NOC-AE-14003078, Response to Requests for Additional Information for the Review of the License Renewal Application - Set 25 (TAC Nos. ME4936 and ME4937)

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Response to Requests for Additional Information for the Review of the License Renewal Application - Set 25 (TAC Nos. ME4936 and ME4937)
ML14073A456
Person / Time
Site: South Texas  STP Nuclear Operating Company icon.png
Issue date: 02/27/2014
From: Gerry Powell
South Texas
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-14003078, STI: 33815159, TAC ME4936, TAC ME4937
Download: ML14073A456 (29)
v • d • e


Text

ALMMAFM Nuclear Operating Company South TexwsPro/cd Eldnrc Generatin$ Station PO. Box 289 Wadswmorh. Tews 77483 February 27, 2014 NOC-AE-1 4003078 10 CFR 54 STI: 33815159 File: G25 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 South Texas Project Units 1 and 2 Docket Nos. STN 50-498, STN 50-499 Response to Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2, License Renewal Application I I

- Set 25 (TAC E

Nos. ME4936 and ME4937)I

References:

1. Letter from G. T. Powell, STPNOC, to NRC Document Control Desk, "License Renewal Application", dated October 25, 2010 (NOC-AE-10002607) (ML103010257)
2. Letter from NRC to STPNOC, "Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2, License Renewal Application - Set 25, dated November 19, 2012, (TAC Nos. ME4936 and ME4937)"(ML12311A438)
3. Letter from G.T. Powell, STPNOC, to NRC Document Control Desk, "Response to Requests for Additional Information for the South Texas Project License Renewal Application- Aging Management Program, Set 22, (TAC Nos. ME4936 and ME4937)",

dated August 21, 2012, (NOC-AE-1 2002897) (ML12248A148)

4. Letter from D. W. Rencurrel, STPNOC, to NRC Document Control Desk, "Partial Response to Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2, License Renewal Application - Set 25 (TAC Nos. ME4936 and ME4937)", dated December 6, 2012, (NOC-AE-1 2002907) (ML12359A063)
5. Letter from G.T. Powell, STPNOC, to NRC Document Control Desk, "Supplement 1 to Request for NRC Staff to Suspend Safety Review of the South Texas Project License Renewal Application (TAC Nos. ME4936 and ME4937)", dated December 19, 2012, (NOC-AE-12002942) (ML12363A102)

By Reference 1, STP Nuclear Operating Company (STPNOC) submitted a License Renewal Application (LRA) for South Texas Project (STP) Units 1 and 2. By Reference 2, the NRC staff requests additional information for review of the STP LRA. By Reference 3, STPNOC provided a partial response and stated in Reference 4 that a response to the remaining requested information will be provided by February 28, 2014. STPNOC's response to the remaining requested information is provided in Enclosure 1 to this letter. Changes to LRA pages described in Enclosure 1 are depicted as line-in/line-out pages provided in Enclosure 2.

NOC-AE-14003078 Page 2 of 3 One regulatory commitment in Table A4-1 of the LRA is revised and is provided in Enclosure 3. This letter does not contain any other regulatory commitments.

Should you have any questions regarding this letter, please contact either Arden Aldridge, STP License Renewal Project Lead, at (361) 972-8243 or Rafael Gonzales, STP License Renewal Project regulatory point-of-contact, at (361) 972-4779.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on ate G. T. Powell Site Vice President RJG

Enclosures:

1. STPNOC Response to Requests for Additional Information
2. STPNOC LRA Changes with Line-in/Line-out Annotations
3. STPNOC Revised Regulatory Commitment

NOC-AE-14003078 Page 3 of 3 cc:

(paper copy) (electronic copy)

Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Kathryn M. Sutton, Esquire 1600 East Lamar Boulevard Morgan, Lewis & Bockius, LLP Arlington, Texas 76011-4511 Balwant K. Singal John Ragan Senior Project Manager Chris O'Hara U.S. Nuclear Regulatory Commission Jim von Suskil One White Flint North (MS 8B1) NRG South Texas LP 11555 Rockville Pike Rockville, MD 20852 Senior Resident Inspector Kevin Polio U. S. Nuclear Regulatory Commission Richard Pena P. 0. Box 289, Mail Code: MN116 L. D. Blaylock Wadsworth, TX 77483 City Public Service C. M. Canady Peter Nemeth City of Austin Crain Caton & James, P.C.

Electric Utility Department 721 Barton Springs Road C. Mele Austin, TX 78704 City of Austin Jim Collins Robert Free City of Austin Texas Department of State Health Services Electric Utility Department 721 Barton Springs Road Austin, TX 78704 John W. Daily Richard A. Ratliff License Renewal Project Manager (Safety) Robert Free U.S. Nuclear Regulatory Commission Texas Department of State Health Services One White Flint North (MS 011-Fl)

Washington, DC 20555-0001 Tam Tran Balwant K. Singal License Renewal Project Manager John W. Daily (Environmental) Tam Tran U. S. Nuclear Regulatory Commission U. S. Nuclear Regulatory Commission One White Flint North (MS 011 F01)

Washington, DC 20555-0001

Enclosure 1 NOC-AE-14003078 Enclosure 1 STPNOC Response to Requests for Additional Information

Enclosure 1 NOC-AE-14003078 Page 1 of 11 SOUTH TEXAS PROJECT, UNITS I AND 2, REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE SOUTH TEXAS PROJECT, UNITS I AND 2, LICENSE RENEWAL APPLICATION SET 25 (TAC NOS.

ME4936 AND ME4937)

RAI A1-2: Follow-up on Operating Experience Implementation (3.0.5)

Background

By letter dated June 14, 2012, STP Nuclear Operating Company (STPNOC or the applicant) revised license renewal application (LRA) Section Al, which is part of the updated final safety analysis report (UFSAR) supplement, to provide a more detailed description of how operating experience will be reviewed on an ongoing basis to address operating experience concerning age-related degradation and aging management during the terms of the renewed licenses. This summary description identifies several enhancements that will be made to the existing Operating Experience Program and the Corrective Action Program.

Issue LRA Section A4 describes the license renewal commitments and is also part of the UFSAR supplement. Commitment No. 41, as revised by letter dated June 14, 2012, addresses the enhancements that will be made to the Operating Experience Program and the Corrective Action Program and states that they will be implemented by December 31, 2014. LRA Section Al describes the same enhancements but does not state an explicit implementation schedule.

Therefore, the staff is unclear with respect to the applicant's intended implementation schedule.

In addition, the staffs position, as described in Final License Renewal Interim Staff Guidance, LR-ISG-2011-05, "Ongoing Review of Operating Experience," is that any enhancements to the existing operating experience review activities should be put in place no later than the date the renewed operating licenses are issued and implemented on an ongoing basis throughout the terms of the renewed licenses. The December 31, 2014, implementation schedule could be after issuance of the renewed operating licenses. As such, it is not clear how operating experience on age-related degradation and aging management will be considered during the terms of the renewed operation licenses prior to full implementation of the enhancements.

Request Clarify the UFSAR supplement regarding the implementation schedule for the enhancements that will be made to the Operating Experience Program and the Corrective Action Program. If implementation will be after issuance of the renewed operating licenses, provide a justification and include any relevant practical considerations that would impact the implementation timeframe.

STPNOC Response:

Response provided in STPNOC letter dated December 6, 2012, from D. W. Rencurrel to NRC Document Control Desk, "Partial Response to Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2, License Renewal Application - Set 25 (TAC Nos.

ME4936 and ME4937)" (NOC-AE-1 2002907) (ML12359A063).

Enclosure 1 NOC-AE-14003078 Page 2 of 11 RAI 4.3.2.11-6: Follow-up RAI on STP CASS LBB Analysis (060A)

Background

The staff notes that the applicant's current position on the leak-before-break (LBB) evaluation of cast austenitic stainless steel (CASS) piping is that it is not a time-limited aging analysis (TLAA) for STP. Regarding the fracture mechanics calculation in the LBB evaluation of CASS piping, the applicant's response to Part 2 of request for additional information (RAI) 4.3.2.11-2 states:

Although the fracture mechanics calculation considers aging of the material property, aging is not based on the plant life. Aging is based on the minimum material properties possible and the value used by the calculation will be the same whether the plant life is 40 years, 60 years, or 100 years. Therefore, fracture mechanics calculation is not a TLAA in accordance with 10 CFR 54.3(a) Criterion 3.

The response to Part 3 of RAI 4.3.2.11-2 cites a technical report from 1983 (Westinghouse Report WCAP-1046, "The Effects of Thermal Aging on the Structural Integrity of Cast Stainless Steel Piping for Westinghouse Nuclear Steam Supply Systems" as the basis for the saturated fracture toughness assumed in the analyses.

Issue Considerable information has been developed since 1983 to provide improved understanding of thermal embrittlement of CASS materials by 0. Chopra of Argonne National Laboratory, C.

Faidy of Electricit6 de France, and others. See, for example NUREG/CR-4513, Rev. 1 (1994)

"Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems"); Appendix A of draft EPRI report 1024966 "Probabilistic Reliability Model for Thermally Aged Cast Austenitic Stainless Steel Piping"; and ASME paper PVP2010-25085 "Flaw Evaluation in Elbows Through French RSEM Code" by C. Faidy.

Although the RAI response states that the material property aging is based on the "minimum material properties possible," the RAI response does not provide justification to support that statement in light of additional information on thermal aging of CASS over the last 29 years, and, in particular, does not demonstrate that the aging after 60 years of operation is bounded by the thermal embrittlement saturation values assumed in the existing analysis.

Request (1) Provide justification that the assumed saturated fracture toughness in the CASS LBB evaluations bounds the expected toughness at 60 years of operation, considering the information sources cited above and others as necessary.

(2) Specify the information sources used in response to Request (1).

(3) Given the response to request (1), identify any changes necessary to the disposition of the LBB analysis for CASS, for example to demonstrate that the analysis "remains valid for the period of extended operation" or the analysis "has been projected to the end of the period of extended operation."

Enclosure I NOC-AE-14003078 Page 3 of 11 STPNOC Response:

1. Provide justification that the assumed saturated fracture toughness in the CASS LBB evaluations bounds the expected toughness at 60 years of operation, considering the information sources cited above and others as necessary.

The reactor coolant loop (RCL) leak-before-break facture mechanics analysis for STP is documented in Westinghouse report WCAP 10559, Technical Bases for Eliminating the Large Primary Loop Pipe Rupture as the Structural Design Bases for South Texas Project Units 1 and 2 . The reference material fracture toughness properties are shown to bound the fully-aged fracture toughness properties of the STP reactor coolant pressure boundary cast stainless steel by comparing the STP fracture toughness properties and chemistry data from the certified material test reports (CMTRs).

The fracture toughness values were compared to the most recent data for the state of the industry and found to be conservative. The gas tungsten arc welds (GTAW) prepared with Types 308 stainless steel filler materials were compared against the results of NUREG/CR-6428, "Effects of Thermal Aging on Fracture Toughness and Charpy-Impact Strength of Stainless Steel Pipe Welds." The SA-351 Grade CF8A base metal was compared against the results of NUREG/CR-4513, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems." The straight pipe segments are centrifugal castings and the elbows are static castings; therefore the material was conservatively assumed to be static-cast CF-8 steel with ferrite content greater than 15%. Jmax defines the range of applicability of the data used and is not affected by the updated data.

2. Specify the information sources used in response to Request (1).

The response to (1) specifically addresses the following documents:

a. US NRC NUREG/CR-6428. Effects of Thermal Aging on FractureToughness and Charpy-ImpactStrength of Stainless Steel Pipe Welds. Rev. 0. May 1996.
b. US NRC NUREG/CR-4513. Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems. Rev. 1. May 1994.

The response does not specifically address Appendix A of draft EPRI report 1024966 "Probabilistic Reliability Model for Thermally Aged Cast Austenitic Stainless Steel Piping" or ASME Paper PVP2010-25085 "Flaw Evaluation in Elbows Through French RSEM Code."

Appendix A of draft EPRI report 1024966 "Probabilistic Reliability Model for Thermally Aged Cast Austenitic Stainless Steel Piping" is not addressed because:

" The material in the EPRI report is CF8M whereas STP Reactor Coolant Loop (RCL) is CF8A.

  • The EPRI report cites NUREG/CR-4513 as the source of the fully aged material toughness properties.

Enclosure 1 NOC-AE-14003078 Page 4 of 11 ASME Paper PVP2010-25085 "Flaw Evaluation in Elbows Through French RSEM Code" is not addressed because:

" The material in the ASME paper is CF8M whereas STP Reactor Coolant Loop (RCL) is CF8A.

  • The only comparable material in the ASME paper is that of elbow #3, based on the low Mo (Molybdenum) concentration. The J-integral calculated with a 0.2 mm crack extension based on the ASME Paper methods is bounded by the fracture toughness J 1c value used in the STP LBB analysis. A 0.2 mm crack extension was used because the ASTM Specification E 813-85 procedure defines J~c as the intersection of the 0.2-mm offset line with the power-law fit (of the form J = CAan).
3. Given the response to Request (1), identify any changes necessary to the disposition of the LBB analysis for CASS, for example to demonstrate that the analysis "remains valid for the period of extended operation" or the analysis "has been projected to the end of the period of extended operation."

LRA Section 4.3.2.11 is revised to identify the fracture mechanics evaluation as a TLAA and disposition in accordance with 10 CFR 54.21 (c)(1)(i). The position was changed because the fracture mechanics evaluation does consider the thermal embrittlement aging mechanism and is defined by the current operating term. As discussed in response #1 of this RAI, the material fracture toughness properties selected for use in the LBB analysis are sufficiently embrittled that they bound the amount of thermal embrittlement that will occur in 60 years. Therefore this TLAA is valid for the period of extended operation and is dispositioned in accordance with 10 CFR 54.21 (c)(1)(i).

Enclosure 2 provides a line-in/line-out markup of LRA Section 4.3.2.11, Section 4.3.2.11, and Appendix A3.2. 1.11.

RAI B2.1.9-3d (021)

Background

RAI B2.1.9-3 and several follow-up RAls have addressed aging management issues associated with coating degradation in the Essential Cooling Water (ECW) system. In the RAI response dated August 21, 2012, STP provided a comprehensive approach toward addressing this issue. The response states that the current inspection interval of 5 years is being increased to 6 years based on industry and STP operating experience, and that this interval aligns with vendor inspection guidance for in-service coatings and with the 6-year major equipment outage and inspection interval. The response also listed a new component type of "coatings," a new intended function of "maintain coating integrity," and a new aging effect requiring management of "loss of coating integrity."

Enclosure 1 NOC-AE-14003078 Page 5 of 11 Issue

1. Further understanding of the operating experience cited in the previous response is needed to validate the bases for increasing the inspection interval from 5 years to 6 years. NRC resident inspectors noted that, for most of the heat exchanger coating inspections they have witnessed, the coatings required at least some "touch-up", with the "turnaround" areas requiring more repair than other areas. In addition, the scope of STP's operating experience reviews is not clear, given that RAI response dated March 29, 2012, states that procedures need to be enhanced to require that protective coating failures be documented in the corrective action program,
2. The staff noted that the new "maintain coating integrity" intended function was not integrated into LRA Table 2.1-1, "Intended Functions: Abbreviation and Definitions."

Request

1. Provide a summary of the inspection results and repair efforts associated with the five sets of components (i.e., water boxes, coolers, and piping) discussed in RAI response dated August 21, 2012. Provide the approximate amount of missing coating material, including the number of locations requiring repair, and the range of repair sizes. Confirm that the operating experience reviews included inspection results and repair efforts beyond those captured in the corrective action program.
2. Ensure that the appropriate tables in the LRA have been updated to reflect the creation of a new intended function of a new component type with a new aging effect requiring management.

STPNOC Response:

1. STPs response to RAI B2.1.9-3 provided an overview of the site specific and industry operating experience identified during the preparation of the operating experience section of aging management program B2.1.9, Open-Cycle Cooling Water System program. That review assessed plant specific work orders and corrective action documentation and concluded that no significant age degradation was being experienced. Response to RAI B2.1.9-3a further clarified that the site specific operating experience review did not result in any condition reports documenting any coating failures resulting in cooling water heat exchanger tube blockage or fouling (NOC-AE-11002683, ML11181A037, NOC-AE-12002854, ML12138A065).

The inspection documentation was reviewed to address this RAI. The documents record the visually inspected as-found conditions such as: color change, erosion damage, decrease in thickness, cracking, mechanical damage, corrosion, delaminating, and blistering. The table below documents a summary of the historical conditions identified and repaired. More specific conditions, locations and repair sizes are not captured in the documentation, however, it is concluded from the existing operating experience documentation that the majority of the repairs are addressing minor corrosion and mechanical damage locations. STP has reasonable assurance that the 6 year inspection interval will be effective in identifying degradation conditions prior to any adverse impacts on the system as described in STPs responses to related questions in reference 3 of this letter.

Enclosure 1 NOC-AE-14003078 Page 6 of 11 Preventive Maintenance Review:

Component Coating PM#/WAN PM Repair Inspection Results Complete (Y/N)

Date 3V111VCH004 Belzona 97001684/127051 6/17/99 Y 3 small spots of ESSENTIAL corrosion in water box CHILLED Belzona 97001684/189980 4/16/02 Y Small area of coating WATER damage CHILLER Water Belzona 97001684/253315 10/26/04 Y 2 small areas of Box Covers coating damage UNIT 12A Belzona 97001684/304844 5/5/09 N No Issues 3V1 1 1VCH005 Belzona 97001685/127052 6/22/99 N No Issues ESSENTIAL Belzona 97001685/187178 2/27/02 Y Minor coatings CHILLED damage on inlet WATER waterbox CHILLER UNIT Belzona 97001685/320810 5/14/08 Y 2 small areas of 12B corrosion on return header Belzona 97001685/409295 1/16/13 Y Minor corrosion on east channel head 3V1 1 1VCH006 Belzona 97001690/127054 7/27/99 Y 2 small spots of ESSENTIAL superficial corrosion on CHILLED channel head WATER Belzona 97001690/189142 4/4/02 Y Light areas of CHILLER UNIT corrosion at corner of 12C S waterbox Belzona 97001690/252566 5/25/05 Y Minor coating damage on heads Belzona 97001690/316774 5/20/08 Y Minor coating damage on inlet header Belzona 97001690/409649 1/25/13 N No Issues 3V1 12VCH004 Belzona 97001691/127055 2/2/99 Y 6 return header areas ESSENTIAL and 1 outlet area with CHILLED minor coating damage WATER Belzona 97001691/180004 11/6/01 Y Minor coating damage CHILLER UNIT Belzona 97001691/242779 5/18/04 Y Small corrosion spots 22A and minor coating damage Belzona 97001691/296318 1/20/09 Y Minor coating damage on both heads Belzona 97001691/422418 5/9/13 N No Issues

Enclosure 1 NOC-AE-14003078 Page 7 of 11 Component Coating PM#/WAN PM Repair Inspection Results Complete (Y/N)

Date 3V1 12VCH005 Belzona 97001689/127053 1/14/99 Y WO 383522 written to ESSENTIAL repaired minor CHILLED corrosion on inlet cover WATER Belzona WO 383522 12/13/01 Y repaired minor CHILLER UNIT corrosion on inlet cover 22B Belzona 97001689/182366 12/14/01 N No Issues Belzona 97001689/214406 4/30/03 Y Small amounts of corrosion on heads Belzona 97001689/282556 4/26/06 Y Small indication of corrosion at corner of inlet head Belzona 97001689/363048 2/23/11 Y Slight coating damage on inlet head Belzona 97001689/471825 10/31/13 Y Required coating touchup 3V1 12VCH006 Belzona 97001692/127056 1/18/99 N No Issues ESSENTIAL Belzona 97001692/151418 5/8/01 Y Small section of CHILLED coating broken away WATER from flange area of CHILLER UNIT inlet and outlet area 22C Belzona 97001692/231879 5/5/04 N No Issues Belzona 97001692/299936 10/25/07 Y Inlet and outlet heads minor coating damage Belzona 97001692/391453 2/28/13 Y Minor corrosion on chiller heads 3Q151MHX0136 Belzona 99000487/192745 5/17/01 Y Minor coating damage SDG LUBE OIL to head COOLER Belzona 99000487/269869 3/17/06 Y Small corrosion spot on head Belzona 99000487/299936 1/16/11 Y Minor inlet and return waterbox coating touchup 3Q152MHX0136 Belzona 99000489/177922 12/8/00 Y Minor corrosion around SDG LUBE OIL head gasket area COOLER Belzona 99000489/249129 12/1/05 Y Minor corrosion spots on cover Belzona 99000489/353052 6/9/10 Y Minor corrosion spots

Enclosure 1 NOC-AE-14003078 Page 8 of 11 Component Coating PM#/WAN PM Repair Inspection Results Complete (Y/N)

Date 3Q151MHX0236 Belzona 99000490/189565 10/13/00 Y Minor corrosion around SDG LUBE OIL head COOLER Belzona 99000490/261849 5/20/05 Y Minor coating damage to head Belzona 99000490/353204 1/20/10 Y Minor corrosion south end cover 3Q152MHX0236 Belzona 99000491/177923 5/3/03 Y Minor corrosion SDG LUBE OIL Belzona 99000491/272198 4/27/06 Y Minor coating damage COOLER Belzona 99000491/372285 5/18/12 Y Minor corrosion on heads and covers 3Q151MHX0336 Belzona 99000492/161256 7/28/99 Y Minor corrosion on SDG LUBE OIL south end head COOLER Belzona 99000492/181132 5/4/01 Y Minor coating spot repair Belzona 99000492/224263 5/26/05 Y Minor coating damage on cover and flange Belzona 99000492/355325 12/6/09 Y Minor coating damage 3Q152MHX0336 Belzona 99000493/201551 6/6/02 Y Minor corrosion on SDG LUBE OIL cover COOLER Belzona 99000493/290202 11/15/07 Y South Channel Head has corrosion Belzona 99000493/392215 2/28/13 Y Minor corrosion on inside cover 3Q151MHX0134 Belzona 99000474/192744 5/17/01 Y Minor coating damage SDG JACKET to head WATER Belzona 99000474/269868 3/17/06 Y Minor corrosion on COOLER head Belzona 99000474/371684 1/16/11 Y Minor coating repair on south cover 3Q152MHX0134 Belzona 99000480/177919 12/8/00 Y Minor corrosion on SDG JACKET gasket surface area WATER Belzona 99000480/249128 12/1/05 Y Minor corrosion COOLER Belzona 99000480/353051 6/9/10 Y Minor corrosion 3Q151MHX0234 Belzona 99000483/189564 10/12/00 Y Minor corrosion and SDG JACKET crack in coating of WATER head COOLER Belzona 99000483/260684 5/20/05 Y Coating damage on heads Belzona 99000483/353203 1/20/10 Y Minor coating repair south cover

Enclosure 1 NOC-AE-14003078 Page 9 of 11 Component Coating PM#/WAN PM Repair Inspection Results Complete (Y/N)

Date 3Q152MHX0234 Belzona 99000484/203951 5/3/03 Y Minor corrosion areas SDG JACKET Belzona 99000484/272197 4/27/06 Y Minor coating damage WATER Belzona 99000484/372284 5/20/12 Y Corrosion repairs COOLER 3Q151MHX0334 Belzona 99000485/161255 7/28/99 Y Corrosion areas on SDG JACKET south cover WATER Belzona 99000485/181131 5/4/01 Y Spot repairs to coating COOLER Belzona 99000485/224262 5/26/05 Y Minor corrosion Belzona 99000485/355324 12/6/09 Y Slight coating damage south cover 3Q152MHX0334 Belzona 99000486/201550 6/6/02 Y Minor corrosion on SDG JACKET cover WATER Belzona 99000486/290201 11/15/07 Y Minor corrosion spot COOLER on cover coating Belzona 99000486/392214 3/5/13 Y Coating touchup on south cover 3Q151MDG0134 Belzona 91000720/90027472 2/18/91 N No issues DIESEL 91000720//93000532 8/30/93 N No issues GENERATOR 94000812/94005336 3/7/95 N Minor Rust

  1. 11 Intercooler 94000812/95014107 6/1/96 N Minor Rust Water Boxes DG325020 1/30/98 N No issues 99000476/383973 1/14/11 N No issues 3Q152MDG0134 Belzona 91000629/9306120 11/26/93 N No issues DIESEL WO 211039 GENERATOR 94000809/62604 1/6/97 Y Minor Rust
  1. 21 Intercooler CR 97-160 Water Boxes 9400809/94014546 10/26/95 N Minor rust 9400050/135489 2/4/99 N No issues WO 325041,203177,2031 76 99000494/369200 6/12/10 N No issues 3Q151MDG0234 Belzona 90000736/90027471 3/9/91 N No issues DIESEL 90000736/93000135 10/1/93 N No issues GENERATOR 94000810/94005337 3/29/95 N No issues
  1. 12 Intercooler 94000810/95014001 11/11/96 N No issues Water Boxes 325021 2/2/98 N No issues 99000495/353205 1/20/10 N No issues

Enclosure 1 NOC-AE-14003078 Paqe 10 of 11 Component Coating PM#IWAN PM Repair Inspection Results Complete (Y/N)

Date 3Q1 52MDG0234 Belzona 91000630/93036103 4/12/94 N No issues DIESEL 94000808/94014528 10/15/95 N Minor Rust waterbox GENERATOR head

  1. 22 Intercooler 94000808/62603 11/19/96 N No issues Water Boxes 980000503/135418 1/14/99 N No issues WO 325038,325010, 325015 99000496/348114 5/20/12 N No issues 3Q151MDG0334 Belzona 9000737/90027470 1/24/91 N No issues DIESEL 9000737/93000160 11/22/93 N No issues GENERATOR 94000811/94005338 3/30/95 N No issues
  1. 13 Intercooler 94000811/95014120 9/23/96 N No issues Water Boxes WO 325022 2/12/98 Y Minor corrosion spots 99000497/329340 12/6/09 Y Corrosion spots WO 500792 3Q152MDG0334 Belzona 91000631/93036104 12/10/93 N No issues DIESEL Belzona 94000807/62602 1/20/97 N Minor Zink Corrosion GENERATOR Belzona 99000498/314526 11/17/07 Y Corrosion spots
  1. 23 Intercooler WO 462738 Water Boxes Belzona 99000498/419648 3/2/13 Y Blistering on upper and WO 471081 lower heads 3Q151MDG0134 Plasticap 91000720/90027472 2/18/91 N No issues DIESEL 91000720//93000532 8/30/93 N No issues GENERATOR 94000812/94005336 3/7/95 N No issues
  1. 11 Intercooler 94000812/95014107 6/1/96 N No issues Waterbox 325020 1/30/98 N No issues Interconnecting 99000476/383973 1/14/11 N No issues Piping 3Q152MDG0134 Plasticap 91000629/9306120 11/26/93 N No issues DIESEL W0211039 GENERATOR 94000809/62604 1/6/97 Y No issues
  1. 21 Intercooler CR 97-160 Waterbox 9400809/94014546 10/26/95 N No issues Interconnecting 9400050/135489 2/4/99 N No issues Piping WO 325041,203177,2031 76 99000494/369200 6/12/10 N Noissues

Enclosure 1 NOC-AE-14003078 Page 11 of 11 Component Coating PM#/WAN PM Repair Inspection Results Complete (Y/N)

Date 3Q151MDG0234 Plasticap 90000736/90027471 3/9/91 N No issues DIESEL 90000736/93000135 10/1/93 N No issues GENERATOR 94000810/94005337 3/29/95 N No issues

  1. 12 Intercooler 94000810/95014001 11/11/96 N No issues Waterbox 325021 2/2/98 N No issues Interconnecting 99000495/353205 1/20/10 N No issues Piping 3Q152MDG0234 Plasticap 91000630/93036103 4/12/94 N No issues DIESEL 94000808/94014528 10/15/95 N No issues GENERATOR 94000808/62603 11/19/96 N No issues
  1. 22 980000503/135418 1/14/99 N No issues Intercooler WO Waterbox 325038,325010,3250 Interconnecting 15 Piping 99000496/348114 5/20/12 N No issues 3Q151MDG0334 Plasticap 9000737/90027470 1/24/91 N No issues DIESEL 9000737/93000160 11/22/93 N No issues GENERATOR 94000811/94005338 3/30/95 N No issues
  1. 13 94000811/95014120 9/23196 N No issues Intercooler 99000497/329340 12/6/09 N No issues Waterbox Interconnecting Piping 3Q152MDG0334 Plasticap 91000631/93036104 12/10/93 N No issues DIESEL 94000807/62602 1/20/97 N No issues GENERATOR 99000498/314526 11/17/07 N No issues
  1. 23 Intercooler 99000498/419648 3/2/13 N No issues Waterbox Interconnecting Piping
2. NRC question 2 was previously addressed and LRA Table 2.1-1 "Intended Functions" was updated in letter NOC-AE-1 1002763, ML11346A012 to include an intended function abbreviation of MCI "Maintain Coating Integrity". The affected LRA Sections utilizing this function are: LRA Table 2.3.3.9, LRA Table 2.3.3.20, LRA Section 3.3.2.1.9, LRA Section 3.3.2.1.20, LRA Table 3.3.2.9, LRA Table 3.3.2.20, Appendix A1.9, Appendix B2.1.9.
3. The suspension of STP Safety Review activities identified as reference 5 of this letter resulted in implementation activities being delayed. The schedule for Enhancements to the Open-Cycle Cooling Water System program procedures is revised to read "No Later than the date the renewed operating licenses are issued". provides the line-in/line-out revision to LRA Table A4-1 Commitment No. 4.

Enclosure 2 NOC-AE-14003078 Enclosure 2 STPNOC LRA Changes with Line-inlLine-out Annotations

Enclosure 2 NOC-AE-14003078 Page 1 of 10 List of Revised LRA Sections RAI Affected LRA Section Table 4.1-1 4.3.2.11-2a Section 4.3.2.11 Appendix A3.2.1.11 Appendix B2.1.9

Enclosure 2 NOC-AE-14003078 Page 2 of 10 Chapter 4 TIME-LIMITED AGING ANALYSES Table 4.1-1 List of TLAAs TLAA Disposition Report Category Description Category°') Section

1. Reactor Vessel Neutron Embrittlement Analysis N/A 4.2 Neutron Fluence Values iii 4.2.1 Pressurized Thermal Shock ii 4.2.2 Upper-Shelf Energy (USE) ii 4.2.3 Pressure-Temperature (P-T) Limits iii 4.2.4 Low Temperature Overpressure Protection iii 4.2.5 2 Metal Fatigue Analysis N/A 4.3 Fatigue Management Program N/A 4.3.1

,SME III Class I Fatigue Analysis of Vessels, Piping and N/A 4.3.2 Components Reactor Pressure Vessel, Nozzles, Head, and Studs i, iii 4.3.2.1 Control Rod Drive Mechanism (CRDM) Pressure Housings and Core Exit Thermocouple Nozzle i 4.3.2.2 Assemblies (CETNAs)

Reactor Coolant Pump Pressure Boundary Components i, ii, iii 4.3.2.3 Pressurizer and Pressurizer Nozzles ii,iii 4.3.2.4 Steam Generator ASME III Class 1, Class 2 Secondary iii 4.3.2.5 Side, and Feedwater Nozzle Fatigue Analyses ASME III Class 1 Valves ii,iii 4.3.2.6 ASME III Class 1 Piping and Piping Nozzles iii 4.3.2.7 Response to NRC Bulletin 88-08: Intermittent Thermal Cycles due to Thermal-Cycle-Driven Interface Valve ii 4.3.2.8 Leaks and Similar Cyclic Phenomena Response to NRC Bulletin 88-11: Revised Fatigue Analysis of the Pressurizer Surge Line for Thermal iii 4.3.2.9 Cycling and Stratification High Energy Line Break Postulation Based on Fatigue ii, iii 4.3.2.10 Cumulative Usage Factor Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break i 4.3.2.11 (LBB) Elimination of Dynamic Effects of Primary Loop Piping Failures Class 1 Design of Class 3 Feedwater Control Valves i 4.3.2.12 ASME Section III Subsection NG Fatigue Analysis of iii 4.3.3

_Reactor Pressure Vessel Internals South Texas Project Page 4.1-2 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 3 of 10 Chapter 4 TIME-LIMITED AGING ANALYSES Table 4.1-1 List of TLAAs TLAA Disposition Report Category Description Categoryý') Section

_ffects of the Reactor Coolant System Environment on Fatigue Life of Piping and Components (Generic Safety iii 4.3.4 ssue 190)

Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction Factor in ANSI B31.1 and ASME i 4.3.5 Section III Class 2 and 3 Piping ASME Section III Fatigue Analysis of Metal Bellows and 4.3.6 Expansion Joints _ ,__ii_4_3__

3. Environmental Qualification (EQ) of Electric iii 4.4 Equipment
4. Concrete Containment Tendon Prestress Analysis iii 4.5
5. Containment Liner Plate, Metal Containments, and NIA 4.6 Penetrations Fatigue Analysis Fatigue Waivers for the Personnel Airlocks and 4.6.1 Emergency Airlocks Fatigue Design of Containment Penetrations i, iii 4.6.2
6. Other Plant-Specific Time-Limited Aging Analyses NIA 4.7 Load Cycle Limits of Cranes, Lifts, and Fuel Handling i 4.7.1 Equipment Designed to CMAA-70 n-service Flaw Growth Analyses that Demonstrate N/A 4.7.2 3tructural Stability for 40 years rLAA for the Corrosion Effects in the Essential Cooling 4.7.3 Nater (ECW) System Reactor Vessel Underclad Cracking Analyses i 4.7.4 Reactor Coolant Pump Flywheel Fatigue Crack Growth i 4.7.5

_________,nalysis (i) 10 CFR 54.21(c)(1)(i), Validation: The analyses remain valid for the period of extended operation.

(ii) 10 CFR 54.21(c)(1)(ii), Projection: The analyses have been projected to the end of the period of extended operation.

(iii) 10 CFR 54.21(c)(1)(iii), Aging Management: The effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

N/A Not Applicable: Section heading or no TLAA. Disposition categories are not applicable.

South Texas Project Page 4.1-3 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 4 of 10 Chapter 4 TIME-LIMITED AGING ANALYSES 4.3.2.11 Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break (LBB) Elimination of Dynamic Effects of Primary Loop Piping Failures Summary Description A leak-before-break analysis eliminated the need to postulate longitudinal and circumferential breaks in the reactor coolant system primary loop piping, under a 10 CFR 50.12 exemption.

Elimination of these breaks omitted the need to install pipe whip restraints in the primary loop and eliminated the requirement to design for dynamic (jet and whip) effects of primary loop breaks. The containment pressurization, emergency core cooling system, and environmental qualification large-break design bases were not affected.

NRC approval of the use of leak-before-break in the reactor coolant system primary loop piping was granted with STP SER, NUREG-0781, Supplement No. 2.

Analysis The STP LBB analysis demonstrates that reactor coolant system primary loop pipe breaks are highly unlikely and need not be included in the design basis because flaws in reactor coolant system piping would have significant leaks for extended periods before developing into a large break. Such flaws would be detected by the reactor coolant pressure boundary leak detection system long before they become full size breaks.

Fatigue Crack Growth Analyses The final LBB submittal for STP included a fatigue crack growth assessment for a range of materials at a high stress location bounding the primary coolant system. The submittal concluded that the effects of low and high cycle fatigue on the integrity of primary piping are negligible.

FractureMechanics Evaluation The STP leak-before-break analysis for the primary loop, includes a fracture mechanics evaluation which depends on the crack initiation energy integral, JIN. The primary coolant loops at STP are SA 351 Grade CF8A cast stainless steel, which at PWR operating temperatures is subject to time-dependent thermal embrittlement reducing the JIN integral.

Thermal embrittlement effects depend logarithmically on time (more rapid initially, approaching a saturation value over time). The Westinghouse LBB analysis for the primary loop cites a study which determined the effects of thermal aging on piping integrity for a material at thermal embrittlement saturation. The fracture mechanics evaluation considers the thermal embrittlement aging mechanism and is defined by the current operating term. Therefore the fracture mechanics evaluation is a TLAA.

Effects of Power Uprate and Steam Generator Replacement on the LBB Analysis The Westinghouse power uprate report determined that power uprate had no effects on the LBB analysis for the primary loop piping, the pressurizer surge line, or the accumulator lines. (The pressurizer sur-ge line and the accumulator lines are addressed in Section 4.3.2.10 in the discussion on the increase in the CUF for break consideration.) Westinghouse determined that South Texas Project Page 4.3-4 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 5 of 10 Chapter 4 TIME-LIMITED AGING ANALYSES the conclusions of the previous LBB analysis for the reactor coolant piping, pressurizer surge line, and accumulator lines remain valid after steam generator replacement.

Disposition: Validation, 10 CFR 54.21(c)(1)(i) and Aging Management, 10 CFR 54.21(c)(1)(iii)

Acino Managiementof the Fatique Crack Growth Analysis The LBB analysis found that fatigue crack growth effects will be negligible. The basis for evaluation of fatigue crack growth effects in the LBB analysis will remain unchanged so long as the number of transient occurrences remains below the number assumed for the analysis of fatigue crack growth effects.

The Metal Fatigue of the Reactor Coolant Pressure Boundary program described in Section 4.3.1 and B3.1 ensures that the numbers of transients remain below the number actually experienced during the period of extended operation remain below the assumed number; or that appropriate corrective actions maintain the design and licensing basis by other acceptable means. The effects of fatigue will therefore be managed for the period of extended operation. This TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(iii). Continuation of the 10 CFR 50.12 LBB exemption is therefore justified for the period of extended operation.

Validation of the FractureMechanics Evaluation The material fracture tougqhness properties selected for use in the LBB analysis are sufficiently embrittled that they bound the amount of thermal embrittlement that will occur in 60 years.

Therefore this TLAA is valid for the period of extended operation and is dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

South Texas Project Page 4.3-5 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 6 of 10 A3.2.1.11 Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break (LBB) Elimination of Dynamic Effects of Primary Loop Piping Failures A leak-before-break analysis eliminated the need to postulate longitudinal and circumferential breaks in the reactor coolant system primary loop piping. Elimination of these breaks omitted the need to install pipe whip restraints in the primary loop and eliminated the requirement to design for dynamic (jet and whip) effects of primary loop breaks. The containment pressurization, emergency core cooling system, and environmental qualification large-break design bases were not affected.

Aging Mana-gement of the Fatigue Crack Growth Analysis The final LBB submittal for STP included a fatigue crack growth assessment for a range of materials at a high stress locations bounding the primary coolant system. The LBB analysis found that fatigue crack growth effects will be negligible. The basis for evaluation of fatigue crack growth effects in the LBB analysis will remain unchanged so long as the number of transient occurrences remains below the number assumed for the analysis of fatigue crack growth effects.

The Metal Fatigue of Reactor Coolant Pressure Boundary program, described in Section A2.1, ensures that the numbers of transients actually experienced during the period of extended operation remain below the assumed number; or that appropriate corrective actions maintain the design and licensing basis by other acceptable means. The effects of fatigue will therefore be managed for the period of extended operation. This TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(iii).

Validation of the FractureMechanics Evaluation The STP leak-before-break analysis for the primary loop, includes a fracture mechanics evaluation which depends on the crack initiation energy integral, JIN. The material fracture toughness properties selected for use in the LBB analysis are sufficiently embrittled that they bound the amount of thermal embrittlement that will occur in 60 years. Therefore this TLAA is valid for the period of extended operation and is dispositioned in accordance with 10 CFR 54.21 (c)(1)(i).

South Texas Project Page 4.3-6 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 7 of 10 B2.1.9 Open-Cycle Cooling Water System Program Description The Open-Cycle Cooling Water (OCCW) System program manages loss of material and reduction of heat transfer for components in scope of license renewal and exposed to the raw water of the essential cooling water (ECW) and essential cooling water screen wash system.

The program includes surveillance techniques and control techniques to manage aging effects caused by biofouling, corrosion, erosion, cavitation erosion, protective coating failures and silting in components of the ECW system, and structures and components serviced by the ECW system, that are in scope of license renewal. The program also includes periodic inspections to monitor aging effects on the OCCW structures, systems and components, component cooling water heat exchanger performance testing, and inspections of the other safety related heat exchangers cooled by the ECW System, to ensure that the effects of aging on OCCW components are adequately managed for the period of extended operation. The program also includes inspections of a sample of ECW piping for wall thickness prior to the period of extended operation. Subsequent inspections will be scheduled based on the results of the initial inspections. The plant specific configuration of the aluminum-bronze piping inserted inside the slip-on flange downstream of the CCW heat exchanger is inspected at a nominal 216 week interval. An engineering evaluation is performed after each inspection. If the calculated wear over the next inspection interval indicates that the aluminum-bronze piping wall will reduce to a thickness of less than minimum wall thickness plus margin (four years of wear at the actual yearly wear rate), then the pipe will be repaired or replaced in accordance with the corrective action program. Components within the scope of the OCCW System program are: 1) components of the ECW system that are in scope of license renewal and

2) the safety-related heat exchangers cooled by the ECW system: component cooling water heat exchangers, standby diesel generator (SDG) jacket water heat exchangers, (SDG) lube oil coolers, (SDG) intercoolers, essential chiller condensers, and component cooling water pump supplementary coolers. The program is consistent with STPNOC commitments established in responses to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Components.

The surveillance techniques utilized in the Open-Cycle Cooling Water System program include visual inspection, volumetric inspection, and thermal and hydraulic performance monitoring of heat exchangers. The control techniques utilized in the Open-Cycle Cooling Water System program include (1) water chemistry controls to mitigate the potential for the development of aggressive cooling water conditions, (2) flushes and (3) physical and/or chemical cleaning of heat exchangers and of the ECW pump suction bay to remove fouling and to reduce the potential sources of fouling.

Coating installed to mitigate corrosion of the essential chiller water box covers, SDG jacket water coolers, SDG lube oil coolers, SDG intercooler water boxes and interconnection piping are inspected and tested to assure coating integrity. The coatings are visually inspected every six years, and tested after 12 years of service at a six year frequency. The coating tests performed are low voltage holiday test per ASTM D5162, dry film thickness test per ASTM D7091 and Steel Structures Painting Council (SSPC) PA-2 and pull off adhesion test per ASTM D4541. Coating inspections and tests are performed by a qualified Nuclear Coating Specialist (NCS) as defined by ASTM D7108 or by Coatings Surveillance Personnel (CSP) under the technical direction of the NCS.

South Texas Project Page 4.3-7 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 8 of 10 Additional measures used to manage loss of material due to selective leaching for aluminum bronze components in the ECW system are detailed in the plant-specific aging management program Selective Leaching of Aluminum Bronze (B2.1.37).

NUREG-1801 Consistency The Open-Cycle Cooling Water System program is an existing program that, following enhancement, will be consistent with exception to NUREG-1 801,Section XI.M20, Open-Cycle Cooling Water System.

Exceptions to NUREG-1801 Program Elements Affected:

Preventive Actions (Element 2), ParametersMonitored or Inspected (Element 3), Detection of Aging Effects (Element 4)

NUREG-1801,Section XI.M20, Elements 2, 3 and 4, provide for a program of flushing and inspection to confirm that fouling and degradation of surfaces is not occurring. An exception is taken to flushing the ECW train cross-tie dead legs and inspecting the interior of these lines.

Instead, the external surfaces of the cross-tie lines are included in the six month dealloying visual external inspection walkdowns. The cross-tie valves and piping are also included in the essential cooling water system inservice pressure test, which includes VT-2 inspections of these components. Measures used to manage loss of material due to selective leaching are detailed in the Selective Leaching of Aluminum Bronze program (B2.1.37). These inspections and tests provide confidence in the ability to detect leakage in the piping and valves. The cross-tie lines do not have an intended function and are not required for any accident scenario within the design basis of the plant. The cross-tie valves are maintained locked closed.

Enhancements Prior to the period of extended operation, the following enhancements will be implemented in the following program elements:

ParametersMonitored or Inspected (Element 3) and Detection of Aging Effects (Element 4)

Procedures will be enhanced to include visual inspection of the strainer inlet area and the interior surfaces of the adjacent upstream and downstream piping. Material wastage, dimensional change, discoloration, and discontinuities in surface texture will be identified.

These inspections will provide visual evidence of loss of material and fouling in the ECW system and serve as an indicator of the condition of the interior of ECW system piping components otherwise inaccessible for visual inspection. Procedures will also be enhanced to include the acceptance criteria for this visual inspection.

South Texas Project Page 4.3-8 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 9 of 10 Scope (Element 1), ParametersMonitored or Inspected (Element 3), Detection of Aging Effects (Element 4), and Monitoring and Trending (Element 5)

Procedures will be enhanced to require a minimum of 25 ECW piping locations be measured for wall thickness. Selected areas will include locations that are considered to have the highest corrosion rates, such as areas with stagnant flow.

Procedures will be enhanced to require an engineering evaluation after each inspection of the aluminum-bronze piping inserted inside the slip-on flange downstream of the CCW heat exchanger. The engineering evaluation will calculate wear over the next inspection interval using a margin of four years of wear at the actual yearly wear rate. Corrective action in accordance with the corrective action program will be initiated ifthe calculated wear indicates that the aluminum-bronze piping wall will reduce to a thickness of less than minimum wall thickness plus margin (four years of wear at the actual yearly wear rate).

Corrective Actions (Element 7)

Procedures will be enhanced to require loss of material in piping and protective coating failures be documented in the corrective action program. The resolution will include an engineering evaluation of the condition.

No later than the date the renewed operating licenses are issued PriOr to the next acheduled S.npe.tOn. in 2013 the following enhancements to coatings will be implemented ParametersMonitored or Inspected (Element 3) and Detection of Aging Effects (Element 4)

Procedures will be enhanced to inspect and test coatings for loss of coating integrity. The coatings installed to mitigate corrosion of the essential chiller water box covers, SDG jacket water coolers, SDG lube oil coolers, SDG intercooler water boxes and interconnection piping are visually inspected every six years, and tested after 12 years of service at a six year frequency. The coating tests performed are low voltage holiday test per ASTM D5162, dry film thickness test per ASTM D7091 and Steel Structures Painting Council (SSPC) PA-2, and pull off adhesion test per ASTM D4541. Coating inspections and tests are performed by a qualified Nuclear Coating Specialist (NCS) as defined by ASTM D7108 or by Coatings Surveillance Personnel (CSP) under the technical direction of the NCS.

Operating Experience Industry operating experience evaluations, Maintenance Rule Periodic Assessments, and OCCW component performance testing results have shown that the effects of aging are being adequately managed.

A review of the STP plant specific operating experience indicates that macrofouling, general corrosion, erosion corrosion, and cavitation erosion have been observed in aluminum bronze components.

South Texas Project Page 4.3-9 License Renewal Application

Enclosure 2 NOC-AE-14003078 Page 10 of 10 In 2001, plant inspections of the ECW pumps revealed signs of flow erosion and corrosion on the pump internal and external surfaces. The pump vendor recommended application of Belzona coating to provide protection against erosion and corrosion and the coating was applied to the internal wetted surfaces of all ECW pumps. Use of Belzona has improved pump performance and service life of the components.

In May 2005, damage was discovered in the slip-on flange immediately downstream of the component cooling water heat exchanger 1B ECW return throttle valve. The damage was due to cavitation erosion. The corresponding locations in the other ECW trains were inspected.

The damaged areas of all six trains were replaced or reworked in accordance with the applicable codes and piping specifications. A design modification was performed to coat the affected areas with Belzona, and PMs were generated to perform regular inspections. The use of Belzona for mitigating cavitation erosion has been successful in prolonging service life of the components.

The OCCW System program operating experience information provides objective evidence to support the conclusion that the effects of aging are adequately managed so that the structure and component intended functions are maintained during the period of extended operation.

NRC Generic Letter 89-13 was based on industry operating experience and forms the basis for the STP OCCW System program.

Conclusion The continued implementation of the Open-Cycle Cooling Water System program will provide reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

South Texas Project Page 4.3-10 License Renewal Application

Enclosure 3 NOC-AE-14003078 Enclosure 3 Regulatory Commitments South Texas Project Page 4.3-1 License Renewal Application

Enclosure 3 NOC-AE-14003078 Page 1 of 2 A4 LICENSE RENEWAL COMMITMENTS Table A4-1 identifies proposed actions committed to by STPNOC for STP Units 1 and 2 in its License Renewal Application. These and other actions are proposed regulatory commitments. This list will be revised, as necessary, in subsequent amendments to reflect changes resulting from NRC questions and STPNOC responses. STPNOC will utilize the STP commitment tracking system to track regulatory commitments. The Condition Report (CR) number in the Implementation Schedule column of the table is for STPNOC tracking purposes and is not part of the amended LRA.

Table A4-1 License Renewal Commitments Commitment LRA Implementation Section Schedule 4 Enhance the Open-Cycle Cooling Water System program procedures to: B2.1.9 Prior to the period of

  • include visual inspection of the strainer inlet area and the interior surfaces of the extended operation adjacent upstream and downstream piping. Material wastage, dimensional change, discoloration, and discontinuities in surface texture will be identified. These inspections CR 10-23256 will provide visual evidence of loss of material and fouling in the ECW system and serve as an indicator of the condition of the interior of ECW system piping components otherwise inaccessible for visual inspection.
  • include the acceptance criteria for this visual inspection.
  • require a minimum of 25 ECW piping locations be measured for wall thickness prior to the period of extended operation. Selected areas will include locations considered to have the highest corrosion rates, such as areas with stagnant flow.
  • require an engineering evaluation after each inspection of the aluminum-bronze piping inserted inside the slip-on flange downstream of the CGW heat exchanger, o require the engineering evaluation calculated wear over the next inspection interval using a margin of four years of wear at the actual yearly wear rate, o require corrective action in accordance with the corrective action program be initiated ifthe calculated wear indicates that the aluminum-bronze piping wall will reduce to a thickness of less than minimum wall thickness plus margin (four years of wear at the actual yearly wear rate),
  • require loss of material in piping and protective coating failures be documented in the Corrective action program, and

Enclosure 3 NOC-AE-14003078 Page 2 of 2 Table A4-1 License Renewal Commitments Item # Commitment LRA Implementation Section Schedule protective coating failures is identified.

Enhance the Open-Cycle Cooling Water System program procedures to:

" visually inspect every six years, and test after 12 years of service at a six year frequency Prior to the next the coating applied on the essential chiller water box covers, standby diesel generator scheduled insp.ction (SDG) jacket water coolers, SDG lube oil coolers, SDG intercoolers and interconnection piping. The coating test performed are low voltage holiday test per ASTM D5162, dry film thickness test per ASTM D7091 and Steel Structures Painting Council (SSPC) PA-2 No Later than the date and pull off adhesion test per ASTM D4541, the renewed operating

" require coating inspections and tests be performed by a qualified Nuclear Coating licenses are issued Specialist (NCS) as defined by ASTM D7108 or by Coatings Surveillance Personnel (CSP) under the technical direction of the NCS.

South Texas Project Page 4.3-2 License Renewal Application

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