ML14163A020

Response to Requests for Additional Information for Review of the License Renewal Application - Set 27

ML14163A020
Person / Time
Site:	South Texas
Issue date:	06/03/2014
From:	Gerry Powell South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-14003141, STI: 33880509, TAC ME4936, TAC ME4937
Download: ML14163A020 (137)

Text

Nuclear Operating Company South Tezas Project Electric GeneratinS Station P.. & v 289, Wadsworth, Texas 77483 June 3, 2014 NOC-AE-14003141 10 CFR 54 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 Amplication - Set 27 (TAC Nos. ME4936 and ME4937)

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References:

1. Letter from G. T. Powell, STPNOC, to NRC Document Control Desk, "License Renewal Application", dated October 25, 2010 (NOC-AE-1 0002607)

(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 27 (TAC Nos. ME4936 and ME4937)", March 6, 2014 (ML14050A172)

(AE-NOC-1 4002505)

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 requested additional information for review of the STPNOC LRA.

STPNOC's response to the requests for additional information and its review of ISG 2011-03, "Buried Piping" 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.

Changes to regulatory commitment schedules were added to Table A4-1 of the LRA and is provided in Enclosure 3 to this letter. There are no other regulatory commitments in this letter.

STI: 33880509

NOC-AE-14003141 Page 2 of 3 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 J-t g. Zoi4 Date G.T. Powell Site Vice President RJG

Enclosures:

1.

2.

3.

STPNOC Response to Requests for Additional Information STPNOC LRA Changes with Line-in/Line-out Annotations STPNOC Regulatory Commitments

NOC-AE-14003141 Page 3 of 3 cc:

(paper copy)

(electronic copy)

Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 1600 East Lamar Boulevard Arlington, Texas 76011-4511 Balwant K. Singal Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint North (MS 8B1) 11555 Rockville Pike Rockville, MD 20852 Senior Resident Inspector U. S. Nuclear Regulatory Commission P. O. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 Jim Collins City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 John W. Daily License Renewal Project Manager (Safety)

U.S. Nuclear Regulatory Commission One White Flint North (MS 011-Fl)

Washington, DC 20555-0001 Tam Tran License Renewal Project Manager (Environmental)

U. S. Nuclear Regulatory Commission One White Flint North (MS 011 F01)

Washington, DC 20555-0001 A. H. Gutterman, Esquire Kathryn M. Sutton, Esquire Morgan, Lewis & Bockius, LLP John Ragan Chris O'Hara Jim von Suskil NRG South Texas LP Kevin Polio Cris Eugster L.D. Blaylock CPS Energy Peter Nemeth Crain Caton & James, P.C.

C. Mele City of Austin Robert Free Texas Department of State Health Services Richard A. Ratliff Alice Rogers Texas Department of State Health Services Balwant K. Singal John W. Daily Tam Tran U. S. Nuclear Regulatory Commission NOC-AE-1 4003141 STPNOC Response to Requests for Additional Information NOC-AE-14003141 Page 1 of 18 SOUTH TEXAS PROJECT, UNITS 1 AND 2, REQUEST FOR ADDITIONAL INFORMATION

- SET 27 (TAC NOS. ME4936 AND ME4937)

RAI A.1-3, License Renewal Comments and the UFSAR

Background:

By letter dated October 25, 2010, STP Nuclear Operating Company (STPNOC or the applicant) submitted an application pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Part 54, to renew operating licenses NPF-76 and NPF.BO for South Texas Project, Units 1 and 2. for review by the U.S. Nuclear Regulatory Commission (NRC) staff.

The staff of NRC is reviewing this application in accordance with the guidance in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants." By letter dated February 15, 2013, the NRC provided the 'Safety Evaluation Report with Open Items Related to the License Renewal of South Texas Project, Units 1 and 2" (SER), and requested that STPNOC review the SER and provide comments to the NRC staff. During the review of the STPNOC license renewal application (LRA) by the NRC staff STPNOC made commitments related to aging management programs, aging management reviews, and time-limited aging analyses, as applicable, related to managing the aging effects of structures and components prior to the period o f extended operation (PEO). The list of these commitments, as well as the implementation schedules and the sources for each commitment was included as a table in Appendix A to the SER with Open Items.

In Section 1.7, "'Summary of Proposed License Conditions" of the SER with Open Items, the staff stated that following its review of the LRA including subsequent information and clarifications provided by the applicant, it identified proposed license conditions. The first license condition requires the applicant to include the updated final safety analysis report (UFSAR) supplement, required by 10 CFR 54.21(d) In the next UFSAR update, required by 10 CFR 50.71(e), following the issuance of the renewed licenses. It states that the applicant may make changes to the programs and activities described in the UFSAR supplement provided the applicant evaluates such changes in accordance with the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

The second license condition will state, in part, that the applicant's UFSAR supplement describes certain programs to be implemented and activities to be completed prior to the PEO and that the applicant shall implement those new programs and enhancements to existing programs as noted in certain commitments no later than 6 months prior to the PEO.

The specific license condition will also state that the applicant shall complete those activities as noted in certain commitments by the 6 month date prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later. Finally, the specific license condition will state that the applicant shall notify the NRC in writing within 30 days of implementing the programs, and include the status of those activities to be completed by the NOC-AE-14003141 Page 2 of 18 6 month date prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The NRC plans to revise Appendix A of the SER to align with this guidance and to reformat the license condition to be as follows:

The UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised during the license renewal application review process, and as supplemented by Appendix A of NUREG (XXXX). "Safety Evaluation Report Related to the License Renewal of South Texas Project, Units 1 and 2" dated (Month Year),

describes certain programs to be implemented and activities to be completed prior to the PEO.

a) The licensee shall implement those new programs and enhancements to existing programs no later than 6 months prior to

PEO, b) The licensee shall complete those inspection and testing activities, as noted in Commitment Nos. x through xx of Appendix A of NUREG XXXX, by the 6-month date prior to PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The licensee shall notify the NRC in writing within 30 days after having accomplished item (a) above and include the status of those activities that have been or remain to be completed in item (b) above.

The staff also notes that in the course of its evaluating multiple commitments to be implemented in the future in order to arrive at a conclusion of reasonable assurance that requirements of 10 CFR 54.29(a) have been met, these license renewal commitments must be incorporated either into a license condition or into a mandated licensing basis document, such as the UFSAR. Those commitments that are incorporated into the UFSAR are typically done so by incorporating each one verbatim (or by a summary and a commitment reference number) into the respective UFSAR summaries in the applicant's LRA Appendix A.

Issue:

As proposed by the applicant and as reflected in the SER Appendix A, the implementation schedule for some commitments may conflict with the implementation schedule intended by the proposed revision to the license condition. In addition, these licensing commitments need to be incorporated either into a license condition or into the applicant's UFSAR summary in such a manner as discussed above.

Request:

1. Identify those commitments to implement new programs and enhancements to existing programs. Indicate the expected date for completing the implementation of each of these programs and enhancements.

2.

Identify those commitments to complete inspection or testing activities prior to the PEO.

Indicate the expected dates for the completion of each of these inspection and testing activities.

NOC-AE-14003141 Page 3 of 18

3.

For each commitment in the SER Appendix A, Identify where and how STPNOC proposes that it be incorporated into either a license condition or into the STP UFSAR.

STPNOC Response: (RAI A.1-3, License Renewal Comments and the UFSAR)

1. LRA, Section AO, "Appendix A Introduction," LRA Table A4-1, and LRA Appendix B1.2 have been revised to indicate when the commitments to implement new programs and enhancements to existing programs will be completed. Specifically, implementation of new programs and enhancements to existing programs no later than 6 months prior to period of extended operation (PEO).

2.

LRA, Section AO, "Appendix A Introduction," LRA Table A4-1, and LRA Appendix B13.2 have been revised to indicate when the inspection and testing activities will be completed. Specifically, inspection and testing activities will be completed by the 6-month date prior to PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

3.

LRA, Section AO, "Appendix A Introduction," is updated to state that (LRA) Section A4 contains summary descriptions of license renewal commitments. These summary descriptions of aging management programs, time-limited aging analyses, and license renewal commitments will be incorporated in the STP UFSAR Update following issuance of the renewed operating license in accordance with 10 CFR 50.71(e). provides the line-in/line-out revision to LRA, Section AO, "Appendix A Introduction,"

and LRA Appendix B1.2. provides the line-in/out revision to LRA Table A4-1 for License Renewal Commitments.

RAI 3.0.3.1, Guidance from LR-ISG-2012-02 Backcqround:

Recent industry operating experience (OE) and questions raised during the staff's review of several LRAs has resulted in the staff concluding that several aging management programs (AMP) and aging management review (AMR) items in the LRA may not or do not account for OE involving aging effects such as recurring internal corrosion, corrosion under insulation, and flow blockage in fire water system components. In order to provide updated guidance, the NRC staff has issued LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" (Agency Wide Documents Access and Management System (ADAMS)

Accession No. ML13227A361).

NOC-AE-14003141 Page 4 of 18 Issue:

The staff noted that the applicant may not have incorporated the updated guidance into its AMPs.

Request:

Please provide details on how the updated guidance of LR-ISG-2012-02 has been accounted for in your AMPs and AMR Tables or provide adequate justification why incorporation is not required.

STPNOC Response: (RAI 3.0.3-1 Guidance from LR-ISG-2012-02)

The following provides the details on how STP is applying the updated guidance of LR-ISG-2012-02 to the License Renewal Application aging management programs (AMPs) and aging management review (AMR) tables.

A. Recurring Internal Corrosion The past ten years of plant operating experience was reviewed to identify if recurring internal corrosion is occurring in raw water or wastewater environments. Recurring internal corrosion is identified by both the number of occurrences of internal aging effects with the same aging mechanism and the extent of degradation at each localized site. Internal corrosion is classified as recurring where, Operating experience found one or more case of internal corrosion per refueling outage that has occurred over three or more sequential or non-sequential cycles in 10 years, or one or more case of internal corrosion per refueling outage that has occurred over two or more sequential or non-sequential cycles in 5 years, and the component did not meet plant specific acceptance criteria, or reduction in wall thickness is greater than 50 percent regardless of the minimum wall thickness.

The following is the results of the plant operating experience review for systems exposed to raw water or wastewater environments.

Component Cooling Water, no recurring internal corrosion was identified.

Chilled Water HVAC, no recurring internal corrosion was identified.

Standby Diesel Generator, no recurring internal corrosion was identified.

Nonradioactive Waste Plumbing Drains & Sumps, no recurring internal corrosion was identified.

Radioactive Vents & Drains, no recurring internal corrosion was identified.

Essential Cooling Pond Makeup, no recurring internal corrosion was identified.

Essential Cooling Water & ECW Screen Wash, recurring selective leaching was identified on the aluminum bronze components exposed to the raw water environment.

Fire Protection, recurring internal corrosion was identified on the carbon steel, and cast iron components exposed to the raw water environment.

Non-radioactive Chemical Waste, no recurring internal corrosion was identified.

Open Loop Aux Cooling, only a small portion of this system is in-scope for (a)(2), no recurring internal corrosion was identified in the in-scope portion.

Oily Waste, no recurring internal corrosion was identified.

NOC-AE-14003141 Page 5 of 18 Liquid Waste Processing, no recurring internal corrosion was identified.

Solid Waste Processing, no recurring internal corrosion was identified.

Recurring internal selective leaching of the aluminum bronze components in the Essential Cooling Water & ECW Screen Wash systems is managed by a plant specific aging management program B2.1.37, Selective Leaching of Aluminum Bronze program.

Recurring internal corrosion of the steel fire protection components is managed by aging management program B2.1.13, Fire Water System program. LRA Table 3.3.2-17 is revised to add an aging evaluation line for recurring internal corrosion for carbon steel and cast iron components. LRA Appendix Al.13, Appendix B2.1.13, Table A4-1 Commitment 8 and LRA Basis Document AMP XI.M27 (B2.1.13), Fire Water System program are revised to perform testing and inspection as recommended in LR-ISG-2012-02 for aging management program NUREG 1801 XI.M27, Fire Water Systems. provides the line-in/out revision to LRA Table 3.3.2-17, LRA Section 3.3.2.1.17, Appendices A1.13, and B2.1.13. provides the line-in/out revision to LRA Table A4-1 for LRA Commitment 8.

B. Representative Minimum Sample Size for Periodic Inspections in GALL AMP XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components LRA Appendix A1.22, Appendix B2.1.22, and LRA Basis Document AMP XI.M38 (B2.1.22),

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program are revised as follows to comply with the recommendation of LR-ISG-2012-02.

1 ) The AMP is revised to specify that opportunistic inspections will be supplemented with scheduled inspections. If at a minimum in each 10-year period during the period of extended operation 20 percent up to a maximum of 25 components with the same combination of material, environment and aging effect are not opportunistically inspected. Opportunistic inspections will continue to be performed when the minimum sample size is reached.

2) The AMP is revised to require visual inspection of flexible polymeric components be performed whenever the component surface is accessible.

3) The AMP is revised to augmented visual inspections by physical manipulation of at least 10 percent of accessible surface area of elastomers. provides the line-in/out revision to LRA Appendices A1.22 and B2.1.22.

NOC-AE-14003141 Page 6 of 18 C. Flow blockage of Water-Based Fire Protections System Piping GALL AMP XI.M27, Fire Water Systems The operating experience review indicated that recurring internal corrosion of the steel fire protection component has occurred. Industry operating experience indicates that flow blockage has occurred in dry sprinkler piping that would have resulted in failure of the sprinklers to deliver the required flow to combat a fire. Based on the recommendation of LR-ISG-2012-02 for AMP XI.M27, Fire Water Systems LRA Appendix A1.13, Appendix B2.1.13, and LRA Basis Document XI.M27 (B2.1.13), Fire Water System program are revised as follows.

1) AMP is revised to incorporate the testing recommendations in LR-ISG-2012 AMP XI.M27 Table 4a, Fire Water System Inspection and Testing Recommendations. The revised AMP includes the recommended inspection and test from NFPA 25, 2011 Edition.

2) AMP is revised to remove the alternative of using wall thickness evaluations instead of flow testing and internal inspections. The AMP is revised to only specify flow testing and internal inspections for managing flow blockage.

3) AMP is revised to use follow-up volumetric examinations if internal visual inspections detect surface irregularities that could indicate loss below nominal piping wall thickness.

4) AMP is revised to include augmented test and inspections of normal dry piping segments that cannot be drained or piping segments that allow water to collect. In each of the 5-year interval beginning with the 5-year period before the period of extended operation STP will perform either a flow test or flush sufficient to detect low blockage or will visual inspect 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect. Additionally, volumetric wall thickness inspections are required in each 5-year interval commencing during the period of extended operation, 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect.

5) AMP is revised to require the fire water storage tanks be inspected in accordance with the inspection requirement in NFPA 25, 2011 Edition.

6) AMP is revised to remove the fire detection testing and maintenance requirements.

These components are managed using the preventive maintenance program for active components.

7) AMP is revised to include monitoring of flow rates and that flow testing, internal and external visual inspections are performed. Volumetric wall thickness inspections are conducted on portions of water-based components that are periodically subject to flow but are normally dry.

8) AMP is revised to change the term biofouling to fouling.

LRA Table 3.3.2-17 and LRA Section 3.3.2.1.17 are revised to add AMR lines to manage flow blockage due to fouling and to change the AMP for carbon steel, stainless steel and copper alloy components exposed to plant indoor air (int) from AMP B2.1.22, Inspection of Internal Surfaces in Miscellaneous Piping and Dusting Components to AMP B2.1.13, Fire Water System.

LRA Table A4-1 Item 8 is revised to include the Fire Water System program procedures enhancements for the inspection in accordance with NFPA 25, 2011 Edition.

NOC-AE-14003141 Page 7 of 18 provides the line-in/out revision to LRA Table 3.3.2-17, LRA Section 3.3.2.1.17, Appendices A1.13, and B2.1.13. provides the line-in/out revision to LRA Table A4-1 for LRA Commitment 8.

D. Revisions to the Scope and Inspection Recommendations of GALL Report AMP XI.M29, "Aboveground Metallic Tanks" GALL AMP XI.M29, Aboveground Metallic Tanks, is not credited to manage the aging effects of tanks. STP uses AMP XI.M38 (B2.1.22), Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program to manage the aging effect of tanks.

There are two outdoor tanks (per unit) within the scope of license renewal. These tanks are the auxiliary feedwater storage tank and the fire water storage tank. LRA Table 3.4.2-6 provides aging management details for the auxiliary feedwater storage tank. LRA Table LRA Table 3.3.2-17 provides aging management details for the fire water storage tank.

LRA Appendix A1.22, Appendix B2.1.22, LRA Basis Document XI.M38 (B2.1.22), Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program are revised to confirm the absence of loss of material by performing a volumetric examination of the auxiliary feedwater storage tank bottom from inside of the tank. The volumetric examination will be performed each 10-year period stating 10 years before entering the period of extended operation.

LRA Table 3.4.2-6 is revised to remove the AMR line for Atmosphere/Weather. The auxiliary feedwater storage tank is completely enclosed in concrete and is not exposed to the Atmosphere/Weather environment. Since this tank is not exposed to Atmosphere/Weather environment, the aging effect of cracking is not applicable. The external environment for this tank is encased in concrete as shown on LRA Table 3.4.2-6.

LRA Tables 2.3.3-17 and 3.3.2-17 is revised to inspect the fire water storage tank using AMP B2.1.13, Fire Water System program in accordance with NFPA 25. LRA Appendix Al. 13, Appendix AMP B2.1.13 and LRA Basis Document XI.M27 (B2.1.13), Fire Water System program are revised to inspect the fire water storage tank in accordance with NFPA 25, 2011 Edition Sections 9.2.5.5, 9.2.6 and 9.2.7.

NOC-AE-14003141 Page 8 of 18 Auxiliary Feedwater Storage Tank Ref LRA Table 3.4.2-6 Material Environment Aging Effect AMP Inspection Stainless Dry Gas (Int)

None None None Steel Tanks Side Walls Stainless Secondary Loss of material Water Chemistry One-time inspection Steel Tanks Water (Int)

(B2.1.2) and One-Side Walls Time Inspection (B2.1.16)

Stainless Encased in None None None Steel Tanks Concrete (Ext)

Side Walls Stainless Concrete (Ext)

Loss of material Inspection of Internal Volumetric Steel Tank Surfaces in examination of the Bottom Miscellaneous Piping tank bottom from and Ducting inside the tank each Components 10-year period stating (B2.1.22) 10 years before entering the period of extended operation to confirm the absence of loss of material due to corrosion.

Fire Water Storage Tank Ref LRA Table 3.3.2-17 Material Environment Aging Effect AMP Inspection Carbon Raw Water (Int)

Loss of material Fire Water System Visual inspection Steel (B2.1.13) every 5 years.

Nondestructive ultrasonic readings are taken to evaluate the wall thickness where there is evidence of pitting or corrosion Carbon Atmosphere/

Loss of material Fire Water System Visual inspection Steel Weather (Ext)

(B2.1.13) annually Carbon Concrete (Ext)

Loss of material Fire Water System Bottom thickness Steel Tank (B2.1.13) ultrasonic tests are Bottom performed on each tank during the first 10-year period of extended operation NOC-AE-14003141 Page 9 of 18 Two indoor tanks (per unit) have a volume greater than 100,000 gallons, the safety injection refueling water storage tank and the reactor makeup-water storage tank. These tanks are exposed to an internal environment of water and the tank base sits on concrete. The tanks are designed to near-atmosphere pressures.

LRA Table 3.2.2-4, Safety Injection Refueling Water Storage Tank provides aging management details for the safety injection refueling water storage tank. LRA Table 3.3.2-5, Reactor Water Makeup System provides aging management details for the reactor make-up-water storage tank.

LRA Tables 3.2.2-4 and 3.3.2-5 are revised to add aging management lines for the tank bottoms to manage the loss of material using AMP B2.1.22, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program.

LRA Appendix A1.22, Appendix B2.1.22, and LRA Basis Document XI.M38 (B2.11.22),

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program are revised to confirm the absence of loss of material by performing a volumetric examination of the safety injection refueling water storage tank and reactor makeup-water storage tank bottoms from inside of the tanks. The volumetric examination will be performed each 10-year period stating 10 years before entering the period of extended operation.

Safety Injection Refueling Water Storage Tank Ref LRA Table 3.2.2-4 Material Environment Aging Effect AMP Inspection Stainless Plant Indoor Air Loss of material Inspection of Internal Visual inspection Steel (Int)

Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Stainless Treated Borated Loss of material Water Chemistry One-time inspection Steel Water (Int)

(B2.11.2) and One-Time Inspection (B2.1.16)

Stainless Borated Water None None None Steel Leakage (Ext)

Stainless Plant Indoor Air Cracking External Surfaces See Note 1 Steel (Ext)

Monitoring Program (B2.1.20)

NOC-AE-14003141 Page 10 of 18 Stainless Concrete Loss of material Inspection of Internal Volumetric Steel Tank Surfaces in examination of the Bottom Miscellaneous Piping tank bottom from and Ducting inside the tank each Components (B2.1.22 10-year period stating 10 years before entering the period of extended operation to confirm the absence of loss of material due to corrosion.

Note

1) As stated in RAI B2.1.16-3, for Unit 1 RWST only: Perform a one-time internal tank bottom and side weld inspection to confirm the effectiveness of the corrective actions to repair the leaking tank floor 5 years prior to entering the period of extended operation.

The inspection will include VT-W; PT; and Vacuum Box Test of the floor bottom and side welds.

Reactor Water Makeup Tank Ref LRA Table 3.3.2-5 Material Environment Aging Effect AMP Inspection Stainless Demineralized Loss of material Water Chemistry One-time inspection Steel Water (Int)

(B2.1.2) and One-Time Inspection (B2.1.16)

Stainless Plant Indoor Air Loss of material Inspection of Internal Visual inspection Steel (Int)

Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Stainless Plant Indoor Air None None See Note 1 Steel (Ext)

Stainless Concrete Loss of material Inspection of Internal Volumetric Steel Tank Surfaces in examination of the Bottom Miscellaneous Piping tank bottom from and Ducting inside the tank each Components (B2.1.22 10-year period stating 10 years before entering the period of extended operation to confirm the absence of loss of material due to corrosion.

Note

1) As stated in RAI 3.4.2.6-2, the plant is not within five miles of a saltwater coastline, there are no roads treated with salt in the winter within 1/2 mile of the plant, the soil does not contain more than trace chlorides, there are no chlorine treated water sources NOC-AE-14003141 Page 11 of 18 nearby, and the outdoor environment is not subject to industry pollution. Therefore, cracking is not an applicable aging effect. provides the line-in/out revision to LRA Tables 2.3.3-17, 3.2.2-4, 3.3.2-5, 3.3.2-17 3.4.2-6, Appendices A1.13, A1.22, B2.1.13 and B2.1.22. provides the line-in/out revision to LRA Table A4-1 for LRA Commitment 8.

E. Corrosion Under Insulation LRA Appendix A1.20, Appendix B2.1.20, LRA Basis Document XI.M36 (B2.1.20), External Surfaces Monitoring of Mechanical Components program are revised to perform periodic visual inspects of the exterior surfaces of insulated components exposed to outdoor air or plant indoor air where the indoor component operating temperature is below the dew point. The exterior surfaces visual inspection will be performed 10-years prior to the period of extended operation and if corrosion is detected every 10 years during the period of extended operation. Where no loss of material has occurred or no evidence of stress corrosion cracking has occurred, subsequent inspection (every 10 years) will consist of visual inspections of the insulation jacket or protective outer layer exterior surface for damage. If insulation jacket or protective outer layer damage is observed, the insulation will be removed for inspection of the component exterior surface. For each material type (carbon steel, stainless steel) a minimum of 20 percent of the in-scope piping length or 20 percent of the component service area will be inspected after the insulation has been removed. As an alternate any combination of a minimum 25 1-foot axial length sections and components are inspected for each material type. Inspection locations will focus on components most susceptible to aging because of time in service or severity of operating conditions.

The following table identifies the systems with insulated components that operate below the dew point, and may be exposed to condensation or are exposed to atmosphere weather. LRA table 3.0-1 plant indoor air external environment definition states that plant systems may produce external component surface temperatures at or below the dew point. Plant Indoor Air (External) with condensation is potentially aggressive. As recommended by LR-ISG-2012-002 Section E, the existing aging management evaluations in LRA Tables 3.3.2.6, 3.3.2.7, 3.2.2.9, 3.3.2.10, 3.3.2.11, 3.3.2.12, 3.3.2.17, 3.3.2.19, 3.3.2.24, 3.3.2.27, 3.4.2.1, and 3.4.2.6 for insulated carbon steel components manage the loss of material aging effect using the AMP B2.1.20, External Surfaces Monitoring Program. The existing aging management evaluations in LRA Tables 3.3.2.11 and 3.3.2.12 for insulated stainless steel dust work manage the aging effect loss of material using the AMP B2.1.20, External Surfaces Monitoring Program.

The existing aging management evaluations in LRA Tables 3.3.2.19, 3.3.2.27, 3.4.2.4 and 3.4.2.6 for insulated stainless steel components are revised to manage the loss of material aging effect using the AMP B2.1.20, External Surfaces Monitoring Program. LRA table 3.4.2.6 is revised to add the aging effect of cracking to insulated components exposed to Atmosphere/

Weather. As stated in RAI 3.4.2.6-2, the plant is not within five miles of a saltwater coastline, there are no roads treated with salt in the winter within 1/2 mile of the plant, the soil does not contain more than trace chlorides, there are no chlorine treated water sources nearby, and the outdoor environment is not subject to industry pollution. Therefore, cracking is not an applicable aging effect for insulated stainless steel components exposed to plant indoor air steel.

NOC-AE-14003141 Page 12 of 18 GALL AMP XI.M29, Aboveground Metallic Tanks, is not credited to manage the aging effects of tanks. STP uses AMP XI.M38 (B2.1.22), Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program to manage the aging effect of loss of material for indoor stainless steel tanks. There are no insulated outdoor tanks at STP.

Insulated Components Operating Below the Dew Point or Installed Outdoors System Component Material External LRA Table AMP Id Type Environment AF Piping, piping Carbon Atmosphere/

3.4.2-6 External Surfaces components, and

Steel, Weather (Revised)

Monitoring piping elements Stainless Program Steel (B2.1.20)

BA Piping, piping Carbon Plant Indoor 3.3.2-7 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

CC Piping, piping Carbon Plant Indoor 3.3.2-6 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

CH Piping, piping Carbon Plant Indoor 3.3.2-9 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

CV Piping, piping Carbon Plant Indoor 3.3.2-19 External Surfaces components, and

Steel, Air Monitoring piping elements Stainless Program Steel (B2.1.20)

CV Tanks Carbon Plant Indoor 3.3.2-19 External Surfaces

Steel, Air (Revised)

Monitoring Stainless Program Steel (B2.1.20)

DR Piping, piping Carbon Plant Indoor 3.3.2-24 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

DW Piping, piping Carbon Plant Indoor 3.4.2-4 External Surfaces components, and Steel Air (Revised)

Monitoring piping elements Stainless Program Steel (B2.1.20)

EP Piping, piping Carbon Plant Indoor 3.3.2-27 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

FP Piping, piping Carbon Plant Indoor 3.3.2-17 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

NOC-AE-14003141 Page 13 of 18 System ' Component Material Exteinal

-LRA Table AMP Id Type Envirqnment MS Piping, piping Carbon Plant Indoor 3.4.2-1 External Surfaces components, and Steel Air Monitoring piping elements Program (B2.1.20)

SS Piping, piping Stainless Plant Indoor 3.3.2-27 External Surfaces components, and Steel Air (Revised)

Monitoring piping elements Program (B2.1.20)

HE Ductwork Carbon Plant Indoor 3.3.2-10 External Surfaces Dampers

Steel, Air Monitoring Air Handlers Carbon Ventilation Program Steel Atmosphere (B2.1.20)

HF Ductwork Carbon Plant Indoor 3.3.2-11 External Surfaces Dampers

Steel, Air Monitoring Air Handlers Carbon Ventilation Program Steel Atmosphere (B2.1.20)

(Galvanized)

Stainless Steel HM Ductwork Carbon Plant Indoor 3.3.2-12 External Surfaces Dampers

Steel, Air Monitoring Air Handlers Carbon Program Steel (B2.1.20)

Stainless Steel provides the line-in/out revision to LRA Tables 3.3.2-19, 3.3.2-27, 3.4.2-4, 3.4.2-6, Appendices A1.20 and B2.1.20.

F. External Volumetric Examination of Internal Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, "Buried and Underground Piping and Tanks" The Oily Waste System credits AMP B2.1.22, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components for the inspection of the buried piping internal surfaces. This buried piping has clean outs that allow access to perform inspection specified by AMP B2.1.22.

Revising AMP B2.1.18, Buried and Underground Piping and Tanks to credit the condition of internal surfaces of accessible piping where the material, environment and aging effects are similar is therefore not required. Additionally STP does not credit the use of external volumetric inspections to detect internal corrosion of underground piping.

G. Specific Guidance for Use of the Pressurization Option for Inspecting Elastomers in GALL Report AMP XI.M38 NOC-AE-14003141 Page 14 of 18 STP does not plan to credit the pressurization option for the inspection of elastomers in AMP B2.1.22, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.

STP AMP B2.1.22 uses physical manipulation of at least 10 percent of accessible surface area of elastomers within the scope of the program, when appropriate for the component configuration and material, to detect hardening and loss of strength of elastomers.

H. Miscellaneous Changes LRA Appendix A1.20, Appendix B2.1.20, LRA Basis Document XI.M36 (B2.1.20), External Surfaces Monitoring of Mechanical Components program are revised to specify that visual inspection cover 100 percent of the accessible component. provides the line-in/out revision to LRA Appendices A1.20 and B2.1.20.

LRA Appendix A1.22, Appendix B2.1.22, and LRA Basis Document AMP XI.M38 (B2.1.22),

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program are revised to specify that visual inspections of flexible elastomers components be performed whenever the component surface is accessible. provides the line-in/out revision to LRA Appendices A1.22 and B2.1.22.

The aging effect for the in-scope thermal insulation (calcium silicate and fiberglass) used for reducing heat transfer is revised to Reduced Thermal Insulation Resistance. The insulation aluminum jacketing is installed with a vapor barrier and overlapping edges in accordance with plant procedures to create a drainable surface and prevent in-leakage of moisture. LRA Appendix A1.20, Appendix B2.1.20, and LRA Basis Document XI.M36 (B2.1.20), External Surfaces Monitoring of Mechanical Components program are revised to inspect the insulation aluminum jacketing for damage at a frequency not to exceed one refueling cycle.

LRA Tables 3.1.2-2, 3.3.2-19, 3.4.2-1, 3.4.2-3 and 3.4.2-5, and LRA Sections 3.1.2.1.2, 3.3.2.1.19, 3.4.2.1.1, 3.4.2.1.3, and 3.4.2.1.5 are revised to add the aging effect of Reduced Thermal Insulation Resistance managed by AMP XI.M36 (B2.1.20), External Surfaces Monitoring of Mechanical Components program. provides the line-in/out revision to LRA Tables 3.1.2-2, 3.3.2-19, 3.4.2-1, 3.4.2-3, 3.4.2-5, Sections 3.1.2.1.2, 3.3.2.1.19, 3.4.2.1.1, 3.4.2.1.3, and 3.4.2.1.5, Appendices A1.20 and B2.1.20.

NOC-AE-14003141 Page 15 of 18 RAI 3.0.3-2, Loss of coating integrity for Service Level III coatings Backqround:

Recent industry OE and questions raised during the staffs review of several LRAs have resulted in the staff concluding that several AMPs and AMR items in the LRA may not or do not account for loss of coating integrity for Service Level III (augmented) coatings.

Issue:

Industry OE indicates that degraded coatings have resulted in unanticipated or accelerated corrosion of the base metal and degraded performance of downstream components (e.g.,

reduction in flow, drop in pressure, reduction in heat transfer) due to flow blockage. Based on these industry OE examples, the staff has questions related to how the aging effect loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage (e g.,

cavitation damage downstream of a control valve), would be managed for Service level III (augmented) coatings.

For purposes of this RAI, Service Level Ill (augmented) coatings include those used in areas outside the reactor containment whose failure could adversely affect the safety function of a safety-related structures, systems, and components, or applied to the internal surfaces of in-scope components and whose failure could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4(a)(3) (e.g., fire protection, station blackout).

The term "coating" includes inorganic (e.g., zinc-based) or organic {e.g., elastomeric or polymeric) coatings, linings {e.g., rubber, cementitious), and concrete surfacers that are designed to adhere to a component to protect its surface.

1. The terms "paint" and "linings" should be considered as coatings.

The staff believes that to effectively manage loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage of Service Level III (augmented) coatings, an AMP should include:

1. Baseline visual inspections of coatings installed on the interior surfaces of in-scope components should be conducted in the 10-year period prior to the period of extended operation.

2. Subsequent periodic inspections where the interval is based on the baseline inspection results. For example:

a. If no peeling, delamination, blisters, or rusting are observed, and any cracking and flaking has been found acceptable, subsequent inspections could be conducted after multiple refueling outage intervals (e.g., for example six years, or more If the same coatings are in redundant trains and not exposed to turbulent flow)

NOC-AE-14003141 Page 16 of 18

b.

If the inspection results do not meet the above; but a coating specialist has determined that no remediation is required, subsequent inspections could be conducted every other refueling outage interval.

c.

If coating degradation is observed that required repair or replacement, or for newly installed coatings, subsequent inspections should occur at least once during each of the next two refueling outage intervals to establish a performance trend on the coatings.

3. All accessible internal surfaces for tanks and heat exchangers should be inspected.

A representative sample of internally coated piping components not less than 73 1-foot axial length circumferential segments of piping or 50 percent of the total length of each coating material and environment combination should be inspected.

4. Coatings specialists and inspectors should be qualified in accordance with an American Society for Testing and Materials International standard endorsed in RG 1.54. "Service Level 1, 11, and III Protective Coatings Applied to Nuclear Power Plants," including staff guidance associated with a particular standard.

5.

Monitoring and trending should include pre inspection reviews of previous inspection results.

6. The acceptance criteria should include that indications of peeling and delamination are not acceptable. Blistering can be evaluated by a coating specialist; however, physical testing should be conducted to ensure that the blister is completely surrounded by sound coating bonded to the surface.

The "Safety Evaluation Report with Open Items Related to the License Renewal of South Texas Project (STP), Units 1 and 2," Section 3.0.3.2.6, documents the staff position regarding internal coatings for open-cycle cooling water piping. The staff noted that in light of the recent industry operating experience, including loss of coating integrity at STP, further detail, as requested below, is required for these coatings as well as others installed on the internal surfaces of in-scope piping, piping components, heat exchangers, and tanks.

For further information on managing loss of coating integrity, see Draft LR-ISG-2013-01, "Aging Management of Loss of Coaling Integrity for Internal Service Level III (augmented)

Coatings," (ADAMS Accession Number ML13262A442)

Request:

If coatings have been installed on the internal surfaces of in scope components ( i.e.,

piping. piping components, heat exchangers, and tanks), state how loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage will be managed, including:

1. the inspection method

2. the parameters to be inspected

3. when inspections will commence and the frequency of subsequent inspections

4. the extent of inspections and the basis for the extent of inspections if it is not 100 NOC-AE-14003141 Page 17 of 18 percent

5. the training and qualification of individuals involved in coating inspections

6. how trending of coating degradation will be conducted

7. acceptance criteria

8. corrective actions for coatings that do not meet acceptance criteria, and

9. the program(s) that will be augmented to include the above activities If necessary, provide revisions to LRA Section 3, Table 2s, Appendix A, and Appendix B.

STPNOC Response: (RAI 3.0.3-2, Loss of coating integrity for Service Level III coatings)

The following responses address the nine (9) RAI questions as follows:

1. The inspection methods used to inspect coatings are visually inspection of the coatings for deterioration, degradation and erosion. 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.

2. Coatings are inspected for loss of coating integrity caused by blistering, cracking, peeling, delamination physical damage and erosion. LRA tables 3.3.2.9 and 3.3.2.20 identify loss of coating integrity as the aging effect for coatings (Ref STP letter NOC-AE-1 2002897 dated August 21, 2012). LRA Sections 3.3.2.1.4, 3.3.2.1.7 and 3.3.2.1.17, Tables 2.3.3-4, 2.3.3-7, 2.3.2-17, 3.3.2-4, 3.3.2-7, and 3.3.2-17 are revised to identify loss of coating integrity as the aging effect for coatings installed on the internals of in-scope components in the Essential Cooling Water and ECW Screen Wash System, Compressed Air System and Fire Protection System.

3. Except for the EW pump internals, coatings are visual inspected every six years, and tested after 12 years of service at a six-year frequency. The EW pump internals and discharge piping reducer are inspected during the nominal 10-year refurbishment periodicity. Since inspections are presently being performed, baseline visual inspections conducted in the 10 years prior to the period of extended operation are not required.

4. Visually inspect are performed on 100% of the coated internal surfaces. The low voltage holiday test is based on ASTM D5162 requirements. The dry film thickness test is based on ASTM D7091 and SSPC PA-2 requirements and the pull off adhesion test is based on ASTM D4541 requirements.

5. 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.

NOC-AE-14003141 Page 18 of 18

6. Monitoring and trending of coatings is based on a pre-inspection review of the previous inspections results including any subsequent repairs activities. The coatings specialist will prepare a post-inspection report that includes a list and location of all areas of deterioration. Where possible, photographic documentation indexed to inspection locations are to be obtained.

7. The acceptance criteria for coatings are that no erosion, corrosion, cavitation erosion, flaking or peeling of the coatings is observed. Coatings not meeting these criteria are considered degraded and a condition report is initiated to document and resolve the concern.

8. Coatings not meeting the acceptance criteria described in item 7 above are repaired as needed.

9. The following revisions are made to the aging management programs to include activities for managing coating installed on the internals of in-scope components.

LRA Appendix A1.9, Appendix B2.1.9, Table A4-1 Commitment 4 and LRA Basis Document AMP XI.M20 Open Cycle Cooling Water System program are revised to include monitoring and trending of coatings degradation.

LRA Appendix B2.1.9, Table A4-1 Commitment 4 and LRA Basis Document AMP XI.M20 Open Cycle Cooling Water System program are revised to include the acceptance criteria for coatings.

See STP letter NOC-AE-12002897 dated August 21, 2012 ML12248A148 for the other activities related to managing coating integrity in LRA Appendix A1.9, Appendix B2.1.9, Table A4-1 Commitment 4 and LRA Basis Document AMP XI.M20 Open Cycle Cooling Water System.

LRA Appendices Al.13, A1.22, B2.1.13 and B2.1.22, Table A4-1 Commitment 4 and 8, and LRA Basis Documents AMP XI.M27, Fire Water System program and AMP XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program are revised to manage loss of coating integrity where coatings are installed on the internals of the in-scope components. provides the line-in/out revision to LRA Appendices A1.9, Al.13, A1.22, B2.1.9, B2.1.13 and B2.1.22, LRA Sections 3.3.2.1.4, 3.3.2.1.7 and 3.3.2.1.17, Tables 2.3.3-4, 2.3.3-7, 2.3.2-17, 3.3.2-4, 3.3.2-7, and 3.3.2-17. provides the line-in/out revision to LRA Table A4-1 for LRA Commitments 4 and 8.

NOC-AE-14003141 STPNOC LRA Changes with Line-in/Line-out Annotations NOC-AE-14003141 Page 1 of 82 List of Revised LRA Sections RAI Affected LRA Section RAI A.1-3 AO RAI 3.0.3-2 A1.9 RAI 3.0.3-1 A1.13 RAI 3.0.3-2 RAI 3.0.3-1 A1.20 RAI 3.0.3-1 A1.22 RAI 3.0.3-2 RAI A.1-3 B1.2 RAI 3.0.3-2 B2.1.9 RAI 3.0.3-1 B2.1.13 RAI 3.0.3-2 RAI 3.0.3-1 B2.1.20 RAI 3.0.3-1 B2.1.22 RAI 3.0.3-2 RAI 3.0.3-1 Section 3.1.2.1.2 RAI 3.0.3-2 Section 3.3.2.1.4 RAI 3.0.3-2 Section 3.3.2.1.7 RAI 3.0.3-1 Section 3.3.2.1.17 RAI 3.0.3-2 RAI 3.0.3-1 Section 3.3.2.1.19 RAI 3.0.3-1 Section 3.4.2.1.1 RAI 3.0.3-1 Section 3.4.2.1.3 RAI 3.0.3-1 Section 3.4.2.1.5 RAI 3.0.3-1 Section 3.4.2.1.6 RAI 3.0.3-2 Table 2.3.3-4 RAI 3.0.3-2 Table 2.3.3-7 RAI 3.0.3-1 Table 2.3.3-17 RAI 3.0.3-2 RAI 3.0.3-1 Table 3.1.2-2 RAI 3.0.3-1 Table 3.2.2-4 RAI 3.0.3-1 Table 3.2.2-5 RAI 3.0.3-2 Table 3.3.2-4 RAI 3.0.3-2 Table 3.3.2-7 RAI 3.0.3-1 Table 3.3.2-17 RAI 3.0.3-2 RAI 3.0.3-1 Table 3.3.2-19 RAI 3.0.3-1 Table 3.3.2-27 RAI 3.0.3-1 Table 3.4.2-1 RAI 3.0.3-1 Table 3.4.2-3 RAI 3.0.3-1 Table 3.4.2-4 RAI 3.0.3-1 Table 3.4.2-5 RAI 3.0.3-1 Table 3.4.2-6 NOC-AE-14003141 Page 2 of 82 AO APPENDIX A INTRODUCTION Introduction This appendix provides the information to be submitted in a Supplement to the Updated Final Safety Analysis Report (UFSAR) Update as required by 10 CFR 54.21 (d) for the STP License Renewal Application. Section Al of this appendix contains summary descriptions of the programs used to manage the effects of aging during the period of extended operation. Section A2 contains summary descriptions of programs used for management of time-limited aging analyses during the period of extended operation. Section A3 contains evaluation summaries of TLAAs for the period of extended operation. Section A4 contains summary descriptions of license renewal commitments. Included in Section A4, Table A4-1, "License Renewal Commitments," are commitments for license renewal and an associated schedule for completion of the commitments. Unless noted otherwise, the following implementation schedule will apply for new programs, enhanced programs, and specific activities to be completed prior to the period of extended operation (PEO).

a. Implement new programs and enhancements to existing programs no later than 6 months prior to PEO.

b. Complete inspection and testing activities by the 6-month date prior to PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

c. Notify the NRC in writing within 30 days after having accomplished item (a) above and include the status of those activities that have been or remain to be completed in item (b) above.

These summary descriptions of aging management programs, time-limited aging analyses, and license renewal commitments will be incorporated in the STP UFSAR Update following issuance of the renewed operating license in accordance with 10 CFR 50.71(e).

NOC-AE-14003141 Page 3 of 82 A1.9 OPEN-CYCLE COOLING WATER SYSTEM The Open-Cycle Cooling Water System program manages loss of material and reduction of heat transfer for components within the scope of license renewal and exposed to the raw water of the essential cooling water system. Included are components of the essential cooling water (ECW) system that are within the scope of license renewal, the component cooling water heat exchangers and the other safety related heat exchangers cooled by the essential cooling water system. The program includes chemical treatment and control of biofouling, periodic inspections, flushes and physical and chemical cleaning, and heat exchanger performance testing/ inspections to ensure that the effects of aging will be managed during 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 Component Cooling Water (CCW) heat exchanger is inspected at a nominal 216 week interval. An engineering evaluation is performed after each inspection. Corrective action in accordance with the corrective action program will be initiated 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). The program is consistent with STP commitments as established in responses to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Components.

Coating installed to mitigate corrosion of the essential chiller water box covers, standby diesel generator (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, dry film thickness test and pull off adhesion test. Coating inspections and tests are performed by a qualified Nuclear Coating Specialist (NCS) or by Coatings Surveillance Personnel under the technical direction of the NCS. Monitoring and trending of coatings is based on a pre-inspection review of the previous inspections results including any subsequent repairs activities.

NOC-AE-14003141 Page 4 of 82 A1.13 FIRE WATER SYSTEM The Fire Water System program manages loss of material and loss of coating integrity for water-based fire protection systems consisting of piping, fittings, valves, sprinklers, nozzles, hydrants, hose stations, standpipes and fire water storage tanks. The internal surfaces of water-based fire protection system piping that is normally drained, such as dry-pipe sprinkler system piping, are included within the scope of the program. Periodic inspections, testing, and cleaning are performed on the following.

Sprinkler inspections every 18 months per NFPA 25, 2011 Edition Section 5.2.1.1 50-year sprinkler replacement or testing per NFPA 25, 2011 Edition Section 5.3.1

" Standpipe and hose systems flow tests every 3 years per NFPA 25, 2011 Edition Section 6.3.1 Underground and exposed piping flow tests every 3 years per NFPA 25, 2011 Edition Section 7.3.1 Hydrants flow testing and visually inspection annually per NFPA 25, 2011 Edition Section 7.3.2 Fire pumps suction screens cleaning and inspections per NFPA 25, 2011 Edition Section 8.3.3.7 Fire water storage tank exterior inspections annually per NFPA 25, 2011 Edition Section 9.2.5.5 Fire water storage tank interior visual inspections every 5 years per NFPA 25, 2011 Edition Section 9.2.6 and 9.2.7, and bottom thickness ultrasonic tests every 10 years Main drain testing every 18 months per NFPA 25, 2011 Edition Section 13.2.5 Deluge Valve testing annually per NFPA 25, 2011 Edition Sections 13.4.3.2.2.through 13.4.3.2.5 Water Spray Fixed System strainers cleaning and inspections per NFPA 25, 2011 Edition Section 10.2.1.6, 10.2.1.7, 10.2.7 Spray/sprinkler nozzles full flow test every 18 months per NFPA 25, 2011 Edition Section 10.3.4.3 Foam water sprinkler systems spray nozzle strainers per NFPA 25, 2011 Edition Section 11.2.7.1 Foam water sprinkler systems operational test discharge patterns annually per NFPA 25, 2011 Edition Section 11.3.2.6 Foam water sprinkler systems storage tank visual inspection for internal corrosion once every 10 years Internal surface of piping and branch lines obstruction inspections every 5 years per NFPA 25, 2011 Edition Sections 14.2 and 14.3 hydrant inpcinfiro Ai flushing, spOrikler inspections5, and flow tesF-ts-in accor_,_dance With National Fi~ro Protect'ion AssocAiation_

(NF=PA) codes and stand-ardsr-ensurie that the water based fi*e protection systems are capable of per.formng thGeF intended functionR.. The fire water system pressure is continuously monitored such that loss of system pressure is immediately detected and corrective actions are initiated.

Internal and external visual inspections are performed on accessible exposed portions of fire water piping during plant maintenance activities. The inspections detect loss of material due to corrosion, ensure that aging effects are managed, and detect surface irregularities that could indicate wall loss below nominal pipe wall thickness. When surface irregularities are detected, follow-up volumetric wall thickness examinations are performed.

NOC-AE-14003141 Page 5 of 82 Augmented inspections are performed on the portions of water-based fire protection components that have been wetted but are normally dry or piping segments that cannot be drained or segments that allow water to collect. The augmented inspections are either flow tested or flushed sufficient to detect flow blockage or 100 percent visually inspected in each 5-year interval, beginning 5 years prior to the period of extended operation.

Augmented volumetric wall thickness inspections are performed on 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect in each 5-year interval of the prior to the period of extended operation. The 20 percent of piping inspected in each 5-year interval shall be in different location than previously inspected piping.

Coatings installed on the internals of in-scope fire water components are inspected and tested to assure coating integrity. The coatings are visual 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, dry film thickness test and pull off adhesion test. Coating inspections and tests will be performed by a qualified Nuclear Coating Specialist (NCS) or by Coatings Surveillance Personnel under the technical direction of the NCS. Monitoring and trending of coatings is based on a pre-inspection review of the previous inspections results including any subsequent repairs activities.

The Fire Water System program conducts an Air Or w.a~ter. flow test through each open head spray/sprinkler nozzle to verify the flowv. isS unobshtruc~ted. The program will replace sprinklers prior to 50 years in service or Will fielid srietest a representative saample of the sprinklers and test them ever' 10 yearcs thereafter dur~ing the pcriod of extended operation to ensure signs, ot degradation),

suc~h as corrosion, are detected in a timely manner. NOn nRuieoucrc exam~inations Will be8 perfrme oneprGesetative samples of fire water piping to detect any loss of m~aterial due1 to corrosion, to ensur~e that aging effects are m~anaged, wall thickness is within a*ceptable limits and degradation

• ill be d-e-tectede be 1fore the lss of intended fucti O:ther~'ise, internal inpetin ar used to evaluate wall thickness to identify evidence o~f loss ot

~4atel~ab NOC-AE-14003141 Page 6 of 82 A1.20 EXTERNAL SURFACES MONITORING PROGRAM The External Surfaces Monitoring program manages loss of material for external surfaces of steel, stainless steel, aluminum, copper alloy components and elastomers, including protective paints, coatings, caulking, a4d-sealants, and insulation for reduced thermal insulation resistance. The program also manages hardening and loss of strength for elastomers and cracking of stainless steel. The program includes those systems and components within the scope of license renewal that require external surface monitoring. Visual inspections of external surfaces conducted during engineering walkdowns will be used to identify aging effects and leakage. When appropriate for the component configuration and material, physical manipulation of at least 10 percent of the available surface area will be used to augment visual inspection to confirm the absence of elastomer hardening and loss of strength.

Visual inspections are conducted on insulation iacketing, outdoor insulated components, and indoor insulated components exposed to condensation. A minimum of 20 percent of the in scope piping length or 20 percent of the surface area whose configuration does not conform to a 1-foot axial length determination is inspected every 10 years during the period of extended operation after the insulation is removed. As an alternate any combination of a minimum 25 1-foot axial length sections and components are inspected for each material type. For each insulated tank, the exterior surface is inspected after the removal of insulation from 25 1-square-foot sections or 20 percent of the surface area.

Where inspection determine that there is no loss of material or evidence of stress corrosion cracking (SCC), subsequent inspection may consists of visual inspection of the exterior surface of the insulation iacketing material or protective outer layer for evidence of damage that could allow in-leakage of moisture. If insulation iacket or protective outer layer damage is observed, the insulation will be removed for inspection of the component exterior surface. Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage.

Periodic monitoring Qf the stainless steel external surfaces of Refueling Water Storage Tanks will include visual inspection for leakage to detect cracks.

Loss of material for external surfaces is managed by the Boric Acid Corrosion program (A1.4) for components in a system with treated borated water or reactor coolant environment on which boric acid corrosion may occur, Buried Piping and Tanks Inspection program (A1.8) for buried components, Fire Water System Program (B2.1.13) for components in the fire protection system, and Structures Monitoring Program (A1.32) for civil structures, and other structural items which support and contain mechanical and electrical components.

The External Surfaces Monitoring program is a new program that will be implemented prior to the period of extended operation. Industry and plant-specific operating experience will be evaluated in the development and implementation of this program.

NOC-AE-14003141 Page 7 of 82 A1.22 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND DUCTING COMPONENTS The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, loss of material, and hardening and loss of strength of the internal surfaces of piping, piping components, ducting, tanks, and other components that are not inspected by other aging management programs.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that uses the work control process for preventive maintenance and surveillance to conduct and document inspections. The program performs visual inspections to detect aging effects that could result in a loss of component intended function. Visual inspections of internal surfaces of plant components are performed by qualified personnel during the conduct of periodic maintenance, predictive maintenance, surveillance testing, and corrective maintenance. Opportunistic inspections will be supplemented with scheduled inspections if at a minimum in each 1 0-year period during the period of extended operation 20 percent up to a maximum of 25 components with the same combination of material, environment and aging effect are not opportunistically inspected. Where practical, the locations for these supplemental inspections will be selected from components most susceptible to aging.

Opportunistic inspections will continue to be performed when the minimum sample size is reached.

upplemental inspections no-t performed concurrently With planned Work activities will be performed. The loca-tionps an;d-interv;als fo-r these supplemental isetosare based on assessments Of the likelihood of significant degradation and-onA current industry and plant Gpocific operating experience.

Visual inspections of flexible polymeric components are performed whenever the component surface is accessible. Ad44itially, Visual inspections are wifllbe augmented by physical manipulation of at least 10 percent of accessible available surface area of elastomers within the scope of the program, when appropriate for the component configuration and material, to detect hardening and loss of strength of internal surfaces of elastomers. In cases where internal surfaces are not available for visual inspection, an internal visual inspection may be substituted with a volumetric examination.

The program also includes the following.

Volumetric examination of the tank bottoms of the auxiliary feedwater storage tanks, the reactor mýakeup-water storage tanks, and the safety iniection refueling water storage tanks aRd the firewator storage tanks-from inside each 1 0-year iperiod stating 10 years before entering te period of extended operation the-ta;nks within 5 years prior to enteFrig the perioAd of eQxtendd oporation and-w.~hene-ver the tanks are dr;ained, to confirm the absence of loss of material due to corrosion.

The program also Rincludes'- Volumetric evaluation to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

The Iprogram; includes Visual inspections of the floating seals in the reactor makeup water storage tanks.

Coatin~gs installed on the internals of in-scope components are inspected and tested to assure coating integrity. The coatings are visual inspected every six years. and tested after 12 years of service at a six-year frequency.

NOC-AE-14003141 Page 8 of 82 The coatingq tests performed are low voltagqe holiday test, dry film thickness test and pull off adhesion test. Coating inspections and tests will be performed by a qualified Nuclear Coating Specialist (NCS) or by Coatings Surveillance Personnel under the technical direction of the NCS. Monitoring and trending of the coatings are to be based on a pre-inspection review of the previous inspections results including any subsequent repairs activities.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program will be implemented prior to the period of extended operation. Industry and plant-specific operating experience will be evaluated in the development and implementation of this program.

NOC-AE-14003141 Page 9 of 82 B1.2 METHOD OF DISCUSSION For those aging management programs that are consistent with the assumptions made in Sections X and XI of NUREG-1801, or are consistent with exceptions, each program discussion is presented in the following format:

A program description abstract of the overall program form and function is provided.

A NUREG-1801 consistency statement is made about the program.

Exceptions to the NUREG-1801 program are outlined and a justification is provided.

Enhancements to ensure consistency with NUREG-1 801 or additions to the NUREG-1801 program to manage aging for additional components with aging effects not assumed in NUREG-1 801 for the NUREG-1 801 program. A pFoposed

,,hedu'le fo com;pletion i6 d-iscussed16.

Operating experience information specific to the program is provided.

A conclusion section provides a bases statement of reasonable assurance that the program is effective, or will be effective, once enhanced.

For those programs that are plant-specific, the above form is followed with the additional discussion of all 10 elements.

Included in Section A4, Table A4-1, "License Renewal Commitments," are commitments for license renewal and an associated detailed schedule for completion of the commitments related to these aainq manaqement orocirams.

NOC-AE-14003141 Page 10 of 82 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.

NOC-AE-14003141 Page 11 of 82 Monitoring and trending of coatings is based on a pre-inspection review of the previous two inspections results including any subsequent repairs activities. The coatings specialist will prepare a post-inspection report that includes a list and location of all areas of deterioration.

Where possible, photographic documentation indexed to inspection locations are be obtained.

The acceptance criteria for coatings are that no erosion, corrosion, cavitation erosion, flaking or peeling of the coatings is observed. Coatings not meeting these criteria are considered degraded and a condition report is initiated to document and resolve the concern.

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), Parameters Monitored 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:

Parameters Monitored 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.

NOC-AE-14003141 Page 12 of 82 Scope (Element 1), Parameters Monitored 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 if the 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 the following enhancements to coatings will be implemented Parameters Monitored or Inspected (Element 3,) a4d-Detection of Aging Effects (Element 4,) Monitoring and Trendinq (Element 5), and Acceptance Criteria (Element 6)

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-. and (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.

Procedures will be enhanced to monitor and trend coatings installed on the internals of in-scope components.

Procedures will be enhanced to specify the acceptance criteria for coatings as no erosion, corrosion, cavitation erosion, flaking or peeling of the coatings installed on the internals of in-scope components is observed.

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.

NOC-AE-14003141 Page 13 of 82 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 1 B 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.

NOC-AE-14003141 Page 14 of 82 B2.1.13 Fire Water System Program Description The Fire Water System program manages loss of material and loss of coating integrity for water-based fire protection systems consisting of piping, fittings, valves, sprinklers, nozzles, hydrants, hose stations, standpipes and fire water storage tanks. The internal surfaces of water-based fire protection system piping that is normally drained, such as dry-pipe sprinkler system piping, are included within the scope of the program. Periodic inspections, testing, and cleaning are performed on the following.

Sprinkler inspections every 18 months per NFPA 25, 2011 Edition Section 5.2.1.1

" 50-year sprinkler replacement or testing per NFPA 25, 2011 Edition Section 5.3.1 Standpipe and hose systems flow tests every 3 years per NFPA 25, 2011 Edition Section 6.3.1 Underground and exposed piping flow tests every 3 years per NFPA 25, 2011 Edition Section 7.3.1 Hydrants flow testing and visually inspection annually per NFPA 25, 2011 Edition Section 7.3.2 Fire pumps suction screens cleaning and inspections per NFPA 25, 2011 Edition Section 8.3.3.7 Fire water storage tank exterior inspections annually per NFPA 25, 2011 Edition Section 9.2.5.5 Fire water storage tank interior visual inspections every 5 years per NFPA 25, 2011 Edition Section 9.2.6 and 9.2.7, and bottom thickness ultrasonic tests every 10 years Main drain testing every 18 months per NFPA 25, 2011 Edition Section 13.2.5 Deluge Valve testing annually per NFPA 25, 2011 Edition Sections 13.4.3.2.2 through 13.4.3.2.5 Water Spray Fixed System strainers cleaning and inspections per NFPA 25, 2011 Edition Section 10.2.1.6, 10.2.1.7, 10.2.7 Spray/sprinkler nozzles full flow test every 18 months per NFPA 25, 2011 Edition Section 10.3.4.3

" Foam water sprinkler systems spray nozzle strainers per NFPA 25, 2011 Edition Section 11.2.7.1

" Foam water sprinkler systems operational test discharge patterns annually per NFPA 25, 2011 Edition Section 11.3.2.6 Foam water sprinkler systems storage tank visual inspection for internal corrosion once every 10 years Internal surface of piping and branch lines obstruction inspections every 5 years per NFPA 25, 2011 Edition Sections 14.2 and 14.3 STP monitors the fire water system's ability to maintain pressure and flow rates.hy4rapA in*sGpct*in, fire main fluhing, srirnkler irspc-tions, and flow tests in accordanRe with National Fire RProtection Association (NEPRA) codes and st-and-ards ensure that the water based fire protection systems are capable of performing their intended func~tion.

NOC-AE-14003141 Page 15 of 82 The fire water system pressure is continuously monitored such that loss of system pressure is immediately detected and corrective actions initiated.

Internal and external visual inspections are performed on accessible exposed portions of fire water piping during plant maintenance activities. The inspections detect loss of material due to corrosion, ensure that aging effects are managed, and detect surface irregularities that could indicate wall loss below nominal pipe wall thickness. When surface irregularities are detected, follow-up volumetric wall thickness examinations are performed.

Augmented inspections are performed on the portions of water-based fire protection components that have been wetted but are normally dry or piping segments that cannot be drained or segments that allow water to collect. The augmented inspections are either flow tested or flushed sufficient to detect flow blockage or 100 percent visually inspected in each 5-year interval, beginning 5 years prior to the period of extended operation.

Augmented volumetric wall thickness inspections are performed on 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect in each 5-year interval of the prior to the period of extended operation. The 20 percent of piping inspected in each 5-year interval shall be in different location than previously inspected piping.

Coatings installed on the internals of fire water components are inspected and tested to assure coating integrity. The coatings are visual 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, and (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. Monitoring and trending of coatings is based on a pre-inspection review of the previous two inspections results including any subsequent repairs activities. The coatings specialist will prepare a post-inspection report that includes a list and location of all areas of deterioration. Where possible, photographic documentation indexed to inspection locations are be obtained. The acceptance criteria for coatings are that no erosion, corrosion, cavitation erosion, flaking or peeling of the coatings is observed. Coatings not meeting these criteria are considered degraded and a condition report is initiated to document and resolve the concern.

The Fire Water System programq conducts an air o-r w~ater flow test through each open head spray/sprinklor nozzle to verify the flow is unbsruc6#1ted. The FirFe Water Systemn progaram will roplace Sprinklers prior to 50 yearsi srieFo the programn will field seRvice test a representative sample of the sprinklers And test them every 10 years therea;fter durwing-the peri.d

? extended operation. to enure sgns 0? degradatin,.I as corrosin, a detected in a timely* n~anneF-Vo/lumetri*

c exinans will be perfor*medo*

fire water piping. As an altenative, intrnal i nSpections Will be performed on accessible exposed portions of fire water piping dur~ing plant m

1aintenance activities. The inRsPetions detect l6ss of material duo to corrosion, ensIur that aging effec-ts are managed, ensure wall thickness6 is w~ithin acceptable limits, and detect degraDAtioRn ehfori the les of intend-e function.

If a repr*eGntativ nu mber of inspetins have tbeeRn omfpleted pFrir to the period of extended operatfion, the fire protection coordinato determines that additional inspectfion oreaiations are required, locations will bhe selected based on system susceptibility to cers rfo)uling and evidence of perfoFrmance degradation during sysotem flow. tes6ting or periodic flushes.

NOC-AE-14003141 Page 16 of 82 4f Where material and environment conditions for above grade and below grade piping are similar, the results of the inspections of the internal surfaces of the above grade fire protection piping can be extrapolated to evaluate the condition of the internal surfaces of the below grade fire protection piping. If not, additional inspection activities are needed to ensure that the intended function of below grade fire protection piping will be maintained consistent with the current licensing basis.

Results of the flow testing are monitored and trended. Degradation identified by flow testing or visual inspection is evaluated in accordance with the corrective action program.

The acceptance criteria for the fire water system are the system maintains the required pressure and flow. The fire water piping minimum wall thickness is maintained and no fouling is observed during inspections of sprinklers and associated piping. Sprinklers that show signs of leakage or corrosion shall be replaced. If the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected, the material is removed and the source is determined and corrected.

NUREG-1801 Consistency The Fire Water System program is an existing program that, following enhancement, will be consistent, with exception to NUREG-1801,Section XI.M27, Fire Water System.

Exceptions to NUREG-1801 Program Elements Affected:

Scope of Program (Element 1)

NUREG-1801 provides a program for managing carbon steel and cast iron components in fire water systems. The fire water system contains additional materials of construction, specifically, copper alloy and stainless steel. The Fire Water System program manages aging effects of copper alloy and stainless steel fire water system components with an internal environment of water.

Detection of Aging Effects (Element 4)

NUREG-1801 requires inspection of fire protection systems in accordance with the guidance of NFPA-25. STP performs power block hose station gasket inspections at least once every 18 months, rather than annually as specified by NFPA-25. STP has been inspecting at an 18 month frequency for over 10 years, and no degradation leading to a loss of function has occurred. A visual inspection of hose stations is conducted every six months for accessible locations and 18 months for stations that are not accessible during normal operations. These hoses are also hydrostatically tested every three years. Hoses are replaced when indications of deterioration are observed either by visual inspection or failure of a hydrostatic test, this replacement includes inspection of the gasket. Since aging effects are typically manifested over several years, differences in inspection and testing frequencies are insignificant.

NOC-AE-14003141 Page 17 of 82 Enhancements Prior to the period of extended operation, the following enhancements will be implemented in the following program elements:

Scope (Element 1)

Procedures will be enhanced to manage coatings installed on the internals of in-scope fire water components for loss of coating integrity.

PrFevontivo Ations (Element 2), Parameters Monitored or Inspected (Element 3,) and Detecti of Aging Effets (/,ement 4)

Procedures Will be enhanced to include Volu.metric examination.o*

r di.ot measurement on rer.eeRntatiVAe l.c-,atinrs of the fire water system to determine pipe wall thickne*,.

Procedures will be enhanced to perform flow testing of the each fire water loops is performed at least once every three five years, consistent with NFPA 25 Section 6.3.1 Procedures will be enhanced to follow-up volumetric wall thickness examinations when surface irregularities are detected.

Procedures will be enhanced to perform volumetric wall thickness inspections on portions of water-based components that are periodically subiect to flow but are normally dry.

Procedures will be enhanced to manage coatings installed on the internals of in-scope fire water components for loss of coating integrity.

Detection of Aging Effects (Element 4)

Procedures will be enhanced to perform periodic inspections, testing, and cleaning on the following Sprinkler inspections every 18 months per NFPA 25, 2011 Edition Section 5.2.1.1 50-year sprinkler replacement or testing per NFPA 25, 2011 Edition Section 5.3.1 Standpipe and hose systems flow tests every 3 years per NFPA 25, 2011 Edition Section 6.3.1 Underground and exposed piping flow tests every 3 years per NFPA 25, 2011 Edition Section 7.3.1 Hydrants flow testing and visually inspection annually per NFPA 25, 2011 Edition Section 7.3.2 Fire pumps suction screens cleaning and inspections per NFPA 25, 2011 Edition Section 8.3.3.7 Fire water storage tank exterior inspections annually per NFPA 25, 2011 Edition Section 9.2.5.5 Fire water storage tank interior visual inspections every 5 years per NFPA 25, 2011 Edition Section 9.2.6 and 9.2.7, and bottom thickness ultrasonic tests every 10 years Main drain testing every 18 months per NFPA 25, 2011 Edition Section 13.2.5 Deluge Valve testing annually per NFPA 25, 2011 Edition Sections 13.4.3.2.2 through 13.4.3.2.5 Water Spray Fixed System strainers cleaning and inspections per NFPA 25, 2011 Edition Section 10.2.1.6, 10.2.1.7, 10.2.7 Spray/sprinkler nozzles full flow test every 18 months per NFPA 25, 2011 Edition Section 10.3.4.3 NOC-AE-14003141 Page 18 of 82 Foam water sprinkler systems spray nozzle strainers per NFPA 25, 2011 Edition Section 11.2.7.1 Foam water sprinkler systems operational test discharge patterns annually per NFPA 25, 2011 Edition Section 11.3.2.6 Foam water sprinkler systems storage tank visual inspection for internal corrosion once every 10 years Internal surface of piping and branch lines obstruction inspections every 5 years per NFPA 25, 2011 Edition Sections 14.2 and 14.3 Procedures will be enhanced to perform follow-up volumetric wall thickness examinations when surface irregularities are detected.

Procedures will be enhanced to perform either flow testing or flushing sufficient to detect flow blockage or 100 percent visually inspection in each 5-year interval, beginning 5 years prior to the period of extended operation on portions of water-based fire protection components that have been wetted but are normally dry or piping segments that cannot be drained or segments that allow water to collect.

Procedures will be enhanced to perform volumetric wall thickness inspection are performed on 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect in each 5-year interval of the prior to the period of extended operation. The 20 percent of piping inspected in each 5-year interval shall be in different location than previously inspected pipinq.

Procedures will be enhanced to perform coating inspections of the coatings installed on the internals of in-scope fire water components. The coatings are visual 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, and (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.

PFrocedures will be enhaned to replace sprinklers prior to 50 years in so.R.ice or field re...,-e test a represontative sample and test eVery 10 years thereafter to ensure signs of degradation alre d-et~ected in a timely m~anner.

Monitoring and Trending (Element 5)

Procedures will be enhanced ferto monitor and trendi&-ef-fire water piping flow parameters recorded during fire water flow tests.

Procedures will be enhances to monitor and trend coatings installed on the internals of in-scope fire water components.

Acceptance Criteria (Element 6)

Procedures will be enhanced to specify the following acceptance criteria.

Minimum design fire water piping wall thickness is maintained.

NOC-AE-14003141 Page 19 of 82 Fouling shall not be observed during inspections of sprinklers and associated piping in the sprinkler system that could cause flow blockage.

Sprinklers that show signs of leakage or corrosion shall be replaced. If any sprinklers fails the representative sample testing required for sprinkler in service for 50 years, all sprinklers within the are represented by the sample will be replaced.

No erosion, corrosion, cavitation erosion, flaking or peeling of the coatings installed on the internals of in-scope fire water components is observed.

Sufficient foreign organic or inorganic material obstructing pipe or sprinklers is removed and its source is determined and corrected.

Corrective Action (Element 7)

Procedures will be enhanced to specify the following corrective action.

Coatings not meeting the acceptance criteria are considered degraded and a condition report is initiated to document and resolve the concern.

Operating Experience A review of the past 12 years of plant operating experience showed no signs of gasket degradation or fire hose degradation due to inspection intervals of 18 months and three years, respectively.

The review of operating experience contained in STP condition reports (CRs) were evaluated for aging effects associated with the Fire Water System program. Of these CRs, 45 were determined to have applicable aging effects associated with the Fire Water System program.

The following is a summary of the aging effects reported in these CRs.

Leakage has been discovered coming from supply line piping connections. The associated connections were repaired by replacing the gasket and no further leakage has been observed from these locations. Leakage from fire hydrants has been observed at hydrant barrel connections. The hydrants were evaluated and replaced. Drain valves have leaked by causing corrosion to the associated surface. The valves were replaced and the problem was corrected.

Leakage has been observed from the threaded connections to installed relief valves. These connections were repaired and no further leakage has been observed from the threaded connections. Valve packing leakage in supply line valves has caused corrosion of the associated packing follower and retaining bolts. The leakage was corrected and degraded components were evaluated and replaced where required.

While performing the five year inspection of a fire water storage tank it was noted that the base of the tank needed repainted, that a weld located at the top of the tank between the roof and sidewall needed to be repaired and a recirculation line pipe hanger needed to be replaced. The base of the tank was repainted, the weld was repaired and the hanger was replaced. No loss of intended function occurred.

Based on this review of STP operating experience, the Fire Water System program effectively identifies and corrects the fire water system components aging effects prior to the loss of intended function.

NOC-AE-14003141 Page 20 of 82 Conclusion The continued implementation of the Fire Water System program provides reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

NOC-AE-14003141 Page 21 of 82 B2.1.20 External Surfaces Monitoring Program Program Description The External Surfaces Monitoring Program manages loss of material for external surfaces of steel, stainless steel, aluminum, copper alloy components, including protective paints, coatings, caulking, sealants, and insulation for reduced thermal insulation resistance. ad elastem And hardenng aRnd loss of strength for elastemers. The program also manages hardening and loss of strength for elastomers and cracking of stainless steel. The program is a monitoring program that includes those systems and components within the scope of license renewal.

Visual inspections are used to identify aging effects and leakage of steel, stainless steel, aluminum, copper alloy components, and elastomers. When appropriate for the component configuration and material, physical manipulation of at least 10 percent of the available surface area of elastomers is used to augment visual inspections to confirm the absence of hardening or loss of strength. Personnel performing external surfaces monitoring inspections will be qualified in accordance with site controlled procedures and processes.

Visual inspections are conducted on insulation iacketing, outdoor insulated components, and indoor insulated components exposed to condensation, which operated below the dew point (100 deg. F). A minimum of 20 percent of the in scope piping length or 20 percent of the surface area whose configuration does not conform to a 1-foot axial length determination is inspected Every 10 years during the period of extended operation after the insulation is removed. As an alternate any combination of a minimum 25 1-foot axial length sections and components are inspected for each material type. For each insulated tank, the exterior surface is inspected after the removal of insulation from 25 1-square-foot sections or 20 percent of the surface area.

Where inspection determine that there is no loss of material or evidence of stress corrosion cracking (SCC), subsequent inspection may consists of visual inspection of the exterior surface of the insulation iacketing material or protective outer layer for evidence of damage that could allow in-leakage of moisture. If insulation jacket or protective outer layer damage is observed, the insulation will be removed for inspection of the component exterior surface. Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage.

The External Surfaces Monitoring Program will be implemented by a new procedure. System inspections and walkdowns will be required and will consist of periodic visual inspections of 100 percent of the accessible components surface for indications of loss of material, leakage, elastomer hardening and loss of strength, and aging effects of protective paints, coatings, caulking, a-4n-sealants, and insulation for reduced thermal insulation resistance.

Periodic monitoring of the stainless steel external surfaces of Refueling Water Storage Tanks at least every re-fueling cycle will include visual inspection for leakage to detect cracks.

The following aging management programs are used to manage aging for external surfaces that are not within the scope of the External Surfaces Monitoring Program.

1) Boric Acid Corrosion program (B2.1.4) for components in a system with treated borated water or reactor coolant environment in which boric acid corrosion may occur.

2) Buried Piping and Tanks Inspection program (B2.1.18) for buried components.

NOC-AE-14003141 Page 22 of 82

3) Structures Monitoring Program (B2.1.32) for civil structures, and other structural items which support and contain mechanical and electrical components.

4) Fire Water System Program (B2.1.13) for components in the fire protection system.

The External Surfaces Monitoring Program is a new program that will be implemented prior to the period of extended operation. Within the ten year period prior to the period of extended operation, and continuing into the period of extended operation, periodic inspections will be performed.

NUREG-1801 Consistency The External Surfaces Monitoring program is a new program that, when implemented, will be consistent, with exception to NUREG-1801,Section XI.M36, External Surfaces Monitoring.

Exceptions to NUREG-1801 Pro-gram Elements Affected:

Scope of Program (Element 1) and Detection of Aging Effects (Element 4)

NUREG-1801,Section XI.M36 requires the program to visually inspect the external surface of in-scope components and monitor external surfaces of steel components in systems within the scope of license renewal and subject to AMR for loss of material and leakage. The External Surfaces Monitoring Program has expanded the materials inspected to include stainless steel, aluminum, copper alloy, and elastomer external surfaces within the scope of license renewal.

The use of visual inspection to detect loss of material and leakage of stainless steel, aluminum, copper alloy and elastomer external surfaces is an effective method for these materials.

NUREG-1801,Section XI.M36 requires the program to manage loss of material and leakage.

The External Surfaces Monitoring Program also includes, among the aging effects to be managed, cracking, elastomer hardening and loss of strength. Elastomer hardening and loss of strength is managed by physical manipulation of elastomer components to detect hardening and loss of strength.

NUREG-1801,Section XI.M36 requires a program of visual inspection to detect loss of material and leakage. The External Surfaces Monitoring Program primarily uses visual inspection to detect loss of material and leakage and is augmented by physical manipulation of at least 10 percent of the available surface area of elastomers when appropriate to the component material and design. Manipulation of elastomers is an effective method to augment the visual inspection of elastomers in detecting the aging effect of hardening and loss of strength.

Enhancements None Operating Experience The External Surfaces Monitoring Program is a new program. Routine system walkdowns are performed as part of the systems engineering program. The STP condition reporting program is used in conjunction with the system walkdowns to identify and resolve issues to plant equipment.

NOC-AE-14003141 Page 23 of 82 Industry operating experience that forms the basis for this program is included in the operating experience element of the corresponding NUREG-1801 aging management program. A review of plant condition reporting documents, as well as other STP current licensing basis documents, since 1998, was performed to ensure that there is no unique, plant-specific operating experience in addition to that in NUREG-1801. The review identified no unique operating experience. The condition reporting program was proven to be effective in maintaining the material condition of plant systems.

As additional industry and plant-specific applicable operating experience becomes available, it will be evaluated and incorporated into the program through the STP condition reporting and operating experience programs.

Conclusion The implementation of the External Surfaces Monitoring 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.

NOC-AE-14003141 Page 24 of 82 B2.1.22 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Description The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, loss of material, and hardening and loss of strength of the internal surfaces of piping, piping components, ducting, tanks, and other components that are not inspected by other aging management programs. The program also manages the coating installed on the inside of the instrument air receiver tanks for loss of coating integrity.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that uses the work control process for preventive maintenance and surveillance to conduct and document inspections. The program performs visual inspections to detect aging effects that could result in a loss of component intended function. Visual inspections of internal surfaces of plant components are performed by qualified personnel during periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. Opportunistic inspections will be supplemented with scheduled inspections if at a minimum in each 10-year period during the period of extended operation 20 percent up to a maximum of 25 components with the same combination of material, environment and aging effect are not opportunistically inspected. Where practical, the locations for these supplemental inspections will be selected from components most susceptible to aging. Opportunistic inspections will continue to be performed when the minimum sample size is reached.

Supplemental inspections not performo~d concurrently With planned work PactiitiS Will be perfor4ed. The Iocations and intervals for these supplemeRtal iRn*pGtioRs are based on assome6Gni;tr of the likolihood Of significant degradation) and on current industry and plant specific operating experi*ence. This program Will be initiated prior to entering the period of extended operation and provides for periodic inspection of a selected set of sample components within the scope of this program.

Visual inspections of flexible polymeric components are performed whenever the component surface is accessible. Additiocally, Visual inspections are-will-be-augmented by physical manipulation of at least 10 percent of accessible available surface area of elastomers within the scope of the program, when appropriate for the component configuration and material, to detect hardening and loss of strength of internal surfaces of elastomers. In cases where internal surfaces are not available for visual inspection, an internal visual inspection may be substituted with a volumetric examination.

The program also includes the following.

Volumetric examination of the tank bottoms of the auxiliary feedwater storage tanks, the reactor makeup-water storage tanks, and the safety iniection refueling water storage tanks aRd-4he firoa';-ter storage taRnks from inside the tanks each 10-year period stating 10 years before entering the period of extended operation within 5 years prior to e*ten,*g the period Of extended operation and whenever the tanks are drained, to confirm the absence of loss of material due to corrosion.

The program also iRcludes Volumetric evaluation (ultrasonic examination) to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

NOC-AE-14003141 Page 25 of 82 The program incl6ude s visual inspections of the floating seals in the reactor makeup water storage tanks. The first inspection is to be accomplished within five years prior to the period of extended operation with follow-up inspections every five years thereafter.

Coatings installed on the internals of in-scope components are inspected and tested to assure coating integrity. The coatings are visual 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, and (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. Monitoring and trending of the coatings are to be based on a pre-inspection review of the previous two inspections results including any subsequent repairs activities. The coatings specialist will prepare a post-inspection report that includes a list and location of all areas of deterioration.

Where possible, photographic documentation indexed to inspection locations are be obtained.

The acceptance criteria for coatings are that no erosion, corrosion, flaking or peeling of the coatings is observed. Coatings not meeting these criteria are considered degraded and a condition report is initiated to document and resolve the concern.

T-his

.prgra will be initiated prior t entering the period Of tended

,peration and provides f.o periodic inspection of a selected set of sample compnPGents Within the scope Of this program.

The Internal sof Internl u

rfaces i

n irnoally perfosred throuigh scheduied preentiVe maintenance and surveillance inspections, such that work opportunIities are sufficient to detect aging and provide reasonable assurance that intenmdedn fule nctions are maintaiNRed.Splmna inspections net performed concrretl with plnndwokactviie will be performed The locations &And inevl o hs upeetlisetoswill be based On assessm~ents Of the likelfihood-of signfificant degradation and on current industry and plant specific operating NUREG-1 801 Consistency The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that, when implemented, will be consistent with exception to NUREG-1 801,Section XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.

Exceptions to NUREG-1801 Program Elements Affected:

Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), and Monitoring and Trending (Element 5)

NUREG-1801 Section XI.M38 provides for a program of visual inspections of the internal surfaces of miscellaneous steel piping and ducting components to ensure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. The exceptions to NUREG-1801,Section XI.M38 are an increase to the scope of the materials inspected to include stainless steel, aluminum, copper alloy, stainless steel-cast austenitic, nickel alloys, glass and elastomers, in addition to steel, and an increase to the scope of aging effects to include hardening and loss of strength for elastomers.

NOC-AE-14003141 Page 26 of 82 Additionally, visual inspections will be augmented (1) by physical manipulation of at least 10 percent of available surface area of elastomers within the scope of the program to detect hardening and loss of strength of elastomers when appropriate for the component configuration and material, (2) volumetric examinations of the tank bottoms of the auxiliary feedwater storage tanks, the reactor makeup-water storage tanks, and the safety iniection refueling water storage tanks and the firewater storage tAnkq from inside the tanks, to confirm the absence of loss of material due to corrosion, and (3) volumetric evaluation to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

Enhancements None Operating Experience The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program; therefore, plant-specific operating experience to verify the effectiveness of the program is not available. However, visual inspections were conducted during periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. These records provided evidence of STP using maintenance opportunities to conduct internal inspections during normal plant activities. Industry operating experience that forms the basis for this program is included in the operating experience element of the corresponding NUREG-1801 aging management program. A review of plant condition reporting documents, as well as other STP current licensing basis documents, since 1998, was performed to ensure that there is no unique, plant-specific experience in addition to that in NUREG-1801. The review identified no unique operating experience.

Many of the plant condition reporting documents discussed above concerned corrosion found in HVAC systems. The corrective actions for these conditions generally included removal of the corrosion and painting to prevent recurrence.

As additional industry and plant-specific applicable operating experience becomes available, it will be evaluated and incorporated into the program through the STP condition reporting and operating experience programs.

Conclusion The implementation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 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.

NOC-AE-14003141 Page 27 of 82 3.1.2.1.2 Reactor Coolant System Materials The materials of construction for the reactor coolant system component types are:

Carbon Steel Aluminum Insulation Calcium Silicate Insulation Fiberglass Nickel Alloy Stainless Steel Stainless Steel Cast Austenitic Environment The reactor coolant system component types are exposed to the following environments:

Borated Water Leakage Demineralized Water Dry Gas Lubricating Oil Plant Indoor Air Reactor Coolant Treated Borated Water Aging Effects Requiring Management The following reactor coolant system aging effects require management:

Cracking Loss of fracture toughness Loss of material Loss of preload Reduced thermal insulation resistance due to moisture intrusion NOC-AE-14003141 Page 28 of 82 Aging Management Programs The following aging management programs manage the aging effects for the reactor coolant system component types:

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1)

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

External Surfaces Monitoring Program (B2.1.20)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

One-Time Inspection of ASME Code Class 1 Small-Bore Piping (B2.1.19)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 29 of 82 3.3.2.1.4 Essential Cooling Water and ECW Screen Wash System Materials The materials of construction for the essential cooling water and ECW screen wash system component types are:

Aluminum Belzona Carbon Steel Carbon Steel clad with Copper-Nickel Copper Alloy Copper Alloy (Aluminum > 8 percent)

Ductile Iron Nickel-Alloys Stainless Steel Stainless Steel Cast Austenitic Environment The essential cooling water and ECW screen wash system components are exposed to the following environments:

Borated Water Leakage Buried Plant Indoor Air Raw Water Aging Effects Requiring Management The following essential cooling water and ECW screen wash system aging effects require management:

Loss of coatinq integrity Loss of material Loss of preload Reduction of heat transfer NOC-AE-14003141 Page 30 of 82 Aging Management Programs The following aging management programs manage the aging effects for the essential cooling water and ECW screen wash system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

Buried Piping and Tanks Inspection (B2.1.18)

External Surfaces Monitoring Program (B2.1.20)

Open-Cycle Cooling Water System (B2.1.9)

Selective Leaching of Aluminum Bronze (B2.1.37)

NOC-AE-14003141 Page 31 of 82 3.3.2.1.7 Compressed Air System Materials The materials of construction for the compressed air system component types are:

Carbon Steel Carbon Steel (Galvanized)

Cast Iron (Gray Cast Iron)

Coatings Copper Alloy Copper Alloy (> 15 percent Zinc)

Stainless Steel Stainless Steel Cast Austenitic Environment The compressed air system component types are exposed to the following environments:

Borated Water Leakage Closed Cycle Cooling Water Lubricating Oil Plant Indoor Air Aging Effects Requiring Management The following compressed air system aging effects require management:

Loss of coating integrity Loss of material Loss of preload NOC-AE-14003141 Page 32 of 82 Aging Management Programs The following aging management programs manage the aging effects for the compressed air system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

Closed-Cycle Cooling Water System (B2.1.10)

External Surfaces Monitoring Program (B2.1.20)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Selective Leaching of Materials (B2.1.17)

NOC-AE-14003141 Page 33 of 82 3.3.2.1.17 Fire Protection System Materials The materials of construction for the fire protection system component types are:

Aluminum Carbon Steel Carbon Steel (Galvanized)

Cast Iron (Gray Cast Iron)

Copper Alloy Belzona Ductile Iron Elastomer Stainless Steel Environment The fire protection system component types are exposed to the following environments:

Atmosphere/ Weather Borated Water Leakage Buried Closed-Cycle Cooling Water Concrete Diesel Exhaust Dry Gas Encased in Concrete Fuel Oil Plant Indoor Air Raw Water Ventilation Atmosphere NOC-AE-14003141 Page 34 of 82 Aging Effects Requiring Management The following fire protection system aging effects require management:

Cracking Flow blockage due to fouling Hardening and loss of material Loss of coating integrity Loss of material Loss of material, recurring internal corrosion Loss of preload Reduction of heat transfer Aging Management Programs The following aging management programs manage the aging effects for the fire protection system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

Buried Piping and Tanks Inspection (B2.1.18)

Closed-Cycle Cooling Water System (B2.1.10)

External Surfaces Monitoring Program (B2.1.20)

Fire Protection (B2.1.12)

Fire Water System (B2.1.13)

Fuel Oil Chemistry (B2.1.14)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

One-Time Inspection (B2.1.16)

Open-Cycle Cooling Water System (B2.1.9)

Selective Leaching of Materials (B2.1.17)

NOC-AE-14003141 Page 35 of 82 3.3.2.1.19 Chemical and Volume Control System Materials The materials of construction for the chemical and volume control system component types are:

Aluminum Carbon Steel Cast Iron (Gray Cast Iron)

Copper Alloy (>15% Zinc)

Copper Alloy Insulation Calcium Silicate Insulation Fiberglass Nickel Alloys Stainless Steel Stainless Steel Cast Austenitic Thermoplastics Environment The chemical and volume control system component types are exposed to the following environments:

Borated Water Leakage Closed-Cycle Cooling Water Demineralized Water Dry Gas Lubricating Oil Plant Indoor Air Reactor Coolant Secondary Water Steam Treated Borated Water Zinc Acetate NOC-AE-14003141 Page 36 of 82 Aging Effects Requiring Management The following chemical and volume control system aging effects require management:

Cracking Loss of material Loss of preload Reduced thermal insulation resistance due to moisture intrusion Reduction of heat transfer Wall thinning Aging Management Programs The following aging management programs manage the aging effects for the chemical and volume control system component types:

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1)

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

Closed-Cycle Cooling Water System (B2.1.10)

External Surfaces Monitoring Program (B2.1.20)

Flow-Accelerated Corrosion (B2.1.6)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

One-Time Inspection of ASME Code Class 1 Small-Bore Piping (B2.1.19)

Selective Leaching of Materials (B2.1.17)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 37 of 82 3.4.2.1.1 Main Steam System Materials The materials of construction for the main steam system component types are:

Aluminum Carbon Steel Copper Alloy Insulation Calcium Silicate Insulation Fiberglass Stainless Steel Environment The main steam system components are exposed to the following environments:

Atmosphere/Weather Borated Water Leakage Dry Gas Lubricating Oil Plant Indoor Air Secondary Water Steam Aging Effects Requiring Management The following main steam system aging effects require management:

Cracking Loss of material Loss of preload Reduced thermal insulation resistance due to moisture intrusion Wall thinning NOC-AE-14003141 Page 38 of 82 Aging Management Programs The following aging management programs manage the aging effects for the main steam system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

External Surfaces Monitoring Program (B2.1.20)

Flow-Accelerated Corrosion (B2.1.6)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 39 of 82 3.4.2.1.3 Feedwater System Materials The materials of construction for the feedwater system component types are:

Aluminum Carbon Steel Insulation Calcium Silicate Insulation Fiberglass Stainless Steel Environment The feedwater system components are exposed to the following environments:

Borated Water Leakage Dry Gas Lubricating Oil Plant Indoor Air Secondary Water Aging Effects Requiring Management The following feedwater system aging effects require management:

Cracking Loss of material Loss of preload Reduced thermal insulation resistance due to moisture intrusion Wall thinning Aging Management Programs The following aging management programs manage the aging effects for the feedwater system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

External Surfaces Monitoring Program (B2.1.20)

Flow-Accelerated Corrosion (B2.1.6)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 40 of 82 3.4.2.1.5 Steam Generator Blowdown System Materials The materials of construction for the steam generator blowdown system component types are:

Aluminum Carbon Steel Copper Alloy Insulation Calcium Silicate Insulation Fiberglass Stainless Steel Stainless Steel Cast Austenitic Environment The steam generator blowdown system components are exposed to the following environments:

Borated Water Leakage Demineralized Water Plant Indoor Air Secondary Water Steam Aging Effects Requiring Management The following steam generator blowdown system aging effects require management:

Cracking Loss of material Loss of preload Reduced thermal insulation resistance due to moisture intrusion Wall thinning NOC-AE-14003141 Page 41 of 82 Aging Management Programs The following aging management programs manage the aging effects for the steam generator blowdown system component types:

Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

External Surfaces Monitoring Program (B2.1.20)

Flow-Accelerated Corrosion (B2.1.6)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

One-Time Inspection (B2.1.16)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 42 of 82 3.4.2.1.6 Auxiliary Feedwater System Materials The materials of construction for the auxiliary feedwater system component types are:

Aluminum Carbon Steel Copper Alloy (>15% Zinc)

Stainless Steel Stainless Steel Cast Austenitic Environment The auxiliary feedwater system components are exposed to the following environments:

Atmosphere/ Weather Buried Concrete Dry Gas Encased in Concrete Lubricating Oil Plant Indoor Air Secondary Water Steam Wall Thinning Aging Effects Requiring Management The following auxiliary feedwater system aging effects require management:

Cracking Loss of material Loss of preload Reduction of heat transfer NOC-AE-14003141 Page 43 of 82 Aging Management Programs The following aging management programs manage the aging effects for the auxiliary feedwater system component types:

Flow-Accelerated Corrosion (B2.1.6)

Bolting Integrity (B2.1.7)

Buried Piping and Tanks Inspection (B2.1.18)

External Surfaces Monitoring Program (B2.1.20)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Selective Leaching of Materials (B2.1.17)

Water Chemistry (B2.1.2)

NOC-AE-14003141 Page 44 of 82 Table 2.3.3-4 Essential Cooling Water and ECW Screen Wash System Component.Type.

Intended Function Closure Bolting Leakage Boundary (spatial)

Pressure Boundary

_ Structural Integrity (attached)

Maintain Coating Integrity Expansion Joint Filter Pressure Boundary Filter I Pressure Boundary Flow Element

,Pressure Boundary Heat Exchanger (CCW Pump Room)

]Heat Transfer

_ Pressure Boundary Orifice IPressure Boundary

!T hrottle Piping I Leakage Boundary (spatial)

I Pressure Boundary

!Structural Integrity_(attachedj Pump

Pressure Boundary Strainer Strainer Element Pressure Boundary Filter Thermowell I

Pressure Boundary Traveing SreenFilter Tubing Valve Leakage Boundary (spatial)

Pressure Boundary IStructural Integrity (attached)

Leakage Boundary (spatial)

Pressure Boundary Structural Integrity (attached)

NOC-AE-14003141 Page 45 of 82 Table 2.3.3-7 Compressed Air System Component Type IntendedlFunction j

Accumulator Pressure Boundary Closure Bolting

,Leakage Boundary (spatial) 1 Pressure Boundary

___Structural Integrity (attached)

Coatin Maintain Coatinq Integrity Compressor Leakage Boundary (spatial)

Pressure Boundary....

Filter Filter Pressure Boundary F,exible-Hoses],Structural Integrity (attached)

Flexible Hoses Pressure Boundary Heat Exchanger (Air)

Heat Transfer Pressure Boundary Heat Exchanger (BA Compressor Package-1 Leakage Boundary (spatial)

Piping Leakage Boundary (spatial)

Pressure Boundary

__Structural Integrity (attached)

Solenoid Valve Pressure Boundary Tank

' Pressure Boundary Tubing Pressure Boundary Valve Leakage Boundary (spatial)

Pressure Boundary Structural Integrity (attached)

NOC-AE-14003141 Page 46 of 82 Table 2.3.3-17 Fire Protection System Component Type"'

Intended Function Caulking and Sealant Pressure Boundary Closure Bolting Pressure Boundary Structural Integrity (attached)

____Maintain Coatingq Integrity Damper Fire Barrier

_ Pressure Boundary Filter (Halon)

Filter Pressure Boundary Flame Arrestor Pressure Boundary Flexible Hoses Pressure Boundary Flow Element Pressure Boundary Heat Exchanger (Diesel Fire Pump Jacket Heat Transfer

.Water)

Pressure Boundary Hydrant Pressure Boundary Orifice Pressure Boundary iThrottle Piping FLeakage Boundary (spatial)

Pressure Boundary 1Spray

_ Structural Integrity_(attached)

Piping (Halon)

Pressure Boundary

• Spray_

Pump Pressure Boundary Valveoid

-Pressure Boundary Solenoid Valve (Halon)

Pressure Boundary Sprinkler Head Pressure Boundary SP____________ra____

Strainer Pressure Boundary t u t

.a.n

~. g ~

a tt a che d)...........

strainer Element Filter Tank Fire Water Storagqe)

Pressure Boundary Tank (FP Fuel Oil)

Pressure Boundary Tubing Pressure Boundary Valve

-Pressure Boundary Structural Integrity (attached)_

Valve (Halon)

Boundary NOC-AE-14003141 Page 47 of 82 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation - Reactor Coolant Svstem Table 3.1.2-2 Component Intended Material" 4 EnVironment Aging.Effect.

Aging Management. J NUREG-Table I Item Notes Type; Function Requiring.

Program <

1801 Vol.

• ' Management

__2 Item Indicator LBS, SIA Stainless Treated Borated Cracking Water Chemistry V.D1-31 3.2.1.48 E, 2 Steel Water (Int)

(B2.1.2) and One-Time Inspection (B2.1.16)

Insulation INS Insulation Plant Indoor Air Nene NGRe None None j

Calcium (Ext)

Reduced thermal External Surfaces H, 6 Silicate insulation Monitoringq Progqram resistance due to (B2.1.20) moisture intrusion Insulation INS Insulation Plant Indoor Air NGne NOne None None J

Fiberglass (Ext)

Reduced thermal External Surfaces H, 6 insulation Monitoringq Progqram resistance due to (B2.1.20)

I ___ ___ I__I__Imoisture intrusion I II Insulation INS Stainless Plant Indoor Air None None IV.E-2 3.1.1.86 C

I Steel (Ext)

Notes for Table 3.1.2-2:

Standard Notes:

A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

F Material not in NUREG-1801 for this component.

H Agqin.q effect not in NUREG-1 801 for this component, material and environment combination.

NoPithor the-componcnt nrG the mat~eriall and cnViFRnmen.t cmitions evaluated in NUJREG 1801.

NOC-AE-1 4003141 Page 48 of 82 Plant Specific Notes:

1 Water Chemistry (B2.11.2) and ASME Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD (B2.11.1) are used to manage this aging effect for Cast Austenitic Stainless Steel (CASS) components.

2 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.11.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

3 Component is part of RCP oil collection system.

4 This non NUREG-1801 line item was created because there is no line item for a component made of nickel alloy with borated water leakage (Ext) with an aging effect of cracking/ stress corrosion cracking.

5 Loss of Preload is conservatively considered to be applicable for all closure bolting.

6 The aging effect of reduced thermal insulation resistance due to moisture intrusion is manaqed by AMP B2.1.20, External Surfaces Monitoring Program. Reference LR-ISG-2012-02 Appendix C Item VI1.1.S-403.

NOC-AE-14003141 Page 49 of 82 Engineered Safety Features - Summary of Aging Manacement Evaluation - Safety Injection System Table 3.2.2-4 Component Intended Material

• Environment

• Aging*Effect Aging Management NUR.EG-1 Table I Item Note's Type.

Function Requiring Program 801 Vol. 2

,. ".. I M anagem ent "tem Tank PB Stainless Borated Water None None V.F-13 3.2.1.57 C

Steel Leakage (Ext)

Tank PB Stainless Concrete (Ext)

Loss of material Inspection of Internal None None G, 3 Steel Surfaces in Miscellaneous Pipinq and Ductingq Components (B2.1.22) 1 1

Tank PB Stainless Plant Indoor Air Cracking External Surfaces None None H, 2 Steel (Ext)

Monitoring Program (B2.1.20)

Notes for Table 3.2.2-4:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

G Fnvironment not in NItIRFC-1,801 for thi.s comnonpnt aind material.

G Environment not in NUREG-1801 for this component and material H

Aging effect not in NUREG-1801 for this component, material and environment combination.

NOC-AE-14003141 Page 50 of 82 Plant Specific Notes:

1 Water Chemistry (B2.1.2) and One-Time Inspection (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

2 Cracking of stainless steel external surface of the Reactor Water Storage Tank exposed to plant indoor air is managed by External Surfaces Monitoring Program (82.1.20) 3 A visual inspection of the external surface of the bottom of tanks sittingq directly on soil or concrete cannot be performed. A volumetric examination from the inside of the bottom of the tank is performed in lieu of an external inspection.

NOC-AE-14003141 Page 51 of 82 Auxiliarv Systems - Summary of Aai a Management Evaluation - Reactor MakeuD Water System Table 3.3.2-5 Component Intended :MaterialI Environment

• A~ging Effect Aging Management NUREG-f' Table:

Item Notes Type Function

.Reauiring

m.

Program 1801 Vol....

.Management 2 Item.,*

Seal PB

'Elastomer

Plant Indoor Air Hardening and IInspection of Internal VIIF2-7 3.3.1.11

E (Ext)'

loss of strength Surfaces in Miscellaneous Piping i,

~and Ducting

_Components (B2.1.22)........

Tank PB Stainless Steel Concrete (Ext)

Loss of material Inspection of Internal Surfaces in Miscellaneous Pipingq

and Ducting

Comaonents (B2.1.22)

None None

'G, 3 Tank PB Stainless Demineralized Steel lWater (Int)

I 1

1 Loss of material Water Chemistry (B2.1.2) and One-Time jInspection (B2.1.16)

VIII.E-29 3.4.1.16

!A Notes for Table 3.3.2-5:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

G Environment not in NUREG-1 801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material, and environment combination.

Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 The Reactor Make-up Water Storage Tank floating seal cannot be readily inspected from the treated water side. Credit for aging management of the floating seal is by physical inspection from the accessible topside of the floating seal following the inspection attributes in XI.M38, Inspection of Internal Surfaces. The XI.M38 inspections will determine if the elastomeric floating seal is experiencing hardening, and loss of strength.

3 A visual inspection of the external surface of the bottom of tanks sitting directly on soil or concrete cannot be performed. A volumetric examination from the inside of the bottom of the tank is performed in lieu of an external inspection.

NOC-AE-14003141 Page 52 of 82 Auxiliary Systems - Summary of Aging Management Evaluation - Essential Cooling Water and ECW Screen Wash System Table 3.3.2-4 Corponent Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes

• Type Function I ".Requiring Program.

180.1 Vol.

. *M anagem ent.

2Iltem Closure Bolting LBS, PB, Stainless Plant Indoor Air ILoss of preload Bolting Integrity (B2.1.7) None None H, 1 SIA Steel (Ext L

t'*_uirni

Pnit, Dl n

I~a^ Alntnr /Pýv\\

I I ^cc

^f tnnnl on-'

n~n_*tl

('*.nlinn Klnno I Knna IVl*JI integrity Water System (B2.1.9)

Expansion PB Nickel Alloys Plant Indoor Air None

'None VIII.I-9 3.4.1.41 IA JointI(Ext)_____

Notes for Table 3.3.2-4:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.

C Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1 801 for this component, material, and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1 801.

NOC-AE-14003141 Page 53 of 82 Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 Carbon steel clad with copper-nickel is not a material addressed in NUREG-1801. The External Surfaces Monitoring Program (B2.1.20) manages the aging of the exterior carbon steel surfaces of this material that are exposed to Plant Indoor Air (External). The Open-Cycle Cooling Water program (B2.1.9) manages the aging of the copper-nickel clad surfaces of this material that are exposed to raw water.

3 Loss of material by selective leaching is managed by the Selective Leaching of Aluminum Bronze program (B2.1.37) instead of the Selective Leaching of Materials program (B2.1.17) for components made of aluminum bronze (copper alloy > 8 percent aluminum).

4 The buried copper alloy piping in the EW system at STP is SB169 (which has a maximum of 0.2% zinc and 7% nominal aluminum content with an allowable range of aluminum of 6-8%). The weld material used in this piping has an aluminum content of between 8.5-11%. This aging evaluation is applicable for the welds in the buried EW piping which have the potential for greater than 8% aluminum and thus are considered susceptible to selective leaching.

5 Coatings are managed for loss of coating integrity to provide assurance that the coatings will not adversely affect the intended function of downstream components due to fouling. No credit is taken for the coatings to protect the base metal from loss of material.

NOC-AE-14003141 Page 54 of 82 Table 3.3.2 Componen Closure Bolti CQo~ating

-7 A,

W.;;r, f3/4rnnr 0',vnr, f A It-C A

IF"^

-n-.

fln-mrnn,4 Ap 0.,nnn

-f Ay l

Iu I y

~ L i ny U '

l J

IV o I

I 1 0 IL L V Ca Iua1,I U I I-U 1..

J I I /.ti 0c g ia e

t

.NUR 0E G -I V

t Type 1Intended Material Environment

.Aging Effect Aging. Management NUIREG-1Tab

• Function

,.Requiring.

Program 1801 Voi.

.te

_Management 2 Item 1J ng LBS, PB, Stainless

!Plant Indoor Air Loss of preload Bolting Integrity None None SIA Steel (B2.1.7)._

WMCI Coatinqs Plant Indoor Air Loss of coatinq Inspection of Internal None None integrity Surfaces in IMiscellaneous Piping and Ducting

_Components (B2.1.22)

PB Carbon

!Plant Indoor Air

'Loss of material MiExternal Surfaces VII.I-8 3.3.1.5 Steel (Ext)

Monitoring Program B21. 20_

le I

Notes m,,,

H, 1

-47 Compressor

• 8 B

Notes for Table 3.3.2-7:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in. NUREG-1 801 for this component, material, and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1801.

Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22) is used in lieu of NUREG-1 801,Section XI.M24, Compressed Air Monitoring because this is an aging effect which occurs on the internal surfaces of these components.

3 Non-inhibited copper alloy > 15 percent zinc SSCs with surfaces exposed to ventilation atmosphere (internal) or plant indoor air (internal) are subject to wetting due to condensation and thus are subject to loss of material due to selective leaching.

4 Coatings are managed for loss of coating integrity to provide assurance that the coatings will not adversely affect the intended function of downstream components due to foulinq. No credit is taken for the coatings to protect the base metal from loss of material.

NOC-AE-14003141 Page 55 of 82 Due to the number of changes, Table 3.3.2-17 is shown as the complete table, not just the changed lines for RAIs 3.0.3-1 and 3.0.3-2.

Component, Intended [ Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol..

"M anagem ent"

[ 2 Item ".

tC-n"in~iw ~nnrI PR i

Sealant 4

Closure Bolting Closure Bolting PB PB, SIA Closure Bolting Closure Bolting Closure Bolting Closure Bolting Coating Damper PB PB PB, SIA PB, SIA MCI FB, PB Elastomer

Atmosphere/

Hardening and E)

Weather (Ext) loss of strength M

Carbon Steel !Atmosphere/

Loss of preload B

iweather (Ext)

Carbon Steel Borated Water Loss of material 1B Leakage (Ex

[(

Carbon Steel lAtmosphere/

Loss of material B

CWeather (Ext_

Carbon Steel Buried (Ext)

Loss of material Bi Carbon Steel Plant Indoor Air Loss of material Bc

.............(E x~t)

Carbon SteelI Plant Indoor Air Loss of preload BC

_ (Ext)

Belzona I Raw Water (Ext)

Loss of coating lFi S.integrity-Carbon Steel Encased in None Ni

.(Galvanized), Concrete(Ext)

Carbon Steel Ventilation Loss of material (Galvanized) !Atmosphere(Int)

Aluminum Dry Gas (Int)

None Ni Aluminum Plant Indoor Air None Ni

__ _ (Ext)

Copper Alloy Dry Gas (Int)

None Ni Copper Alloy I Plant Indoor Air None

[N Carbon Steel! Fuel Oil (Int)

Loss of material Fi I ar onitoring Program 2.1.20) olting Integrity (B2.1.7) None None 3.3.1.89 H, 1 A

oric Acid Corrosion 2.1.4)

VII.1-2 clting Integrity (B2.1.7) VII.I-1 uried Piping and Tanks VII.G-25 3.1.43 3.3.1.19 B

B I

~ternaI Surfaces None None I G 4 spection (B2.1.18)__

clting Integrity (B2.1.7) VII.l-4 clting Integrity (B2.1.7) IVII.I-5 1-re Water System I None 32.1.13) one.VII.J-21 I

3.3.1.43 B

1 3.3.1.45 B

None 14 3.3.1.96

!A Damper Filter (Halon)

FB, PB re Protection (B2.1.12) IVII.F4-2 one VII.J-2 3.3.1.72 IE, 5 3.3.1.97 IA I

PB Filter (Halon)

Filter (Halon)

PB FIL one V.F-2 one

[VII.J-4 3.2.1.50 1A 3.3.1.97 A

1 Filter (Halon)

Flame Arrestor FIL PB one re Protection (B2.1.12) id Fuel Oil Chemistry 2.1.14)

VIII.1-2 3.4.1.41 A

+

VII.G-21 3.3.1.64 B

I (B NOC-AE-14003141 Page 56 of 82 Table 3.3.2-17 Auxiliary Svstems-Summarv of Aaina Manaaement Evaluation - Fire Protection System (Continued)

Compo..nt Intended

Material.

Enviroment AgingEffect Aging Management NUR.EG-

.Table 1 Item Notes Type&

Function Requiring Program 1801 Vol.1 Flame Arrestor PB Carbon Steel Plant Indoor Air Loss of material External Surfaces VII.I-8 3.3.1.58 B

(Ext)

Monitoring Program

~ (13B2.1.20)_

Flexible Hoses PB Stainless

Plant Indoor Air None None VII.J-15 3.3.1.94

'A Steel

.j(Ext

__. I 20)-I Flexible Hoses Flexible Hoses Flow Element Flow Element Flow Element Flow Element' PB Stainless

!Plant Indoor Air Loss of material i n.Spection Of nteFRal Steel i(Int)

I*,*

MiscellAAneouS Piping i

land D'-cting

.omponents (132.1.22)

'Fire Water System 3(B2.1.13)

Stainless

'Plant Indoor Air Flow blockage Fire Water System Steel Int) jdue to fouling

.(B2.1.13) _...

Carbon Steel 'Plant Indoor Air Loss of material External Surfaces (Galvanized) (Ext)

Monitoring Program

((B2.1.20)

V.A-26 None None H, 10 None PB PB P B...........

PB PB None H, 10 Carbon Steel Raw Water Int)

(Galvanized)

Carbon Steel Raw Water (Int)

(Galvanized)

Carbon Steel Raw Water (Int)

(Galvanized)

Loss of material, Fire Water System recurring internal (B2.1.13) corrosion Flow blockage Fire Water System due to fouling (132.1.13)

.d u e to~ o u lin~q................

... B

.1.

3........................

Loss of material Fire Water System

'(B2.1.13)

VII.1-8

.i..N.S.......

None None IVII.G-24 3.3.1.58 B

INone H, 6 None 3.3.1.68

-~~~

Heat Exchanger (DFP Jacket Water Heat Exchanger (DFP Jacket Water)

HT, PB HT, PB Copper Alloy Closed Cycle

'Cooling Water (Int)

Loss of material Closed-Cycle Cooling

Water System (B2.1.10)

V.A-5 3.2.1.29 1B Copper Alloy !Closed Cycle LCooling Water (Int)

Reduction of heat iClosed-Cycle Cooling transfer

'Water System (B2.1.10)

V.A-11 3.2.1.30 lB NOC-AE-14003141 Page 57 of 82 Table 3_3.2-17 Auxiliarv Svstems - Summary of Aaina Manaacement Evaluation - Fire Protection System (Continued)

.Component Intended Material E

n Aging Effect Aging Management NUREG-. Table I Item Notes

• ."o,'M anagem ent 2 Item Heat PB Copper Alloy Plant Indoor Air None None VIII.I-2 13.4.1.41 A

Exchanger (Ext)

(DFP Jacket Water)

C A

R e

r W Heat HT, PB Copper Alloy Raw Water (Ext)

Loss of material Fire Water System VII.G-12 3.3.1.70 1 B Exchanger

(B2.1.13)

(DFP Jacket Heat HT, PB Copper Alloy Raw Water (Ext)

Reduction of heat lOpen-Cycle Cooling VII.C1.6 3.3.1.83 113 Exchanger transfer lWater System (B2.1.9)

(DFP Jacket Heat PB Copper Alloy,Raw Water (Int)

Loss of material FireWaterSystem VII.G-12 3.3.1.70 iB Exchanger

,(B2.1.13)

(DFP Jacket Wate~r.

P Cs rn

~_

Hydrant

-PB Cast iron

!Atmosphere/

Loss of material

!External Surfaces VII.I-9 3.3.1.58 1B (Gray Cast Weather (Ext) i Monitoring Program

• o r )........

..B....................

.g.1

.2 0 )

iHydrant PB Cast Iron Raw Water (Int)

Loss of material, Fire Water System.

Nne.

Nne H6 I,(Gray Cast recurring internal.(B2.1.13)

__Iron corrosion Hydrant PB Ca st I ron -

Raw Water (Int)

Loss of material Selective Leaching of VII.G-14 3.'31.85 -

B (Gray Cast

.Materials (B2.1.17)

Iron)_.....

Hydrant PB Cast Iron Raw Water (Int)

Loss of material Fire(WaterSystem VIG24 8

1B (Gray Cast 02.1.13)

[

Iron).iI Orifice Orifice PB, TH 4iPB -TH Stainless Steel Stainless Steel Plant Indoor Air

.(Ext)

None Raw Water (Int)

Flow blockage due to foulinci None Fire Water System (B2.1.13)

VII.J-15 3.3.1.94

!A None None H. 9 NOC-AE-14003141 Page 58 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aging Management Evaluation - Fire Protection System (Continued)

Componrent, Intended Material Environment Aging Effect-[ Aging Mahagement NUIEG-Table 1 Item Notes-T.i"e.

Function Requiring P~ogram.. [.1801 Vo.i

.e.

Managem ent 2 ltem,

Orifice PB, TH Stainless Raw Water (Int)

Loss of material Fire Water System IVII.G-19 3.3.1.69 B

Steel

__I(B2.1.13)

Piping PB Aluminum IBorated Water Loss of material Boric Acid Corrosion VII.E1-10 3.3.1.88 jA Leakage (Ext)

.(B2.

_)

I.....

Piping PB Aluminum Dry Gas (Int).

None None VII.J-2 3.3.1.97 A

Piping PB Carbon Steel TAtmosphere/

Loss of material External Surfaces Vii.l-9 3.3.1.58 B

Weather (Ext)

Monitoring Program

.(B2.1.20 Piping PB--

-13

-a r b on S tee_ -l Borated Water Loss of material Boric Acid Corrosion VII.1-10 3.3.1.89 A

PLeakage (xo i(B2.1.4) n

-Carbon Stel!iiesel Exhaust*

oufae itrnV12I (Int)

'Surfaces in Miscellaneous Piping and Ducting ompo ent (B2.1.22) J_

Piping PB Carbon Steel IFuel Oil (Int)

Loss of material Fuel Oil Chemistry VII.H2-24 3.3.1.20 l(B2.1.14) and One-Time I Inspection (B2.1.16) iin,.

DI n"

-n C

, 11r f,

/lnN K,,-,I

[X

)A I_

q 1 07 IA

>I L/

W ly

ý0 W

ý ii I

Piping (Halon)

[PB`

Piping (Halon) [PB Carbon Steel Dry Gas (Int)

Carbon Steel Plant Indoor Air

__(Ext)_

Carbon Ste~el Plant Indoor Air (Ext) iping PB None None 4

VII.J-23 Loss of material Fire Protection (B2.1.12) VII.I-8 Loss of material External Surfaces VII.I-8 Monitoring Program

.........- (B2.1.20)

Loss of material" Fire Water System None 3.3.1.97 IA 3.3.1.58 E, 2 3.3.1.58 1B Piin

.PB....

Carbon Steel: Raw Water (Int)

Carbon Steel: Raw Water (Int)

None H, 6 recurrinq internal c....rr.. s. i. n..

Flow blockaqge due to fouling (B2.1.13)

.i~

e...

.Fire Water System (132.1.13)

None None

'H, 7 NOC-AE-14003141 Page 59 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aging Management Evaluation - Fire Protection System (Continued)

.ComponentIntended

..Material.

. EnVironment Aging Effect [ Aging Management NUREG-Table I Item Note&

.. Type..

Function

'I.:Requiring

• Program*

1Ki801 Vol.

M a n a g e m e n t 2 Ite m 1Piping PB Carbon Steel I Raw Water (Int)

Loss of material Fire Water System

'(132.1.13)

VII.G-24 3.3.1.68 B

Piping PB, SIA ICarbon Steel !Atmosphere/

'(Galvanized) Weather (Ext)

PB, LBS, Carbon Steel Borated Water SIA, SP I(Galvanized) Leakaae Loss of material lExternal Surfaces I Monitoring Program (B2.1.?0 Loss of material Bi oric Acid Corrosion (B2.1.4)

VII.I-9 3.3.1.58 B

Piping VII.l-10 3.3.1.89 A

Piping Piping LBS, PB, ICarbon Steel Plant Indoor Air SIA, SP (Galvanized) (Ext)

LBSPB, -Carbon Steel Plant Indoor Air SIA, SP (Galvanized) (Int)

Loss of material Loss of material IExternal Surfaces Monitoring Program i(B2.11.20)

VII.1-8 3.3.1.58 B

4

~1~.~

LBS, PB, Carbon Steel i Plant Indoor Air

....IA SP (Galvanized)

I--nt

PiBS, PB, ;Carbon Steel Raw Water (Int) 1SlA SP (Galvanized)

I!nspccti9n of !nternal i Mscellancous Piping Compoents(EB2.1.22)

I Fire Water System

,(B2.1.13) 1 Fire Water System (B2.1.13)

Fire Water System (B2.1.13)

VUI.G 23 None None BH, 12 Flow blockaqe due to foulinq Loss of material, recurring internal None None H, 12 None None Piping Piping Piping Pi ng i

.*................corrosion

• e...

IBS, PB, Carbon Steel Raw Water (Int)

Flow blockage Fire Water System

.iSl SP (Galvanized) due to fouling i(132.1.13)

LBS PB, C carbon Steel Raw Water (Int)

Loss of material I Fire Water System SIA, SP l(Galvanized)

!(B2.1.13)

PB

'Cast Iron

Plant Indoor Air Loss of material

External Surfaces (Gray Cast (Ext)

!Monitoring Program ronL (1B2.1.20)

(Gray Cast recurring internal

((B2.11.13)

_ i corrosion None IVI 1. G-4

.None 13.3.1.68 H 7 1B1 VII.l-8 13.3.1.58 B

None

[None I-, 6 NOC-AE-14003141 Page 60 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aclinq Manaaement Evaluation - Fire Protection System (Continued)

Component Intended

'Material Environment Aging Effect 4 Aging Management NUREG-Table:: Item.Notes.

Type.

.unction:

'Requiring"R

.Program.

1801.Vol.

.Management

.. 2 Item Piping PB Cast Iron iRa Water (I nt)

Loss of material;ire Water System IVlI.G-24 3.3.1.68 1B (Gray Cast (B2.1.13)

Iro n )

Piping PB Cast Iron (Gray Cast Ironl)___o Ductile Iron Raw Water (Int)

Loss of material Piping PB

'Buried (Ext)

-Loss of material

'Selective Leaching of VII.G-14 Materials (B2.1.18) iBuried Piping and Tanks!VII.G-25 Ijlnspection_(B2.1.18)

In s..

pe *.........

_, )..

Fire Water System

}None (B2.1.13) 3.3.1.19 B

3.3.1.85 B

]Ductile Iron Ibuoctile-Iron Raw Water (I/nt)

Raw Water (Int)

Loss of material, Irecurrinq interna

!corrosion None iH, 6 Piping

.P-B DuctileIron Raw-Water(Int)

Piping PB Stainless

'Diesel Exhaust Steel (Int)

I Flow blockage Fire Water System None

ýdue to fouling S(B2.1.13)

Loss ofmaterial Fire Water-System...

.V

-;4

,(B2.1.13)

Cracking Inspection of Internal VII.H2-1 Surfaces in Miscellaneous Piping and Ducting

__Components (B2.1.22)

---

I.......................

o ~ ~ ~ ~n s

!...2 _

Loss of material Inspection of Internal VII.H2-2

!Surfaces in

}Miscellaneous Piping and Ducting Components (B2.1.22)

,4None

'H, 7

." i;.. 68...........B 3.3.1.68

'B 3.3.1.06 IE 3.3.1.18 E

Piping Stainless Steel

....ies Exh au E(Int)

Piping (Halon)

SP Stainless IDry Gas (Int)

Steel None None I None VII.J-19 1

I ping (Halon)

S Stainless Steel Stainless Steel___

...i

~n i *.o r Plant Indoor Air (Ext)

None VII.J-15 3.3.1.97 IA 3.3.1.94 1A 3.3.1.94 1IA Piping PB I Plant Indoor Air (Ext)

None

!None 1VII.J-15 NOC-AE-14003141 Page 61 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aaina Manaaement Evaluation - Fire Protection Svstem (Continued)

Cormpnonent Intended Material Environment..

• Aging Effect..IAginManagement NUREG-Table Type.

Function Requiring Program 1801 Vol.

.i__

Management 2 Item ::

Pump

Pum.

Pump Pump Solenoid Valve Solenoid Valve

.Halon)

Solenoid Valve Solenoid Valve PB PBIPB frB PB PB Cast Iron Plant Indoor Air (Gray Cast (Ext)

Iron)___

(

Cast Iron Raw Water (Int)

(Gray Cast Iron)

Cast Iron Raw Water (Int)

(Gray Cast J._.ro n_

Cast Iron Raw Water (Int)

(Gray Cast Iron_)

Copper Alloy Atmosphere/

Weather (Ext)

Copper Alloy Dry Gas (Int)

Loss of material

!External Surfaces Monitoring Program

....... (B2.1:20)

,Loss of material, Fire Water System recurring internal

((B2.1.13) corrosion Loss of materiali Fire Water System (B2.1.13)

VIINo-8 N3o3n1.

,None iNone 58 H6 B

Loss of material iSelective Leaching of

'Materials (B2.1.17)

Loss of materialI External Surfaces

,Monitoring Program

.(B.2.1.20)

None iNone VII.G-24 1VII.G-14 None VII.J-4 1.68 B.. ~...

3.3.1.68 jB3 3.3.1.85 B

None IG 3.3.1.97 1A

-~

4.

---

_+ _

I PB PB Copper Alloy 1 Plant Indoor Air (Ext)

Copper Alloy IPlant Indoor Air Copper Alloy Plant Indoor Air (Int)

None None VIII.1-2 3.4.1.41 A

None None VIII.1-2 341.41 Solenoid Valve PB Loss of material

,,,npeti9 Of t.. Ral GA-

.Surfaccs None IMOcellan-ous Piping GeMPGe~tS(B2.1.221, Fire Water System (B2.1.13)

None

@A 11 Solenoid Valve PB

Copper Alloy Plant Ind(

SolnoiVave.

Coe A

wInt)

So76len'oid -Val 1v--e,P-B Cpe lo a

)or Air Flow blockage Fire Water System due to fouling (B2.1.13)_____

er (Int)

Flow blockage IFire Water System

_ due to fouling

((B2.1.13)

None None None None 1H,11 NOC-AE-14003141 Page 62 of 82 Table 3.3.2-17 Auxiliarv Svstems - Summary of Aaina Manaaement Evaluation - Fire Protection System (Continued)

Componentx Antended Material Environment" AgingýEffect, Aging Management NUREG-Table 1 Item Notes

• Type

.Function Requiring Program 1801 Vol.

Management

[

2 Item Solenoid Valve PB Copper Alloy iRaw Water (Int)

Loss of material 1,Fire Water System VII.G-12 3.3.1.70 B

i i __

__i(B2.1.13)_

Sprinkler PB, SP Copper Alloy Plant Indoor Air None None VIII.I-2 3.4.1.41 A

!_(.Ext)

Sprinkler PB Copper Alloy I Raw Water (Int)

Flow blockage

[Fire Water Systems None None H, 8 P

due to fouling (B2.1.13) 2 Sprinkler PB, SP Copper Alloy !Raw Water-(-I n-t)-

Los's of material Fire.1Water Systems VII1:. G-1:2 3.3.1.70

!B

,~~~~~~

..... (132.1. *13)}

IB2'11 1-

_B_'_

Strainer PB Carbon Steel Plant Indoor Air ss of material External Surfaces VII.I-8 3.3.1.58 (Galvanized) i(Ext)

L Monitoring Program i

{

I(132.1.20)

Strainer PB Carbon Steel IPlant Indoor Air Loss of material pect1GR Of nteFRal V.......

• G3.7 (Galvanized) '(Int)

SufaGes -

None None H, 12 Miscellaneous Piping 1COmponents (B2.1.22)

Fire Water Systems

___.(B2.1.13)_

Strainer PB Carbon Steel Plant Indoor Air Flow blockage J Fire Water Systems None None H, 12 (Galvanized) I(Int) due to fouling (1B2.1.13)

'Strainer PB, SIA Cast Iron Plant Indoor Air Loss of material I External Surfaces VII.I-8 3.3.1.58 B

(Gray Cast (Ext)

I Monitoring Program Iron)

I.(B2.1.20)

Si PBSIA Cast Iron

• Ra Water (Int)

Loss of material, Fire Water System None None H 6 S(Gray Cast recurrinq internal

((B2.1.13)

Ilron) corrosion B

Strainer PB, SIA Cast Iron i Raw Water (Int)

Loss of material FireWater System-IVI.G-24 3.3.1.68 B

I,

, (Gray Cast rn)_____

j s(B2.1.13) j __,_

Strainer PB, SIA Cast Iron (Gray Cast I~ro n ),.....

!Raw Water (Int)

Loss of material Selective Leaching of Materials (B2.1.17)

VII.G-14 3.3.1.85 B

NOC-AE-14003141 Page 63 of 82 Table 3.3.2-17 Auxiiar Systems - Summary of Aging Management Evaluation - Fire Protection System (Continued)

Component Intended Material

.Environment.. lAging Effect Aging Management; NUREG-Tableil Item Notes."

Type Function 1 "

Requiring Program,.

1861 Vol.

Management 2item rn_____

Strainer FIL Copper Raw Water (Ext)

Flow blockagie Fire Water System None None H, 8 E

rlement 1Strainer Element IL E a ier*_n....

IStrainer Element Strainer Element Tank (Fire Water Storage)

F Ii-CFi FIL PiB Copper Alloy: Raw Water (Ext)

C...e. Alloy.Ra Water

.Int)

Copper Alloy Raw Water (Int)

Carbon Steel iAtmosphere/

.Weather (Ext) due LO lOUll[1,L

.Loss of material Flow blockage jdue to foulinq Loss of material 1Dt~z. I.. 13)

Fire Water System (B.2... !...................

Fire Water System (B2.1.13)

' Fire Water System (B32.1.13)

E.tern.l.urfacos IVIMonitorig Program 1(6 2.120)

Fire Water System (RB2 113)

..V.!.I.,.G-12 B

3.3.1.70 B

'None None H. 8 IV, 3-3.1 7-0 2W

-~

Loss of material None 3.3A468 None 9-H, 13 I..........

Tank (Fire Water Storage)

PB Carbon Steel Concrete (Ext)

Carbon Steel Plant Indoor Air Fu(Ext)

Carbon Steell Fuel Oil (I nt)

Tank (Fire Water Stora..e)

Tank (FP Fuel ail)

PB Loss of material

'np..

Ion of Internal None SyufaGes hmiscollAncou s Piping Components (B2.1.22)

Fire Water System (B2.1.13)

Loss of material

[Fire Water System --

None 1 (B2.1.13)

Loss of material Fuel Oil Chemisy 1..

.11H2-24

((B2.1.14) and One-Time" i Inspection (B2.1.16)

Loss of material iExternal Surfaces VII.I-8

'Monitoring Program Loss..........

... F(B_2.-1.20)

_N Loss of material,

• Fire Water System

.None None None 1G, 3 3.3.1.20 B

Tank (FP Fuel 911)

Tank (Fire Water Storage)

Tatnk.

.Fir

.e.

LWater Storagqe)

PB Carbon Steel IPlant Indoor Air

+

÷ T3.3.1.5 K.

2 PB Carbon Steel Raw Water (Int)

Pg...

"carbon Stee l Raw W ater (Int) 3

[B H,6 None recurring internal corrosion Loss of material (B2.1.13)

Fire Water System 3........

3-16 dB-H 13 (B2..3_

None INone NOC-AE-14003141 Page 64 of 82 Table 3.3.2-17 Auxiliary Systems-Summary of Aair Manaaement Evaluation - Fire Protection System (Continued)

Corn ponetti Intended Material Environment

" Aging Effect

":Aging>Management NUREG-Table1 Item Notes

.Type Function Requiring Program 1.801 Vol.

Item1 oes I _

ype____

I __

Management, 2 Item Tubing Tubing PB Stainless Steel Stainless Steel Atmosphere/

Weather (Ext)

Plant Indoor Air (Ext)

None iNone None None INone VII.J-1 5 I

Tubing Tubing T uin.....

PB

.PB

[PB Stainless Steel Plant Indoor Air (Int)

Stainless Plant Indoor Air Stainless Raw Water (Int)

Steel 1 Sta-n/-1es-s SRaw Water (Int) lSteel Tubin g Loss of material inspectio n.of t*r*nA.l MWiGcellancou6 Piping

'Cand Ducting CGomponents (132.1.22)

I Fire Water System

((B2.1.13)

Flow blockaqe Fire Water System due to fouling

.3(B2.11.13)

Flow blockage Fire Water System

'due to foulin (3B2.1. 13)

Loss of material

'Fire Water System

_.(1B2.1.13)

'None None Loss of material lFire Protection (B2.1.12)

Loss of material

Fuel Oil Chemistry

((B2.1.14) & One Time

___Inspection (B2.11.16)

Loss of material

External Surfaces Monitoring Program (B 2..20.)

Loss of material, Fire Water System VNAo26 None None None VII.G-19 None IG 3.3.1.94 A

32.1.08 E

None H, 10 None Hl,10 None H, 9 3.3.1.69

• B

'Valve (Halon)

Valve (Halon)

PB PB Carbon Steel Dry Gas (Int)

Carbon Steel !Plant Indoor Air Carbon Steel FuelOilnt)

VII.J123 13.3.1.97 A

VII.1-8 3.3.1.58 1E, 2

!Valve Valve Valve Valve PB VII.H2-24 VII. 1-8 3.3.1.20 B

3.3.1.58 B

Carbon Steel Plant Indoor Air (Ext)

PB Carbon Steel Raw V*

Carbon Steel Raw V

/ater (Int)

None Irecurring internal :(B2.1.13) icorrosion later (Int)

Flow blockage Fire Wate

,.[.dueto foulinq (B2.1.13) m None None None H, 6 r Syste NOC-AE-14003141 Page 65 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aginr Management Evaluation - Fire Protection System (Continued) aComponent Intended Materia I Environment :

Aging Effect Aging Management NUREG:

Table 1 Ireif

• Notes CmoetIntne AgngEemiIR~

• Type Function f

Requiring Program>.

1801 Vol.

___________=*

ater I Management

_____ _____________M 2 Itemr Valve PB Carbon Steel i Raw Water (Int)

+/-

Atmosphere!

Valve PB Cast Iron Atmosphere/

Weather (Ext)

Buried (Ext)

I Loss of material I Fire Water System (B2.1.13)

Loss of material External Surfaces Monitoring Program

_ (B2.1.20)

Loss of material I Buried Piping and Tanks Inspection (B2.1.18)

VII.G-24 VII.-9 7.31.58 B

_ 1 3.3.1.68 lB Valve

,PB ICast Iron VII.G-25 3.3.1.19

'B i

-- ---- - -- - -+/-1 Valve PB, SIA

!Valve I

IA

~PBA SValve

~

PB Cast Iron Cast Iron Cast Iron (Gray Cast

,Iron).,.-,-

Cast Iron (Gray Cast Iron)

Plant Indoor Air (Ext)

Raw Water (Int)

Atmosphere/

Weather (Ext)

Buried (Ext)

Loss of material External Surfaces

.Monitoring Program I (B2.1.20),

Loss of material Fire Water System Loss of material External Surfaces

.Monitoring Program 1 (32..20)_

Loss of material iSelective Leaching of

.Materials (B2.1.17)

VII.1-8 VII.G-24 VII.1-9 VII.G-15 3.3.1.58 lB 3.3.1.68

,B 3.3.1.58 1B 3.3.1.85 1B

[Valve PB Valve JPB Valve S1A Valve iPB L

I-

+

+/-

-l Cast Iron (Gray Cast

,ron).

Cast Iron (Gray Cast ITon)2 Cast Iron (Gray Cast Iron)

Buried (Ext)

Plant Indoor Air (Ext)

Plant Indoor Air (Ext)

Loss of material Buried Piping and Tanks Inspection (B2.1.18)

Loss of material External Surfaces

!Monitoring Program (B2.1.20)_

Loss of material I External Surfaces Monitoring Program

@(B2.1.20)

VII.G-25 None None 3.3.1.19 1 B None None G

4-1G Valve Valve PB Cast Iron (Gray Cast Iro n )

PB SIA Cast Iron (Gray Cast Iron)

!Plant Indoor Air (Ext)

Raw Water (Int)

Loss of

Loss of material External Surfaces

'Monitoring Program

.(B2.1..20) material Loss of material.

recurring internal corrosion None None IF H 6

.N n o...............n.e...

None None NOC-AE-14003141 Page 66 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of A-qin q Management Evaluation - Fire Protection System (Continued)

Component Intended Material Environment AgingýEffect Aging Management NUREG-Table 1 Item Notes Type-Function Reqdiring Program.

1801: Vol.

i

_.....Management.ý 2 Item Valve PB, SIA Cast Iron (Gray Cast Iron)

Raw Water (Int)

Loss of material

Selective Leaching of Materials (B2.1.17)

Loss of material Fire Water System l(B2.1.13)

VII.G-14 3.3.1.85 B

Valve Valve PB, SIA PB Cast Iron (Gray Cast Ironprl Copper -Alloy Raw Water (Int)

VII.G-24 None 3.3.1.68 B

None rG

ýAtmosphere!

Weather (Ext)

Loss of material External Surfaces Monitoring Program (132.1.20)

Valve (Halon)

Valve (Halon)

PB Copper Alloy !Dry Gas (Int)

Copper Alloy :Plant Indoor Air (Ext)

None None ne None VII.J-4 3.3.1.97 No VIII.I-2 3.4.1.41 Valve Valve PB, SIA Copper Alloy !Plant Indoor Air (Ext)

Copper Alloy Plant Indoor Air (Int)

INone None Loss of material l.pc.tien Of InternAl

!Surfacesin MiScellaneou6 Piping Components (132.1.22)

I Fire Water System.

(g2.1.13)

Flow blockage Fire Water System due to fouling (132.1.13)

VIII. 1-2 None 3.4.1.41 3.3428 None

'A

ýA IA E

1H, 11 iH iH, 11 Valve PB Copper Alloy Plant Indoor Air i(Int)

None None None H8 Valve Valve Valve (Halon)

Valve (Halon) w PB, SIA Copper Alloy Raw Water (Int)

Copper Alloy Raw Water (Int)

Flow blockage 1 Fire Water System due to fouling (B2.1.13)

Loss of material Fire Water System (B2.1.13)

None VII.G-12 None

'-I, 8 3.3.1.70 B

PB 15B Stainless Dry Gas (Int)

Steel Stainless

Plant Indoor Air Steel (Ext)

None INone VII.J-19 3.3.1.97 A

3.3.1.94 A

None None VII.J-15 NOC-AE-14003141 Page 67 of 82 Table 3.3.2-17 Auxiliary Systems - Summary of Aqinq Manaqement Evaluation - Fire Protection System (Continued)

....Component.[Intenfled Materiald

• Environment Aging Effect Aging Management

.NUREG' Table I Item Notes Type Function

,,Requiring Program t 1801 Vol.

Management 2 Item:..

Valve PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A

Steel (Ext) j Valve PB Stainless Raw Water (Int)

Flow blockage Fire Water System None jNone H 9

__Steel

_]due to fouling (132. 1.1.13_____

Valve PB Stainless Steel Raw Water (Int)

Loss of material Fire Water System (B2.1.13)

VII.G-19 3.3.1.69 1B NOC-AE-14003141 Page 68 of 82 Notes for Table 3.3.2-17:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

F Material not in NUREG-1 801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1 801.

Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 The Fire Protection program (B2.1.12) is used to manage aging of the external surfaces of halon piping.

3 A visual inspection of the external surface of the bottom of tanks sitting directly on soil or concrete cannot be performed. A volumetric examination from the inside of the bottom of the tank is performed in lieu of an external inspection.

4 The External Surfaces Monitoring Program (B2.1.20) is used to manage the hardening and loss of strength of the caulking found between the firewater storage tank (FWST) bottom to concrete foundation interface to prevent water entry under the tank bottom.

5 Fire Protection Program (B2.1.12) manages the aging effects associated with this fire damper material and environment combination.

6 The Fire Water System program (B2.1.13) is used to monitor for recurring internal corrosion in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-400 7

The Fire Water System program (B2.1.13) is used to monitor steel components for flow blockage due to foulingq in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-33 8

The Fire Water System program (B2.1.13) is used to monitor copper alloy components for flow blockage due to fouling in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.AP-197 9

The Fire Water System program (B2.1.13) is used to monitor stainless steel components for flow blockage due to fouling in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-55 10 The Fire Water System program (B2.1.13) is used to monitor stainless steel components for loss of material and flow blockage in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-404 11 The Fire Water System program (B2.1.13) is used to monitor copper alloy components for loss of material and flow blocka-ge in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-404 12 The Fire Water System program (B2.1.13) is used to monitor steel components for loss of material and flow blockage in the Fire Protection system. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-404 13 The Fire Water System program (B2.1.13) is used to monitor loss of material in the Fire Water Storage Tanks. Reference LR-ISG-2012-02 Appendix C Line VII.G.A-412 14 Coatings are managed for loss of coating integrity to provide assurance that the coatings will not adversely affect the intended function of downstream components due to fouling. No credit is taken for the coatings to protect the base metal from loss of material.

NOC-AE-14003141 Page 69 of 82 Table 3.3.2-19 Auxiliary Systems - Summary of Aging Management Evaluation - Chemical and Volume Control System Cornmoi ht Type Intended Material Environment Aging.Effect Aging.Management:

NUREG6-YTable 1"1:

Notes Function Requiring

ý,irogram p1801 Vol.

Item

,__ :Management V

1',2 Item Insulation INS Aluminum Plant Indoor Air (Ext)

None None V.F-2 3.2.1.50 C

4-Insulation Insulation Orifice Piping Piping Piping INS Insulation Plant Indoor

'Nene Nene Calcium Silicate Air (Ext)

Reduced thermal Extern*

I insulation Monitor iresistance due to (B2.1.2 moisture i intrusion INS Insulation

!Plant Indoor INone NEne Fiberglass Air (Ext)

!Reduced thermal Externa insulation Monitor resistance due to (B2.1.2 moisture Sintrusion_

PB, TH Stainless Steel !Borated Water: None None

_ LJ eakage

_E____

SIA Stainless Steel iDry Gas (Int)

None None 113S, SIA -Stainless Steel 'Plant Indoor INGen ml aAir (Ext)

I Loss of material

,Externa LBesSelPAnt Inoo N(Be.1.21 Monitor (132.11.2i LBS

'Stainless Steel Secondary

!,Loss of material Water C Water (Int)

(B2.11.2 S4

_Inspecti al Surfaces ring Program 0)

I Surfaces inq Program 0)

None None None

!None J

A A H, 6 VII.J-16 3.3.1.99

+

+

VII.J-19 3.3.1.97 4

I Surfaces inq Program

.0 )

Them istry and One-Time ion (B2.1.16)

None None VIII.D1-4 3.4.1.16 Tank PB

'Stainless Steel jDry Gas (Int)

None None VII.J-19 1

3.3.1.9 c

NOC-AE-14003141 Page 70 of 82 None K6 Tank I LBS, PB, ISlA I-Tank LBS, PB,

_ SIA Stainless Steel !Plant Indoor IAir (Ext)

Stainless Steel Plant Indoor

.. Air (Ext)_.

Stainless Steel Dry Gas (Int)

I I

Loss of material I External Surfaces iMonitorinq Program (B2.1.20)

None None None None VII.J-15 3.3.1.94 C

Al A H, Valve Valve SIA None VII.J-19 None 3.3.1.97 3-.3.94 None LBS, SIA Stainless Steel Plant Indoor Air (Ext)

LosE Crac Valve PB Stainless Steel Reactor Coolant (Int) e IxNen of material External Surfaces iMonitoring Program

_____(B2.1.20)

'king ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD for Class 1

,components (B2.1.1) land Water Chemistry

[(B2.1.2)_

IV.C2-5 3.1.1.68 A

Notes for Table 3.3.2-19:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material, and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1801.

NOC-AE-14003141 Page 71 of 82 Plant Specific Notes:

1 NUREG-1801 does not address the aging effect of nickel-alloys in borated water leakage. Nickel-alloys subject to an air with borated water leakage environment are similar to stainless steel in a borated water leakage environment and do not experience aging effects due to borated water leakage.

2 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

3 Non-inhibited copper alloy > 15% zinc SSCs with surfaces exposed to ventilation atmosphere (internal) or plant indoor air (internal) are subject to wetting due to condensation and thus are subject to loss of material due to selective leaching.

4 The reduction of heat transfer aging effect is not identified in NUREG-1801 for this component, material, and environment combination.

Reduction of heat transfer is not expected in heat exchangers with reactor coolant or treated borated water environments as long as water chemistry is maintained. Reduction of heat transfer is managed with Water Chemistry (B2.1.2) and One Time Inspection (B2.1.16).

5 The aging effect of reduced thermal insulation resistance due to moisture intrusion is managed by AMP B2.1.20, External Surfaces Monitoring Program. Reference LR-ISG-2012-02 Appendix C Item VI1.1.S-403.

6 The External Surfaces Monitoring program (B2.1.20) is used to monitor insulated stainless steel components exposed to plant indoor air for loss of material. Reference LR-ISG-2012-02 Appendix C Line VII.A2.A-405 NOC-AE-14003141 Page 72 of 82 Auxiliary Systems - Summary of Aging Management Evaluation - Miscellaneous Systems in scope ONLY for Table 3.3.2-27 Criterion 10 CFR 54.4 (a) (2)

Component.:Intended ~Material Envirofniment r

KA Ing Effect Aging Management NUREG Table 1 Item Notes Type Function Requiring Program 1801 Vol.

TypeM*agemen 2____:

Item'

" *

• i: *

!i Management 2 Item* *:,:iz **

Piping LBS5 Stainless Steel LBS, SIA 'Stainless Steel Piping Uemtneralized

Water (Int)

!Plant Indoor Air (Ext)

Loss ot material iWater Chemistry

!VIII.F-29

'(B2.1.2) and One-Time I I Inspectioqn @B2_.1.1,6)__

11 Loss of material I External Surfaces

!None Monitoring Program

-(B2.1.20)

None

'None VII.J-15 3.4.1.16 None A

H, 11 A

LBS, SIA Stainless Plant Indoor Air Steel I(Ext) 3.3.1.94

+

[Valve Valve

.V.a.........v.e.

Valve SIA Stainless Dry Gas (Int)

Steel LBS Stainless Plant Indoor Air Steel j(Ext)

LBS, SIA Stainless Plant Indoor Air Steel (Ext)

None None VII.J-19 Loss of material External Surfaces jMonitoring Program N(B2.1.20)

SNone None 3.3.1.97 A

None H, 11 3.3.1.94 1A None VII.J-15 Notes for Table 3.3.2-27:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

F Material not in NUREG-1 801 for this component.

G Environment not in NUREG-1 801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material, and environment combination.

NOC-AE-14003141 Page 73 of 82 Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 Operating experience does not suggest there is any aging effect, and the use of stainless steel up to 200'F and 50 weight-percent NaOH is common in industrial applications with no special consideration for aging. There is no NUREG-1 801 line that includes NaOH environment.

3 The component environment is radioactive waste drains that have been evaluated as a raw water environment. Loss of material on internal component surface exposed to radioactive waste drains environment is managed by Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) instead of the Open-Cycle Cooling Water program (B2.1.9).

4 The internal environment of these components is comprised of nonradioactive waste streams which may include oil and other contaminants that are evaluated as raw water. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) manages this uncontrolled raw water environment rather than the Open-Cycle Cooling Water program (B2.11.9).

5 The external environment of these components is comprised of nonradioactive waste streams which may include oil and other contaminants that are evaluated as raw water. The External Surfaces Monitoring (B2.1.20) manages this uncontrolled raw water environment rather than the Open-Cycle Cooling Water program (B2.1.9).

6 PVC is relatively unaffected by water, concentrated alkalis, and non-oxidizing acids, oils, and ozone.

7 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

8 Loss of material by selective leaching will be managed by Selective Leaching of Aluminum Bronze (B2.1.37) instead of Selective Leaching of Materials (B2.1.17) for components made of aluminum bronze (copper alloy greater than 8 percent aluminum).

9 The internal environment of these components is comprised of raw water. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22) manages this raw water environment more appropriately than Open-Cycle Cooling Water program (B2.1.9).

10 Wall thinning due to erosion-corrosion is managed by the Flow-Accelerated Corrosion program (B2.1.6).

11 The External Surfaces Monitoring program (B2.1.20) is used to monitor insulated stainless steel components exposed to plant indoor air for loss of material. Reference LR-ISG-2012-02 Appendix C Line VII.A2.A-405 NOC-AE-14003141 Page 74 of 82 Steam and Power Conversion System - Summary of Aging Management Evaluation - Main Steam System Table 3.4.2-1 Component Intended

" Material Environment.,

• Aging Effect.

Aging Management 1 NUREG-Tabl*e 1Item Notes Type Function Requiring Program 801 Vol.

M anagem ent. J 2 Item. "

Insulation INS Aluminum Plant Indoor Air (Ext)

None None V.F-2 3.2.1.50 C

Insulation tINS L,

Insulation Fiberglass Insulation Calcium Silicate Plant Indoor Air (Ext)

Nee Reduced thermal insulation resistance due to moisture intrusion

- L.-.-..__ _.____ _.

Insulation tINS None

,'External Surface Monitorinq Progr (B2.1.20)

!External Surface Monitorinq Progq I(B2.1.20)

.None None H-2

s am None None J -H 2 am Plant Indoor Air (Ext)

None Reduced thermal insulation resistance due to moistIJrR intrusion mni-,ture intnigion

÷ Orifice PB, TH Carbon Steell Lubricating Oil I(Int)

Loss of material

'Lubricating Oil Analysis i(B2.1.23) and One-Time Inspection (B2.1.16)

VIII.A-14 3.4.1.07 B

Notes for Table 3.4.2-1:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1 801.

NOC-AE-14003141 Page 75 of 82 Plant Specific Notes:

1 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

2 The aginq effect of reduced thermal insulation resistance due to moisture intrusion is managed by AMP B2.1.20, External Surfaces Monitorino Proaram. Reference LR-ISG-2012-02 ADoendix C Item VI1I..S-403.

NOC-AE-14003141 Page 76 of 82 Ft*fam *nd Pnwp~r flonvp~r.*inn F£v.ctp~m - 5iimma~rv of Aciina M1anaaement Evaluation - Feedwater Svstem ThhIl

.-R 4 2-.

Component Intended Material Environment Aging.Effect

Aging Management NUREG-Table 1 Item Notes Type Fuction

.Requiring, Progr am 1801 Vol.11 i

_ *Management 2_"_____

..:.2._Item_

Insulation INS Aluminum Plant Indoor Air None None V.F-2 3.2.1.50 iC Ext) insulation INS Insulation Plant Indoor Air NeRe NOee None None IJ4H 2 Fiberglass (Ext)

Reduced thermal ?External Surfaces insulation IMonitorinq Proqram I

resistance due to (B2.1.20) moisture intrusion Insulation INS Insulation Plant Indoor Air Neoe

'Nene None None JH 2 Calcium (Ext)

Reduced thermal External Surfaces Silicate insulation Monitoring Program resistance due to 1(12.11.20) ri I

I~

moisture intrusion r

• fi l

l I I

r-Il III 1M n A 1 Al A

U1,/

I !,1 Steel

!(Ext)

I, Notes for Table 3.4.2-3:

Standard Notes:

A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

H Aging effect not in NUREG-1801 for this component, material and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1 801.

Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 The agingq effect of reduced thermal insulation resistance due to moisture intrusion is managed by AMP B2.1.20, External Surfaces Monitoring Program. Reference LR-ISG-2012-02 Appendix C Item VII.1.S-403.

NOC-AE-14003141 Page 77 of 82 Steam and Power Conversion System - Summary of Aging Management Evaluation - Demineralized Water (Make-up) System Table 3.4.2-4 Component Intended Material Environment Aging Effect Aging Management I NUREG-Table I Ite"m Notes' Type Function Requiring ~.

Program 1801 Vol.

M anagemen.

2d1,em j M a a

em n 2 te

• 1 Piping Piping LBS, PB, SIA LBS, SIA

'L-BS, PB, SIA LBS, PB, SIA i&LBSISIA Stainless Steel Stainless Steel Stainless Steel Demineralized Water (Int)

Plant Indoor Air (Ext)

Plant Indoor Air (Ext)

Valve Valve Stainless Demineralized Steel Water (Int)

Stainless

!Plant Indoor Air Steel (Ext)

Wall thinning i Flow-Accelerated C~ror.si~n_(B2,!.).

Loss of material External Surfaces Monitoring Program

'______-ne

___ (B2.1.20)

None

None Loss of material

'Water Chemistry

(B2.1.2) and One-Time Loss____

Inspection (B2.1.16)

Loss of material I External Surfaces

!Monitoring Program (1B2.1.20)

None VIII.1-10 3.4.1.41 IA None VIII.E-29 None None H,2 None

H, 3 3.4.1.16 IA None

ýH3 L n I

Valve e *,PB, Stainless Steel

!Plant Indoor Air oL(Ext)....

c None NoneVII-1 i3.4.1.41

!A Notes for Table 3.4.2-4:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment combination.

Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 Wall thinning due to erosion-corrosion is managed by the Flow-Accelerated Corrosion program (B2.1.6).

3 The External Surfaces Monitoring program (B2.1.20) is used to monitor insulated stainless steel components exposed to plant indoor air for loss of material. Reference LR-ISG-2012-02 ADoendix C Line VII.A2.A-405 NOC-AE-14003141 Page 78 of 82 Steam and Power Conversion System - Summary of Aging Management Evaluation - Steam Generator Blowdown System Table 3.4.2-5

ýCo mpbnent" Inten~ded

'Mate'rial Envirbhment Agin ffc Aging Management NUREG~

Table Iltem, oe Type Function Requiring Program 1801VOIC.*

I____

I________Management 2 Item x____:

Insulation

.FutJion Insulation Pipingd-INS INS Aluminum Plant Indoor Air i (Ext)

Insulation Plant-Indoor Air Fiberglass (Ext)

None None 1 V. F-2 3.2.1.50 C

NORe

'NORe Reduced thermal lExternal Surfaces insulation I Monitoring Progqram resistance due to (B2.1.20) moisture intrusion NeRe

'NOe Reduced thermal External Surfaces insulation Monitoring Progqram resistance due to (B2.1.20) moisture intrusion None None j-H3

---

4

-I Insulation Calcium Silicate Plant Indoor Air (Ext)

None INone IJ-H 3 a

4 a

PB, LBS, SIA Carbon Steel Borated Water

_ Leakage (Ext)

Loss of material Boric Acid Corrosion (B2.1.4)

VIII.H-9 3.4.1.38 A

Notes for Table 3.4.2-5:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP E

Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.

H Aging effect not in NUREG-1801 for this component, material and environment combination.

J Neither the component nor the material and environment combination is evaluated in NUREG-1801.

NOC-AE-14003141 Page 79 of 82 Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manages loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

3 The acqing effect of reduced thermal insulation resistance due to moisture intrusion is managed by AMP B2.1.20, External Surfaces Monitorina Proaram. Reference LR-ISG-2012-02 Aooendix C Item VlI.I.S-403.

NOC-AE-14003141 Page 80 of 82 Steam and Power Conversion System - Summary of Aging Management Evaluation - Auxiliary Feedwater Table 3.4.2-6 Piping 4

-~

LBS, PB, SIA Carbon Steel Secondary Water t(Int)

Wall thinning Flow-Accelerated Corrosion (B2.1.6)

VIII.E-35 3.4.1.29 B

Piping Pipin LBS, PB, SIA LBS, PB, SIA Stainless Steel Stainless Steel Atmosphere/

Weather (Ext)

Atmosphere/

Weather (Ext)

None Loss of material Crackinq None External Surfaces Monitoring Program i(R21 2go)

None None

!G-ýH 6 J.

lExternal Surfaces Monitoring Program (B2.1.20)

None None None

!G, 4 SIA JSolenoid Valve 'PB iTank f an-k Stainless

[Atmosphere/

None

'None Steel

!W eather (Int)..........

Copper Alloy Plant Indoor Air iNone None

(>15% Zinc) (Ext) 1Stainless DtrGs(het /

None None SteHE4 Wea~her fExp)

_-St-ails

- Dry Gas (Int) iNone None None V. F-3 3.2.1.53 A

P-B

'VIII.1-12

.3.4.1.44 A

Steel Tubing Tubing Carbon Steel

+LBS, PB, SIA Stainless Steel Plant Indoor Air (Ext)

Atmosphere/

Weather (Ext)

Atmosphere/

Weather (Ext)

Loss of material i External Surfaces Monitoring Program S(132.1.20)

+

VIII.H-7 None None 3.4.1.28 1B None LBS, PB, SIA Stainless Steel Loss of material External Surfaces Monitoring Pro~gram

_(B2.1.20)

Crackingq External Surfaces Monitoring Pro-gram (B12.1. 20)

Loss of material FLubricating Oil Analysis

'(B2.1.23) and One-Time

_lnspection (B2.1.16.-

G-H 6

+/-

+

None None ITubing LBS, PB, Stainless ILubricating Oil SIA Steel

!(Int)

VIII.G-29 3.4.1.19

'B NOC-AE-14003141 Page 81 of 82 Valve PB, Valve PB, Carbon Steel I Secondary Water (Int)

Stainless Atmosphere/

Steel Weather (Ext)

Stainless Atmosphere/

Steel Weather (Ext)

Loss of material Water Chemistry 1(B2.1.2) and One-Time

!Inspection (2.1.16)

Neae lNene Loss of material External Surfaces IMonitorincq Program

.(132.1.20)

Cracking I External Surfaces Monitoring Program (B2.1.20)

VIII.G-38 3.4.1.04

!A None INone G-H, 6 Valve None None I.

I.

I I

Valve PB Stainless

.See Plant Indoor Air (Ext)

None None VIII.1-10 3.4.1.41 A

Notes for Table 3.4.2-6:

Standard Notes:

A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material, and environment combination.

NOC-AE-14003141 Page 82 of 82 Plant Specific Notes:

1 Loss of preload is conservatively considered to be applicable for all closure bolting.

2 Non-inhibited copper alloy >15% zinc SSCs with surfaces exposed to ventilation atmosphere (internal) or plant indoor air (internal) are subject to wetting due to condensation and thus are subject to loss of material due to selective leaching.

3 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.

4 These items are assigned the environment of Atmosphere/ Weather (Internal). The items are vented or open to the outside atmosphere so the distinction between internal and external is not relevant for aging purposes.

These stainless steel components are located outside with an uncontrolled external air environment and are not exposed to aggressive chemical species. The STP plant outdoor environment is not subject to industry air pollution or saline environment. Alternate wetting and drying has shown a tendency to "wash" the surface material rather than concentrate contaminants. Stainless steel does not experience any appreciable aging effects in this environment.

5 A visual inspection of the external surface of the bottom of tanks sitting directly on soil or concrete cannot be performed. A volumetric examination from the inside of the bottom of the tank is performed in lieu of an external inspection.

6 The External Surfaces Monitorinq program (B2.1.20) is used to monitor insulated stainless steel components exposed to atmosphere weather for loss of material. Reference LR-ISG-2012-02 Appendix C Line VII.A2.A-405 7

The External Surfaces Monitoring program (B2.1.20) is used to monitor insulated stainless steel components exposed to atmosphere weather for crackina. Reference LR-ISG-2012-02 Aooendix C Line VII.A2.A-405 NOC-AE-14003141 Regulatory Commitments NOC-AE-14003141 Page 1 of 31 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 Item #

.Commit.nent.

L ImplementatAon Sec.ion..2 ri St chedule ot 1

Enhance the Water Chemistry program procedures to:

B2.1.2 Pror to the, include a statement that the sampling frequency for the primary and secondary water extended.p.r*tiGn systems is temporarily increased whenever corrective actions are taken to address an abnormal chemistry condition for action level parameters, and that this increased Completed sampling is utilized to verify that the desired condition has been achieved, and when it is CR 10-23251 achieved the sampling frequencies are returned to the EPRI recommended frequencies.

2 Enhance the Boric Acid Corrosion program procedures to:

B2.1.4 Prior to the period of state that susceptible components adjacent to potential leakage sources include

.xtn*ded op*.*.*,R electrical components and connectors. The program will also state that it is applicable to other materials (such as aluminum and copper alloy) that are susceptible to boric acid Completed corrosion.

CR 10-23254 3

Enhance the Bolting Integrity program procedures to:

B2.1.7 Complete no later conform to the guidance contained in EPRI TR-104213 than six months evaluate loss of preload of the joint connection, including bolt stress, gasket stress, LQPrior to the period of flange alignment, and operating condition to determine the corrective actions consistent extended operation with EPRI TR-104213.

CR 10-23255-1 4

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

B2.1.9 Complete no later include visual inspection of the strainer inlet area and the interior surfaces of the than six months adjacent upstream and downstream piping. Material wastage, dimensional change, LQPrior to the period of extended operation NOC-AE-14003141 Page 2 of 31 Table A4-1 License Renewal Commitments Item # IC.ommitment LRA Implementation Sectio

'ched 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.

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 CCW 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 if the 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

" require an engineering evaluation be performed when loss of material in piping or 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 the coating applied on the essential chiller water box covers, standby diesel generator (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 and pull off adhesion test per ASTM D4541, Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23256 Complete no later than the date the renewed operating license is issued NOC-AE-14003141 Page 3 of 31 Table A4-1 License Renewal Commitments Item #

Commitment A : :

Implemenftation,

,<S'.

ion Schedule

• require coating inspections and tests be performed by a qualified Nuclear Coating Specialist (NCS) as defined by ASTMV 07108 or by Coatings Surveillance Personnel (CSP) under the technical direction of the NCS.

• require monitoring and trending of coatings installed on the internals of in-scope cornponents.

• specify the acceptance criteria for coatings as no erosion, corrosion, cavitation erosion, flaking or peeling of the coatings installed on the internals of in-scope components is observed.

• require coatings not meeting these criteria be considered degraded and a condition report be initiated to document and resolve thecoer.__________

5 Enhance the Closed-Cycle Cooling Water System program procedures to:

B2.1.10 Complete no later include visual inspection of representative samples of each combination of material and than six months water treatment program at least every ten years and opportunistically, and pPrior to the period of include acceptance criteria, extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

________CR 10-23257-1 6

Enhance the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

B2.1-.11 Prior to thc period o Handling Systems program procedures to:

.xtendcd eperatiGn.

Sinspect crane structural members for loss of material due to corrosion and rail wear.

Completed

___I_

CR 10-23258 NOC-AE-14003141 Page 4 of 31 Table A4-1 License Renewal Commitments Iteni#

Commitment LRA Implementation

.,Section Schedule S; 7

Enhance the Fire Protection program procedures to:

B2.1.12 Complete no later provide visual inspection for corrosion and mechanical damage on halon system than six months components at least once every six months, 212rior to the period of provide inspections to detect the following penetration seal deficiencies: signs of extended operation.

degradation such as cracking, seal separation from walls and components, separation Insp~ections to be of layers of material, rupture and puncture of seals, comiolete no later include qualification criteria for individuals performing inspections of fire doors, fire than six months prior barrier penetration seals, fire barrier walls, ceilings and floors in accordance with to the PEO or the end NUREG-1 801, of the last refueling include the following fire barrier inspection acceptance criteria: no cracks, spalling, or outage prior to the loss of material that would prevent the barrier from performing its design function, and PEO, whichever loss of material that would prevent the barrier from performing its design function, and occurs later.

provide visual inspection for degradation, corrosion and mechanical damage on Halon system components at least once every six months.

R1235 8

Enhance the Fire Water System program procedures to perform periodic inspections, testing.

B2.1.13 Complete no later and cleaning on the following:

than six months include volumetric examinations or direct measurement on representative locations of QPrior to the period of the fire water system to determine pipe wall thickness, extended operation.

replace sprinklers prior to 50 years in service or field service test a representative Inspections to be sample and test every 10 years thereafter to ensure signs of degradation are detected complete no later in a timely manner, and than six months prior trending of fire water piping flow parameters recorded during fire water flow tests=,

to the PEG or the end Sp~rinkler inspections every 18 months per NFPA 25, 2011 Edition Section 5.2.1.1, of the last refueling 50-year sprinkler replacement or testing per NFPA 25. 2011 Edition Section 5.3.1.

outage prior to the Standpipe and hose systems flow tests every 3 years per NFPA 25. 2011 Edition PEG, whichever Section 6.3.1, occurs later.

Underground and exposed Piping flow tests every 3 years per NFPA 25. 2011 Edition CR 10-23260 Section_7.3.1, NOC-AE-14003141 Page 5 of 31 Table A4-1 License Renewal Commitments

.Item #

.~Commitment

.LRA'~

lmplementation 4

Section

'Scheduile 4'

. "4 4*::ii:.*"!'

Hydrants flow testing and visually inspection annually per NFPA 25, 2011 Edition Section 7.3.2, Fire pumps suction screens cleaning and inspections per NFPA 25, 2011 Edition Section 8.3.3.7, Fire water storage tank exterior inspections annually per NFPA 25, 2011 Edition Section 9.2.5.5, Fire water storage tank interior visual inspections every 5 years per NFPA 25, 2011 Edition Section 9.2.6 and 9.2.7 and bottom thickness ultrasonic tests every 10 years, Main drain testing every 18 months per NFPA 25, 2011 Edition Section 13.2.5, Deluge Valve testing annually per NFPA 25 Sections 13.4.3.2.2 through 13.4.3.2.5, Water Spray Fixed System strainers cleaning and inspections per NFPA 25, 2011 Edition Section 10.2.1.6, 10.2.1.7, 10.2.7, Spray/sprinkler nozzles full flow test every 18 months per NFPA 25, 2011 Edition Section 10.3.4.3, Foam water sprinkler systems spray nozzle strainers per NFPA 25, 2011 Edition Section 11.2.7.1, Foam water sprinkler systems operational test discharge patterns annually per NFPA 25 Section 11.3.2.6, Foam water sprinkler systems storage tank visual inspection for internal corrosion once every 10 years, and Internal surface of pipinq and branch lines obstruction inspections every 5 years per NFPA 25 Sections 14.2 and 14.3.

Procedures will be enhanced to:

perform follow-up volumetric wall thickness examinations when surface irregularities are detected; perform either flow testing or flushing sufficient to detect flow blockage or 100 percent visually inspection in each 5-year interval, beginninq 5 years prior to the 1period of I

NOC-AE-14003141 Page 6 of 31 Table A4-1 License Renewal Commitments Item>,

• ,* Commitment

• i,'iii

• • LRA Implementation i Section

'Schedule..

extended operation on portions of water-based fire protection components that have been wetted but are normally dry or piping segments that cannot be drained or segments that allow water to collect:

perform volumetric wall thickness inspection are performed on 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect in each 5-year interval of the prior to the period of extended operation. The 20 percent of piping inspected in each 5-year interval shall be in different location than previously inspected piping; monitor and trend fire water piping flow parameters recorded during fire water flow tests specify the acceptance criteria to be:

o Minimum design fire water piping wall thickness is maintained.

o Fouling shall not be observed during inspections of sprinklers and associated piping in the sprinkler system that could cause flow blockage.

o Sprinklers that show signs of leakage or corrosion shall be replaced. If any sprinklers fails the representative sample testing required for sprinkler in service for 50 years, all sprinklers within the are represented by the sample will be replaced.

o Sufficient foreign organic or inorganic material obstructing pipe or sprinklers is removed and its source is determined and corrected; manage coatings installed on the internals of in-scope fire water components for loss of coating integrity; visually inspect coatings installed on the internals of in-scope fire water components 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, and (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:

• monitor and trend coatinos installed on the internals of in-scooe fire water components:

monitor__

an trn cotia intle on the-interna-s of-insco fire__water____________

NOC-AE-1 4003141 Page 7 of 31 Table A4-1 License Renewal Commitments Item#

Commitment LRA

.1m plemenitation Section Schedule 4 <,

4.

specify the acceptance criteria for coatings as no erosion, corrosion, cavitation erosion.

flaking or peeling of the coatings installed on the internals of in-scope fire water components is observed: and require coatings not meetinq the acceptance criteria be considered de-graded and a condition report be initiated to document and resolve the concern.

9 Enhance the Fuel Oil Chemistry program procedures to:

B2.1.14 Complete no later extend the scope of the program to include the SDG fuel oil drain tanks, than six months check and remove the accumulated water from the fuel oil drain tanks, day tanks, and QPrior to the period of storage tanks associated with the SDG, BOP, lighting diesel generator, and fire water extended operation.

pump diesel generators. A minimum frequency of water removal from the fuel oil tanks Inspections to be will be included in the procedure, complete no later include 10-year periodic draining, cleaning, and inspection for corrosion of the SDG fuel than six months prior oil drain tanks, lighting diesel generator fuel oil tank, BOP diesel generator fuel oil day to the PEO or the end tanks, and diesel fire pump fuel oil storage tanks, of the last refueling outagqe prior to the PEO, whichever require periodic testing of the lighting diesel generator fuel oil tank and the SDG and occurs later.

diesel fire pump fuel oil storage tanks for microbiological organisms, require analysis for water, biological activity, sediment, and particulate contamination of the diesel fire pump fuel oil storage tanks, lighting diesel generator fuel oil tank, and the CR-1 0-23261 BOP diesel generator fuel oil day tanks on a quarterly basis, conduct ultrasonic testing or pulsed eddy current thickness examination to detect corrosion-related wall thinning once on the tank bottoms for the SDG and diesel fire pump, and the BOP diesel generator fuel oil day tanks, and incorporate the sampling and testing of the diesel fire pump fuel oil storage tanks for particulate contamination and water and to incorporate the trending of water, particulate contamination, and microbiological activity in the SDG and diesel fire pump fuel oil storage tanks, lighting diesel generator fuel oil tank, and the BOP diesel generator fuel oil day tanks.

NOC-AE-14003141 Page 8 of 31 Table A4-1 License Renewal Commitments Item #

Commitment LR o.lmplementation Section Schedule 10 Enhance the Reactor Vessel Surveillance program procedures to:

B2.1.15 Complete no later include the withdrawal schedule and analysis of the ex-vessel dosimetry chain, than six months demonstrate that the reactor vessel inlet and out nozzles are exposed to a fluence of 2Prior to the period of less than 1017 n/cm2, or will incorporate the adjusted reference temperature (ART) for extended operation.

the inlet and outlet nozzles with bounding chemistry and fluence values into the P-T limit Inspections to be

curves, complete no later enhance the program to include the Unit 2 bottom head torus in the Reactor Vessel than six months prior Surveillance program.

to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23262 11 Implement the One-Time Inspection (OTI) program as described in LRA Section B2.1.16.

B2.1.16 Start implementation dýDuring the 10 years prior to the period of extended operation.

Compl'ete no l-;ter.

than ix FmonthS prior to PEOInspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO.

NOC-AE-1 4003141 Page 9 of 31 Table A4-1 License Renewal Commitments Item #

Commitment

.LRA:

SImplemoentation Section Schedule whichever occurs later.

_______CR 10-23263 12 Implement the Selective Leaching of Materials program as described in LRA Section B2.1.17.

B2.1.17 Start implementation dDuring the five years prior to the period of extended operation. Gornplete no) later than six months prior to PEG.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23267 13 Enhance the Buried Piping and Tanks Inspection program specifications to:

B2.1.18 Prio-r to-the perfiod of extended operation Lower coated piping carefully into a trench to avoid external coating damage.

Start implementation Use proper storage and handling practices to prevent damage to pipe coating prior to

ýduring the 10 years installation. These practices include padded storage, use of proper slings for installation prior to the period of and ultraviolet light resistant topcoats.

extended operation.

Over excavate trenches and use qualified backfill for bedding piping. Take care during Complete no later backfilling to prevent rocks and debris from striking and damaging the pipe coating.

than SiX monthsprior Include the coating used for copper alloy buried piping in the coating database. The te-E-ýO Inspections NOC-AE-14003141 Page 10 of 31 Table A4-1 License Renewal Commitments Item#

Co"mitment LRA Implementation Section Schedule

...2 coating system must be in accordance with NACE SP0169-2007, and will be used for repair or for new coatings of the buried copper alloy piping in the essential cooling water system.

Coat the portion of the essential cooling water system copper alloy piping directly embedded in backfill or directly encased in concrete, extending the coating 2 feet or more above grade.

Enhance the Buried Piping and Tanks Inspection program procedures to:

Consider backfill located within 6 inches of the pipe, and consistent with ASTM D 448-08 size number 67, acceptable. Backfill quality is determined through examination during the inspections conducted by the program. Backfill that does not meet the ASTM criteria, during the initial and subsequent inspections of the program, is considered acceptable if the inspections of buried piping do not reveal evidence of mechanical damage to the pipe coatings due to the backfill.

Ensure the cathodic protection system survey is performed annually.

Monitor the output of the cathodic protection system rectifiers every 2 months. The measured current at each rectifier is recorded and compared against a target value.

Following the completion of the plant yard cathodic protection system annual survey, record the current of the rectifier used to achieve an acceptable pipe/soil potential.

That current will be the target current for the rectifier until the next annual survey. If the current measured at the rectifier during the bimonthly monitoring deviates significantly from the target value, a condition report should be created. The rectifier current should be adjusted to an acceptable value. The results of the survey will be documented and trended to identify degrading conditions. When degraded rectifier performance is identified, documentation is required in accordance with the corrective action program.

The system should not be operated outside of established acceptable limits for longer than 90 days.

Recommend increased monitoring of the cathodic protection system and/or additional inspections if adverse indications are discovered during the monitoring of the cathodic protection system.

to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23268 NOC-AE-14003141 Page 11 of 31 Table A4-1 License Renewal Commitments Item #

Commitment LRA Implementation

'Section Schedule

?....*i.:,"..:"

i;

":i;% '

Evaluate the effectiveness of isolating fittings, continuity bonds and casing isolation, during the plant yard cathodic protection system annual survey. This may be accomplished through electrical measurements.

Visually inspect buried piping and, if significant indications of degradation are observed, the visual inspections are supplemented by surface and/or volumetric non-destructive testing.

Define the inspection interval for the program directed inspections as every 10 years, beginning the 10 year interval prior to the period of extended operation.

Select the buried and underground piping inspection locations based on risk, considering susceptibility to degradation and consequences of failure.

External Corrosion Direct Assessment, as described in NACE Standard Practice SP0502-2010, will be considered for use in identifying inspection locations.

Credit opportunistic examinations of non-leaking pipes toward required examinations, only if they meet the risk ranking selection criteria.

Guided wave ultrasonic, or other advanced inspection techniques should be used, if practical, for the purpose of determining piping locations that should be inspected.

These inspections may not be used as substitutes for inspections required by the program.

Credit an inspection of piping shared between Units 1 and 2 toward the required inspections of only one unit.

Examine any piping, valves and closure bolting exposed during inspections.

Examine bolting for loss of material and loose or missing fasteners.

" Include two alternatives to directed inspections of the buried or underground piping that is safety-related, hazmat or both. The first alternative is to hydrostatically test 25 percent of the subject piping on an interval not to exceed 5 years. The second is an internal inspection of 25 percent of the subject piping by a method capable of accurately determining pipe wall thickness.

Flow testing of the fire mains, as described in NFPA 25, to detect degradation of the buried pipe in lieu of visual inspections of the fire protection system buried and NOC-AE-1 4003141 Page 12 of 31 Table A4-1 License Renewal Commitments Item" Commitment LRA Implementation Section Schedule

__._.._,_ _..__*__.___.____._.___...__.....__"._.__.,_ _. 1.

Schedule__

underground piping.

Define "hazmat pipe" as pipe that, during normal operation, contains fluids that, if released, would be detrimental to the environment.

Include examples of adverse indications discovered during piping inspections.

Repair or replacement of the affected component when adverse indications failing to meet the acceptance criteria described in the program are discovered.

Indicate that an analysis may be conducted to determine the potential extent of the degradation, when it is observed.

Double inspection sample sizes within the affected piping categories, when adverse indications are detected during inspection of safety related or hazmat buried pipe. If adverse indications are found in the expanded sample, the inspection sample size is again doubled. This doubling of the inspection sample size continues until no more adverse conditions are found. If adverse conditions are extensive, inspections may be halted in an area of concern that is planned for replacement, provided continued operation does not pose a significant hazard. Expansion of sample size may be limited to the piping subject to the observed degradation mechanism.

Define the scope of inspection for buried piping using the criteria in NUREG-1 801. The scope of inspection will be based on the condition of cathodic protection, backfill and coating of the piping. Ensure the scope of inspection increases when the cathodic protection system does not meet operability requirements, or when backfill is examined and does not meet the backfill acceptance criteria.

Examine at least 10 feet of piping during each inspection of buried piping. If the entire length piping is less than 10 feet, inspect the entire length of piping.

Indicate that the inspections may be limited to 10 percent of the piping under consideration, per inspection interval, regardless of the inspection scope prescribed in the NUREG-1801 guidance.

Perform one inspection of all buried stainless steel safety-related piping per inspection interval.

Examine at least 10 feet of piping during each inspection of underground piping. If the NOC-AE-14003141 Page 13 of 31 Table A4-1 License Renewal Commitments Item Commitment

.LRo Implementation

.Section.Schedule entire length of piping is less than 10 feet, inspect the entire length.

Inspect the underground stainless steel pipe in the auxiliary feedwater system once each inspection interval.

Observe for brittle failure at flanges, connections, and joints due to frost heaving, soil stresses, or ground water effects during inspection of buried piping.

Indicate that for coated piping, there should be no evidence of coating degradation. If coating degradation is present, it may be considered acceptable if it is determined to be insignificant by an individual possessing a NACE operator qualification, or otherwise meeting the qualifications to evaluate coatings as described in 49 CFR 192 and 195.

• Indicate that for any hydrostatic tests credited by the program, the condition "without leakage" may be met by demonstrating that the test pressure does not change significantly during the test.

14 Implement the One-Time Inspection of ASME Code Class 1 Small-Bore Piping program as B2.1.19 Start implementation described in LRA Section B2.1.19.

d!Quring the 6 years prior to the period of extended operation.

Complete no) Iater than Gix month pIo to-P-EG. Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs NOC-AE-14003141 Page 14 of 31 Table A4-1 License Renewal Commitments Item #

Commitmr LRA i1mpilenientation Section

' Schedule later.

CR 10-23270 15 Implement the External Surfaces Monitoring Program as described in LRA Section B2.1.20.

B2.1.20 Complete no later than six months Q2Prior to the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refuelingq outage prior to the PEO, whichever occurs later.

CR 10-23272 16 Enhance the Flux Thimble Tube Inspection program to generate a new procedure that includes B2.1.21 Complete no later provisions to:

than six months Perform a wall thickness eddy current inspection of all flux thimble tubes that form part QPrior to the period of of the reactor coolant system pressure boundary. The inspections are scheduled for extended operation.

each outage, and may be deferred by using an evaluation that considers the actual Inspections to be wear rate.

complete no later Evaluate flux thimble tube wear by design engineering personnel and perform than six months prior corrective actions based on evaluation results after each inspection, to the PEO or the end Trend wall thickness measurements and calculate wear rates by design engineering of the last refueling personnel after each inspection.

outa-ge prior to the Take corrective actions to reposition, cap or replace the tube, if the predicted wear (as PEO, whichever a measure of percent through wall) for a given flux thimble tube is projected to exceed occurs later.

the established acceptance criterion prior to the next outage.

Include a description of the testing and analysis methodology and percent through CR 10-23273 NOC-AE-14003141 Page 15 of 31 Table A4-1 License Renewal Commitments Item #

Commitment LRA Implermentation Secti*n Schedule acceptance criteria of a maximum of 80 percent through wall loss.

Remove flux thimbles from service to ensure the integrity of the reactor coolant system pressure boundary for flux thimble tubes that cannot be inspected over the tube length, that are subject to wear due to restriction or other defect, and that can not be shown by analysis to be satisfactory for continued service.

17 Implement the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting B2.1.22 Start implementation Components program as described in LRA Section B2.1.22.

d During the five year period prior to the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23274 18 Enhance the Lubricating Oil Analysis program procedures to:

B2.1.23 Complete no later require analysis for particle count of the lubricating oil for the centrifugal charging pump, than six months and

_QPrior to the period of require that sample analysis data results, for which no acceptance criteria is specified, extended operation be evaluated and trended against baseline data and data from previous samples to Inspections to be determine the acceptability of oil for continued use.

complete no later than six months prior to the PEO or the end of the last refueling outage prior to the NOC-AE-14003141 Page 16 of 31 Table A4-1 License Renewal Commitments Item.#

Commi t

LRA Implementation tSection Schedule PEO. whichever occurs later.

CR 10-23276 19 Implement the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental B2.1.24 Complete no later Qualification Requirements program as described in LRA Section B2.1.24.

than six months Qprior to the period of extended operation.

Inspections to be complete no la2ter than six months prior to the PEO or the end of the last refueling outage prior to the PEO. whichever occurs later.

CR 10-23279 20 Enhance the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental B2.1.25 Complete no later Qualification Requirements program procedures to:

than six months identify the cables, manholes, and trenches that are within the scope of the QPrior to the period of program,

extended operation.

require all in-scope non-EQ inaccessible medium and low voltage power Inspections to be cables (>400 volts) exposed to significant moisture be tested at least once complete no later every six years with the first test being completed prior to period of extended than six months prior operation, to the PEG or the end require that the acceptance criteria be defined prior to each test for the specific of the last refueling type of test performed and the specific cable tested, outage prior to the S

require an engineering evaluation that considers the age and operating PEO, whichever environment of the cable be performed when the test acceptance criteria are occurs later.

not met. The engineering evaluation shall consider the significance of the test or inspection results, the operability of the component, the reportability of the ICRt1 0-23275-1 NOC-AE-14003141 Page 17 of 31 Table A4-1 License Renewal Commitments Item #

Commitment LRA Implementation 7

Section, Schedule 4 4 event, the extent of the concern, the potential root causes for not meeting the test or inspection acceptance criteria, the corrective actions required, and the likelihood of recurrence.

inspect in-scope manholes and trenches based on plant specific operating experience with water accumulation, require inspections being conducted at least annually, event-driven inspections of in-scope manholes will be performed as an on-demand activity based on actual plant experience, perform direct observation that cables are not wetted or submerged, remove collected water and verification of sump pump operability, initiate a corrective action if wetted cables or inoperable sump pumps are

found, inspect cables/splices and cable support structures if wetted cables are found, take corrective actions to keep cables dry, manhole inspection results are evaluated based on actual plant experience with the inspection frequency increased based on experience with water accumulation.

testing of in-scope inaccessible medium and low voltage (>400 volts) power cables exposed to significant moisture using a test capable of detecting reduced insulation resistance, trend inspection and test results to provide additional information on the rate of cable insulation degradation, test frequency may be adjusted based on test results or operating experience, require that the acceptance criterion for manhole and trench be, cables/splices and support structures is that they are not submerged or immersed in water, and require an extent of condition when an unacceptable condition or situation is identified.

21 Enhance the Metal Enclosed Bus program procedures to:

[ B2.1.26 I Complete no later NOC-AE-14003141 Page 18 of 31 Table A4-1 License Renewal Commitments

• Item #

Commitment I

"f '

"at "ion Section Schedule em..aio

• i*.

i**

Identify the metal enclosed buses that are within the scope of the program.

Inspect internal portions of all MEBs for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water intrusion every 10 years.

Inspect non-segregated phase bus insulation and isolated phase bus insulators for signs of embrittlement, cracking, melting, swelling, or discoloration every 10 years.

Inspect internal bus supports for structural integrity and signs of cracks every 10 years.

Inspect bus enclosure assemblies for loss of material due to corrosion and hardening of boots and gaskets every 10 years.

Inspect 20 percent of the population of non-segregated phase bus accessible bolted connections insulation material (with a maximum sample size of 25) for surface anomalies every five years.

Perform the first inspection of all portions of in-scope MEBs prior to the period of extended operation.

Identify acceptance criteria for non-segregated phase bus insulation and isolated phase bus insulators as no unacceptable visual indications of surface anomalies.

Identify acceptance criteria for non-segregated phase bus sections and internal portions of isolated phase bus as no unacceptable indications of corrosion, cracks, foreign debris, excessive dust buildup, loss of material, hardening, or evidence of water intrusion.

Identify acceptance criteria for the exterior of MEBs as no unacceptable indications of general corrosion.

Identify acceptance criteria for boots and gaskets as no unacceptable indications of cracking, checkering, or discoloration.

Identify acceptance criteria for accessible bolted connection insulation material as no unacceptable evidence of embrittlement, cracking, melting, discoloration, swelling, or surface contamination.

than six months Ql:Prior to the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR-1 0-23280-1 NOC-AE-14003141 Page 19 of 31 Table A4-1 License Renewal Commitments Item.n #

Commitment K

LRA Implementation Section

.S:chedule Require an engineering evaluation when acceptance criteria are not met, to include a determination of corrective actions Require an engineering evaluation to determine whether the unacceptable conditions may be applicable to other accessible or inaccessible MEBs.

22 Enhance the ASME Section X1, Subsection IWL program procedures to:

B2.1.28 Pri*or t the period oe incorporate the 2004 Edition of ASME Section XI, Subsection IWL (no addenda),

extended.peration.

supplemented with the applicable requirements of 10 CFR 50.55a(b)(2).

Completed CR 10-23597 23 Enhance the ASME Section X1, Subsection IWF program procedures to:

B2.1.29 Complete no later incorporate the 2004 Edition of ASME Section X1, Subsection IWF (with no addenda).

than six months specify the preventive actions for storage, protection and lubricants recommended in Q2Prior to the period of Section 2 of Research Council for Structural Connections publication "Specification for extended operation.

Structural Joints Using ASTM A325 or A490 Bolts" for ASTM A325, ASTM F-1 852 and Inspections to be

/or ASTM 490 bolts, and complete no later specify that visual examinations are augmented with volumetric examinations, in than six months prior accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-to the PEO or the end G-1, to detect stress corrosion cracking for 20 percent (25 bolts maximum per unit) of of the last refueling high strength bolts greater than 1-inch nominal diameter and with an actual yield outage prior to the strength greater than or equal to 150 ksi.

PEO, whichever occurs later.

CR 10-23598-1 24 Enhance the 10 CFR Part 50 Appendix J program procedures to:

B2.1.30 Prior to the period o, specify a surveillance frequency of 10 years following a successful Type A test.

extended operation Completed CR 10-23599 25 Enhance the Structures Monitoring Program procedures to:

B2.1.32 Complete no later include the switchyard control building into the scope of the Structures than six months NOC-AE-14003141 Page 20 of 31 Table A4-1 License Renewal Commitments Item #~

Commitment LR

]mplementationi Section _Schedule_

Monitoring Program, specify inspections of seismic gaps, caulking and sealants, duct banks and manholes, valve pits and access vaults, doors, electrical conduits, raceways, cable trays, electrical cabinets/enclosures and associated anchorage, monitor at least two groundwater samples every five years for pH, sulfates, and chloride concentrations, specify that the inspection frequency for structures within the scope of license renewal will be in accordance with ACI 349.3R, Table 6.1, which specifies:

o For below-grade structures and structures in controlled interior environment (except inside primary containment), all accessible areas of both units will be inspected every 10 years.

o For all other structures (including inside primary containment), all accessible areas of both units will be inspected every 5 years.,

specify inspector qualifications in accordance with ACI 349.3R-96, require the performance of a periodic visual inspection of the accessible sections of the spent fuel pool and transfer canal tell-tale drain lines for blockage every five years. The first inspection will be performed within the 5 years before entering the period of extended operation, specify ACI 349.3R-96 and ACI 201.1 R-68 as the basis for defining quantitative acceptance criteria, and specify the preventive actions for storage, protection and lubricants recommended in Section 2 of Research Council for Structural Connections publication "Specification for Structural Joints Using ASTM A325 or A490 Bolts" for ASTM A325, ASTM F1 852 and/or ASTM 490 bolts.

Procedures will be enhanced to perform opportunistic inspections of exposed Dortions of the below-arade concrete when excavated for any reason,

_Prior to the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23600-1 NOC-AE-14003141 Page 21 of 31 Table A4-1 License Renewal Commitments Item #

Commitment LRA Implementation Section Schedule Procedures will be enhanced to require an evaluation should ground water be determined to be aggressive or inspections of accessible concrete structural elements identify degradation. The evaluation will be performed to determine the appropriate actions necessary to assure that the affected structures will continue to perform their intended function. These actions may include increased visual inspections or other examination techniques.

1. specify that visual examinations will be augmented with volumetric examinations, in accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, to detect SCC for 20 percent (25 bolts maximum) of high strength bolts greater than 1-inch nominal diameter and with an actual yield strength greater than or equal to 150 ksi.

26 Enhance the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power B2.1.33 Complete no later Plants program procedures to:

than six months specify inspections at intervals not to exceed five years or to immediately follow LPrior to the period of significant natural phenomena except sediment monitoring, which is performed every extended operation.

ten years..

Inspections to be specify the preventive actions for storage, protection and lubricants recommended in complete no later Section 2 of Research Council for Structural Connections publication "Specification for than six months prior Structural Joints Using ASTM A325 or A490 Bolts" for ASTM A325, ASTM F-1 852 and to the PEO or the end

/or ASTM 490 bolts.

of the last refuelingq specify ACI 349.3R-96 and ACI 201.1 R-68 as the basis for defining quantitative outagqe prior to the acceptance criteria.

PEO, whichever occurs later.

CR 10-23601 -1 27 Implement the PWR Reactor Internals program as described in LRA Section B2.1.35.

B2.1.35 Completed CR 10-23602 28 Implement the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental B2.1.36 Complete no later Qualification Requirements program as described in LRA Section B2.1.36.

than six months

_:_P--rior to the period of NOC-AE-14003141 Page 22 of 31 Table A4-1 License Renewal Commitments Item#

Commitment LRA Implementation

_Section__

Schedule extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refuelinq outagqe prior to the PEO, whichever occurs later.

CR 10-23603

4.

.4-29 As additional industry and plant-specific applicable operating experience becomes available, it will be evaluated and incorporated into each aging management program or in the development of a new aging management program(s), as necessary, to provide assurance that the effects of aging will be managed during the period of extended operation.

B2.1.16 B2.1.17 B2.1.19 B2.1.20 B2.1.22 B2.1.24 B2.1.35 B2.1.36 B1.4 Start implementation wWithin ten years prior to entering the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refuelingq outagqe prior to the PEO, whichever occurs later.

CR 10-23604 30 Enhance the Metal Fatigue of Reactor Coolant Pressure Boundary program procedures to:

B3.1 Complete no later include additional locations necessary to ensure accurate calculations of fatigue, than six months include additional transients that contribute significantly to fatigue usage, pPrior to the period of include counting of the transients used in the fatigue crack growth analyses, which extended operation.

support the leak-before-break analyses and ASME Section XI evaluations to ensure Inspections to be NOC-AE-14003141 Page 23 of 31 Table A4-1 License Renewal Commitments Item. #

cmmitment LRA Implementation i

ISection Schedule the analyses remain valid, complete no later include additional transients necessary to ensure accurate calculations of fatigue, than six months prior fatigue usage monitoring at specified locations, and specify the frequency and process to the PEO or the end of periodic reviews of the results of the monitored cycle count and CUF data at least of the last refuelinq once per fuel cycle, outage prior to the include additional cycle count and fatigue usage action limits, which will invoke PEO, whichever appropriate corrective actions if a component approaches a cycle count action limit or a occurs later.

fatigue usage action limit. The acceptance criteria associated with the NUREG/CR-6260 sample locations for a newer vintage Westinghouse plant will CR 10-23605 account for environmental effects on fatigue, and include appropriate corrective actions to be invoked if a component approaches a cycle count action limit or a fatigue usage action limit. Acceptable corrective actions include fatigue reanalysis, repair, or replacement. Re-analysis of a fatigue crack growth analysis must be consistent with or reconciled to the originally submitted analysis and receive the same level of regulatory review as the original analysis.

31 STPNOC will:

3.1 Concurrent with A.

For Reactor Coolant System Nickel-Alloy Pressure Boundary Components:

industry initiatives (1) Implement applicable NRC Orders, Bulletins and Generic Letters associated with nickel-and upon completion alloys; (2) implement staff-accepted industry guidelines, (3) participate in the industry submit an inspection initiatives, such as owners group programs and the EPRI Materials Reliability Program, for plan and not less managing aging effects associated with nickel-alloys, and (4) upon completion of these than 24 months programs, but not less than 24 months before entering the period of extended operation, before entering the STPNOC will submit an inspection plan for reactor coolant system nickel-alloy pressure period of extended boundary components to the NRC for review and approval, and operation.

B.

For Reactor Vessel Internals:

(1) Participate in the industry programs for investigating and managing aging effects on reactor CR 10-23606 internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, STPNOC will submit an inspection plan for I reactor internals to the NRC for review and approval.

I I

NOC-AE-14003141 Page 24 of 31 Table A4-1 License Renewal Commitments Item #

Com.mitment:

.LRA Implementation%

Section

Schedule, 0'

"0

,* =**:i::*

32 The seven diesel generator cooling water expansion joints that are projected to exceed the 4.3.6 Complete no later analyzed number of cycles during the period of extended operation will be replaced. The than six months analyses for the replacement expansion joints will include the period of extended operation.

2Prior to the period of extended operation.

Replacement to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23607 33 Periodic inspection of a sample of transmission conductor connections for loose connections 3.6.2.2.3 Complete no later using thermography is currently performed as part of the preventive maintenance activities, than six months The periodic thermography will continue into the period of extended operation.

pPrior to the period of extended operation.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 10-23608 34 Prior to the period of extended operation, STP will perform a review of design basis ASME B3.1 Complete no later Class 1 component fatigue evaluations to determine whether the NUREG/CR-6260-based than six months NOC-AE-14003141 Page 25 of 31 Table A4-1 License Renewal Commitments te"m #

'Commitment":.

LRA t

".molementatiopn Section Schedule components that have been evaluated for the effects of the reactor coolant environment on QPrior to the period of fatigue usage are the limiting components for the STP configuration. If more limiting extended operation.

components are identified, the most limiting component will be evaluated for the effects of the reactor coolant environment on fatigue usage. If the limiting location consists of nickel alloy, the CR 11-17184 methodology for nickel alloy in NUREG/CR-6909 will be used to perform the environmentally-assisted fatigue calculation. The additional evaluation will be performed through the Metal Fatigue of Reactor Coolant Pressure Boundary Program in accordance with 10 CFR 54.21 (c)(1)(iii).

35 Enhance the ASME Section XI, Subsection IWE program procedures to:

B2.1.27 Complete no later specify the preventive actions for storage, protection and lubricants recommended in than six months Section 2 of Research Council for Structural Connections publication "Specification for

_Prior to the period of Structural Joints Using ASTM A325 or A490 Bolts" for ASTM A325, ASTM F-1 852 and extended operation.

/or ASTM 490 bolts, CR 11-19936-1 36 Enhance the Masonry Wall Program procedures to:

B2.1.31 Complete no later Procedures will be enhanced to specify that the inspection frequency for structures than six months within the scope of license renewal will be in accordance with ACI 349.3R, Table 6.1, pPrior to the period of which specifies:

extended operation.

For below-grade structures and structures in controlled interior environment (except Inspections to be inside primary containment), all accessible areas of both units will be inspected every 10 complete no later years.

than six months prior For all other structures (including inside primary containment), all accessible areas of to the PEO or the end both units will be inspected every 5 years.

of the last refuelinq outa~qe prior to the PEO, whichever occurs later.

CR 11-19937-1 NOC-AE-14003141 Page 26 of 31 Table A4-1 License Renewal Commitments Item

.C.

Commitment, LRA Implementation Section' Schedule 37 Groundwater samples will be taken at multiple locations around the site every three months for B2.1.32 Completed at least 24 consecutive months. The samples will analyze for pH, sulfates, and chlorides. This sampling plan will begin no later than September 2012.

CR 11-20856-1 38 Enhance the Reactor Head Closure Studs program procedures to:

B2.1.3 Complete no later preclude the future use of replacement closure stud assemblies fabricated from than six months material with an actual measure yield strength greater than or equal to 150 ksi. The 1P-rior to the period of use of currently installed components and any spare components which are currently extended operation.

on site is allowed.

Inspections to be complete no later than six months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

CR 11-22923-1 39 Enhance the Selective Leaching of Aluminum Bronze procedures to:

B2.1.37 Compete no later examine aluminum bronze materials exposed during inspection of the buried essential than six months cooling water piping for evidence of selective leaching, prior to the period of perform periodic metallurgical testing of aluminum bronze material components to extended operation.

update the structural integrity analyses, confirm load carrying capacity, and determine Inspections to be degree of dealloying as follows:

complete no later

• Above ground ECW System components removed from service will be tested than six months prior as follows:

to the PEO or the end

• For each 10 year interval beginning 10 years prior to the period of extended of the last refuelingq operation, 20 percent of leaking components removed from service, but at least outage prior to the one, will be tested every five years.

PEO, whichever o Tensile test samples from a removed component will be tested to include both occurs later.

leaking and non-leaking portions of the component.

NOC-AE-14003141 Page 27 of 31 Table A4-1 License Renewal Commitments Item #

Commitment

".LRA Implementation.

4<

.Section' Schedule~

• If at least two leaking components are not identified two years prior to the end CR 11-28986 of each 10-year testing interval, a risk-ranked approach based on those components most susceptible to degradation will be used to identify candidate components for removal and testing so at least two components are tested during the 10-year interval.

o The samples will be tested for chemical composition including aluminum content, mechanical properties (such as yield and ultimate tensile strengths) and microstructure.

" Trend ultimate tensile strength and compare to the acceptance criterion.

" Determine degree of dealloying and presence of cracks by destructive examination. Trend the degree of dealloying and cracking by comparing examination results with previous examination results.

o Perform an engineering evaluation at the end of each test to determine if the sample size requires adjustment based on the results of the tests.

o The acceptance criterion for ultimate tensile strength value of aluminum bronze material is greater than or equal to 30 ksi. The acceptance criterion for yield strength is equal to or greater than one-half of the ultimate strength.

" Initiate a corrective action document when the acceptance criterion is not met.

" and if a leak from below-grade welds is discovered by surface water monitoring or during a buried ECW piping inspection, a section of each leaking weld will be removed for destructive metallurgical examination.

40 Enhance the Protective Coating Monitoring and Maintenance Program procedures to specify:

B2.1.39 Complete no later Parameters monitored or inspected include any visible defects, such as blistering, than six months cracking, flaking, peeling, rusting, and physical damage, as specified in ASTM D 5163-

Prior to the period of

08.

extended operation.

Inspection frequencies, personnel qualifications, inspection plans, inspection methods, Inspections to be and inspection equipment that meet the requirements of ASTM D 5163-08.

complete no later A pre-inspection review is performed of the previous two monitoring reports and, based than six months prior on inspection report results, prioritize repair areas as either needing repair during the to the PEO or the end NOC-AE-14003141 Page 28 of 31 Table A4-1 License Renewal Commitments Item Commitment L

Implementati:..

same outage, needing repair during the next available outage, or re-evalua ted in next of the last refuelinq available outage.

outage prior to the A standardized coating condition assessment report form that will include the PEO. whichever identification of coatings found intact with no defects identified, and the identification of occurs later.

coatings that were not inspected and the reason why the inspection cannot be conducted.

CR 12-8955 A standardized coating condition assessment report that will include written and/or photographic documentation of coating inspection areas, failures, and defects.

Destructive/non-destructive tests are performed by individuals trained in the applicable referenced standards of Guide D5498 on an as-needed basis as determined by the Nuclear Coatings Specialist.

41 Enhance the STP Operating Experience Program and Corrective Action Program for managing Al No later than the date the effects of aging to:

the renewed Add License Renewal Interim Staff Guidance and revisions to NUREG-1 801, "Generic operating licenses Aging Lessons Learned (GALL) Report', to the Operating Experience Program (QEP) are issued procedure as sources of information within the scope of this program, Revise the QEP procedure to include "aging effects" to the list of characteristics for CR 12-8990 determining applicability of an OF document that may require further evaluation. A screened-in evaluation should consider (a) systems, structures, or components, (b) materials, (c) environments, (d) aging effects, (e) aging mechanisms, and (f) aging management programs,

• Review the Corrective Action Program Event Codes to determine if additional codes are needed to ensure age-related degradation effects are identified, SPerform a training "needs analysis" for those plant personnel, including aging management program owners, who screen, assign, evaluate, implement, and submit plant-specific and industry operating experience information for age-related effects.

Include in the analysis:

" A requirement that individuals complete training before performing tasks, and o A determination of the periodicity of the training.

Revise the OEP procedure to provide criteria for reporting plant-specifichoperating forCR 12-8990 NOC-AE-14003141 Page 29 of 31 Table A4-1 License Renewal Commitments Iltem #

Commitment LRA Implementation.

::*::::Section Schedule

• ________experience of age-related degradation.

42 Enhance the Reactor Head Closure Studs program procedures to:

B2.1.3 Starting with the 0perform a remote VT-i1 of stud insert #30 (Unit 2 only) concurrent with the volumetric current (Third examination once every 10 years to verify no additional loss of bearing surface area.

Interval) 10-year ASME Section XI inspection interval CR 12-1 51 70 43 0

The seal cap enclosures from Unit 2 Safety Injection System Check Valve S10010A B2.1.7 Unit 1 completed and from Unit 1 and Unit 2 Chemical Volume Control System Check Valves CVOOO1, CV0002, CV0004, and CV0005 will be permanently removed. After removal of the seal Q-1.-2-Ref ue 14R g cap enclosures, the component bolting will be replaced or inspected for intergranular Otage (t4Rit--24 stress corrosion cracking.

Unit 2 completed I

CR 12-21155 44 Structural integrity analyses will be updated and testing will be conducted to confirm that B2.1.37 February 28, 2014 methodologies and assumptions based on past information remain valid.

July 31, 2014 Six samples from three aluminum bronze components recently removed from (revised per service will be tested.

NOC-AE-1 4003090)

• The samples will be tested for chemical composition including aluminum content, mechanical properties (such as fracture toughness, yield and ultimate tensile CR 12-221 50 strengths) and microstructure.

The acceptance criterion for ultimate tensile strength value of aluminum bronze material is greater than or equal to 30 ksi. The acceptance criterion for fracture toughness is 65 ksi in11 for aluminum bronze castings and at welded joints in the heat affected zones. The acceptance criterion for yield strength is equal to or greater than one-half of the ultimate strength.

• Trend ultimate tensile strength and compare to the acceptance criterion.

Determine degree of dealloying and presence of cracks by destructive NOC-AE-14003141 Page 30 of 31 Table A4-1 License Renewal Commitments Item #

Commitment L..

LRA Implementation; n rsection Schedule.

examination. Trend the degree of dealloying and cracking by comparing examination results with previous examination results.

The structural integrity analyses will be updated, as required.

The results of the testing and any required changes to the structural integrity analyses will be completed and sent to the NRC staff for review.

45 Enhance the Selective Leaching of Aluminum Bronze procedures to:

B2.1.37 Fbrua.y 28, 2014 Volumetrically examine aluminum bronze material components in the ECW system that demonstrate external leakage where the configuration supports this type July 31, 2014 of examination, (revised per Destructively examine each aluminum bronze material component in the ECW NOC-AE-1 4003090) system that demonstrates external leakage for the presence or absence of internal cracks and for the degree of dealloying. Profiling will continue until 10 percent of CR 12-26987 susceptible components are examined to validate the input parameters to the structural integrity analyses.

o Trend the degree of dealloying and cracking by comparing examination results with previous examination results.

Metallurgically test aluminum bronze material components in the ECW system that demonstrate external leakage until the following population of components is tested:

o At least three different size components of two samples each are tested, and o

At least nine total samples are tested.

o Perform fracture toughness testing of test samples that include a crack in the dealloyed material where sufficient sample size supports bend testing.

o Trend ultimate tensile strength and compare to the acceptance criterion.

o Test samples for chemical composition including aluminum content, mechanical properties (such as yield and ultimate tensile strengths) and microstructure.

o Determine the degree of dealloying by destructive examination.

o Trend the degree of dealloying and cracking by comparing examination results with previous examination results.

NOC-AE-14003141 Page 31 of 31 Table A4-1 License Renewal Commitments

..Item Co ment*

• LRA Implementation..

Item#

Cor...im...

Section Schedule The acceptance criterion for ultimate tensile strength value of aluminum bronze material is greater than or equal to 30 ksi. The acceptance criterion for fracture toughness is 65 ksi in 12 for aluminum bronze castings and at welded joints in the heat affected zones. The acceptance criterion for yield strength is equal to or greater than one-half of the ultimate strength.

Perform an engineering evaluation at the end of each test to determine if the sample size requires adjustment based on the results of the tests.

Update the structural integrity analyses as required to validate adequate load carrying capacity.

46 Leak rates that could occur upstream of any individual component supplied by the ECW N/A

,MArch 31, 2013 system will be determined to validate the maximum size flaw for which piping can still perform its intended function.

July 31, 2014

• A summary of the results of these leak rates will be provided to the NRC for review.

(revised per NOC-AE-1 4003090)

CR 12-27257 47 Unit 1 RWST only: Perform a one time internal tank bottom and side weld inspection to confirm B2.1.20 Five years prior to the the effectiveness of the corrective actions to repair the leaking tank floor 5 years prior to Period of Extended entering the period of extended operation. The inspection will include VTW; PT; and Vacuum Operation Box (VB) Leak Test of susceptible locations of the floor bottom and side welds to ensure no leaks.

CR 14-1154