, License Renewal Application," (ADAMS Accession No. ML103260155)
Dear Sir or Madam:
By Reference 1, Energy Northwest requested the renewal of the Columbia Generating Station (Columbia) operating license. Via Reference 2, the Nuclear Regulatory Commission (NRC) requested additional information related to the Energy Northwest submittal.
Transmitted herewith in the Attachment is the Energy Northwest response to the Request for Additional Information (RAI) contained in Reference 2. Enclosure 1 contains Amendment 23 to the Columbia License Renewal Application. No new commitments are included in this response.
If you have any questions or require additional information, please contact Abbas Mostala at (509) 377-4197.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 2 of 2 I declare under penalty of perjury that the foregoing is true and correct. Executed on the date of this letter.
JReectful ly, ambhir Vice President, Engineering
Attachment:
Response to Request for Additional Information
Enclosure:
License Renewal Application Amendment 23 cc:
NRC Region IV Administrator NRC NRR Project Manager NRC Senior Resident Inspector/988C EFSEC Manager RN Sherman - BPA/1399 WA Horin - Winston & Strawn EH Gettys - NRC NRR (w/a)
BE Holian - NRC NRR RR Cowley - WDOH
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 1 of 9 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION "Request for Additional Information for the Review of the Columbia Generating Station, License Renewal Application,"
(ADAMS Accession No. ML103260155)
Omesh RAI 3.1.2.2.1-01
Background:
In LRA Table 3.1.1, in addition to the fatigue assessment of pressure vessel support skirt and attachment welds, the applicant used Item 3.1.1-01 for the pressure boundary bolting exposed to air. The applicant added that the effect of cracking due to fatigue of pressure boundary bolting is managed by the Bolting Integrity Program. The staff noted that there are two rows: LRA Table 3.1.2-1 Row 320 and LRA Table 3.1.2-3 Row 8, which are associated with Table 3.1.1 Item 3.1.1-01. Both rows represent pressure boundary steel bolting exposed to uncontrolled indoor air, and the aging effect of cracking due to fatigue is managed by the Bolting Integrity Program. Also, both rows cite generic note E, indicating that the material, environment, and aging effect is consistent with the GALL Report but a different aging management program is credited.
Issue:
GALL Report Vol. 1, Table 1, Line ID 1, specifically relates a fatigue TLAA to managing the aging effect of fatigue. The staff noted that the Fatigue Monitoring Program is the aging management method recommended under the GALL Report item to manage the aging effect of metal fatigue, and any other option such as a comprehensive inspection needs to be evaluated on a case-by-case basis.
It is not clear to the staff which closure bolting is represented in the LRA line items, Row Numbers 320 and 8. These two rows included in the LRA indicate that cracking due to fatigue will be managed by the Bolting Integrity Program. It is not clear to the staff if the cited generic note E is appropriate as the GALL Report Vol. 1, Table 1, Line IDs 1 and 4 specifically recommend fatigue TLAA to manage aging effect of fatigue.
The staff also reviewed LRA Section 4.3 and noted that a TLAA associated with pressure boundary bolting was not specifically identified. The staff further noted that LRA Section 4.3 does not address a disposition of TLAA in accordance with 10 CFR 54.21 (c)(1 )(iii), that the effects of aging will be managed by the Bolting Integrity Program.
Furthermore, the staff noted that air-indoor uncontrolled is listed in the "Environment" column for Rows 324 and 312 of LRA Table 3.1.2-1 and both rows cite GALL Report Item IV.A 1-7 in the "NUREG-1801 Volume 2 Item" column. However, the staff noted that reactor coolant is listed in "Environment" for the GALL Report Item IV.A1 -7.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 2 of 9 Request:
(1) Clarify what specific bolting in the reactor pressure vessel and reactor coolant pressure boundary are represented in Table 3.1.2-1 Row 320 and Table 3.1.2-3 Row 8, respectively.
(2) Clarify and justify how the cracking due to fatigue of pressure boundary bolting can be adequately managed by the Bolting Integrity Program. This justification, at a minimum, should include a demonstration that the Bolting Integrity Program is effective to manage fatigue cracking of metal bolts of the reactor coolant pressure boundary caused by anticipated cyclic strains in the material. Justify that'generic note E is appropriate for both Row 320 of Table 3.1.2-1 and Row 8 of Table 3.1.2-3.
(3) Justify why a TLAA in LRA Section 4.3 associated with closure bolting does not need to be identified and why LRA Section 4.3 does not need to address a TLAA disposition, in accordance with 10 CFR 54.21 (c)(1)(iii), that the effects of aging will be managed by the Bolting Integrity Program is not required.
(4) Justify that generic note A is appropriate for both AMR line items, Rows 324 and 312 of Table 3.1.2-1, which cite GALL Report Vol.2 Item IV.A 1-7, but designated air-indoor uncontrolled as the environment.
Energy Northwest Response:
(1) The bolting included in Table 3.1.2-1 Row 320 is the studs and nuts used to attach the three nozzles on the reactor vessel head, and the capscrews and washers between the Control Rod Drive (CRD) mechanisms and the CRD housings, the incore dry tubes and the incore housings, and between the power range monitors and the incore housings, as explained in LRA Section 2.3.1.1, page 2.3-5.
The bolting included in Table 3.1.2-3 Row 8 is pressure retaining bolting (i.e. valve closure bolting, pump closure bolting, flange bolting) in the Class 1 portions of the following systems: Control Rod Drive, High Pressure Core Spray, Low Pressure Core Spray, Main Steam, Reactor Core Isolation Cooling, Reactor Feedwater, Residual Heat Removal, Reactor Recirculation, Reactor Water Cleanup, and Standby Liquid Control, as explained in LRA Section 2.3.1.3.
(2) The Bolting Integrity Program described in NUREG-1801 Volume 2 (Section XI.M18) detects cracking of bolts regardless of the aging mechanism causing those cracks.
NUREG-1 801 XI.M1 8, Section 4 calls for the bolting to be inspected for leakage and cracking during periodic system walkdowns. NUREG-1801 XI.M18, Section 10 specifically mentions fatigue as a bolting degradation mechanism.
As no TLAA of pressure boundary bolting exists (see response to item 3 below);
Line 320 from LRA Table 3.1.2-1 and Line 8 from LRA Table 3.1.2-3 is revised to delete the comparison to NUREG-1801 Vol. 2 line item IV.A1-6. An LRA markup is provided changing the NUREG-1801 Volume 2 Item, Table 1 Item, and Note for Line
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 3 of 9 320 of LRA Table 3.1.2-1 and Line 8 of LRA Table 3.1.2-3 to NA, NA, H. Summary Table 3.1.1 is modified accordingly. Plant-Specific Note 0110 is added for clarification.
(3) 10 CFR 54, Section 3(a)(6) defines TLAA as calculations that are in the Current Licensing Basis. Energy Northwest has searched Columbia's licensing bases, and no fatigue calculation has been found for the miscellaneous bolting discussed in this RAI. Therefore, there is no TLAA of pressure boundary bolting to be dispositioned per 10 CFR 54.
(4) The referencing of GALL Report Vol. 2 Item IV.A1-7 in LRA Table 3.1.2-1 Rows 312 and 324 was a typographical error. An LRA markup is provided changing the GALL Report Vol. 2 Item for LRA Table 3.1.2-1 Rows 312 and 324 from IV.A1-7 to IV.A1 -6, which designates an indoor air environment. Summary Table 3.1.1 is modified accordingly. A generic note C is used because the component is different, but the material, environment, and aging effect are the same.
Omesh Follow up question to RAI 4.3-02
Background:
In the response to RAI 4.3-02 (dated August 26,2010) the applicant stated that the original equipment manufacturer (OEM) stress report for the Columbia reactor vessel calculated a CUF for the CRD penetrations but did not include the incore housing penetration. These penetrations were evaluated in a generic stress report. The applicant stated that since this is a generic analysis and not a Columbia-specific analysis, it is not considered a Columbia CUF of record and thus is not a TLAA. The applicant also stated that Columbia listed the generic incore penetration CUF analysis in earlier versions of the basis documents upon which the LRA was based, but deleted it because it was not a plant-specific analysis. Unfortunately reference to the CUF for the incore housing penetrations was not also deleted from Appendix C, Table C-8; the applicant stated that it will be amended in response to this RAI to correct this oversight.
Issue:
The applicant has listed the generic incore penetration CUF analysis in the earlier versions of the basis documents but did not provide any other details regarding the analysis. Furthermore, LRA Table 3.1.2-1 presents the AMR results for reactor pressure vessel and includes TLAA line item 3.1.1-02 for CRD housing and stub tube in rows 246 and 253, respectively, and incore housing in row 259, indicating that a TLAA for the incore housing is included in Columbia design basis documents. If the generic incore penetration CUF analysis was included in the design basis document, it is not clear to the staff why it was later deleted from the basis documents. The applicant did not provide a justification or technical basis for this action.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 4 of 9 Request:
Since fatigue CUF analyses for the CRD housing, CRD stub tubes, and incore housing penetrations are identified as TLAAs in the initial design basis documents and in the plantspecific response to BWRVIP applicant action items in LRA Appendix C, either (a) provide the reference of the fatigue CUF analysis and resultant CUF values for the incore housing penetrations or (b) provide a technical basis why the analysis does not conform to the definition of a TLAA and can be deleted from Appendix C, Table C-S.
Energy Northwest Response:
There appear to be two areas that warrant further clarification in the follow-up question.
The first is that a CUF for the incore housing penetrations appears in Columbia "design basis documents." There is a distinction between "design basis documents" for the plant and the "basis documents" generated as partof the integrated plant assessment (IPA) to support license renewal. The plant design basis documents contain the detailed design of the plant as defined in 10 CFR 50.2, and are the documents on which licensing and operation of the plant are based. During the IPA, a license renewal basis document (not a plant design basis document) was developed by searching all documents on the Columbia site to identify fatigue analyses contained, or incorporated by reference, in the current licensing basis. This search also uncovered the generic analysis of the incore housing penetration and it was initially listed in the license renewal basis document. During a subsequent review of the license renewal basis document, it was determined that the generic incore housing penetration analysis was not a Columbia design basis document and the results of that analysis were deleted from the license renewal basis document. The CUF of the incore housing penetrations does not appear in any Columbia "design basis document."
The second is whether row 259 of LRA Table 3.1.2-1 implies that there is a design basis fatigue analysis of record for the incore housing penetrations. This was never intended to be the case. Table 3.1.2-1 identifies fatigue with the aging management program of TLAA and compared to GALL line item IV.A1-7, for every sub-component of the reactor vessel because the original equipment manufacturer's fatigue analyses of the reactor vessel bounded every sub-component of the reactor vessel; whether or not a CUF was specifically calculated for that sub-component. There are multiple entries in Table 3.1.2-1 (for example the vessel flange, vessel shells, nozzles N12, N13, N14, etc.) for which no CUF is listed in LRA Table 4.3-3. There are other entries in Table 3.1.2-1 (for example the RRC outlet nozzles and feedwater nozzles) for which multiple CUFs were calculated and are listed in Table 4.3-3. There is no direct correlation between the rows of Table 3.1.2-1 and the CUFs in Table 4.3-3. As such, Row.259 of LRA Table 3.1.2-1 does not imply there is a CUF of record for the incore housing penetrations.
The generic incore housing penetration fatigue analysis does not conform to the definition of a TLAA, and the erroneous indication in LRA Appendix C, Table C-8 that an incore housing penetration CUF TLAA exists for Columbia was corrected in response to
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 5 of 9 RAI 4.3-02 (letter G02-10-164). The generic incore housing penetration fatigue analysis is not a TLAA because it does not satisfy elements 4 or 6 of 10 CFR 54.3.
(4) Were determined to be relevant by the licensee in making a safety determination; (6) Are contained or incorporated by reference in the CLB.
The CUF for the incore housing penetration is not cited in any Columbia design basis document and was not used in making a safety determination. The incore housing penetration fatigue analysis is not contained or incorporated by reference in Columbia's current licensing basis (It is not referenced in the FSAR, and has not been docketed by Energy Northwest).
A review of recently approved BWR applications (Cooper, Susquehanna) and recently submitted BWR applications (Hope Creek, Duane Arnold) found that none of these plants list a CUF for the incore housings and none mention this generic fatigue analysis; further supporting that this is not a TLAA.
Omesh Follow up question to RAI Cumulative Fatigue Damage AMR
Background:
In the response to RAI Cumulative Fatigue Damage AMR (dated August 26, 2010), the applicant stated that Columbia opted not to list fatigue TLAA of non-Class 1 components in the Section 3.2 tables because they are not managed by an Aging Management Program. As stated in LRA Section 4.3.4, all non-Class 1 components were reviewed as part of the Aging Management Review process. For non-Class 1 components, fatigue evaluation is accomplished by utilization of a stress range reduction factor. The applicant stated that these fatigue analyses of non-Class 1 components remain valid through the extended period of operation because none of the Columbia systems will reach the analyzed 7000 full range expansion cycles. The applicant added that since there is no implicit/explicit fatigue analysis, there is no fatigue aging effect for non-Class 1 components. The applicant stated that in either case there is no fatigue managed by a GALL AMP.
Issue:
10 CFR 54.21 (a)(1 ) requires that the license renewal application to identify and list those components subject to an aging management review. As stated in LRA Section 4.3.4, all nonClass 1 components are part of the Aging Management Review.
Therefore, LRA Tables 3.2.2X, 3.3.2-X, and 3.4.2-X should include all components associated with AMR items related to TLAA for managing cumulative fatigue damage of non-Class 1 components.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 6 of 9 Request:
Justify that LRA Tables 3.2.2-X, 3.3.2-X, and 3.4.2-X do not need to identify and list all the AMR results, which include the components associated with a TLAA for managing cumulative fatigue damage of non-Class 1 components, that are in scope of license renewal in accordance with 10 CFR 54.4 and are subject to an AMR in accordance with 10 CFR 54.21(a)(1).
Energy Northwest Response:
Energy Northwest agrees that the AMR results which include the components associated with a TLAA for non-class 1 components should be included in the LRA tables. The LRA is amended to include line items in LRA tables to identify piping and in-line piping components where an aging management review (AMR) related to TLAA for cumulative fatigue damage was performed for non-Class 1 components. This also includes the Heating Steam, the Heating Steam Condensate, the Heating Steam Vent, and the Sealing Steam systems that were added to the scope of license renewal as part of Amendment 1 to the LRA. The amended LRA pages are attached as an enclosure to this response.
Holston RAI B.2.A-3
Background:
GALL AMP XI.M32, "One-Time Inspection" states in element 4, "detection of aging effects" that the inspection includes a representative sample of the system population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin.
Columbia has several programs which are consistent with GALL AMP XI.M32, including the Chemistry Program Effectiveness Inspection, Cooling Units Inspection, Diesel Starting Air Inspection, Diesel Systems Inspection, Diesel Driven Fire Pumps Inspection, Flexible Connection Inspection, Heat Exchangers Inspection, Lubricating Oil Inspection, Monitoring and Collection Systems Inspection, Service Air Inspection, and Supplemental Piping/Tanks Inspection Programs. In the LRA, each one-time inspection program has a statement similar to the following: "The sample population will be determined by engineering evaluation based on sound statistical sampling methodology, and, where practical, will be focused on the components most susceptible to aging, such as due to their time in service, the severity of conditions during normal plant operation, and the lowest design margins."
In its response to RAI B.2.A-2 dated October 13, 2010, the applicant stated that the components selected for inspection as part of its one-time inspection programs will be
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 7 of 9 those most susceptible to aging effects as defined by time in service, severity of operating conditions, and design margins. The applicant provided a flow chart that described how the sample size would be selected based on the discrete number of components in the population. The chart stated that 5% of the components would be inspected for a population size of 21 -200 components, a minimum sample size of 1 component would be inspected for populations of less than 20, and a maximum sample size of 10 components would be inspected for populations over 200.
Issue:
Due to the uncertainty in determining the most susceptible locations and the potential for aging to occur in other locations, the staff noted that large sample sizes (at least 20%) may be required in order to adequately confirm an aging effect is not occurring. It is unclear to the staff how the sample sizes outlined in the response to RAI B.2.A-2 are adequate to provide confidence that the remaining population of components that are not inspected are not experiencing degradation.
Request:
Provide technical justification for the adequacy of the sample sizes chosen at ensuring that the components not inspected are not experiencing degradation.
Energy Northwest Response:
The following Columbia programs have been converted to plant-specific programs, and are no longer one-time inspections consistent with GALL XI.M32: Cooling Units Inspection, Diesel Systems Inspection, Diesel-Driven Fire Pump Inspection, Flexible Connections Inspection, Monitoring & Collection Systems Inspection, and Service Air Inspection.
For the remaining one-time inspection programs (i.e., Chemistry Program Effectiveness Inspection, Diesel Starting Air Inspection, Heat Exchangers Inspection, Lubricating Oil Inspection, and Supplemental Piping/Tanks Inspection), the selected set of components to be sampled will be determined based on material-environment-aging effect combinations. Each material-environment-aging effect combination will represent a sample population. Energy Northwest has chosen to base the sample sizes on the staff recommendation of 20% of each population, based on material-environment-aging effect combinations, up to a maximum of 25 inspections per population.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 8 of 9 Holston RAI B.2.47-1
Background:
GALL AMP XI.M33, "Selective Leaching of Materials" states in element 1, "scope of program" that the program includes a one-time visual inspection and hardness measurement of a selected set of sample components to determine whether loss of material due to selective leaching is not occurring for the period of extended operation.
LRA Section B.2.47, Selective Leaching Inspection, states that the program includes (a) determination of the sample size based on an assessment of materials of fabrication, environment and conditions, and operating experience; and (b) identification of the inspection locations in the susceptible system or component.
Issue:
Due to the uncertainty in determining the most susceptible locations and the potential for aging to occur in other locations, the staff noted that large sample sizes (at least 20%) may be required in order to adequately confirm an aging effect is not occurring.
The applicant's Selective Leaching Inspection Program did not include specific information regarding how the selected set of components to be sampled or the sample size will be determined.
Request:
Provide specific information regarding how the selected set of components to be sampled will be determined and the size of the sample of components that will be inspected.
Energy Northwest Response:
For the Selective Leaching Inspection, the selected set of components to be sampled will be determined based on material-environment combinations. Each material-environment combination will represent a sample population. The materials are those that have been determined to be susceptible to selective leaching; i.e., gray cast iron and copper alloys with greater than 15% zinc. The environments to which frequent and prolonged exposure could lead to selective leaching are fuel oil, moist air (including condensation), raw water, treated water (including closed cycle cooling water and steam), and soil (buried components). There are, therefore, nine separate populations (there are no copper alloy > 15% Zn components within the scope of license renewal that are buried and exposed to soil):
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 9 of 9 Material Environment Copper Alloy > 15% Zn Condensation Copper Alloy > 15% Zn Fuel Oil Copper Alloy > 15% Zn Raw Water Copper Alloy > 15% Zn Treated Water (Closed Cycle Cooling Water)
Gray Cast Iron Fuel Oil Gray Cast Iron Condensation and Moist Air Gray Cast Iron Raw Water Treated Water (including Closed Cycle Cooling Water and Steam)
Gray Cast Iron Soil Energy Northwest has chosen to base the size of each sample on the staff recommendation of 20% of each population, based on material-environment combinations, up to a maximum of 25 inspections per population.
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 1 of 2 License Renewal Application Amendment 23 LRA Section Number Page Number RAI Number Table 3.1.1 ne I 3.1.1 -0 3.1-10 RAI 3.1.2.2.1-01 Line Item 3.1.1-01 Table 3.1.2-1 Linle Item231 3.1-77 RAI 3.1.2.2.1-01 Line Item 312 Table 3.1.2-1 3.1-78 RAI 3.1.2.2.1-01 Line Items 320, 324 Table 3.1.2-3 3.1-94 RAI 3.1.2.2.1-01 Line Item 8 Plant-Specific Notes 3.1-116 RAI 3.1.2.2.1-01 Insert Line Item Plant-Specific Notes 3.1-116a RAI 3.1.2.2.1-01 Line Item 0110 Table 3.2.2.1 Tbe32213.2-49 CFD AMR Insert Line Items Table 3.2.2.1 3.2-49a CFD AMR Line Items 125, 126 Table 3.2.2.2 Tbe32223.2-68 CFD AMR Insert Line Items Table 3.2.2.2 3.2-68a CFD AMR Line Items 159-162 Table 3.3.2-11 Tal 13.3-162 CFD AMR Insert Line Items Table 3.3.2-11 3.3-162a CFD AMR Line Items122, 123 Table 3.3.2-33 ITable Item23 3.3-302 CFD AMR Insert Line Item Table 3.3.2-33 3.3-302a CFD AMR Line Item 51 Table 3.3.2-37 3.3-340 CFD AMR Insert Line Item Table 3.3.2-37 3.3-340a CFD AMR Line Item 88 Table 3.3.2-39 Tal 93.3-368 CFD AMR Insert Line Items Table 3.3.2-39 3.3-368a CFD AMR Line Items 121-123 Table 3.3.2-45 Insert Line Item 3.3-397g CFD AMR
RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION Page 2 of 2 LRA Section Number Page Number RAI Number Table 3.3.2-45 3.3-397m CFD AMR Insert Line Item Table 3.3.2-47 Inet ie tm3.3-397n CFD AMR Insert Line Item Table 3.4.2-1 Insert Line Item Table 3.4.2-1 3.4-40a CFD AMR Line Item 43 Table 3.4.2-2 Insert Line Item Table 3.4.2-2 3.4-43a CFD AMR Line Item 26 Table 3.4.2-4 Insert Line Items Table 3.4.2-4 3.4-65a CFD AMR Line Items 111-113 Table 3.4.2-7 Tbe34273.4-76 CFD AMR Insert Line Items Table 3.4.2-7 Tbe34273.4-76a CFD AMR Line Item 20 & 21 Table 3.4.2-8 Tbe34283.4-76b CFD AMR Insert Line Item 5 B.2.12 B-61 B.2.A-3 B.2.12 B-61a B.2.A-3 B.2.16 B-74 B.2.A-3 B.2.16 B-74a B.2.A-3 B.2.30 B-125 B.2.A-3 B.2.30 B-125a B.2.A-3 B.2.37 B-148 B.2.A-3 B.2.37 B-148a B.2.A-3 B.2.51 B-199 B.2.A-3 B.2.51 B-199a B.2.A-3
Columbia Generating Station License Renewal Application Technical Information Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of NUREG-1801 Item t
Aging Effect/
Aging Management Further Number ComponentCommodity Mechanism Programs Evaluation Discussion Recommended 3.1.1-01 Steel pressure vessel support Cumulative fatigue TLAA, evaluated in Yes, TLAA Fatigue is a TLAA.
the RPV skirt and attachment welds damage accordance with closure 10 CFR 54.21(c)
In addition to the support skirt, studs and this item is also used for <
stabilizer Prc6cUro boundar; bolting brces xpe"..d to F..
Fatig. uo brackets.
bolting ic, manogod b9y the Belting Refer to Section 3.1.2.2.1 for further information.
3.1.1-02 Steel; stainless steel; steel with Cumulative fatigue TLAA, evaluated in Yes, TLAA Fatigue is a TLAA.
nickel-alloy or stainless steel damage accordance with cladding; nickel-alloy reactor 10 CFR 54.21(c) and Refer to Section 3.1.2.2.1 for vessel components: flanges; environmental effects further information.
nozzles; penetrations; safe ends; are to be addressed for thermal sleeves; vessel shells, Class 1 components heads and welds 3.1.1-03 Steel; stainless steel; steel with Cumulative fatigue TLAA, evaluated in Yes, TLAA Fatigue is a TLAA.
nickel-alloy or stainless steel damage accordance with cladding; nickel-alloy reactor 10 CFR 54.21(c) and Refer to Section 3.1.2.2.1 for coolant pressure boundary environmental effects further information.
piping, piping components, and are to be addressed for piping elements exposed to Class 1 components reactor coolant Aging Management Review Results Page 3.1-10 AJmenmn 2213
~m~endment 23
Columbia Generating Station License Renewal Application Technical Information Aging Management Review Results Page 3.1-77 FAmendment 23 1
Columbia Generating Station License Renewal Application, Technical Information Table 3.1.2-1 Aging Management Review Results - Reactor Pressure Vessel NUREG-Mti En R
rAging Effect Aging Management 1801 Table 1 Notes Row Component intended Maeil Evironment{ AguiingEfetN E-No.
Type Function(s)
Mang Program Volume 2 Item Management Item RPV Support Air-indoor Cracking - Flaw Inservice Inspection -
318 Skirt Bearing Support Steel uncontrolled Growth IWF N/A N/A H
Plate (External)
RPV Support Air-indoor Inservice Inspection -
319 Skirt Bearing Support Steel uncontrolled Loss of material IWF N/A N/A H
Plate (External)
Bolting N/A otn Pressure Air-indoor Cracking -
320 Bodr Pressure Steel uncontrolled Cacig Bolting Integrity IVEA4-6 3-4.4-0 32 oundary' Boundary (Etra)
Fatigue Bolting (External)
Pressure Pressure Air-indoor B
321 Boundary Boundary Steel uncontrolled Cracking - SCC Bolting Integrity IV.C2-7 3.1.1-52 0102 Bolting (External)
Pressure Air-indoor 322 Boundary Boundary Steel uncontrolled Loss of material Bolting Integrity IV.C1-12 3.1.1-52 B
Bolting (External)
Pressure Pressure Air-indoor 323 Boundary Steel uncontrolled Loss of pre-load Bolting Integrity IV.Cl-10 3.1.1-52 B
Bolting (External)
IiV.A1-6 3.1.1-01 RPV Closure Air-indoor E
r 324 Studs, Nuts Peure Steel uncontrolled Cacig TLAA 4V.A-1-4
.4.4 2
A and Washers Boundary (External)
Fatigue
_NT CY Aging Management Review Results Page 3.1-78 FAmendment 23 1
Columbia Generating Station License Renewal Application Technical Information Table 3.1.2-3 Aging Management Review Results - Reactor Coolant Pressure Boundary Aging ffectNUREG-Aging Effect Aging Management 1801 Table I oe Row Component Intended Material Environment Requiring No.
Type Function(s)
Management Program Volume 2 Item Item Pressure Reactor 1
Annubar Stainless Steel Coolant Cracking - Flaw Small Bore Class 1 boundary (Internal)
Growth Piping IfieNA
/AR Reactor 2 Annubar b
arR Stainless Steel Coolant Cracking -
BWR Water Chemistry IV.C1-1 3.1.1-48 A
boundary (Internal)
Pressure Reactor Cracking -
Small Bore Class 1 3
Annubar boundary Stainless Steel Coolant SCC/IGA Piping eIV.C11 3.1.148 A
(Internal)
SC/IAipng__e_._
Pressure Reactor 4
Annubar boundary Stainless Steel Coolant Loss of Material BWR Water Chemistry IV.C1-14 3.1.1-15 A
(Internal)
Pressure Reactor Chemistry Program 5
Annubar Stainless Steel Coolant Loss of Material Effectiveness IV.C1-14 3.1.1-15 A
boundary (Internal)
Inspection Pressure Air-Indoor 6
Annubar Boury Stainless Steel Uncontrolled None None IV.E-2 3.1.1-86 A
Boundary (External)
Pressure Air-Indoor Bolting boundary Stainless Steel Uncontrolled Loss of Pre-load Bolting Integrity IV.C2-8 3.1.1-52 B
(External)
N/
N/A-Air-Indoor Crcig-Pressure AirIndoroCrackinge Bolting Integrity E--
8 Bolting boundary Steel Uncontrolled Fatigue (External)
I_______
Program E__J Program1 Aging Management Review Results Page 3.1-94 January2010 F-mendmencndrn23 ff47-
Columbia Generating Station License Renewal Application Technical Information Plant-Specific Notes:
0101 NUREG-1801 Chapter IV does not list indoor air as an environment for carbon steel or low alloy steel components such as the vessel shell. This aging management review finds that there is no identified aging effect for these components whose temperature is
>212 OF based on their being exposed to indoor air.
0102 Only high strength bolting (yield strength > 150 ksi) and bolting with sulfide containing lubricants, whether carbon or stainless steel, are susceptible to SCC.
0103 NUREG-1801 item IV.C1-1 covers multiple types of cracking in multiple sizes of components. IV.C1-1 lists three programs: ISI, BWR Water Chemistry, and Small Bore Piping. BWR Water Chemistry does not affect cracking due to flaw growth (loading) and Small Bore Piping is not applicable for the reactor vessel. Therefore, using ISI as the aging management program is a match to NUREG-1801.
0104 The internal attachments inside the vessel only have an external environment, which is reactor coolant.
0105 The aging effect of loss of material due to flow accelerated corrosion applies only to Main Steam, Reactor Core Isolation Cooling, Reactor Feedwater, Reactor Recirculation, Reactor Water Clean-Up, and Residual Heat Removal system piping. Other areas of the reactor coolant pressure boundary do not have the conditions necessary for flow accelerated corrosion.
0106 The aging effect determination for the Air-indoor uncontrolled (Internal) environment is the same as the NUREG-1 801 determination for an Air-indoor uncontrolled (External) environment because the material is the same and the internal environment is equivalent to the external environment evaluated in the NUREG-1801 item Monitoring of the external surface condition will be used to characterize the aging effects on the internal surfaces.
0107 GALL item IV.B1-4 is for nickel alloy and the safe ends are stainless steel. However, nickel alloy and stainless steel are similar for cracking due to SCC/IGA. The same GALL item was used for both the nickel alloy nozzles and the stainless steel safe ends for consistency.
0108 The BWR Feedwater Nozzle Program manages cracking due to any mechanism for the feedwater nozzle assembly, including the nozzle, safe end, and thermal sleeve.
0109 Cracking of the N12, N13, and N14 nozzle to vessel weld is included because the weld is nickel alloy, whereas the nozzle is low alloy steel. For other aging effects, the weld is included with the nozzle.
0110 1ne of the two access hole covers has a modified configuration with a stainless steel top hat. The welds of both
[access' hole covers to the shroud support plate are nickel alloy, backfilled to eliminate crevices.
Aging Management Review Results 1
Page 3.1-116 ilnsert A from Page 3.1-116a jAmendment 23 Z^41,
Columbia Generating Station License Renewal Application Technical Information Insert A for Page 3.1-116 Plant-Specific Notes:
0111 The Bolting Integrity manages all cracking of bolting, including cracking due to fatigue, in accordance with NUREG-1 801 Volume 2 Section XI.M18, "Bolting Integrity."
Aging Management Review Results Page 3.1-116a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.2.2-1 Aging Management Review Results - Residual Heat Removal System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table I Notes No.
Type Function(s)
Management Program Volume 2 Item Item Structural Air-indoor Loss of External Surfaces C
121 Valve Body integrity Steel uncontrolled material Monitoring 3.2.1-31 (Internal) m rMin0 122 Valve Body Treated water Loss of BWR Water V.D2-33 3.2.1-14 A
Sintegrity Steel (Internal) material Chemistry Structural Treated water Loss of Chemistry Program 123 Valve Body Steel Effectiveness V.D2-33 3.2.1-14 A
integrity (Internal) material Inspection Structural Steel Air-indoor Loss of External Surfaces 124 Valve Body integrity Steelxuncontrolled material Monitoring V.E-7 3.2.1-31 A
1 2 4 V a l v e B o d y i n t e g r i t y
~ ( E x t e r n a l )
N1 Insert A on page 3.2-49a Aging Management Review Results Page 3.2-49 lAmendment 23
--January=2&,0-=
Columbia Generating Station License Renewal Application Technical Information Insert A for Paqe 3.2-49 Aging Management Review Results Page 3.2-49a Amendment 23 Aging Management Review Results Page 3.2-49a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.2.2-2 Aging Management Review Results - Reactor Core Isolation Cooling System dAging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table 1 No.
Type Function(s)Management Program Volume Item Management 2 Item Structural Air-indoor Loss of External Surfaces 158 Valve Body integrity Steel uncontrolled material Monitoring
______3_2.1_31_A (External) materialMonitoring Aging Management Review Results Page 3.2-68
-JanuaTy=2010-FAmendment 23
Columbia Generating Station License Renewal Application Technical Information Insert A into pagqe 3.2-68 Table 3.2.2-2 Aging Management Review Results - Reactor Core Isolation Cooling System Row Component Intended Aging Effect NUREG-Rd Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume 1 Item 2 Item 159 Piping Pressure Stainless Steam Cracking -
TLAA N/A N/A H
Boundary Steel (Internal)
Fatigue Pressure Steam Cracking -
TLAA VI1I.1B2-5 A
Boundary (Internal)
Fatigue 1
161 Piping Structural Stainless Steam Cracking -
TLAA N/A N/A H
Integrity Steel (Internal)
Fatigue 162 Piping Structural Steel Steam Cracking -
TLAA VIII.1B2-5 3.4.1 A
162_
PipingIntegrity Steel (Internal)
Fatigue I
1 1
Aging Management Review Results Page 3.2-68a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-11 Aging Management Review Results - Control Rod Drive System Row Component Intended Aging Effect Aging NUREG-Row Componen Fntendd Material Environment Requiring Management 1801 Table 1 Notes No.
Type Function(s)
Maaeet Porm Volume Item Management Program 2 Item Treated Chemistry 116 Valve Body Structural Stainless Tated Loss of Program integrity Steel water material Effectiveness VII.E3-15 3.3.1-24 A
(Internal)
Inspection Structural Stainless Air-indoor 116 Valve Body Strity Steel uncontrolled None None VII.J-15 3.3.1-94 A
integrity Steel (External) 117 Valve Body Structural Steel Lubricating Loss of Lubricating Oil VI1.C2-13 3.3.1-14 A
integrity oil (Internal) material Analysis 118 Valve Body Structural Steel Lubricating Loss of Lubricating Oil VII.C2-13 3.3.1-14 A
integrity oil (Internal) material Inspection Structural Treated Loss of BWR Water 119 Valve Body integrity Steel water maeilCeityVII.E3-18 3.3.1-17 A
(internal) material Chemistry Treated Chemistry 120 Valve Body Structural Steel water Loss of Program integrity (Internal) material Effectiveness VII.E3-18 3.3.1-17 Inspection Structural Air-indoor Loss of External 121 Valve Body integrity Steel uncontrolled Surfaces VII.l-8 3.3.1-58 A
(External) material Monitoring Insert A on page 3.3-162a Aging Management Review Results Page 3.3-162
-Janaary120T 0' FAmendment 23
Columbia Generating Station License Renewal Application Technical Information Insert A into page 3.3-162 Table 3.3.2-11 Aging Management Review Results - Control Rod Drive System Aging Effect NUREG-RowMaterial Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume 1 Item 2 Item Treated 122 Piping Pressure Stainless water > 60 °C Cracking -
TLAA VII.E3-14 3.3.1-A Boundary Steel (140 OF)
Fatigue2 (Internal)
Treated Pressure water > 60 OC Cracking -
3.2.1-123ePipingSteel TLAA V. D2-32 A
123 Piping Boundary (140 OF)
Fatigue 1
(Internal)
Aging Management Review Results Page 3.3-162a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-33 Aging Management Review Results - Process Sampling Radioactive System Aging Effect Aging NUREG-Row Component Intended Aging Effect agint 1801 Table No.
Type Function(s)
Material Environment Requiring Management Volume 1 Item Notes Management Program 2 Item Treated Monitoring and Structural Stainless Loss of Collection VII.E3-3.3.1-E 49 Valve Body integrity Steel (140 °F) material Systems 15 24 0305 (Internal)
Inspection Structural Stainless Air-indoor3.3.1-50 Valve Body uncontrolled None None VII.J-15
- 3.
A y integrity Steel (External)
Insert new row 51 on page
- 3. 3 -30.3 a02 Aging Management Review Results Page 3.3-302
=Janvary=20+-1 PýThýýdnnt 23
Columbia Generating Station License Renewal Application Technical Information Insert A into page 3.3-302 Table 3.3.2-33 Aging Management Review Results - Process Sampling Radioactive System Row Component Intended Aging Effect NUREG-Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume 1 Item 2 Item Treated Structural Stainless water > 60 OC Cracking -
TLAA VIIE3-14 3.3.1-A Integrity Steel (140 -F)
Fatigue 1
(Internal)
Aging Management Review Results Page 3.3-302a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-37 Aging Management Review Results - Reactor Building HVAC Systems Row Component Intended Aging Effect Aging NUREG-No.
Type Function(s)
Material Environment Requiring Management Volume Item Notes Management Program 2 Item Structural Raw water Loss of Potable Water 3.3.1-integrity (Internal) material Monitoring 76 81 Valve Body Structural Steel Steam Loss of BWR Water N/A N/A G
integrity (Internal) material Chemistry Chemistry 82 Valve Body Structural Steel Steam Loss of Program N/A N/A G
integrity (Internal) material Effectiveness Inspection Flow-Structural Steam Loss of Accelerated 83 Valve Body integrity Steel (Internal) material Corrosion N/A N/A G
(FAC)
Structural Air-indoor Loss of External 3.3.1-84 Valve Body ntegructu Steel uncontrolled material Surfaces VII.I-8 583A 84 Val y integrity (External)
Monitoring Structural Condensation Loss of External 3.3.1-85 Valve Body integrity Steel (External) material Surfaces VIII-11 58A Monitoring Insert new row 88 on page 3.3-340a Insert new rows 86 and 87 from Page 3.3-340a Aging Management Review Results Page 3.3-340
- Jpnu, 2010.v**",-,
Iame fy 23n
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-37 Aging Management Review Results - Reactor Building HVAC Systems Aging Effect Aging NUREG-Row Component Intended Material Environment Reuirin Manaement 1801 Table I Notes No.
Type Function(s)
Mqang Progem Volume Item Management Program 2 Item Heat Exchanger 86 (fins) (RRA-Heat transfer Copper Alloy Condensation Loss of Open-Cycle VII.F2-14 3.3.1-E CC-12, 13, 14, (External) material Cooling Water 25 15,17, 19, &
20)
Heat Exchanger 87 (fins) (RRA-Heat transfer Copper Alloy Condensation Reduction in Open-Cycle N/A N/A H
CC-12, 13, 14, (External) heat transfer Cooling Water 15, 17, 19, &
1____ _
- 20) 1 1
1 88 Piping Structural Steel Steam Cracking -
TLAA VIII.B2-5 3.4.1-1 A
Integrity (Internal)
Fatigue Aging Management Review Results 3.3-340a Anrzrndmzrt 1-j~enmnt 23
-~
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-39 Aging Management Review Results - Reactor Water Cleanup System T
Aging Effect Aging NUREG-Row Component Intended Material Environment Requiring Management 1801 Table 1 Notes Management Program Volume Item 2 Item Structural Treated Loss of BWR Water 3.3.1-115 Valve Body integrity Steel water maeilCeity VI.E3-118 17A (internal) material Chemistry Treated Chemistry 116 Valve Body Structural Steel water Loss of Program VII.E3-18 3.3.1-A integrity (Internal) material Effectiveness 17 Inspection Treated Structural water > 60 °C Loss of BWR Water 3 3.3.1-A integrity (140 °F) material Chemistry 17 0305 (Internal)
Treated Chemistry 118 Valve Body Structural Steelwater>60 C
Loss of Program VII.E3-18 3.3.1-A integrity (140 OF) material Effectiveness 17 0305 (Internal)
Inspection Treated Flow-119 Valve Body Structural Steel water > 60 °C Loss of Accelerated N/A N/A H
integrity (140 °F) material Corrosion (Internal)
(FAC)
Structural Air-indoor Loss of External 3.3.1-120 Valve Body integrity Steel uncontrolled materialSurfaces V.-8 58A (External) materialMonitoring_58 Insert new rows 121 - 123 on page 3.3-368a Aging Management Review Results Page 3.3-368 VJantrary2010-FAmendment 23 1
Columbia Generating Station License Renewal Application Technical Information Insert A into paae 3.3-368 Table 3.3.2-39 Aging Management Review Results - Reactor Water Cleanup System NUREG-Aging Effect Aging NRG R
Component Intended Aging Eaging 1801 Table 1 Row No.
Type Function(s)
Material Environment Requiring Management Volume 2 Item Notes Management Program Item Treated 121 Piping Pressure Stainless water > 60 0C Cracking -
TLAA VII.E3-14 3.3.1-1 A
Boundary Steel (140 °F)
Fatigue (Internal)
Treated Piping Pressure water > 60 °C Cracking -
122 Boundary Steel (140 OF)
Fatigue TLAA V.D2-32 3.2.1-1 A
(Internal)
Treated 123 Piping Structural Stainless water > 60 °C Cracking -
TLAA VII.E3-14 3.3.1-1 A
Integrity Steel (140 OF)
Fatigue (Internal)
Aging Management Review Results Page 3.3-368a Amendment 23 Aging Management Review Results Page 3.3-.368a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-45 Aging Management Review Results - Heating Steam System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume I Item 2 Item Structural Steam Loss of Chemistry Program 50 Valve Body integrity Steel (Internal) material Effectiveness N/A N/A G
Inspection 51 Valve Body Structural S
Steam Loss of Flow-Accelerated N/A N/A G
integrity (Internal) material Corrosion (FAC)
Structural Air-indoor Loss of External Surfaces 3 3 1-52 Valve Body Steel uncontrolled VII.1-8 A
ntegnty (External) material Monitoring 58 53 Piping Structural Steel Steam Cracking -
TLAA VIILB2-5 3.4.1-1 A
P Integrity (Internal)
Fatigue Aging Management Review Results Page 3.3-397g Amendment4-
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-46 Aging Management Review Results - Heating Steam Condensate System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume I Item 2 Item Structural Treated water Loss of BWR Water VII.E3-3.3.1-A 46 Valve Body integrity Steel
> 60 0C (140 OF) (Internal) material Chemistry 18 17 0305 Structural Treated water Loss of Chemistry Program VII.E3-3.3.1-A 47 Valve Body integrity Steel
> 60 OC (140 Lossrofl Effectiveness nF) (internal) material Inspection 18 17 0305 Structural Air-indoor Loss of External Surfaces 3.3.1-48 Valve Body integrity Steel uncontrolled VII.I-8 A
(External) material Monitoring 58 49 Piping Structural Steel Steam Cracking -
TLAA VIII.B2-5 3.4.1-1 A
Integrity (Internal)
Fatigue Aging Management Review Results Page 3.3-397m AmendmentX
Columbia Generating Station License Renewal Application Technical Information Table 3.3.2-47 Aging Management Review Results - Heating Steam Vent System NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume I Item 2 Item Structural Air-indoor Loss of 3.3. 1-1 Bolting integrity Steel uncontrolled material Bolting Integrity VII.-4 B
(External)
I Air-indoor Structural Stelinconr Loss of pre-3.3.1-2 Bolting integrity Steel uncontrolled Bolting Integrity VII.I-5 B
(External) od4 3
Pi Structural Steam Loss of BWR Water N/A NIA G
integrity (Internal) material Chemistry Structural Steam Loss of Chemistry Program 4
Piping integrity Steel (Internal) material Effectiveness N/A N/A G
i (Inspection 5
Piping Structural Steel Steam Loss of Flow-Accelerated N/A N/A G
integrity (Internal) material Corrosion (FAC)
Structural Air-indoor Loss of External Surfaces 3.3.1-6 Piping integrity Steel uncontrolled VIII-8 A
i (External) material Monitoring 58 7
Piping Structural Steel Steam Cracking -
TLAA VIII.B2-5 3.4.1-1 A
Integrity (Internal)
Fatigue Aging Management Review Results Page 3.3-397n Amendment fi
Columbia Generating Station License Renewal Application Technical Information Insert new row 43 on page 3.4-40a Aging Management Review Results Page 3.4-40 Jamuay-2.0et0t IAmendment 23
Columbia Generating Station License Renewal Application Technical Information Insert A into oaqe 3.4-40 Table 3.4.2-1 Aging Management Review Results - Auxiliary Steam System NUREG-Aging Effect Aging NRG Component Intended Material Environment Aging Eaging 1801 Table 1 Notes Row No.
Tp Fucins Maeil Evrmnt Requiring ManagementVoue2 Im Type Function(s)
Maaeet Porm Volume 2 Item Management Program Item 43 Piping Structural Steel team Cracking-TLAA VIII.B2-5 3.4.1-1 A
Integrity (internal)
Fatigue Aging Management Review Results Page 3.4-40a Amendment 23 Aging Management Review Results Page 3.4-40a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.4.2-2 Aging Management Review Results - Condensate (Auxiliary) System NUREG-Aging, Effect NRG Row Component Intended Mring Aging Management 1801 Table No.
Type Function(s)
Material Environment Requiring Program Volume 1 Item Notes Management-2 Item Structural Air-indoor -.
ý1 18 Valve Body Steel uncontrolled None None VIIIIH-7 integrity (External) 28 0406 Structural Air-indoor Loss of External Surfaces 3.4. 1-C 19 Valve Body integrity Steel uncontrolled material Monitoring V.-7 28 0404 (Internal)
Structural Air-indoor Loss of External Surfaces 3.4.1-20 Valve Body Struty Steel uncontrolled VIII.H-7 A
integrity (External) material Monitoring 28 Add new rows 21 through 25 o Table Insert new row 26 on page 3.4.2-2 as shown
]3.443a on pages 3.4-43a Aging Management Review Results Page 3.4-43 F
-rn-January-2l-IAmendment X 2
Columbia Generating Station License Renewal Application Technical Information Table 3.4.2-2 Aging Management Review Results - Condensate (Auxiliary) System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume I Item 2 Item Air-indoor VI.-
21 Tank (CO-Structural Air-indoonrole Loss of External Surfaces VIIH7 3.4.1-C 21 TK-4) integrity Steel uncontrolled material Monitoring 28 0404 Tt(internal)
Tank (CO-Structural Moist air Loss of Supplemental 22 TK-4) integrity Steel (Internal) material Piping/Tank N/A N/A G
Inspection Treated 23 Tank (CO-Structural Steel water > 60 OC Loss of BWR Water VIII.E-33 3.4.1-C TK-4) integrity (140 °F) material Chemistry 04 (Internal)
Treated 24 Tank (CO-Structural Steel water > 60 °C Loss of Chemistry Program 34 1 24SelEffectiveness VIII.E-33 3..-C TK-4) integrity (140 OF) material 04 (Internal)
Inspection Tank (CO-Structural Steel Air-indoor Loss of External Surfaces VIII.H-7 3.4.1-A 25 TK-4) integrity uncontrolled material Monitoring 28
~~~~~~(External)
Treated water 26 Piping Structural Steel
> 60oC (1400F) Cracking-TLAA VIII.D2-6 3.4.1-1 A
Integrity (Internal)
Fatigue Aging Management Review Results Page 3.4-43a Amzr.drnzr~t 1 Aging Management Review Results Page 3.4-43a jAmendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.4.2-4 Aging Management Review Results - Main Steam System TAging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
M am Program Volume 1 Item
~Management 2 Item Pressure Steam-Loss of Chemistry Program 3.4.1-Prsur telEffectiveness VIII.B2-3 3
97 Valve Body boundary Steel (Internal) material Inspection 98 Valve Bod Pressure Steel Steam Loss of Flow-Accelerated VIII B24 3.4.1-A y
boundary (Internal) material Corrosion (FAC) 29 Pressure Air-indoor Loss of External Surfaces 3.4.1-99 Valve Body boundary Steel uncontrole material Monitoring 28 (External)
Structural iSt-a4 L-e Ass-eA SupplemeRtal Structural Steam Loss of BWR Water 3.4.1-101 Valve Body integrity Steel (Internal) material Chemistry 37VIII.B2-3 Structural Steam Loss of Chemistry Program 3.4.1-E Stucurl Sea Lssof Effectiveness VIII.B2-3 3
102 Valve Body integrity Steel (Internal) material Inspection 103 Valve Bod Structural Steel Steam Loss of Flow-Accelerated VIII B24 3.4.1-A y
integrity (Internal) material Corrosion (FAC) 29 Structural Air-indoor Loss of External Surfaces 3.4.1-104 Valve Body integrity Steel uncontrolled material Monitoring 28 (External) melnog Insert new rows 105-110 from Insertnewrows 111-113 Page3.4-65a from page 3.4-65a Aging Management Review Results Page 3.4-65 Jauray 2010 2
jAmendment
Columbia Generating Station License Renewal Application Technical Information Insert A for Paae 3.4-65 Table 3.4.2-4 Aging Management Review Results - Main Steam System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table No.
Type Function(s)
Mang Program Volume I Item Management 2 Item Structural Stainless Steam Loss of Chemistry Program 3.4.1-105 Orifice Effectiveness VIII.B2-1 13A 105eintegrity Steel (Internal) material Inspection 13 106 Orifice Structural Stainless Steam C
BWR Water VIII B22 3.4.1-A integrity Steel (Internal)
Cracking Chemistry 37 Structural Stainless Steam Chemistry Program 3.4.1-107 Orifice integrity Steel (Internal)
Cracking Effectivenesson VIII.2-2 37 E
Structural Stainless Steam Loss of Chemistry Program 3.4.1-Effectiveness VIII.8B2-1 1
108 Piping integrity Steel (Internal) material Inspection
_______13 109 Piping Structural Stainless Steam BWR Water VIII 622 3.4.1-A integrity Steel (Internal)
Cracking Chemistry 37 Structural Stainless Steam Chemistry Program 3.4.1-110 Piping integrity Steel (Internal)
Cracking Effectiveness VIII.B2-2 37 E
integrty Stel (Intrnal)Inspection____
111 Piping Pressure Stainless Steam Cracking -
TLAA N/A N/A H
Boundary Steel (Internal)
Fatigue 112 Piping Pressure Steel Steam Cracking -
TLAA VIII.B2-5 34.1-1 A
Boundary (Internal)
Fatigue 113 Piping Structural Steel Steam Cracking -
TLAA VII.B2-5 3.4.1-1 A
Integrity (Internal)
Fatigue I
Aging Management Review Results Page 3.4-65a AMARdMARt 49 jArnenFm-e-n-t-2-3-k-----;)1'
Columbia Generating Station License Renewal Application Technical Information Table 3.4.2-7 Aging Management Review Results - Reactor Feedwater System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume m
Item 2 Item Treated Structural water> 6000 Loss of Chemistry Program 17 Valve Body Strity Steel (140 w
F) material Effectiveness VIII.D2-7 3.4.1-A integriy (Internal) material Inspection 04 0403 Treated Structural water > 60 OC Loss of Flow-Accelerated VIII.D2-8 3.4.1-A 18 Valve Body integrity Steel (140 OF) material Corrosion (FAC) 29 0403
_(Internal)
I..
Structural Loss of External Surfaces 3.4.1-19 Valve Body integrity Steel uncontrolled VIII.H-7 A
(External) material Monitoring 28
- lInsert new rows 20 land 21 on page 13.4-76a Insert New Table 3.4.2,8 from page 3.4-76e, b
Aging Management Review Results Page 3.4-76 jAmendment 1
23
Columbia Generating Station License Renewal Application Technical Information Insert into 3.4-76 Table 3.4.2-7 Aging Management Review Results - Reactor Feedwater System NUREG-Component Intended Aging Effect Aging 1801 Table 1 Row No.
Type Function(s)
Material Environment Requiring Management Volume 2 Item Notes StreFunctural)
Management Program Item Treated 20 Piping Structural Stainless water > 60 °C Cracking -
TLAA VII.E4-13 3.3.1-2 A
Integrity Steel (140 OF)
Fatigue (Internal)
Treated 21 Piping Structural
- Steel, water > 60 "C Cracking -
TLAA VIII.D2-6 3.4.1-1 A
Integrity (140 °F)
Fatigue (Internal)
Aging Management Review Results Page 3.4-76a Amendment 23
Columbia Generating Station License Renewal Application Technical Information Table 3.4.2-8 Aging Management Review Results - Sealing Steam System Aging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801 Table Notes No.
Type Function(s)
Management Program Volume 1 Item 2 Item 1
Piping Structural Steel Steam Loss of BWR Water VIII.C-4 3.4.1-A integrity (internal) material Chemistry 02 2
Piping Structural Steel Steam Loss of Chemistry Program VIII.C-4 3.4.1-A integrity (Internal) material Effectiveness 02 Inspection 3
Piping Structural Steel Steam Loss of Flow-Accelerated VIII.C-5 3.4.1 -
A integrity (internal) material Corrosion (FAC) 29 4
Piping Structural Steel Air-indoor Loss of External Surfaces VIII.H-7 3.4.1-A integrity uncontrolled material Monitoring 28 (External) 5 Piping Structural Steel Steam Cracking -
TLAA VIII.B2-5 3.4.1-1 A
Integrity (Internal)
Fatigue Aging Management Review Results Page 3A-76e Amendment/
~
I t
Aging Management Review Results Page 3.4-76a <ý b I Amendmentl <--ý
Columbia Generating Station B.2.12 Chemistry Program Effectiveness Inspection License Renewal Application Technical Information
" Parameters Monitored or Inspected The parameters to be inspected by the Chemistry Program Effectiveness Inspection include wall thickness and visual evidence of surface degradation as measures of loss of material, or of cracking for stainless steel exposed to treated water above 140 IF and copper alloy > 15% Zn exposed to fuel oil. Inspections will be performed by qualified personnel using established NDE techniques, including visual, volumetric, and surface techniques.
- Detection of Aging Effects The Chemistry Program Effectiveness Inspection will use a combination of established volumetric and visual examination techniques (such as equivalent to VT-1 or VT-3) performed by qualified personnel on a sample population of subject mechanical components to identify evidence of a loss of material, or cracking of stainless steel exposed to treated water above 140 IF and copper alloy > 15% Zn exposed to fuel oil, or to confirm a lack thereof on the susceptible internal and external surfaces of components.
I_*nsert A from page
.t.tistl..l
.amplmi.g m..thed.l.gy, and, where practical, focused on the components most susceptible to aging, such as due to their time in service, the severity of conditions during normal plant operations, and design margins.
The Chemistry Program Effectiveness Inspection will be conducted within the 10-year period prior to the period of extended operation.
" Monitoring and Trending This one-time inspection activity is used to characterize conditions and to determine if, and to what extent, further actions may be required.
The activity includes increasing the inspection sample size and location if degradation is detected.
The sample size will be determined by engineering evaluation of the materials of construction, the environment (i.e., service conditions), aging effects, and operating experience (e.g., time in-service, susceptible locations, lowest design margin).
Unacceptable inspection results (if degradation is detected), if any, will be evaluated using the Columbia corrective action process to determine the need for subsequent aging management activities and for further monitoring and trending of the results.
- Acceptance Criteria Indications or relevant conditions of degradation detected during the inspection will be compared to pre-determined acceptance criteria, such as design minimum wall thickness for piping. If the acceptance criteria are not met, then the indications and conditions will be evaluated under the corrective action program to determine whether they could result in a loss of component intended function during the period of extended operation.
Aging Management Programs Page B-61 a
2_v,0
[Amendment23 1
Columbia Generating Station License Renewal Application Technical Information Insert A to page B-61:
The sample population will be 20% of the total population for each material environment group (e.g., steel - treated water), up to a maximum of 25 inspections per group Aging Management Programs Page B-61a Amendment 23 Aging Management Programs Page B-61 a Amendment 23
B.2.16 Diesel Starting Air Inspection Columbia Generating Station License Renewal Application Technical Information Parameters Monitored or Inspected The parameters to be inspected by the Diesel Starting Air Inspection include wall thickness or visual evidence of internal surface degradation, of the DSA System air dryers and downstream piping and components (excluding the DSA System air receivers) as measures of loss of material.
Inspections will be performed by qualified personnel using established NDE techniques (i.e., ultrasonic examination).
Visual inspection of downstream piping and components for evidence of corrosion and corrosion products may be performed.
Detection of Aging Effects The Diesel Starting Air Inspection will use a combination of established visual examination techniques and non-destructive methods performed by qualified personnel on a sample population of the DSA System air dryers and downstream piping and components (excluding the DSA System air receivers) to identify evidence of any loss of material.
Insert A from page
,,,.,rB-74a I
There are three air dryers in the DSA System.
^
pe s
e..
F dryers and the deAnStrcam piping and compencnts will be deetermnined by-nirn
,.,luatin based n s.und stati4*tial sampling m..thede,.gy.
The results of previous inspections will be utilized in consideration of those components most susceptible to degradation. Components will also be evaluated based upon time in service, the severity of conditions during normal plant operation (i.e., the results of the air quality sampling), and design margins.
The Diesel Starting Air Inspection will be conducted within the 10-year period prior to the period of extended operation.
" Monitoring and Trending No actions are taken as part of the Diesel Starting Air Inspection to monitor or trend inspection results. This is a one-time inspection activity used to determine if, and to what extent, further actions (including monitoring and trending) may be required.
Sample size will be determined by engineering evaluation, as described in the Detection of Aging Effects element above. Results of the inspection activities that require further evaluation and resolution (e.g., if degradation is detected), will be evaluated using the Columbia corrective action process, including expansion of the sample size and inspection locations to determine the extent of the degradation.
Acceptance Criteria Indications or relevant conditions of degradation detected during the inspections will be compared to pre-determined acceptance criteria. If the acceptance criteria are not met, then the indications and conditions will be evaluated under the corrective action program to determine whether they could result in a loss of component intended function during the period of extended operation.
Aging Management Programs Page B-74 7
-j-Mnfy -29i--
Amendment 23
Columbia GeneratingStation License Renewal Application Technical Information Insert A to pagqe B-74:
The sample population will be 20% of the total population for each material environment group (e.g., steel - raw water), up to a maximum of 25 inspections per group.
Aging Management Programs Page B-74a Amendment 23
B.2.30 Heat Exchangers Inspection Columbia Generating Station License Renewal Application Technical Information Residual Heat Removal (RHR) heat exchanger RHR pump seal coolers Reactor Recirculation (RRC) pump seal coolers Radwaste Building Mixed Air (WMA) heat exchangers A representative sample of heat exchanger and cooler surfaces that are exposed to treated water, closed cooling water, and indoor air will be examined for evidence of a reduction in heat transfer capabilities due to fouling, or to confirm a lack thereof, with engineering evaluation of the results.
Preventive Actions No actions are taken as part of the Heat Exchangers Inspection to prevent aging effects or to mitigate aging degradation.
Parameters Monitored or Inspected The parameters to be inspected by the Heat Exchangers Inspection include visual or volumetric evidence of surface fouling as a measure of reduction in heat transfer capabilities. Inspections will be performed by qualified personnel using established NDE techniques.
Detection of Aging Effects The Heat Exchangers Inspection will use visual examination techniques (VT-3 or equivalent) performed by qualified personnel on a sample population of the heat exchangers and coolers within the scope of the inspection to identify evidence of fouling on heat transfer surfaces, or to confirm a lack thereof.
Insert A from page B-I 25a.
The samfple population will be dletermliined bynincig v uto eo and, where practical, will be focused on the components most susceptible to aging, such as due to their time in service, the severity of conditions during normal plant operations, and the lowest design margins with respect to heat transfer.
The Heat Exchangers Inspection activities will be conducted within the 10-year period prior to the period of extended operation.
Monitoring and Trending This one-time inspection activity is used to characterize conditions and determine if, and to what extent, further actions may be required. The activity includes increasing the inspection sample size and location if degradation is detected.
Sample size will be determined by engineering evaluation of the materials of construction, 'environment (i.e., service conditions), aging effects, and operating experience (e.g., time in-service, most susceptible locations, lowest design margins).
Aging Management Programs Page B-125
-J4a.F*ey-2010 jAmendment 23::ý
Columbia Generating Station License Renewal Application Technical Information Insert A to page B-125:
The sample population will be 20% of the total population for each material -
environment group (e.g., steel - raw water), up to a maximum of 25 inspections per group Aging Management Programs Page B-i 25a Amendment 23 Aging Management Programs Page B-1 25a Amendment 23
B.2.37 Lubricating Oil Inspection Columbia Generating Station License Renewal Application Technical Information
" Diesel Lubricating Oil (DLO) System Fire Protection (FP) System
" Low Pressure Core Spray (LPCS) System
" Reactor Core Isolation Cooling (RCIC) System
" Standby Service Water (SW) System A representative sample of components, with special emphasis on 'locations that may be susceptible to the collection of entrained water, will be examined for evidence of loss of material (due to crevice, galvanic, general, or pitting corrosion or selective leaching) or reduction in heat transfer due to fouling, or to confirm a lack thereof, and the results applied to all of the systems and components within the scope of the inspection, based on engineering evaluation.
Preventive Actions No actions are taken as part of the Lubricating Oil Inspection to prevent aging effects or to mitigate aging degradation.
- Parameters Monitored or Inspected The parameters to be inspected by the Lubricating Oil Inspection include wall thickness and visual evidence of internal or external surface degradation as measures of a loss of material or fouling. Inspections will be performed by qualified personnel using established NDE techniques.
" Detection of Aging Effects The Lubricating Oil Inspection will use a combination of established volumetric and visual examination techniques and nondestructive methods performed by qualified personnel on a sample population of subject components to identify evidence of loss of material or fouling or to confirm a lack thereof.
Insert A from page B-148a.
The sample population will be dt-tPFcRmicd b
_WY ncrn c&v0 Va in seo so
,,nd statst
,,al sampling
,meth,-,dlogy, and, where practical, will focus on the components most susceptible to aging, such as due to their time in service, the severity of conditions during normal plant operations, and design margins.
The Lubricating Oil Inspection will be conducted within the 10-year period prior to the period of extended operation.
Monitoring and Trending No actions are taken as part of the Lubricating Oil Inspection to monitor or trend inspection results. This is a one-time inspection activity used to determine if, and to what extent, further actions, including monitoring and trending, may be required.
Aging Management Programs Page B-148
-nuary 2010 IAmendment 23:
Columbia Generating Station License Renewal Application Technical InfoFmation Insert A to page B-148:
The sample population will be 20% of the total population for each material -
environment group (e.g., steel - lubricating oil), up to a maximum of 25 inspections per group Aging Management Programs Page B-148a Amendment 23
Columbia Generating Station B.2.51 Supplemental Piping/Tank Inspection License Renewal Application Technical Information using established NDE techniques (i.e., ultrasonic examination). Visual inspection of tank internals for evidence of corrosion and corrosion products may be performed.
Detection of Aging Effects The Supplemental Piping/Tank Inspection will use a combination of established volumetric and visual examination techniques (such as equivalent to VT-1 or VT-3) performed by qualified personnel on a sample population of subject components to identify evidence of a loss of material.
IJnsert A frmpg s_;tti;otic....al sampling mcthedeegy, and, where practical, will be focused on the components most susceptible to aging, such as due to their time in service, the severity of conditions during normal plant operations, and the lowest design margins.
The Supplemental Piping/Tank Inspection will be conducted within the 10-year period prior to the period of extended operation.
Monitoring and Trending This one-time inspection activity is used to characterize conditions and determine if, and to what extent, further actions may be required. The activity includes provisions for increasing the inspection sample size and location if degradation is detected.
The sample size will be determined by engineering evaluation of the materials of construction, the environment (i.e., service conditions), aging effects, and of operating experience (e.g., time in-service, most susceptible locations, lowest design margins, etc.). Inspection findings that do not meet the acceptance criteria will be evaluated using the corrective action process to determine the need for subsequent aging management activities and for monitoring and trending of the results.
" Acceptance Criteria Indications or relevant conditions of degradation detected during the inspections will be compared to pre-determined acceptance criteria.
If the acceptance criteria are not met, then the indications and conditions will be evaluated under the corrective action program to determine whether they could result in a loss of component intended function during the period of extended operation.
" Corrective Actions This element is common -to Columbia programs and activities that are credited with aging management during the period of extended operation and is discussed in Section 6.1.3.
Confirmation Process This element is common to Columbia programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B.1.3.
Aging Management Programs Page B-199 dantxary;H&e JAmendment 23
Columbia Generating Station License Renewal Application Technical Information Insert A topage B-1 99:
The sample population will be 20% of the total population for each material -
environment group (e.g., steel - treated water), up to a maximum of 25, inspections per group Aging Management Programs Aging Management Programs Page B-i 99a Amendment 23 Page B-1 99a Amendment 23