SBK-L-17087, Supplement 53 - Response to Request for Additional Information for the Review of the Seabrook Station License Renewal Application - LR-ISG-2016-01 - Changes to Aging Management Guidance for Various Steam Generator Components

Supplement 53 - Response to Request for Additional Information for the Review of the Seabrook Station License Renewal Application - LR-ISG-2016-01 - Changes to Aging Management Guidance for Various Steam Generator Components

ML17150A066
Person / Time
Site:	Seabrook
Issue date:	05/25/2017
From:	Mccartney E NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CAC ME4028, LR-ISG-2016-01, SBK-L-17087
Download: ML17150A066 (35)

Text

NEXTera ENERGY ~

SEABROOK May 25, 2017 10 CFR 54 SBK-L-17087 Docket No. 50-443 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Seabrook Station Supplement 53 - Response to Request for Additional Information for the Review of the Seabrook Station License Renewal Application - LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components

References:

1. NextEra Energy Seabrook LLC, letter SBK-L-10077, "Seabrook Station *Application for Renewed Operating License," May 25 , 2010 (Accession Number ML101590099).

2. License Renewal Interim Staff Guidance, LR-ISG-2016-01 "Changes to Aging Management Guidance for Various Steam Generator Components," November 30, 2016 (Accession Number ML16237A383)

3. NRC, "Request for Additional Information for the Review of the Seabrook Station License Renewal Application (CAC NO. ME4028), RAI B.2.1.10 LR-ISG-2016-01, Changes to Aging Management Guidance for Various Steam Generator Components," March 16, 2017 (Accession Number ML17066A488).

4. NextEra Energy Seabrook LLC, letter SBK-L-17082, "Response to Request for Additional Information for the Review of the Seabrook Station License Renewal Application - LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components," May 23, 2017.

In Reference 1, NextEra Energy Seabrook, LLC (NextEra Energy Seabrook) submitted

U.S. Nuclear Regulatory Commission SBK-L-17087 I Page 2 an application for a renewed facility operating license for Seabrook Station Unit 1 in accordance with the Code of Federal Regulations, Title 10, Parts 50, 51, and 54.

In Reference 2, the NRG issued License Renewal Interim Staff Guidance, LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components.

In Reference 3, the NRG requested additional information related to the issuance of LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components (Reference 2).

In Reference 4, NextEra Energy Seabrook, LLC (NextEra Energy Seabrook) proposed to extend the response date for the request for additional information (Reference 3) as related to LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components (Reference 2). provides NextEra Energy Seabrook's response to the NRC's Request for Additional Information (RAI B.2.1.10-3) concerning the issuance of LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components. provides NextEra Energy Seabrook's revised License Renewal Application, Appendix A - Updated Final Safety Analysis Report Supplement, A.2.1.10 Steam Generator Tube Integrity. provides NextEra Energy Seabrook's revised License Renewal Application, Appendix B -Aging Management Programs, B.2.1.10 Steam Generator Tube Integrity. provides the revised LRA Appendix A - Updated Final Safety Analysis Report Supplement Tab.le A.3, License Renewal Commitment List.

The enclosures include changes to the LRA. To facilitate understanding, the changes are explained, and where appropriate, portions of the LRA are repeated with the change highlighted by strikethroughs for deleted text and balded italics for inserted text.

There has been one commitment change; Commitment #55 has been removed. The basis for the commitment removal is provided in Enclosures 2 and 3 of this letter.

If there are any questions or additional information is needed, please contact Mr.

Edward J. Carley, Engineering Supervisor - License Renewal, at (603) 773-7957.

If you have any questions regarding this correspondence, please contact Mr. Kenneth Browne, Licensing Manager, at (603) 773-7932.

U.S . Nuclear Regulatory Commission SBK-L-17087 I Page 3 I declare under penalty of perjury that the foregoing is true and correct.

Executed on May 25, 2017 .

Sincerely, NextEra Energy Seabrook, LLC

°{;McCa~f Regional Vice President - Northern Region Enclosure 1: Supplement 53 - NextEra Energy Seabrook's response to RAI B.2.1.10-3.

Enclosure 2: Supplement 53 - NextEra Energy Seabrook's revised License Renewal Application , Appendix A - Updated Final Safety Analysis Report Supplement, A.2.1.10 Steam Generator Tube Integrity.

Enclosure 3: Supplement 53 - NextEra Energy Seabrook's revised License Renewal Application, Appendix B - Aging Management Programs, B.2.1 .10 Steam Generator Tube Integrity.

Enclosure 4: Supplement 53 - NextEra Energy Seabrook's revised LRA Appendix A -

Updated Final Safety Analysis Report Supplement Table A.3, License Renewal Commitment List

U.S. Nuclear Regulatory Commission SBK-L-17087 I Page 4 cc: D. H. Dorman NRG Region I Administrator J.C. Poole NRG Project Manager P. C. Cataldo NRG Senior Resident Inspector T. M. Tran NRG Project Manager, License Renewal L. M. James NRG Project Manager, License Renewal Mr. Perry Plummer Director Homeland Security and Emergency Management New Hampshire Department of Safety Division of Homeland Security and Emergency Management Bureau of Emergency Management 33 Hazen Drive Concord, NH 03305 perry.plummer@dos.nh.gov Mr. John Giarrusso, Jr., Nuclear Preparedness Manager The Commonwealth of Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399 John.Giarrusso@massmail.state.ma.us

Enclosure 1 to SBK-L-17087 Supplement 53 - NextEra Energy Seabrook's response to RAI B.2.1.10-3.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure II Page 2 RAI 8.2.1.10-3

Background:

The staff issued License Renewal Interim Staff Guidance (LR-ISG) 2016-01, "Changes to Aging Management Guidance for Various Steam Generator Components" (ADAMS Accession No. ML16237A383). LR-ISG-2016-01 provides the following guidance for aging management:

• Visual inspections: steam generator head internal areas (head interior surfaces, divider plate assemblies, tubesheets (primary side) and tube-to-tubesheet welds) in order to identify signs of cracking or loss of material (e.g., rust stains and distortion of divider plates). GALL Report AMP Xl.M19, "Steam Generators,"

which includes these visual inspections, is used to manage loss of material due to boric acid corrosion for channel heads and tubesheets and cracking due to primary water stress corrosion cracking (PWSCC) for divider plate assembles and tube-to-tubesheet welds.

• Frequency of the visual inspections: at least every 72 effective full power months or every third refueling outage whichever results in more frequent inspections

• Implementation of the latest EPRI steam generator guidelines, including: (a)

EPRI Report 1022832 (primary-to-secondary leak guidelines); (b) EPRI Report 1025132 (in-situ pressure test guidelines); (c) EPRI Report 3002007571 (integrity assessment guidelines); and (d) EPRI Report 3002007572 (examination guidelines)

Issue:

The staff needs to confirm whether the applicant's Steam Generator Tube Integrity Program is consistent with the guidance discussed above.

NRC Request #1 Clarify whether the Steam Generator Tube Integrity Program is consistent with the guidance discussed above (i.e., conduct of visual inspections to manage loss of material and cracking due to PWSCC; visual inspection frequency; and implementation or plans for implementation of the latest EPRI steam generator guidelines by the implementation dates provided by the industry). If not, provide justification of why the applicant's Steam Generator Tube Integrity Program is adequate for aging management. As part of the response, clarify whether the aging management associated with LRA item 3.1.1-81 for divider plates uses the Steam Generator Tube Integrity Program.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 1/ Page 3 NextEra Energy Seabrook's Response to RAI 8.2.1.10-3, Request #1 Seabrook's Steam Generator Tube Integrity program is consistent with the guidance presented within LR-ISG-2016-01 concerning visual inspections, inspection frequency, and there are plans to implement the latest available and approved EPRI guidelines by the implementation dates provided by the industry. Appendix A and Appendix B have been revised to reflect these changes as shown in Enclosures #2 and #3.

Aging management associated with License Renewal Application (LRA) Table 3.1.2-4, Steam Generator Summary of Aging Management Evaluation, Table 3.X.1 Item 3.1 .1-81 (LRA page 3.1-96), and Table 3.1.1 (LRA Table 3.1.1- Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System, page 3.1-39) will utilize the Water Chemistry program and the Steam Generator Tube Integrity aging management programs. Table 3.1.2-4 and Table 3.1.1 changes are provided below.

Table 3.1 .2-4 NU REG Aging Effect Aging Component Intended 1801 Table 3.X.1 Material Environment Requiring Management Note Type Function Vol . 2 Item Management Program Item Water Chemistry Steam Program and Reactor Generator Pressure Nickel Steam IV.Dl-6 Coolant Cracking/PWSCC 3.1.1-81 A Divider Boundary Alloy Generator (RP-21)

(External)

Plate Tube Integrity Proa ram Table 3.1.1 Aging Item Aging Effect/ Further Evaluation Component Management Discussion Number Mechanism Recommended Programs Consistent with NUREG-1801, as modified by LR-ISG-2016-01. The Water Chemistry Program, Nickel alloy B.2.1 .2, as well as the or nickel-Steam Generator Tube alloy clad Cracking due Water Chemistry Integrity Program, steam to primary and Steam B.2.1.10, will be used to 3.1.1-81 generator water stress No Generator Tue manage cracking due to divider plate corrosion Integrity Program primary water stress exposed to cracking corrosion cracking in reactor nickel-alloy Steam coolant Generator primary channe l head divider plate exposed to reactor coola nt in the Steam Generator.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 1/ Page 4 NRC Request #2 Given the divider plate assembles are made with Alloy 600 type material susceptible to primary water stress corrosion cracking, provide information to confirm that the industry analyses in EPRI Report 3002002850 assessing the significance of divider plate cracking are applicable and bounding for the conditions at the applicant's unit. If not, identify a plant-specific program that will be used to manage cracking for the divide plate assemblies.

NextEra Energy's Seabrook Response to RAI B.2.1.10-3, Request #2 Industry analyses within EPRI Technical Reports 3002002850, 1014982, and 1020988 are applicable and bounding for NextEra Energy Seabrook Station steam generator divider plate assemblies.

Prior to issuance of LR-ISG-2016-01, Seabrook Station committed to performing an inspection of each steam generator to assess the condition of the divider plate assembly within 5 years prior to the period of extended operation (Commitment #55).

With the issuance of LR-ISG-2016-01 and subsequent evaluation showing that the Seabrook Station steam generator divider plate assemblies are bounded by the industry analyses, Seabrook Station will follow the inspection guidance provided within LR-ISG-2016-01 and remove Commitment #55. Inspections will start during the period of extended operation per LR-ISG-2016-01. A revised License Renewal Application Appendix A.3 Commitment List is provided within Enclosure 4. Commitment #55 changes are shown below.

PROGRAM or UFSAR No. COMMITMENT SCHEDULE TOPIC LOCATION Seabrook will perform an inspection of Steam Generator 'Nithin five years prior each steam generator to assess the 55 Tube Integrity A.2.1.10 to the period of condition of the divider plate Number Not Used extended operation.

assembly.

NRC Request #3 Provide updated UFSAR supplement for this program as necessary.

NextEra Energy's Seabrook Response to RAI B.2.1.10-3, Request #3 See Enclosure 2 for the revised Appendix A - Updated Final Safety Analysis Report Supplement, A.2.1.10 Steam Generator Tube Integrity.

Enclosure 2 to SBK-L-17087 Supplement 53 - NextEra Energy Seabrook's revised License Renewal Application, Appendix A - Updated Final Safety Analysis Report Supplement, A.2.1.10 Steam Generator Tube Integrity.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 2/ Page 2 UFSAR Supplement Appendix A has been revised based on guidance provided within LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components.

A.2.1.10 STEAM GENERATOR TUBE INTEGRITY The Steam Generator Tube Integrity Program manages the aging effects of cracking, loss of material, reduction of heat transfer and wall thinning from flow accelerated corrosion of the Steam Generator components. The program manages the aging of steam generator tubes, tube plugs, tube supports, divider plate assemblies, tube-to-tubesheet welds, heads, primary side tubesheets, and secondary side components that are contained within the steam generator.

The program is based on NEI 97-06 Rev. 3--2:, "Steam Generator Program Guidelines" and the associated EPRI guidelines, the response and commitment to Generic Letter 97-06, "Steam Generator Program Guidelines", and Seabrook Station Technical Specification 3/4.4.5 "Steam Generators" which ensure that the performance criteria for structural integrity, accident-induced leakage, and operational leakage are not exceeded. Seabrook Station has implemented the operational leakage limits found in NUREG-1431, "Standard Technical Specifications for Westinghouse Pressurized Water Reactors". General visual inspections of the internal surfaces of steam generator heads looking for indication of cracking or loss of material (e.g. rust staining) will be performed at least every 72 effective full power months, or every third refueling outage; whichever results in more frequent inspections. This program also utilizes foreign material exclusion and secondary side maintenance activities (e.g.

sludge lancing for deposit removal) to minimize component degradation.

Technical specification requirements on steam generator tube volumetric examinations, condition monitoring, and operational assessments are performed to ensure tube integrity will be maintained until the next inspection.

Seabrook 1..vill perform an inspection of each steam generator to assess the condition of the divider plate assembly *..vithin five years prior to entering the period of extended operation.

Seabrook Station has addressed the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds.

Amendment 131 to the Facility Operating License No. NPF-86 for Seabrook Station, Unit No. 1 was issued on September 10, 2012 (ML12178A537). This amendment provides permanent application of steam generator tube alternate repair criteria, H*.

Enclosure 3 to SBK-L-17087 Supplement 53 - NextEra Energy Seabrook's revised License Renewal Application, Appendix B - Aging Management Programs, B.2.1.10 Steam Generator Tube Integrity

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 2 LRA Appendix B - Aging Management Programs, has been revised based on guidance provided due to issuance of LR-ISG-2016 Changes to Aging Management Guidance for Various Steam Generator Components.

B.2.1.10 STEAM GENERATOR TUBE INTEGRITY Program Description The Seabrook Station Steam Generator Tube Integrity Program is an existing program that manages the aging effects of cracking due to intergranular attack, outer diameter stress corrosion cracking, primary water stress corrosion cracking, and stress corrosion cracking; loss of material due to general, crevice and pitting corrosion, erosion, fretting and wear; reduction of heat transfer due to fouling, and wall thinning from flow accelerated corrosion of the Steam Generator components.

The Seabrook Station program is applicable to managing the aging of Steam Generator tubes, tube plugs, aRG-tube supports, divider plate assemblies, tube-to-tubesheet welds, heads, primary side tubesheets, and secondary side components that are contained within the steam generator. Seabrook Station has not used tube sleeving repair.

Industry experience has shown that mill annealed alloy 600 Steam Generator tubes have experienced tube degradation due to corrosion, primary water stress corrosion cracking, outside diameter stress corrosion cracking, intergranular attack, pitting, and wastage, along with other mechanically induced degradation, such as denting, wear, impingement damage, and fatigue. The Seabrook Station Steam Generator tubes are Alloy 600 thermally treated tubes. The dominant degradation mode at this time for thermally treated alloy 600 tubes is wear.

The Seabrook Station Steam Generator Tube Integrity Program is based on NEI 97-06 Rev. 3, "Steam Generator Program Guidelines", the response and commitment to Generic Letter 97-06, "Degradation of Steam Generator Internals", and Seabrook Station Technical Specification 3/4.4.5, "Steam Generators," which ensure that the performance criteria for structural integrity, accident-induced leakage, and operational leakage are not exceeded. Seabrook Station has implemented the operational leakage limits found in NUREG-1431, "Standard Technical Specifications for Westinghouse Pressurized Water Reactors". General visual inspections of the internal surfaces of steam generator heads looking for indication of cracking or loss of material (e.g. rust staining) will be performed at least every 72 effective full power months, or every third refueling outage; whichever results in more frequent inspections.

This program identifies and maintains Steam Generator design and licensing basis, and establishes a framework for prevention, inspection, evaluation, repair and leakage monitoring measures to ensure that program requirements are met.

Operational leakage limits are included to ensure that, should substantial tube

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 3 leakage develop, prompt action is taken. These limits are described in Seabrook Station Technical Specifications.

Seabrook Station Technical Specification 6.7.6.k, "Steam Generator (SG) Program",

specifies Steam Generator inspection scope, frequency, and acceptance criteria for the plugging and repair of flawed tubes. NRG Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded Steam Generator Tubes", provides guidelines for determining the tube repair criteria and operational leakage limits.

The program includes preventive measures to mitigate degradation related to corrosion phenomena through water chemistry control and the secondary side cleaning and inspection. The Water Chemistry Program, B.2.1.2, mitigates the potentially corrosive effects of the primary and secondary water on the interior and exterior surfaces of the Steam Generator tubes and other Steam Generator internals.

The Steam Generator Tube Integrity Program includes foreign material exclusion guidance, consistent with NEI 97-06. The program includes prevention and detection of foreign objects in the secondary side of the Steam Generators as a means to inhibit wear degradation by performing foreign object search and retrieval at each inspection outage when the hand-hole covers are removed for Steam Generator cleaning.

The objectives of the secondary side inspection plan are to inspect the Steam Generators for foreign objects, perform visual assessments of sludge and visual inspections for secondary side integrity and corrosion. The secondary side inspections have been expanded to examine additional areas of the upper tube bundle and inner tube bundle. The upper internal regions of the tube bundle are inspected for sludge accumulation on the tube support plates. Secondary side inspections are performed every third refueling outage.

The program provides criteria for the qualification of personnel, specific inspection techniques, and associated acquisition and analysis of data, including procedures, probe selection, analysis protocols, and reporting criteria. The performance criteria pertain to structural integrity, accident-induced leakage, and operational leakage.

Nondestructive examination techniques are used to inspect all tubing materials to identify tubes with degradation that may need to be removed from service or repaired. Tubes containing flaws that do not meet the acceptance criteria are plugged. Assessment of tube integrity and plugging or repair criteria of flawed tubes is in accordance with Seabrook Station Technical Specifications.

Degraded plugs and tube supports are evaluated in accordance with the Seabrook Station Corrective Action Program. The program includes requirements for assessment of degradation mechanisms that consider operating experience from similar steam generators and, for each mechanism, defines the inspection techniques as well as the sampling strategy. Compliance with NRG Regulatory Guide 1.121 for plugging or repairing steam generator tubes is achieved through implementation of the NEI 97-06 criteria as incorporated into the program and Seabrook Station Technical Specifications.

Tube inspection scope and frequency, plugging or repair, and leakage monitoring are in accordance with the Seabrook Station Technical Specifications and the

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 4 Seabrook Station Steam Generator Tube Integrity Program implemented in accordance with NEI 97-06.

Plug inspection scope and frequency, plugging or repair, and leakage monitoring are in accordance with the Seabrook Station Steam Generator Tube Integrity Program implemented in accordance with NEI 97-06.

Tube support plate inspection scope and frequency are in accordance with the Seabrook Station Steam Generator Tube Integrity Program implemented in accordance with NEI 97-06 as well as the program enhancements committed to in Seabrook Station's response to GL 97-06.

Tube integrity is demonstrated by satisfying the structural integrity and leakage performance criteria in conjunction with the performance acceptance standards.

Condition monitoring and assessments are performed after inspections to verify that structural and leakage integrity will be maintained for the operating interval between inspections. Comparison of the results of the condition monitoring assessment with the predictions of the previous operational assessment provides feedback for evaluation of the adequacy of the operational assessment and additional insights that can be incorporated into the next operational assessment.

Seabrook i.vill perform an inspection of each steam generator to assess the condition of the divider plate assembly .vithin five years prior to entering the period of 1

extended operation (Per Commitment #55). The inspection techniques used 'Nill be capable of detecting primary water stress corrosion cracking in the steam generator divider plate assemblies and their associated '.velds. Any evidence of cracking will be documented and evaluated under the corrective action program.

Seabrook Station has addressed the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds.

Amendment 131 to the Facility Operating License No. NPF-86 for Seabrook Station, Unit No. 1 was issued on September 10, 2012 (ML12178A537). This amendment provides permanent application of steam generator tube alternate repair criteria, H*.

NUREG-1801 Consistency This program is consistent with NUREG-1801-Xl.M19 as modified by LR ISG 2011 02 LR-ISG-2016-01.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 5 Exceptions to NUREG-1801 There are no exceptions to NUREG-1801-Xl.M19 as modified by LR ISG 2011 02 LR-JSG-2016-01.

Enhancements None Operating Experience

1. Seabrook Station is a four-loop plant with Westinghouse Model F Steam Generators. There are 5626 tubes in each of the four Steam Generators. The design of these Steam Generators includes Alloy 600 thermally treated tubing, full-depth hydraulically expanded tubesheet joints, with urethane (hydrostatic) tack expansions at the tube ends. The tube support plates are broach-holed quatrefoil plates fabricated of Type 405 stainless steel. The U-bends of the first ten rows of tubing were stress relieved after bending. Seabrook Station has completed 13 cycles of plant operations. To date, Seabrook Station has identified the following tube degradation mechanisms:

a. Anti-vibration bar wear due to flow induced vibration in the U-bends of larger radius tubes.

b. Minor wear at flow distribution baffles associated with pressure pulse cleaning.

c. Possible wear due to foreign objects.

d. outside diameter stress corrosion cracking in a small subset of tubes 'Nith elevated residual stress in Steam Generator "D" Outside diameter stress corrosion cracking.

e. top of tubesheet outside diameter stress corrosion cracking in one tube in Steam Generator "C" Primary water stress corrosion cracking.

2. During Refueling Outage 8 (Spring of 2002), axial indications were identified on several Steam Generator tubes at the quatrefoil tube support plates in Steam Generator "D" with eddy current testing and confirmed with ultrasonic examination.

A root cause evaluation was performed and concluded that outside diameter stress corrosion cracking was the degradation mechanism for the Seabrook Station's Steam Generators. The root cause of the cracking has been determined to be high residual stress due to a manufacturing anomaly in a defined subset of Seabrook Station Steam Generator tubes. A total of 21 tubes were identified in the subset, 15 of which had cracks and were plugged. The remaining 6 tubes were inspected and plugged in Refueling Outage 9 (Fall of 2003). Subsequent inspections have shown that outside diameter stress corrosion cracking was limited to the defined subset of the tube population and no longer exists in the Seabrook Station Steam Generators for tubes with high residual stress.

3. During Refueling Outage 12 (Spring of 2008), foreign objects were discovered in Steam Generator "B during the inspection of the steam drum area. The root cause evaluation was performed, which concluded that the cause of the foreign objects being in the Steam Generator was inadequate foreign material exclusion

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 6 controls of material used in Steam Generator "B" steam drum inspection. The root cause evaluation's recommended corrective action to prevent re-occurrence was to revise the job plan for Steam Generator inspection to include a pre-use inspection of all materials brought into the Steam Generators for concealed/loose foreign material. This corrective action has been implemented.

4. The Steam Generator degradation assessment for Refueling Outage 13 (Fall of 2009) identified operating experience at Vogtle Unit 1 where axial and circumferential outside diameter stress corrosion cracking was reported at the top of the hot leg tubesheet. Vogtle has Westinghouse Model F Steam Generators with Alloy 600 thermally treated tubing similar to Seabrook Station. Vogtle Unit 1 was the first U.S. plant to report axial outside diameter stress corrosion cracking at the top of the tube sheet in a Model F Steam Generator. Accordingly, this operating experience was incorporated into the implementation plan for Refueling Outage 13 (Fall of 2009) as part of the Steam Generator inspections.

Subsequently, during Seabrook station's Refueling Outage 13, top of tube sheet inspections were completed. An axial outside diameter stress corrosion cracking indication was found on one tube in Steam Generator "C" hot leg. The indication was approximately 0.2 inches below the top of the tube sheet and was 0.10 inches long. The tube was plugged on both the hot leg and cold leg sides.

The Steam Generator degradation assessment for Refueling Outage 13 also discusses the status of anti-vibration bar wear and the minor wear at flow distribution baffles associated with pressure pulse cleaning.

The flow distribution baffle wear was discovered in Steam Generators "A" and "D". A single wear indication was reported during Refueling Outage 9 (Fall of 2003) at the flow distribution baffle. These indications were retested at Refueling Outage 11 (Fall 2006) to determine if there was any progression of the wear.

These indications are attributed to a prior pressure pulse cleaning of the steam generators, based on the location of the indications relative to the pressure pulse locations. Similar indications have been observed in other Model F steam generators at other plants that have applied the pressure pulse cleaning process.

The re-examination of these indications at Refueling Outage 11 (Fall of 2006) resulted in no degradation found at the location in Steam Generator "A" and no progression of the wear of the indication in Steam Generator "D".

The anti-vibration bar wear is flow induced vibration at the intersections of the tubes with the anti-vibration bars and is an existing indication in all four Steam Generators. Analysis has determined that for Model F Steam Generators, the number of tubes considered susceptible to anti-vibration bar wear is typically less than 3% of the total number of tubes, with only a fraction of the susceptible tubes expected to require plugging. Tubes that were plugged for anti-vibration bar wear continue to wear after plugging and have been observed to wear through wall after a period of time. Analysis for Seabrook Station concluded that the originally worn plugged tubes would not achieve a condition that could present risk of tube separation before contacting the adjacent tubes. It was further determined that, if an active tube is adjacent to a worn, plugged tube, the progression of contact

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 3/ Page 7 wear on the active tube would be very slow and sufficient operating time is available under the current Seabrook Station inspection plan (4 Steam Generators per outage, every other outage) that wear would be identified during the planned inspections. Continuing wear on a plugged tube is benign with respect to tube separation since no risk of tube separation was identified for any axially oriented degradation mechanisms.

5. Through Refueling Outage 13 (Fall of 2009), Seabrook Station has plugged a total of 173 tubes in the Steam Generators (A-34, B-25, C-50, and D-64).

6. LR-ISG-2016-01 was utilized to revise this program. Operating experience as described within the ISG focuses on supplementing the Water Chemistry program with visual inspections within the Steam Generator Tube Integrity program. There have been instances where the Water Chemistry program alone has not been sufficient at preventing aging due to Primary Water Stress Corrosion Cracking on components within the steam generator head. Seabrook will perform general visual inspections of the internal surfaces of steam generator heads looking for indication of cracking or loss of material (e.g. rust staining) at least every 72 effective full power months, or every third refueling outage; whichever results in more frequent inspections.

The operating experience of the Seabrook Station Steam Generator Tube Integrity Program provides objective evidence that the program effectively identifies degradation prior to loss of intended function. Appropriate guidance for evaluation, repair, or replacement is provided for locations where degradation is found. External operating experience is effectively reviewed and incorporated into the Seabrook Station Steam Generator Tube Integrity Program.

Conclusion The Seabrook Station Steam Generator Tube Integrity Program provides reasonable assurance that the aging effects will be adequately managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Enclosure 4 to SBK-L-17087 Supplement 53 - NextEra Energy Seabrook's revised LRA Appendix A - Updated Final Safety Analysis Report Supplement Table A.3, License Renewal Commitment List

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 2 A.3 LICENSE RENEWAL COMMITMENT LIST UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Provide confirmation and acceptability of the implementation ofMRP-227-A by addressing the plant-

1. PWR Vessel Internals A.2.1.7 Complete specific Applicant/Licensee Action Items outlined in section 4.2 of the NRC SER.

Enhance the program to include visual inspection for Prior to the period of extended

2. Closed-Cycle Cooling Water cracking, loss of material and fouling when the in-scope A.2.1.12 operation.

systems are opened for maintenance.

Inspection of Overhead Heavy Enhance the program to monitor general corrosion on the Load and Light Load (Related Prior to the period of extended

3. crane and trolley structural components and the effects of A.2.1.13 to Refueling) Handling operation.

wear on the rails in the rail system.

Systems Inspection of Overhead Heavy Load and Light Load (Related Prior to the period of extended

4. Enhance the program to list additional cranes for monitoring. A.2.1.13 to Refueling) Handling operation.

Systems Enhance the program to include an annual air quality test Prior to the period of extended

5. Compressed Air Monitoring requirement for the Diesel Generator compressed air sub A.2.1.14 operation.

system.

Enhance the program to perform visual inspection of Prior to the period of extended

6. Fire Protection A.2.1.15 penetration seals by a fire protection qualified inspector. operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 3 Enhance the program to add inspection requirements such as spalling, and loss of material caused by freeze-thaw, Prior to the period of extended

7. Fire Protection A.2.1.15 chemical attack, and reaction with aggregates by qualified operation.

inspector.

Enhance the program to include the performance of visual Prior to the period of extended

8. Fire Protection inspection of fire-rated doors by a fire protection qualified A.2.1.15 operation.

inspector.

Enhance the program to include NFPA 25 (2011 Edition) guidance for "where sprinklers have been in place for 50 Prior to the period of extended

9. Fire Water System years, they shall be replaced or representative samples from A.2.1.16 operation.

one or more sample areas shall be submitted to a recognized testing laboratory for field service testing".

Enhance the program to include the performance of periodic Prior to the period of extended

10. Fire Water System flow testing of the fire water system in accordance with the A.2.1.16 operation.

guidance ofNFP A 25 (2011 Edition).

Enhance the program to include the performance of periodic visual or volumetric inspection of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thickness and inner diameter of the fire protection piping ensuring that corrosion product buildup will not result in flow blockage due to fouling. Where surface irregularities are detected, follow-up volumetric examinations are performed. These Within ten years prior to the

11. Fire Water System A.2.1.16 inspections will be documented and trended to determine if a period of extended operation.

representative number of inspections have been performed prior to the period of extended operation. If a representative number of inspections have not been performed prior to the period of extended operation, focused inspections will be conducted. These inspections will commence during the ten year period prior to the period of extended operation and continue through the period of extended operation

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 4 Enhance the program to include 1) In-scope outdoor tanks, except fire water storage tanks, constructed on soil or concrete, 2) Indoor large volume storage tanks (greater than 100,000 gallons) designed to near-atmospheric internal pressures, sit on concrete or soil, and exposed internally to water, 3) Visual, surface, and volumetric examinations of the Within 10 years prior to the

12. Aboveground Steel Tanks outside and inside surfaces for managing the aging effects of A.2.1.17 period of extended operation.

loss of material and cracking, 4) External visual examinations to monitor degradation of the protective paint or coating, and

5) Inspection of sealant and caulking for degradation by performing visual and tactile examination (manual manipulation) consisting of pressing on the sealant or caulking to detect a reduction in the resiliency and pliability.

Enhance the program to perform exterior inspection of the fire water storage tanks annually for signs of degradation and include an ultrasonic inspection and evaluation of the Within ten years prior to the

13. Fire Water System A.2.1.16 internal bottom surface of the two Fire Protection Water period of extended operation.

Storage Tanks per the guidance provided in NFPA 25 (2011 Edition).

Enhance program to add requirements to 1) sample and analyze new fuel deliveries for biodiesel prior to offloading Prior to the period of extended

14. Fuel Oil Chemistry to the Auxiliary Boiler fuel oil storage tank and 2) A.2.1.18 operation.

periodically sample stored fuel in the Auxiliary Boiler fuel oil storage tank.

Enhance the program to add requirements to check for the Prior to the period of extended

15. Fuel Oil Chemistry presence of water in the Auxiliary Boiler fuel oil storage tank A.2.1.18 operation.

at least once per quarter and to remove water as necessary.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 5 Enhance the program to require draining, cleaning and Prior to the period of extended

16. Fuel Oil Chemistry inspection of the diesel fire pump fuel oil day tanks on a A.2.1.18 operation.

frequency of at least once every ten years.

Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10-year draining, cleaning and inspection of the Diesel Generator fuel oil Prior to the period of extended

17. Fuel Oil Chemistry A.2.1.18 storage tanks, Diesel Generator fuel oil day tanks, diesel fire operation.

pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.

Enhance the program to specify that all pulled and tested Prior to the period of extended

18. Reactor Vessel Surveillance capsules, unless discarded before August 31, 2000, are A.2.1.19 operation.

placed in storage.

Enhance the program to specify that if plant operations exceed the limitations or bounds defined by the Reactor Vessel Surveillance Program, such as operating at a lower Prior to the period of extended

19. Reactor Vessel Surveillance cold leg temperature or higher fluence, the impact of plant A.2.1.19 operation.

operation changes on the extent of Reactor Vessel embrittlement will be evaluated and the NRC will be notified.

Enhance the program as necessary to ensure the appropriate withdrawal schedule for capsules remaining in the vessel such that one capsule will be withdrawn at an outage in which the capsule receives a neutron fluence that meets the Prior to the period of extended

20. Reactor Vessel Surveillance A.2.1.19 schedule requirements of 10 CFR 50 Appendix Hand ASTM operation.

E185-82 and that bounds the 60-year fluence, and the remaining capsule(s) will be removed from the vessel unless determined to provide meaningful metallurgical data.

Enhance the program to ensure that any capsule removed, without the intent to test it, is stored in a manner which Prior to the period of extended

21. Reactor Vessel Surveillance A.2.1.19 maintains it in a condition which would permit its future use, operation.

including during the period of extended operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 6 Within ten years prior to the

22. One-Time Inspection Implement the One Time Inspection Program. A.2.1.20 period of extended operation.

Implement the Selective Leaching of Materials Program. The program will include a one-time inspection of selected Selective Leaching of Within five years prior to the

23. components where selective leaching has not been identified A.2.1.21 Materials period of extended operation.

and periodic inspections of selected components where selective leaching has been identified.

Implement the Buried Piping And Tanks Inspection Buried Piping And Tanks Program. Within ten years prior to the

24. A.2.1.22 Inspection period of extended operation One-Time Inspection of Implement the One-Time Inspection of ASME Code Class 1 Within ten years prior to the

25. ASME Code Class 1 Small A.2.1.23 Small Bore-Piping Program. period of extended operation.

Bore-Piping Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects of Prior to the period of extended

26. External Surfaces Monitoring interest, the refueling outage inspection frequency, the A.2.1.24 operation.

training requirements for inspectors and the required periodic reviews to determine program effectiveness.

Inspection oflntemal Surfaces Implement the Inspection oflntemal Surfaces in Prior to the period of extended

27. in Miscellaneous Piping and A.2.1.25 Miscellaneous Piping and Ducting Components Program. operation.

Ducting Components Enhance the program to add required equipment, lube oil Prior to the period of extended

28. Lubricating Oil Analysis analysis required, sampling frequency, and periodic oil A.2.1.26 operation.

changes.

Enhance the program to sample the oil for the Reactor Prior to the period of extended

29. Lubricating Oil Analysis A.2.1.26 Coolant pump oil collection tanks. operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 7 Enhance the program to require the performance of a one-time ultrasonic thickness measurement of the lower portion Prior to the period of extended

30. Lubricating Oil Analysis A.2.1.26 of the Reactor Coolant pump oil collection tanks prior to the operation.

period of extended operation.

ASME Section XI, Subsection Enhance procedure to include the definition of "Responsible Prior to the period of extended

31. A.2.1.28 IWL Engineer". operation.

Enhance procedure to add the aging effects, additional Prior to the period of extended

32. Structures Monitoring Program locations, inspection frequency and ultrasonic test A.2.1.31 operation.

requirements.

Enhance procedure to include inspection of opportunity Prior to the period of extended

33. Structures Monitoring Program when planning excavation work that would expose A.2.l.31 operation.

inaccessible concrete.

Electrical Cables and Implement the Electrical Cables and Connections Not Connections Not Subject to 10 Prior to the period of extended

34. Subject to 10 CFR 50.49 Environmental Qualification A.2.1.32 CFR 50.49 Environmental operation.

Requirements program.

Qualification Requirements Electrical Cables and Connections Not Subject to 10 Implement the Electrical Cables and Connections Not CFR 50.49 Environmental Prior to the period of extended

35. Subject to 10 CFR 50.49 Environmental Qualification A.2.1.33 Qualification Requirements operation.

Requirements Used in Instrumentation Circuits program.

Used in Instrumentation Circuits Inaccessible Power Cables Not Implement the Inaccessible Power Cables Not Subject to 10 Subject to 10 CFR 50.49 Prior to the period of extended

36. CFR 50.49 Environmental Qualification Requirements A.2.1.34 Environmental Qualification operation.

program.

Requirements Prior to the period of extended

37. Metal Enclosed Bus Implement the Metal Enclosed Bus program. A.2.1.35 operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 8 Prior to the period of extended

38. Fuse Holders Implement the Fuse Holders program. A.2.1.36 operation.

Electrical Cable Connections Implement the Electrical Cable Connections Not Subject to Not Subject to 10 CFR 50.49 Prior to the period of extended

39. 10 CFR 50.49 Environmental Qualification Requirements A.2.l.37 Environmental Qualification operation.

program.

Requirements Prior to the period of extended

40. 345 KV SF6 Bus Implement the 345 KV SF6 Bus program. A.2.2.1 operation.

Metal Fatigue of Reactor Enhance the program to include additional transients beyond Prior to the period of extended

41. A.2.3.l Coolant Pressure Boundary those defined in the Technical Specifications and UFSAR. operation.

Enhance the program to implement a software program, to Metal Fatigue of Reactor Prior to the period of extended

42. count transients to monitor cumulative usage on selected A.2.3.1 Coolant Pressure Boundary operation.

components.

The updated analyses will be Pressure -Temperature Limits, Seabrook Station will submit updates to the P-T curves and submitted at the appropriate

43. including Low Temperature LTOP limits to the NRC at the appropriate time to comply A.2.4.1.4 time to comply with 10 CFR Overpressure Protection Limits with 10 CFR 50 Appendix G. 50 Appendix G, Fracture Toughness Requirements.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 41Page9 NextEra Seabrook will perform a review of design basis ASME Class 1 component fatigue evaluations to determine whether the NUREG/CR-6260-based components that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting components for the Seabrook plant configuration. If more limiting 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 identified consists of nickel alloy, the environmentally-assisted fatigue calculation for nickel alloy will be performed using the rules ofNUREG/CR-6909.

(1) Consistent with the Metal Fatigue of Reactor Coolant Pressure Boundary Program Seabrook Station will update the fatigue usage calculations using refined fatigue analyses, if necessary, to determine acceptable CUFs (i.e., less than 1.0) when accounting for the effects of the reactor water Environmentally-Assisted environment. This includes applying the appropriate Fen At least two years prior to the

44. A.2.4.2.3 Fatigue Analyses (TLAA) factors to valid CUFs determined from an existing fatigue period of extended operation.

analysis valid for the period of extended operation or from an analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case).

(2) If acceptable CUFs cannot be demonstrated for all the selected locations, then additional plant-specific locations will be evaluated. For the additional plant-specific locations, if CUF, including environmental effects is greater than 1.0, then Corrective Actions will be initiated, in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program, B.2.3.1. Corrective Actions will include inspection, repair, or replacement of the affected locations before exceeding a CUF of 1. 0 or the effects of fatigue will be managed by an inspection program that has been reviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method accepted by the NRC).

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 10

45. Number Not Used Protective Coating Monitoring Enhance the program by designating and qualifying an Prior to the period of extended

46. A.2.1.38 and Maintenance Inspector Coordinator and an Inspection Results Evaluator. operation.

Enhance the program by including, "Instruments and Equipment needed for inspection may include, but not be Protective Coating Monitoring limited to, flashlight, spotlights, marker pen, mirror, Prior to the period of extended

47. A.2.1.38 and Maintenance measuring tape, magnifier, binoculars, camera with or operation.

without wide angle lens, and self sealing polyethylene sample bags."

Protective Coating Monitoring Enhance the program to include a review of the previous two Prior to the period of extended

48. A.2.1.38 and Maintenance monitoring reports. operation.

Enhance the program to require that the inspection report is Protective Coating Monitoring to be evaluated by the responsible evaluation personnel, who Prior to the period of extended

49. A.2.1.38 and Maintenance is to prepare a summary of findings and recommendations operation.

for future surveillance or repair.

Baseline inspections were completed during OR16.

Perform UT of the accessible areas of the containment liner ASME Section XI, Subsection Repeat containment liner UT

50. plate in the vicinity of the moisture barrier for loss of A.2.1.27 IWE thickness examinations at material. Perform opportunistic UT of inaccessible areas.

intervals of no more than five (5) refueling outages.

51. Number Not Used Implement measures to maintain the exterior surface of the ASME Section XI, Subsection

52. Containment Structure, from elevation -30 feet to +20 feet, in A.2.1.28 Complete IWL a dewatered state.

Replace the spare reactor head closure stud(s) manufactured Prior to the period of extended

53. Reactor Head Closure Studs from the bar that has a yield strength> 150 ksi with ones that A.2.1.3 operation.

do not exceed 150 ksi.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 11 NextEra will address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options:

1) Perform a one-time inspection of a representative sample oftube-to-tubesheet welds in all steam generators to determine if PWSCC cracking is present and, if cracking is identified, resolve the condition through engineering evaluation justifying continued operation or repair the condition, as appropriate, and establish an ongoing monitoring program to perform routine tube-to-tubesheet Steam Generator Tube

54. weld inspections for the remaining life of the steam A.2.1.10 Complete Integrity generators, or

2) Perform an analytical evaluation showing that the structural integrity of the steam generator tube-to-tubesheet interface is adequately maintaining the pressure boundary in the presence oftube-to-tubesheet weld cracking, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be approved by the NRC as part of a license amendment request.

Steam GeB:eFatoF +we 8eabrnok will peFfurm an iB:speetioB: of eaeh steam geB:erntoF Withrn five yearn pFioF to the

55. A.2.1.10 IB:tegFity Number Not Used to assess the eoB:aitioB: of the Eli:viaeF plate assemaly. peFioa of e~tteB:aea operntioB:.

Revise the station program documents to reflect the EPRl Closed-Cycle Cooling Water Prior to the period of extended

56. Guideline operating ranges and Action Level values for A.2.1.12 System operation.

hydrazine and sulfates.

Revise the station program documents to reflect the EPRl Closed-Cycle Cooling Water Prior to the period of extended

57. Guideline operating ranges and Action Level values for A.2.1.12 System operation.

Diesel Generator Cooling Water Jacket pH.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 12 Update Technical Requirement Program 5.1, (Diesel Fuel Oil Prior to the period of extended

58. Fuel Oil Chemistry Testing Program) ASTM standards to ASTM D2709-96 and A.2.1.18 operation.

ASTM D4057-95 required by the GALL Xl.M30 Rev 1 The Nickel Alloy Aging Nozzles and Penetrations program Nickel Alloy Nozzles and Prior to the period of extended

59. will implement applicable Bulletins, Generic Letters, and A.2.2.3 Penetrations operation.

staff accepted industry guidelines.

Implement the design change replacing the buried Auxiliary Buried Piping and Tanks Prior to the period of extended

60. Boiler supply piping with a pipe-within-pipe configuration A.2.1.22 Inspection operation.

with leak detection capability.

Compressed Air Monitoring Replace the flexible hoses associated with the Diesel Within ten years prior to the

61. A.2.1.14 Program Generator air compressors on a frequency of every 10 years. period of extended operation.

Enhance the program to include a statement that sampling Prior to the period of extended

62. Water Chemistry frequencies are increased when chemistry action levels are A.2.1.2 operation.

exceeded.

Ensure that the quarterly CVCS Charging Pump testing is continued during the PEO. Additionally, add a precaution to the test procedure to state that an increase in the eves Prior to the period of extended

63. Flow Induced Erosion A.2.1.2 Charging Pump mini flow above the acceptance criteria may operation.

be indicative of erosion of the mini flow orifice as described in LER 50-275/94-023.

Soil analysis shall be performed prior to entering the period of extended operation to determine the corrosivity of the soil in the vicinity ofnon-cathodically protected steel pipe within Within ten years prior to the

64. Buried Piping and Tanks A.2.1.22 the scope of this program. If the initial analysis shows the period of extended operation.

Inspection soil to be non-corrosive, this analysis will be re-performed every ten years thereafter.

Implement measures to ensure that the movable incore Prior to the period of extended

65. Flux Thimble Tube detectors are not returned to service during the period of NIA operation. - In Progress extended operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 13

66. Number Not Used Perform one shallow core bore in an area that was continuously wetted from borated water to be examined for concrete degradation and also expose rebar to detect any

67. Structures Monitoring Program A.2.1.31 Complete degradation such as loss of material. The removed core will also be subjected to petrographic examination for concrete degradation due to ASR per ASTM Standard Practice C856.

Perform sampling at the leak off collection points for

68. Structures Monitoring Program A.2.1.31 Complete chlorides, sulfates, pH and iron once every three months.

Replace the Diesel Generator Heat Exchanger Plastisol PVC Open-Cycle Cooling Water

69. lined Service Water piping with piping fabricated from A.2.1.11 Complete System AL6XN material.

Inspect the piping downstream of CC-V-444 and CC-V-446 Closed-Cycle Cooling Water to determine whether the loss of material due to cavitation Within ten years prior to the

70. A.2.1.12 System induced erosion has been eliminated or whether this remains period of extended operation.

an issue in the primary component cooling water system.

NextEra has completed testing at the University of Texas Ferguson Structural Engineering Laboratory which Alkali-Silica Reaction (ASR) demonstrates the parameters being monitored and acceptance Monitoring Program I criteria used are appropriate to manage the effects of ASR. A.2.l.31A Prior to the period of extended

71. Building Deformation operation.

NextEra Iimplement the Alkali-Silica Reaction (ASR) A.2.l.31B Monitoring Program Monitoring Program and Building Deformation Monitoring Program described in B.2.1.3 lA and B.2.1.3 lB of the License Renewal Application.

Enhance the program to include management of wall Prior to the period of extended

72. Flow-Accelerated Corrosion A.2.1.8 thinning caused by mechanisms other than FAC. operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 14 Enhance the program to include performance of focused Inspection of Internal Surfaces examinations to provide a representative sample of20%, or a

73. in Miscellaneous Piping and maximum of25, of each identified material, environment, A.2.1.25 Prior to the period of extended Ducting Components and aging effect combinations during each 10 year period in operation.

the period of extended operation.

Enhance the program to perform sprinkler inspections annually per the guidance provided in NFP A 25 (2011 Edition). Inspection will ensure that sprinklers are free of corrosion, foreign materials, paint, and physical damage and Prior to the period of extended

74. Fire Water System installed in the proper orientation (e.g., upright, pendant, or A.2.1.16 operation.

sidewall). Any sprinkler that is painted, corroded, damaged, loaded, or in the improper orientation, and any glass bulb sprinkler where the bulb has emptied, will be evaluated for replacement.

Enhance the program to a) conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material per the guidance provided in NFPA 25 (2011 Edition) and b) If the presence of sufficient foreign Prior to the period of extended

75. Fire Water System organic or inorganic material to obstruct pipe or sprinklers is A.2.1.16 operation.

detected during pipe inspections, the material will be removed and its source is determined and corrected.

In buildings having multiple wet pipe systems, every other system shall have an internal inspection of piping every 5 years as described in NFPA 25 (2011 Edition), Section 14.2.2.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 15 Enhance the Program to conduct the following activities annually per the guidance provided in NFPA 25 (2011 Edition). Prior to the period of extended

76. Fire Water System A.2.1.16 operation.

• main drain tests

• deluge valve trip tests

• fire water storage tank exterior surface inspections The Fire Water System Program will be enhanced to include the following requirements related to the main drain testing per the guidance provided in NFP A 25 (2011 Edition).

• The requirement that if there is a 10 percent reduction in Prior to the period of extended

77. Fire Water System full flow pressure when compared to the original A.2.1.16 operation.

acceptance tests or previously performed tests, the cause of the reduction shall be identified and corrected if necessary.

• Recording the time taken for the supply water pressure to return to the original static (nonflowing) pressure.

Enhance the program to include periodic inspections of in-scope insulated components for possible corrosion under insulation. A sample of outdoor component surfaces that are insulated and a sample of indoor insulated components Prior to the period of extended

78. External Surfaces Monitoring A.2.1.24 exposed to condensation (due to the in-scope component operation.

being operated below the dew point), will be periodically inspected every 10 years during the period of extended operation.

Enhance the program to include visual inspection of internal Open-Cycle Cooling Water coatings/linings for loss of coating integrity. Within 10 years prior to the

79. A.2.1.11 System period of extended operation.

Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

80. Fire Water System A.2.1.16 period of extended operation.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 16 Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

81. Fuel Oil Chemistry A.2.1.18 period of extended operation.

Inspection of Internal Surfaces Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

82. in Miscellaneous Piping and A.2.1.25 period of extended operation.

Ducting Components Enhance the ASR AMP to install extensometers in all Tier 3 areas of two dimensional reinforced structures to monitor expansion due to alkali-silica reaction in the out-of-plane Alkali-Silica Reaction direction.

83. A.2.l.31A December 31,2016.

Monitoring Monitoring expansion in the out-of-plane direction will commence upon installation of the extensometers and continue on a six month :frequency through the period of extended operation.

Evaluate the acceptability of inaccessible areas for structures ASME Section XI, Subsection Prior to the period of extended

84. within the scope of ASME Section XI, Subsection IWL A.2.1.28 IWL operation.

Program.

Enhance the program to perform additional tests and inspections on the Fire Water Storage Tanks as specified in

85. Section 9 .2. 7 ofNFP A 25 (2011 Edition) in the event that it Prior to the period of extended Fire Water System A.2.1.16 is required by Section 9.2.6.4, which states "Steel tanks operation.

exhibiting signs of interior pitting, corrosion, or failure of coating shall be tested in accordance with 9.2.7."

86. Enhance the program to include disassembly, inspection, and Prior to the period of extended Fire Water System A.2.1.16 cleaning of the mainline strainers every 5 years. operation.

Increase the :frequency of the Open Head Spray Nozzle Air

87. Prior to the period of extended Fire Water System Flow Test from every 3 years to every refueling outage to be A.2.1.16 operation.

consistent with LR-ISG-2012-02, AMP XI.M27, Table 4a.

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 17 Enhance the program to include verification that a) the drain holes associated with the transformer deluge system are draining to ensure complete drainage of the system after each

88. test, b) the deluge system drains and associated piping are Within five years prior to the Fire Water System A.2.1.16 configured to completely drain the piping, and c) normally- period of extended operation.

dry piping that could have been wetted by inadvertent system actuations or those that occur after a fire are restored to a dry state as part of the suppression system restoration.

Incorporate Coating Service Level III requirements into the RCP Motor Refurbishment Specification for the internal Inspection oflnternal Surfaces painting of the motor upper bearing coolers and motor air Prior to the period of extended

89. in Miscellaneous Piping and A.2.1.25 coolers. All four RCP motors will be refurbished and operation.

Ducting Components replaced using the Coating Service Level III requirements prior to entering the period of extended operation.

Implement the PWR Vessel Internals Program. The program will be implemented in accordance with MRP-227-A Prior to the period of extended PWR Vessel Internals (Pressurized Water Reactor Internals Inspection and A.2.1.7

90. operation Evaluation Guidelines) and NEI 03-08 (Guideline for the Management of Materials Issues).

U.S. Nuclear Regulatory Commission SBK-L-17087 I Enclosure 4/ Page 18 Implement the Building Deformation Monitoring Program Enhance Structures Monitoring Program to require structural evaluations be performed on buildings and components affected by deformation as necessary to ensure that the structural function is maintained. Evaluations of structures will validate structural performance against the design basis, and may use results from the large-scale test programs, as appropriate. Evaluations for structural deformation will also consider the impact to functionality of affected systems and Building Deformation components (e.g., conduit expansion joints). NextEra will A.2.l.31B 91 March 15, 2020 Monitoring evaluate the specific circumstances against the design basis of the affected system or component.

Enhance the Building Deformation AMP to include additional parameters to be monitored based on the results of the CEB Root Cause, Structural Evaluation and walk downs.

Additional parameters monitored will include: alignment of ducting, conduit, and piping; seal integrity; laser target measurements; key seismic gap measurements; and additional instrumentation.