SBK-L-11062, Response to Request for Additional Information NextEra Energy Seabrook License Renewal Application Request for Additional Information - Set 11

Response to Request for Additional Information NextEra Energy Seabrook License Renewal Application Request for Additional Information - Set 11

ML110960647
Person / Time
Site:	Seabrook
Issue date:	04/05/2011
From:	Freeman P NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-11062, TAC ME4028
Download: ML110960647 (43)

Text

NExTeram ENERGY S SEA BROO0K April 5, 2011 SBK-L- 11062 Docket No. 50-443 U.S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Seabrook Station Response to Request for Additional Information NextEra Energy Seabrook License Renewal Application Request for Additional Information - Set 11

References:

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

2. NRC Letter "Request for Additional Information Related to the Review of the Seabrook Station License Renewal Application (TAC NO. ME4028) - Request for Additional Information Set 11," March 7, 2011. (Accession Number ML110550920)

3. NextEra Energy Seabrook, LLC letter SBK-L- 10179, "Supplement to the NextEra Energy Seabrook, LLC, Seabrook Station License Renewal Application", October 29, 2010.

(Accession Number ML10306002)

4. NextEra Energy Seabrook, LLC letter SBK-L-1 1002, "Seabrook Station Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application Aging Management Programs - Set 4 ", January 13, 2011. (Accession Number ML110140809)

5. NextEra Energy Seabrook, LLC letter SBK-L-1 1003, "Seabrook Station Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application Aging Management Programs - Set 5 ", January 13, 2011. (Accession Number MLl 10140587)

6. NextEra Energy Seabrook, LLC letter SBK-L-11015, "Seabrook Station Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application - Sets 6, 7 and 8", February 3, 2011. (Accession Number MLl 10380081)

NextEra Energy Seabrook, LLC, P.O. Box 300, Lafayette Road, Seabrook, NH 03874

United States Nuclear Regulatory Commission SBK-L-1 1062 / Page 2 In Reference 1, NextEra Energy Seabrook, LLC (NextEra) submitted 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 NRC requested additional information in order to complete its review of the License Renewal Application (LRA). Enclosure 1 contains NextEra's response to the request for additional information and associated changes made to the LRA. For clarity, deleted LRA text is highlighted by strikethroughs and inserted texts highlighted by bold italics. Enclosure 2 contains a technical evaluation associated with the RAI B.2.1.12-8 response.

Commitment numbers 63 and 64 are added to the License Renewal Commitment List. There are no other new or revised regulatory commitments contained in this letter. Enclosure 3 provides a revised LRA Appendix A - Final Safety Report Supplement Table A.3, License Renewal Commitment List, updated to reflect the, license renewal commitment changes made in NextEra Energy Seabrook correspondence to date.

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

Cliche, License Renewal Project Manager, at (603) 773-7003.

If you have any questions regarding this correspondence, please contact Mr. Michael O'Keefe, Licensing Manager, at (603) 773-7745.

Sincerely, NextEra Energy Seabrook, LLC.

Paul 0. Freeman Site Vice President

Enclosures:

- Response to Request for Additional Information Seabrook Station License Renewal Application, Set # 11 and Associated LRA Changes - Chemistry Control in the Seabrook Thermal Barrier Loop - LRA Appendix A - Final Safety. Report Supplement Table A.3, License Renewal Commitment List, updated to reflect the license renewal commitment changes made in NextEra Seabrook correspondence to date.

United States Nuclear Regulatory Commission SBK-L- 11062 / Page 3 cc:

W.M. Dean, NRC Region I Administrator G. E. Miller, NRC Project Manager, Project Directorate 1-2 W. J. Raymond, NRC Resident Inspector R. A. Plasse Jr., NRC Project Manager, License Renewal M. Wentzel, NRC Project Manager, License Renewal Mr. Christopher M. Pope 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 John Giarrusso, Jr., Nuclear Preparedness Manager The Commonwealth of Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399

SBK-L- 11062 Seabrook Station Response to Request for Additional Information NextEra Energy Seabrook License Renewal Application Request for Additional Information - Set 11 Hamrick, S. e-mail Ross, M. e- mail Fernandez, A. e-mail Mashhadi, M. e-mail Dryden, M. S. e-mail Brown, A. e-mail Cliche, R. e-mail Dunn, B. e-mail Carley, E. e-mail Collins, M. e-mail Metcalf, E. e-mail Noble, R e-mail Letter Distribution e-mail File 0018 GLC RMD ORM

United States Nuclear Regulatory Commission SBK-L-1 1062 / Page 4 N~x~era ENERjY7 SEA BROOK I, Paul 0. Freeman, Site Vice President of NextEra Energy Seabrook, LLC hereby affirm that the information and statements contained within are based on facts and circumstances which are true and accurate to the best of my knowledge and belief.

Sworn and Subscribed Before me this "tdayof .,2011 Paul 0. Freeman Site Vice President

Enclosure 1 to SBK-L-11062 Response to Request for Additional Information Seabrook Station License Renewal Application Set 11 and Associated LRA Changes

United States Nuclear Regulatory Commission Page 2 of 25 SBK-L- 11062 / Enclosure 1 Request for Additional Information (RAI) 3.2.2.2.6-02

Background:

By letter dated January 5, 2011, the staff issued request for additional information (RAI) 3.2.2.2.6-01 concerning aging management of stainless steel miniflow orifices in the chemical and volume control system. In its response dated February 3, 2011, NextEra Energy Seabrook, LLC (the applicant) modified its approach by proposing to credit only the Water Chemistry Program for aging management of the subject components. The applicant stated that the Water Chemistry Program is expected to mitigate the potential for erosion in the miniflow orifices by controlling the buildup of corrosion products and particulates that could contribute to erosion. The applicant also included a discussion of quarterly inservice testing required by its technical specifications and trending of the test data by a system engineer. Based on the information provided, the applicant changed Table 3.3.2-3, for the applicable orifice, to state that the Water Chemistry Program will be used to manage this aging effect, and the applicant added plant-specific note 8 with the comparable information.

Issue:

Standard Review Plan -License Renewal (SRP-LR) Section 3.2.2.2.6 states that loss of material due to erosion could occur in the stainless steel high pressure safety injection (HPSI) pump miniflow recirculation orifice exposed to treated borated water and recommends a plant-specific aging management program (AMP) be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI pump for normal charging. The staff noted that the stainless steel. miniflow orifices in the applicant's chemical and volume control system are functionally equivalent to, and in the same environment as the miniflow orifices described in SRP-LR Section 3.2.2.2.6; and they would be subject to the same aging effect.

SRP-LR, Appendix A, Section A.1.2.3.4, states that in a plant-specific AMP, the detection of aging effects should occur before there is a loss of intended function(s). The staff noted that the Water Chemistry Program does not include an inspection or testing activity to detect loss of material due to erosion in the stainless steel miniflow orifices in the chemical and volume control system. The staff also noted that the Generic Aging Lessons Learned (GALL) Report typically recommends using the One-Time Inspection Program to confirm effectiveness of the Water Chemistry Program to mitigate loss of material. Because the applicant has not credited any activity to confirm the Water Chemistry Program's effectiveness to mitigate erosion, the staff does not have sufficient information to conclude that the Water Chemistry Program will provide adequate aging management for the subject miniflow orifices.

Request:

Describe how the existing Water Chemistry Program is capable of detecting the loss of material due to erosion in the stainless steel miniflow orifices, or include in the AMP(s)

United States Nuclear Regulatory Commission Page 3 of 25 SBK-L-1 1062 / Enclosure 1 for these components an inspection or testing activity that is capable of detecting the loss of material due to erosion before the loss of the components' intended function occurs.

NextEra Energy Seabrook Response:

To confirm the Water Chemistry Program's effectiveness, Seabrook Station will Credit its Technical Specification performance monitoring program for the High Pressure Safety Injection Pump (CVCS Charging Pump) to detect loss of material due to erosion in the miniflow orifice. Seabrook Station Technical Specification 4.5.2.f (Emergency Core Cooling Systems - Surveillance Requirements) requires quarterly testing of the CVCS Charging Pumps. The pump is always tested in the same lineup where the flow path is only through the miniflow orifice. Pump flow and differential pressure are measured and recorded and compared to the acceptance criteria. If the acceptance criteria are not met (for flow or differential pressure) through the mini flow orifice, then the pump would be declared inoperable and the Technical Specification Limited Condition for Operation would be entered. Increased flow through the minimum recirculation flow line may be an indication of loss of material due to erosion of the miniflow orifice. If the miniflow orifice would experience erosion to the extent that the acceptance criteria for high flow is not met, then restoration of the pump to operable status would require appropriate corrective actions per the corrective action program.

Seabrook Station's approach is consistent with Branch Technical Position RLSB-1, Section A. 1.1, which states that performance monitoring is one of four acceptable aging management programs (the other three being prevention, mitigation, and condition monitoring programs).

Based on the above discussion, the following changes are made to the LRA.

1. Plant specific note 8 for Table 3.3.2-3, as submitted in response to RAI 3.2.2.2.6-01 (SBK-L-11015 (Reference 6) dated February 3, 2011, Enclosure 1, page 74 of 92) is revised as follows:

8 NUREG- 1801 specifies a plant-specific program for this line item. The Water Chemistry Program will be used to manage the aging effect(s) applicable to this component type, material, and environment combination. To confirm the Water Chemistry Program's effectiveness to mitigate erosion, Technical Specification performance monitoring program for the CVCS Charging Pump will be credited. Performance testing of the pump measures the recirculationflow through the orifice and compares it to the acceptance criteria.Degradationof the orifice will be identifiedby the pump performance testing.

2. Section 3.2.2.2.6, as submitted in response to 3.2.2.2.6-01 (SBK-L-11015 dated February 3, 201 1(Reference, 6), Enclosure 1, page 72 of 92), the following is added to the end of the 2nd paragraph as follows:

United States Nuclear Regulatory Commission Page 4 of 25 SBK-L- 11062 / Enclosure 1 "Seabrook will use Water Chemistry Program, B.2.1.2, to manage loss of material due to erosion of the stainless steel high pressure pump mini-flow orifice in the Chemical and Volume Control System. The Water Chemistry Program is described in Appendix B. To confirm the Water Chemistry Program's effectiveness, Seabrook Station will credit its Technical Specification performance monitoring programfor the High PressureSafety Injection Pump (CVCS ChargingPump) to detect loss of material due to erosion in the miniflow orifice. Seabrook Station Technical Specification 4.5.2.f (Emergency Core Cooling Systems - Surveillance Requirements) requires quarterly testing of the CVCS Charging Pumps. The pump is always tested in the same lineup where the flow path is only through the miniflow orifice. Pumpflow and differentialpressure are measured and recorded and compared to the acceptance criteria.If the acceptance criteriais not met (for flow or differentialpressure), then the pump would be declared inoperable and the Technical Specification Limited Conditionfor Operation would be entered.

Increased flow through the minimum recirculation flow line may be an indication of loss of materialdue to erosion of the piping components in the flow path including the orifice. Restoration of the pump to operable status would require appropriatecorrectiveactionsper the corrective actionprogram.

3. In Section A.3, the following commitment is added to the License Renewal Commitment List:

NO. PROGRAM COMMITMENT UFSAR SCHEDULE or TOPIC LOCATION 63 Flow Ensure that the quarterly CVCS N/A Priorto the Induced ChargingPump testing is continued period of Erosion during the PEO.Additionally, add a extended precaution to the test procedureto state operation that an increase in the CVCS Charging Pump miniflow above the acceptance criteriamay be indicative of erosion of the miniflow orifice as described in LER 50-275/94-023.

Request for Additional Information (RAI) B.2.1.12-8

Background:

The closed-cycle water chemistry guidelines in Electric Power Research Institute (EPRI) topical report (TR) TR-107396 state that higher. levels of hydrazine can increase ammonia levels. Elevated concentrations of ammonia can cause higher levels of corrosion or cracking of copper alloys. The EPRI guideline also states that higher sulfate levels. can lead to stress-corrosion cracking of stainless steel alloys. By letter dated January 13, 2011, the staff issued RAI B.2.1.12-1, in which the staff requested additional information on the effect of hydrazine and sulfate excursions in the thermal barrier

United States Nuclear Regulatory Commission Page 5 of 25 SBK-L- 11062 / Enclosure 1 system for aging during the period of extended operation. The response to RAI B.2.1.12-1 stated that the applicant evaluated the significance of allowing, operation of the thermal barrier system at the elevated hydrazine and sulfate levels, and determined it to be acceptable. The response also stated that routine monitoring during operation at the elevated ranges showed no indication of system or component degradation.

Issue:

The applicant did not provide details of its evaluation that determined the operation at the elevated levels of hydrazine and sulfate would not cause any accelerated aging that could affect components during the period of extended operation. In addition, the applicant did not describe the routine monitoring it had performed during operation at the elevated ranges that could be credited for showing that no system or component degradation had occurred.

Request:

Provide the technical information that describes why the elevated levels of hydrazine and sulfate will not have caused accelerated aging of the components in the thermal barrier system that could affect component functions during the period of extended operation. If it is determined that the elevated levels of hydrazine and sulfate may have caused some accelerated aging, provide information on the AMP that will be used to manage the accelerated aging.

NextEra Energy Seabrook Response:

In response to this RAI, a new evaluation was performed to determine if accelerated aging of the components would occur due to elevated hydrazine and sulfate levels in the thermal barrier (TB) system.. This new evaluation included review of the Seabrook Station Chemistry Study/Technical Information Document (CHSTID) "Evaluation of Sulfate Concentration in Thermal Barrier Closed Cooling Loop" dated December 2004, referenced in the Closed Cycle Cooling Water System AMP and in the response to RAI B.2.1.12-1 provided in SBK-L-1 1002, dated January 13, 2011 (Reference 4).

This new evaluation dated March 28, 2011 is included as Enclosure 2 to this letter. In summary, conclusions are as follows:

"There is no reason to expect that increased carbon steel. or stainless steel corrosion rates occurred from 1999 to 2009 when hydrazine and sulfate concentrations were elevated in the Seabrook TB system. The elevated hydrazine concentrations would be expected to lead to minimum oxygen concentrations in the bulk water and very low electrochemical potentials of the stainless steel surfaces resulting in a minimum tendency for stress corrosion cracking. Sulfate, in the concentration range that was observed, is not expected to be a significant accelerant of SCC of stainless steel at TB system temperatures particularly at the low electrochemical potential of the stainless steel materials at the high hydrazine to oxygen concentration ratio".

United States Nuclear Regulatory Commission Page 6 of 25 SBK-L- 11062 / Enclosure 1 Based on the conclusions of this evaluation, Seabrook Station maintains that the effects of the elevated hydrazine and sulfate levels are insignificant and will not have caused accelerated aging of the components in the thermal barrier system that could affect component functions during the period of extended operation.

As previously stated in response to RAI B.2.1.12-1, Seabrook Station had returned hydrazine and sulfate operating levels to within those recommended in the EPRI Guidelines in early 2010. The Seabrook Station Closed Cooling Water Chemistry Control program has also been revised to reflect those levels in the appropriate sampling schedule.

Request for Additional Information (RAI) 4.7.12-2

Background:

By letter dated January 5, 2011, the staff issued RAI 4.7.12-1 concerning license renewal application (LRA) Section 4.7.12, which discussed the absence of a time-limited aging analysis (TLAA) for metal corrosion allowances. In its response dated February 3, 2011, the applicant revised LRA Section 4.7.12 to include steam generator tube metal corrosion allowance as a TLAA and revised Tables 4.1-1 and 4.1-2 for the disposition method and applicability of the TLAA. However, LRA Section 4.7.12 now states that the TLAA disposition for this issue is in accordance with 10 CFR 54.21 (c)(1 )(iii), whereas the revision to Table4.1-1 states that the TLAA disposition is in accordance with 10 CFR 54.21 (c)(1)(i). In addition, the staff noted that the final safety analysis report (FSAR) supplement in LRA Section A.2.4.5, "Other Plant-Specific TLAAs," had not been revised as a result of this new determination.

Issue:

SRP-LR Section 4.7.3.1.1, "10 CFR 54.21 (c)(1)(i)," states that the justification provided by the applicant is reviewed to verify that the existing analyses are valid., for the period of extended operation. In contrast, SRP-LR Section 4.7.3.1.3, "10 CFR 54.21(c)(1)(iii)," states that the, applicant's proposal to manage the aging effects associated with the TLAA by an AMP is reviewed to verify that the effects of aging will be adequately managed. The staff is unclear which method was used by the applicant. In addition, 10 CFR 54.21(d) states that the FSAR supplement must contain a summary description of the evaluation of TLAAs for the period of extended operation as part of the LRA.

Request:

a) Clarify which method was used to disposition the TLAA associated with the steam generator tube metal corrosion allowance.

United States Nuclear Regulatory Commission Page 7 of 25 SBK-L-1 1062 / Enclosure 1 b) Provide a revised FSAR supplement for the evaluation of the TLAA associated with the steam generator tube metal corrosion allowance, in accordance with 10 CFR 54.21 (d).

NextEra Energy Seabrook Response:

a) In response letter, SBK-L- 11015 (Reference 6); NextEra incorrectly listed the disposition as Aging Management, 10 CFR 54.21(c)(1)(iii). The correct disposition is Validation, 10 CFR 54.2 1(c)(1)(i) as the analyses remains valid for the period of extended operation.

1. In LRA Section 4.7.12, page 4.7-13, the disposition previously provided in SBK-L 11015 (Reference 6) should be revised as follows:

Aging Maenagemen.t, 10 GF*R 5.21 (e)( 1)(iii) The effects eof aging o theintended+,n-tie(s)will be adequately managed for the per,-id of extended oper-ation by the Steam Generater Tube Integr-ity Progra m (B.2. 1.10), whifc m.anages the aging effects of lass of material due to wall thining from f...

accelerated corrosion of the Steam Gener-ator eomponents.

Disposition Validation, 10 CFR 54.21(c)(1)(i) - The analyses remain validfor the period of extended operation.

b) The following UFSAR supplement is provided regarding the TLAA associated with the steam generator tube metal corrosion allowance.

1. In LRA Appendix A, a new section A.2.4.5.11 is provided as follows:

A.2.4.5.11 METAL CORROSIONALLOWANCES AND CORROSION EFFECTS The Seabrook Station licensing basis assumes a general corrosion and erosion rate of 3 mils is for the steam generator tube wall. The corrosion rate is based on a conservative weight loss rate of Inconel tubing in flowing 650'Fprimary side reactor coolantfluid. The weight loss, when equated to a thinning rate andprojectedover a 40-year design operatingobjective, with appropriate reduction after initial hours, is equivalent to 0.083 mils thinning. A linear projection of this thinning rate to a 60-year period is equivalent to 0.1245 mils thinning. This linear projection to 60 years is considered to be conservative because it includes in the base rate the higher rate during the initial hours. The assumed corrosion rate of 3 mils leaves a conservative 2.8 755 mils for general corrosion thinning on the secondary side.

The analyses will remain validfor the period of extended operation in accordancewith 10 CFR 54.21 (c) (1) (i).

United States Nuclear Regulatory Commission Page 8 of 25 SBK-L- 11062 / Enclosure 1 Request for Additional Information (RAI) 3.4.1-37-21

Background:

By letter dated January 5, 2011, the staff issued RAI 3.4.1-37-1. This RAI requested

,information as follows: a) propose to manage aging of these components using water chemistry and an appropriate verification AMP as indicated by the GALL Report for the management of aging in a secondary feedwater/steam environment or justify why the use of a verification AMP is either inconsistent with the GALL Report or technically unnecessary; b) justify why is it unnecessary to consider both the aging effects "loss of material" and "cracking" for each of the components under consideration; c) classify the steam generator feedwater inlet ring (J tube) and the steam generator tubes as steam generator components (making the appropriate verification AMP the Steam Generator Tube Integrity Program) or justify why these components should be considered piping, piping components, or piping elements as proposed by item 3.4.1-37. The applicant responded to this RAI by letter dated February 3, 2011. With one potential exception, the staff found these responses acceptable.

Issue:

In its response to the previous RAI, the applicant reclassified the steam generator feedwater nozzle (thermal sleeve) and the orifice from being consistent with SRP-LR Table 3.4.1-34 (generic note A) to being inconsistent with the GALL Report (generic note H). The applicant also proposed to manage the aging of these components through the use of its Water Chemistry Program. Based on its review, it appears to the staff that the components, materials, environments, and aging effects under consideration are described by SRP-LR Table 3.4-1 ID 84. The staff notes that SRP-LR Table 3.4-1 ID 84, recommends that aging be managed through the use of GALL Report AMP XI.M2, Water Chemistry and either AMP XI.M32, One-Time Inspection, or AMP XI.M1, ASME Section XI, Inservice Inspection.

The staff notes that, in its response to the previous RAI, the applicant stated that these components were not available for inspection. The staff also notes that these components have been addressed in many recent license renewal Safety Evaluation Reports (SERs).

While there have been differences in the approaches to the management of aging of these components from plant to plant, in each case the SER indicates that the accepted method of aging management involves the use of an AMP to manage water chemistry and an AMP to perform at least a one-time inspection to verify the efficacy of the water chemistry program.. This indicates to the staff that water chemistry and inspection programs are necessary for adequate aging management and that these components are generally inspectable.

United States Nuclear Regulatory Commission Page 9 of 25 SBK-L-1 1062 / Enclosure 1 Request:

Please: a) demonstrate why the aging management guidance provided by SRP-LR Table 3.4-1 ID 84 need not be followed; or b} demonstrate why the components under consideration are not inspectable; or c) propose to manage aging of these components in a manner consistent with or equivalent to SRP-LR Table 3.4-1 ID 84.

NextEra Energy Seabrook Response:

a) The aging management guidance provided in NUREG-1800, Table 3.1-1, ID 84, refers to R-36, which is associated with NUREG-1801 line item IV.D2-9. This line item is associated with once-through type steam generators as found in Babcock &

Wilcox pressurized water reactors as described in NUREG-1801, Chapter IV.D2.

Seabrook Station has recirculating-type steam generators as found in Westinghouse pressurized water reactors. Therefore, Chapter IV.D 1 of NUREG- 1801 was utilized instead of Chapter IV.D2.

In Chapter IV.D1 of NUREG-1801 [Steam Generators (Recirculating)], nickel alloy steam generator components such as the secondary side nozzles, vent, drain, and instrumentation lines are not identified as being susceptible to cracking-due to stress corrosion cracking in secondary feedwater/steam environment and therefore, has no corresponding line item in Chapter IV.D 1. Hence, the reason why generic note H was utilized instead of generic note A.

b) Inspectability of the Steam Generator Steam Flow Restricting Orifice and Feedwater Nozzle (Thermal Sleeve)

Inspectability of the Steam Generator Steam Flow Restricting Orifice Seabrook USFAR, Section 5.4.4 describes the steam generator steam flow restricting orifice as follows:

"The flow restrictor consists of seven Inconel (ASME SB-163) venturi inserts which are inserted into the holes in an integral steam outlet nozzle forging. The inserts are arranged with one venturi at the centerline of the outlet nozzle and the other six equally spaced around it. After insertion into the nozzle forging holes, the Inconel venturi inserts are welded to the Inconel cladding on the inner surface of the forgings.

The flow restrictor design has been sufficiently analyzed to assure its structural adequacy. The equivalent throat diameter of the steam generator outlet is 16 inches, and the resultant pressure drop through the restrictor at 100 percent steam6 flow is approximately 3.28 psi. This is based on a design flow rate of 4.135x10 lb/hr. Materials of construction and manufacturing of the flow restrictor are in accordance with Section III of the ASME Code.

United States Nuclear Regulatory Commission Page 10 of 25 SBK-L- 11062 / Enclosure 1 Since the restrictor is not a part of the steam system boundary, no tests and inspection beyond those during fabrication are anticipated."

The steam generator steam flow restricting orifices, are located above the steam generator upper deck plates and do not have manways or an access points to allow for the inspection of the orifices. Therefore, the steam flow restricting orifice is not accessible for visual inspections (direct visual or remote visual) without a plant modification.

Inspectability of the Steam Generator Feedwater Nozzle (Thermal Sleeve)

The Steam Generator Feedwater Nozzle (Thermal Sleeve) is an integral part of the steam generator feedwater ring and is not accessible for direct visual inspections.

However, upon further discussion with the Seabrook Station Steam Generator Tube Integrity Program owner, a remote visual inspection of the feedwater nozzle (thermal sleeve) is feasible by means of entering the feedwater ring via the feedwater ring J tube opening.

c) Aging Management of the Steam Generator Steam Flow Restricting Orifice and Feedwater Nozzle (Thermal Sleeve)

Aging Management of the Steam Generator Steam Flow Restricting Orifice Plant or industry operating experience has not identified any aging effects associated with the steam generator steam flow restricting orifices. Additionally, EPRI Steam Generator Integrity Assessment Guidelines (EPRI 1012987 Rev. 2) has not identified the steam generator steam flow restricting orifices as one of the components requiring inspection. Therefore, verification of the Water Chemistry Program is not needed to provide reasonable assurance that the steam generator steam flow restricting orifice will perform such that the intended functions are maintained consistent with the current licensing basis during the period of extended operation.

Aging Management of the Feedwater Nozzle (Thermal Sleeve)

Although there is currently no plant/industry operating experience and no EPRI requirement or recommendation that warrants inspection of the steam generator feedwater nozzles (thermal sleeves), Seabrook Station will include inspection of the feedwater nozzles (thermalt sleeves) under the Steam - Generator Tube Integrity Program to verify the effectiveness of the Water Chemistry program.

United States Nuclear Regulatory Commission Page 11 of 25 SBK-L-1 1062 / Enclosure 1 Based on the above discussion, the following changes are made to the LRA.

1. Item 8, on page 83 of 92 of Enclosure 1, as submitted in SBK-L-1 1015 dated February 3, 2011 (Reference 6), is revised as follows:

Steam Water Chemistry Generator Program Feedwater Pressure Nickel Secondary H,4-0 Nozzle Boundary Alloy Feedwater/Steam Cracking Steam None None (Thermal (External) GeneratorTube Sleeve) Integrity Program Steam Water Chemistry Generator Pressure Program Feedwater Nickel Secondary'H--

Nee Bounry All Feedwater/Steam Cracking Steam None None 9 Nozzle Boundary Alloy (Internal) GeneratorTube (ThermalIn Sleeve) e rt Integrity Sleeve)_

Program

2. Item 9, on page 84 of 92 of Enclosure 1, as submitted in SBK-L-11015 dated February 3, 2011 (Reference 6), is revised as follows:

Steam Water Chemistry Generator Program Generator Pressure Nickel Secondary Loss of 1,44 Feedwater Pressure Nickel Feedwater/Steam Materia Steam None None 8 Nozzle Boundary Alloy (External) Material Generator Tube8 (Thermal Sleeve) Inerity Integrity Sleeve) _Program Steam Water Chemistry Generator Secondary, Program Feedwater Pressure Nickel Feedwater/Steam Material Steam None None 8,4 Nozzle Boundary Alloy (Internal) Material Generator Tube8 (Thermal Inerity Sleeve) ________ _______

_____ ____________________Program Integrity _____ ___

Request for Additional Information (RAI) B.2.1.22-1

Background:

The applicant's response to RAI B.2.1.22-1, by letter dated January 13, 2011, was not sufficient to resolve all of the staffs questions.

Issue:

a) Although the applicant will be sampling for several different factors (e.g., soil resistivity, water samples) it is not clear to the staff that the stated parameters are sufficient, nor how the results will be combined to determine the level of soil

United States Nuclear Regulatory Commission Page 12 of 25 SBK-L- 11062 / Enclosure I corrosivity such as can be determined by using American Water Works Association C I05/A2.15-10 Table A. 1.

b) The applicant's program only increases the number of planned inspections based on the quality of backfill in the vicinity of the buried pipe. Given that portions of buried in-scope steel piping are not provided with cathodic protection, the staff believes that the number of inspections of this piping should also be informed by localized soil conditions.

c) Given that localized soil conditions can vary, the applicant's response was not clear enough for the staff to conclude that soil samples will be obtained in the vicinity of each buried in-scope steel piping system (excluding fire protection) that is not provided cathodic protection.

d) It is not clear to the staff how often soil samples will be obtained during the period of extended operation.

Request:

a) State what soil parameters will be utilized and how their aggregate impact will be evaluated to determine localized soil corrosivity.

b) State whether localized soil conditions will be utilized to increase the number of inspections or state how there will be reasonable assurance that the piping system's current licensing basis function(s) will be maintained without increasing the number of samples in the absence of localized soil data or with results that indicate that the soil is corrosive.

c) State if soil samples will be obtained in the local vicinity of all buried in-scope steel piping systems (excluding fire protection) that are not provided with cathodic protection.

d) State how often soil sampling will be conducted during the period of extended operation, or if soil samples will not be collected during the period of extended operation, state how it is known that localized soil conditions will not vary with time.

NextEra Eneruv Seabrook Response:

a) To provide additional assurance that the piping will remain capable of performing its intended function, soil will be sampled prior to the period of extended operation (PEO) to confirm that the soil conditions are not corrosive. The number of inspections performed during the PEO will be based on the results of this soil survey. The parameters monitored will be utilized to obtain a comparative corrosion index (corrosivity) for the non-cathodically protected steel piping within the systems monitored. Corrosivity will be determined using established

United States Nuclear Regulatory Commission Page 13 of 25 SBK-L- 11062 / Enclosure 1 soil analysis methodology such as EPRI Report 1021470, "Balance of Plant Corrosion - The Buried Pipe Reference Guide", Chapter 8, "Soil Analysis." The EPRI report arrivesat a corrosion index using combined values for soil resistivity, pH, redox potential, sulfides, and moisture in accordance with American Water Works Association standard C105, and considers the soil to be corrosive if the combined value is greater than 10. Table 8-1 of the EPRI report is titled "AWWA C 105 soil corrosivity index" and mirrors the parameters, values and points shown in the AWWA standard.

b) As described in item a. above, soil will be sampled prior to the period of extended operation (PEO) to confirm that the soil conditions are not corrosive. The number of inspections during the PEO will be based on the results of this soil survey. If soil analysis indicates that the soil is corrosive, the number of inspections for non-cathodically protected steel pipe shall be increased from 4 to 6 for non-HAZMAT piping and from 5% to 71/2% for HAZMAT piping during the PEO.

c) Soil samples will be taken at a minimum of two locations in the vicinity of in-scope, non-cathodically protected steel piping to obtain representative soil conditions for each system, excluding fire protection.

d) Soil will be sampled prior to the PEO to confirm that the soil conditions are not corrosive. If the initial survey shows the soil to be non-corrosive, additional soil samples will be taken at least once every 10 years thereafter, during the PEO, to confirm the initial sample results.

Based on the above discussion, the LRA is revised to incorporate soil sampling and analyses as a preventive action and a factor in determining the scope of buried pipe inspections during the PEO as follows:

1. Section A.2.1.22, as submitted in SBK-L-10179 Supplement 1 dated October 29, 2010 (Reference 3), in Enclosure 1, on page 3 of 18, thelst paragraph of program description is revised as follows:

"The Buried Piping and Tanks Inspection Program manages loss of material from the external surfaces of buried, underground, and inaccessible submerged steel, stainless steel, and polymer piping and components. The plant has no buried tanks in scope for license -renewal. Depending on the material, the program includes external coatings, cathodic protection, analyses for soil corrosivity, and quality of backfill as preventive measures to mitigate corrosion."

United States Nuclear Regulatory Commission Page 14 of 25 SBK-L- 11062 / Enclosure 1

2. In Section A.3, the following commitment is added to the License Renewal Commitment List:

NO. PROGRAM COMMITMENT UFSAR SCHEDULE or TOPIC LOCATION Buried Soil analysis shall be performedprior A.2.1.22 Priorto Pipingand to entering the period of extended entering the 64 Tanks operationto determine the corrosivity period of Inspection of the soil in the vicinity of non- extended cathodicallyprotectedsteel pipe within operation.

the scope of this program. If the initial analysisshows the soil to be non-corrosive,this analysis will be re-performed every ten years thereafter.

3. In Section B.2.1.22, as submitted in Supplement 1, dated October 29, 2010 (SBK-L-10179), in Enclosure 1, on page 4 of 18, the 2' paragraph of Program Description is revised as follows:

The Seabrook Station program will include coating, cathodic protection and backfill quality as preventive measures to mitigate corrosion, and periodic inspections that manage the aging effects of corrosion on buried piping in the scope for license renewal. Soil analyses will be performed to determine the corrosivity of the soil near non-cathodically protected steel pipe. The corrosivity of the soil will be used as a factor in determining the number of locations or percentage of piping to be inspected for non-cathodically protectedsteel piping.

4. In Section B.2. 1.22, as submitted in License Renewal Application Supplement 1, dated October 29, 2010 (SBK-L-10179), in Enclosure 1, Element 4 - Detection of Aging Effects, on page 11 of 18, the following paragraph is added after the Ist full paragraph as follows:

Soil samples will be taken prior to entering the period of extended operation (PEO)to confirm that the soil conditions are not corrosive. The corrosivity of the soil will be'used as a factor in determining the number of locations or percentage of piping to be inspected for non-cathodically protected steel piping.. If the initial survey shows the soil to be non-corrosive, additional soil samples will be taken at least once every 10 years during the PEO to confirm the initialsample results. Soil samples will be taken at a minimum of two locations in the vicinity of in-scope, non-cathodically protected steel piping to obtain representativesoil conditionsfor each system (exceptfor Fire

'Protection if the integrity of that system is monitored by jockey pump performance). The parameters monitored will be utilized to obtain a comparative corrosion index (corrosivity)for the piping within the systems monitored. Corrosivity will be determined using established soil analysis

United States Nuclear Regulatory Commission Page 15 of 25 SBK-L-1 1062 / Enclosure 1 methodology such as EPRI Report 1021470, "Balance of Plant Corrosion -

The Buried Pipe Reference Guide", Chapter 8, "Soil Analysis." The EPRI report arrives at a corrosion index using combined values for soil resistivity, pH, redox potential, sulfides, and moisture in accordance with American Water Works Association standard C105, and considers the soil to be corrosive if the combined value is greaterthan 10.

5. In Section B.2.1.22, as submitted in License Renewal Application Supplement 1, dated October 29, 2010 (SBK-L-10179), in Enclosure 1, Element 4 - Detection of Aging Effects, on page 12 of 18, the Buried Piping Inspections Locations table is revised as follows:

2 Cathodically Applied Inspections per 10-Year Period' ,

Material Type Protected Coatings Adequate Backfill 4 Inadequate Backfill 4 CBA, IA, 'No Yes Yes 1 4 FP, SW AB5 Yes No Yes Non-corrosivesoil 5% 10%

6 Steel Corrosivesoil 7Y2 %

CBA, CO, Non-corrosivesoil 4 DG, FW, No No Yes Corrosivesoil 6,7 6 8 DF, FP Polymer FP No No No 1 2 Stainless DG Yes Yes Yes Steel CO No No Yes GENERAL NOTES:

1. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet.

2. If the length of pipe to be inspected based on the number of inspections times the minimum inspection length (10 feet) exceeds 10% of the length of the piping under consideration, only 10% need be inspected.

3. If the length of pipe to be inspected based on the total length of pipe under consideration times percentage to be inspected is less than 10 feet, either 10 feet or the total length of pipe present, whichever is less, will be inspected.

4. The effectiveness of backfill materials and processes will be determined by the condition of coatings and base materials noted during inspections. If damage to the coatings or base materials are determined to have been caused by the backfill, the backfill will be considered to be "inadequate" (for the purpose of this program).

5. This line is not is use. It has been drained and flushed and is awaiting replacement per EC 12681. The inspection criteria for the replacement piping will be determined based material selection, coating, cathodic protection, and quality of backfill.

6. Soil corrosivityis determined by soil analysisusing a demonstratedmethodology such as EPRI report 1021470, Table 8-1. A value greaterthan 10 using this method is considered corrosive. The number of inspectionsfor non-cathodicallyprotectedsteel piping in corrosive soil apply only to the inspectionsperformed during the period of extended operation.

7. If monitoring ofjockey pump activity is creditedfor verification offire protectionpiping integrity, soil samples in the vicinity of thefire protectionpiping is not required.

United States Nuclear Regulatory Commission Page 16 of 25 SBK-L- 11062 / Enclosure 1

6. In Section B.2.1.22, as submitted in License Renewal Application Supplement 1, dated October 29, 2010 (SBK-L-10179), on Enclosure 1, on page 13 of 18, the following paragraph is added after the 2 nd paragraph of Element 5 - Monitoring And Trending:

For in-scope steel piping not protected by cathodic protection, where initial surveys have shown the soil to be non-corrosive, soil analyses will be performed at least once every 10 years to confirm whether or not the soil in the area of this piping is corrosive. Soil corrosivity is used as one factor in determining the number of locations or percentage of piping to .be inspected during the period of extended operation.

7. In Section B.2.1.22, as submitted in License Renewal Application Supplement 1, dated October 29, 2010 (SBK-L-10179), in Enclosure 1, on page 14 of 18, the following paragraph is added following the 4 th paragraph of Element 6 - Acceptance Criteria:

Soil corrosivity is determined by soil analysis. If the calculated corrosion index value is greater than 10 points (i.e., corrosive soil) the inspection locationsfor non-cathodicallyprotected steel piping are increasedas shown in Element4 - Detection of Aging Effects.

Request for Additional Information (RAI) B.2.1.22-3

Background:

The applicant's response to RAI B.2.1.22-3, by letter dated January 13, 2011, was not sufficient to resolve all of the staffs questions.

Issue:

The applicant stated that it utilized a Keeler and Long 1000 Kolormastic system and Tapecoat 20 primer and wrap when installing flanges to allow access to the underground service water piping that is exposed to raw water. The applicant also stated that the painting system chosen for the piping is designed to protect the pipe from long term external corrosion when exposed to continuous immersion in brackish stagnant water.

The staff does not have sufficient information related to this coating to independently determine that it will provide protection to the piping when exposed to long term immersion.

Request:

Provide copies of the vendor technical data that demonstrated that the coating system was acceptable for long term immersion in a brackish water environment. Alternatively, if the vendor information is proprietary, provide a copy of the applicable portions of the engineering evaluation of the coating system.

United States Nuclear Regulatory Commission Page 17 of 25 SBK-L- 11062 / Enclosure 1 NextEra Energy Seabrook Response:

In SBK-L-11003 dated January 13, 2011(Reference 5), response to RAI B.2.1.22-3 Seabrook Station made reference to three different types of pipe coatings inside the Service Water Inspection Vault without adequate explanation of these products. An explanation of the types of coating products installed on the piping in the vault and a description of the physical piping and coating configuration -is provided below.

Coating Systems Utilized in the Service Water Inspection Vault Existing Coal-tar CoatingSystem This is the original vendor applied coal tar coating that was applied to the buried steel and stainless steel piping. This original vendor applied coal tar coating was fabricated and applied in accordance with the requirements of American Water Works Association (AWWA) Standard 'C203. This standard also meets the requirements of NACE SP0169-2007, "Standard Practice, Control of External Corrosion on Underground or Submerged Metallic Piping Systems", Table 1.

Tapecoat 20 Tapecoat 20 is a field applied coating system (i.e. for making repairs to the original vendor applied coal tar coating or coating the pipe at field welded joints). Tapecoat 20 is a 58 mil thick, hot applied coal tar coating (in tape form) that meets the original Seabrook Station pipe coating specification as well as the requirements of AWWAC203. See attached Tapecoat Company product sheet.

Keeler and Long 1000 Kolormastic Keeler and Long 1000 Kolormastic is an epoxy based painting system. It utilizes a high solids combination of aluminum and stainless steel pigments dispersed in a two component polyamine epoxy to produce a coating that is chemically resistant. The dry film thickness of one coat of Keeler and Long 1000 Kolormastic is approximately 5-8 mils. See attached KL1000 product sheet.

Physical description of the vault piping and coating configuration To provide access to the service water piping for periodic visual internal inspections, a portion of the underground piping was replaced with a removable spool piece. The modification to create the removable spool piece included excavating the pipe, pouring a concrete vault for future access to the spool pieces, cutting the pipe and installing flanges to the existing pipe and the new spool pieces.

United States Nuclear Regulatory Commission Page 18 of 25 SBK-L- 11062 / Enclosure 1 The remaining original piping in the vault is coated with the original coal tar epoxy.

The installation of Tapecoat 20 was limited to the restoration of the original vendor applied coal tar coating on the existing pipe ends to which the mating sides of the drop-out spool flanges were welded.

The coating of the drop-out spools, including the flanges, consists of two coats of Keeler and Long 1000 Kolormastic epoxy-based paint with no additional over coating or wrapping. As stated above, the dry film thickness of each coat of Keeler and Long 1000 Kolormastic is approximately 5-8 mils.

Vendor Technical Data/Engineering Evaluation Technical data from the vendor demonstrating that the Keeler and Long 1000 Kolormastic coating system is acceptable for long term immersion is not readily available. As stated in response to RAI B.2.1.22-3, the engineering change document that installed the drop-out spool pieces in the vaults stated that the painting system chosen for the service water piping within the vault was designed to protect the pipe from long term external corrosion based on continuous immersion in brackish, stagnant water. However, no separate engineering evaluation was performed for the specific products utilized for this application.

Method of Inspection/Acceptance Criteria Seabrook Station has determined that periodic inspection of the vault piping is the best approach for managing the aging for these components.

Because the coating on the pipe spools consists only of two layers of paint, visual inspection of the pipe spools in the Service Water Inspection Vault, as prescribed by the Seabrook Station Buried Piping and Tanks Inspection Program (two inspections every ten years) will provide adequate indication of loss of material due to corrosion.

Loss of coating integrity due to blistering, cracking, flaking, peeling, rusting, or physical damage would be readily apparent.

The coating applied to the flange-to-pipe weld and exposed piping outside of the spool piece (Tapecoat 20) meets the original pipe coating specification and AWWA Standard C203. This coating is a hot applied coal tar coating completely saturated into and bonded to both sides of a high tensile strength fabric. In addition, it has a polyester film adhering to the coating which facilitates unwinding of the roll and acts as an outer wrap. As described in the response to RAI B.2.1.22-3, water absorption of coal-tar enamels is extremely low making this the optimum choice of coatings.

This portion of the piping in the Service Water vault will be visually inspected for damage or degradation of the coating.

Per the Seabrook Station Buried Piping and Tanks Inspection program, coated piping will be inspected and evaluated by an individual possessing a NACE operator

United States Nuclear Regulatory Commission Page 19 of 25 SBK-L-11062 / Enclosure 1 qualification or by an individual otherwise meeting the qualifications to evaluate coatings, as contained in 49 CFR 192 and 195. Any coating and wrapping degradation will be documented and evaluated under the corrective action program.

Plant Specific Operating Experience Installation of the Service Water Inspection Vault drop-out spools was performed in 1995. Since that time, this vault has been accessed several times to remove one or more of the pipe spools for internal inspection of the Service Water buried piping.

There has been no documented degradation to the paint on the pipe spools or the coal tar epoxy coating on the original pipe ends noted during these inspections.

Based on the above discussion, in Section B.2.1.22, as submitted in License Renewal Supplement 1 dated October 29, 2010 (SBK-L-10179), on Enclosure 1, page 13, the 1st paragraph of Element 6 - Acceptance Criteria is revised as follows:

For coated piping, there should be either no evidence of coating degradation or the type and extent of coating degradation should be insignificant as evaluated by an individual possessing a NACE operator qualification or'by an individual otherwise meeting the qualifications to evaluate coatings as contained in 49 CFR 192 and 195. Any coating and wrapping degradation will be documented and evaluated under the corrective action program. Where the protective coating consists of paint with no other coating or wrapping (e.g., drop-out spools in the Service Water Inspection Vault), inspection of the painted surface should confirm no evidence of coating degradation(exposed metal) or degradation of the pipe surface due to corrosion.

United States Nuclear Regulatory Commission Page 20 of 25 SBK-L- 11062 / Enclosure 1 Tapecoat 20 Corrosion Protection Features/Specifications/Application Composition:

Tapecoat 20 consists of a specially formulated pliable coal tar coating completely saturated intoand bonded to both sides of a high tensile strength fabric. In addition it has a polyester film adhering to the coating which facilitates unwinding of the roll and acts as an outerwrap, providing additional mechanical strength against backfill and.soil stress.

Technical Data:

Softening Point: 170°F +1- 5-F (77o-C-3`C)

Penetration at 77°F: (25,,C):11.81-31.49 mils.(3-.8 mm)

Thickness: 58 mils. 4- 2 (1,47. +/- .05 mm)

ASTM G-8 C.D.: Excellent Oil & Hydrocarbon Resistance: Excellent Meets Federal Spec HHT 30a Meets AWWA Standard C203 Compatible with coal tar, asphalt, polyethylene, polypropylene, FBE andother factory coatings.

Tests. Used: ASTM E-28; ASTM D-5,; ASTM G-8; ASTM G-20. Tests are conducted accord-ing to the latest revisions.

Application Equipment: A torch with wide mouth burner is recommended.

Surface Preparation: Surface must be clean anddry. Wire brush to remove any loose rustand scale, dust or dirt. Oil, grease and all other residue are to be removed from pipe surface. Use torch to warm the surface and remove moisture prior to priming.

Primer Application: TC Omni-phi.me is the compatible'primer for use with Tapecoat 20. Apply primer to the prepared surface by brush or roller at the rate of approximately 2:50 square feet per gallon(7.37 m2/liter), TC Omniprime should be applied 4" beyond the area to be wrapped with tape. Let primer dry before applying Tapecoat 20. TC Omniprime can also be.used on stainless steel.

Tape Application: There are two recommended methods for applying Tapecoat 201to a prop-erly prepared and primed surface.

• Spiral Wrap: Flash flame of torch onto the side of the coating without the polyester film (outside of rbll) until a smooth and glossy finishis Obtained. Apply properly heated coating with-tension to the surface ofthe pipe.. Alternately heat and spiral wrap in a single thickness with a continuous 1/4" to 1" overlap (6.35 to 25.4 mii) of tape.

Cigarette Wrap: Precut strips of Tapecoat 20 to a lenigth equal to the'cirCumference of the pipe plus a minimum of 3" for overlap. Follow general tape application. instructions described above.

P0 Box 631, Evanston, IL 60204-0631

• 152.7 LyLonsSt. Evanston, IL 60201-3551 USA 800/758-6041 847/866-8500 Fax: 800/332-8273, Fax: 84-7/866:8596 www.tapecpat.com

United States Nuclear Regulatory Commission Page 21 of 25 SBK-L- 11062 / Enclosure 1 KOLORMASTIC No. 1000 SERIES GENERIC TYPE: POLYAMINE EPOXY WITH METALLIC PIGMENTS PRODUCT A high solids combination of aluminum and stainless steel DESCRIPTION: pigments dispersed in a two component polyamine epoxy to produce a coating that is chemically resistant to splash or spillage of alkalies, acids, fresh and salt water, and most solvents.

RECOMMENDED USES: May be used to touch up inorganic or organic zinc rich primed surfaces which have been hand or power tool cleaned only.

May be used for the painting or repainting of most steel surfaces, such as structural steel, tanks, bridges and piping.

NOT RECOMMENDED Immersion service in strong acids or alkalies.

FOR:

.COMPATIBLE Kolor-Poxy Hi-Build Enamels TOPCOATS: Kolor-Poxy Enamels Anodic Self-Priming Paints Kolorane Enamels Poly-Silicone Enamels Acrythane Enamels Acite Hi-Build Enamels PRODUCT Solids by Volume: 87% 0 3%

CHARACTERISTICS: Solids by Weight: 92% +/- 3%

Recommended, Dry Film Thickness: 5.0 - 8.0 mils Theoretical Coverage: 279 Sq. Ft./Gallon @ 5.0 mils DFT Finish: Metallic Luster, Satin Finish Available Colors: Aluminum and'Limited Colors Drying Time @ 72°F To Touch: 4 Hours To Handle: 8 Hours To Recoat: 24 Hours VOC Content: 0.8 Pounds/Gallon 99 Grams/Liter May, 1992 11198RIM TECHNICAL BULLETIN -

United States Nuclear Regulatory Commission Page 22 of 25 SBK-L-I 1062 / Enclosure I No. 1000 SERIES E.100 rc "CHNIC) L D)

PHYSICAL DATA: Weight per gallon: 10.6 -0.5 (pounds)

Flash Point (Pensky-Martens): >100° F Shelf Life: 2 Years Pot Life @72° F: 2 Hours Temperature Resistance: 200*F Viscosity 9 770 F: SemikPaste Gloss (60 meter): 25+ 5 Storage Temperature: 50 - 85 F Mixing Ratio (Approx. by Volume): 3:1 APPLICATION DATA: Application Procedure Guide: APG,8 Wet Film Thickness Range: 5.7 - 9.2 mils Dry Film Thickness Range:: 5.0 - 8.0 mils Temperature Range: 50- 950 F (see APG-8)

Relative Humidity* 80% Maximum Substrate Temperature: Dew Point + 5 0 F Minimum Surface Preýparation: SSPC-SP2,SP3,SP6,SP7 Induction.Time @ 72 F: None Recommended Solvent

@ 50 - 85OF: No. 3700

@ 86 - 95 F: No. 2200 Application Methods Air Spray Tip Size: .073' - .086" Pressure: 30 - 60 PSIG Thin: 1.0 Qt/Gal (Maximum)

Airless Spray Tip Size: .021"- .031" Pressure: 2500 - 4000 PSIG Thin: 1.0 Qt/Gal (Maximum)

Brush or Roller

. Thin: 1.0 Qt/Gal (Maximum)

P. 0. Box 460, 856 Echo Lake Road Watertown, CT 06795 Tel: (203) 274-6701 Fax: (203) 274-5857 This.Information is presented as accurate end coirect, In good faith, to assist the .user In specification and applicatlon. No warranty Isexpressed or Imptlied. No liability Isassumed. MEMBER SUTMItRtaN Product specifications are subject to change without notice.

United States Nuclear Regulatory Commission Page 23 -of25 SBK-L-1 1062 / Enclosure I EslO

( U~ Keeler & Long/PPG KolormasticTM I856

! Echo Lake Road Watertown, CT 06795 KLIOOO/KLIOOOB PPG High Performance Coatings 1-800-238-8596 Aluminum nf ftnati n Product Code: KL1000 Aluminum Part A. Substrate: Steel KLI000B Curing Agent Part B Substrate The service life of the coating is directly Product: Epoxy-Polyamine Preparation: related to the surface preparation.

Suggested A primerifinish recommended for the paint Remove all loose paint, mill scale and Use: or repaint of most steel surfaces such as rust. The surface to be coated must be structural steel, tanks, bridges and piping. dimensionally stable, dry, clean and free of contamination.

Not Immersion service in strong acids or Recommended alkalies. Steel* Non-Immersion: SSPC-SP2/3 Hand/Power Tool Cleaning minimum.

. I- Immersion: SSPC-SPIO (NACE No. 2)

Color. Aluminum Near White Metal Blast Cleaning minimum.

Gloss 6ff: 20-40 typically Topcoats: Kolor-PoxyTM HI-Build Enamels, Kolor-Weight/Gallon: 10.3 +/- 0.5 ibs./gal. (mixed) PoxyTk Enamels, Acrythane Tm Enamels, In Service Heat KoloraneTM Enamels, Poly-SilTm Enamels Limitations: .2000F (93*C) maximum, dry heat and Anodic Self-Priming Paints F)ash Point: Part A 130OF (54.40C) Application Air Spray: DeVitbiss MBC gun, 704 or 765 Part B 200F .(93.3°C) Method: air cap with "E" or "EX" tip and needle or equivalent equipment. Atomization Package: KL1000 Is filled in five gallon pails at 3.0 Pressure: 30-60 psi.

gallons (11.4 liters:) or one gallon containers at 0.75 gallon (2.84 liters). Airless Spray: Equipment capable of KLIOOOB Is filled in one gallon maintaining a minimum of 2500 psi at the containers at 1.00 gallon (3.79 liters) or tip without surge., 0.021" (0.533 mm) to quart containers at 0.25 gallon (0.946 0.031" (0.787 mm) orifice.

liters). Brush: Use a high quality natural bristle PercentSolids brush.

by Volume: 84.1 +/- 3.0% (mixed, calculated)

Roller: Use a 3/8" nap polyester-nylon PercentSolids roller cover with a solvent resistant core.

by Weight: 88.7 +/- 3.0% (mixed, applied and air dried) Refer to Application Guide APG-8 for additional Information; VOC, Air Dried: 139 g/L (1.16 lbs./gal.) mixed VOC, EPA 24: 164 gIL (1.37 lbs./gal.) mixed Parts Base by Volume:. 3 parts KLIOOO Air Dry @ 77-F (25-C) ASTM D5895 Parts Catalyst Dry to Touch: 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by Volume: 1 part KLIOOOB Dry to Handle: 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Thinner Code & Thin up to 25% by volume with KL3700 as Dry to Recoat: 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Percent: needed for application.

Drying times listed may vary depending Digestion Time: None required on temperature, humidity and air movement.

rhe statement and methods presented in this bulletin are based upon the best available data and practices known to PPG/Keeler & Long at the present time. They are not representations or warranties ofperfonnance, results or comprehensiveness of such data. Since PPG /Keeter & Long is constantly improving its coatings and paint fomnsslas, future technical data may vary somewhat from what was available when this bulletin was printed. Contact your PPG/Keeler & Long Sales Representative for

'the most up-t6-date information.

E.100 May, 2004

United States Nuclear Regulatory Commission Page 24 of 25 SBK-L- 11062 / Enclosure 1 E.100 SKeelerI LongiPPG KolormasticTM(

856 Echo Lake Road Watertown, CT 06795 KL I O00/KL 1 O00B

, PPG High Performance Coatings 1-800-238-8596 Aluminum PFotUfe: 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at 77*F (25cC)

Coverage Sq.

Ft/Gal. @ I ml: 1349 sq. ft./gal.

Mixing 'Mechanically agitate KL1000 Part A thoroughly. Add KL1000B Part B to KL1000 Part A. Mix Instructions. thoroughly until uniform.

Wet Film Per Coat: 6.0 to 14.3 mils Dry Film Per Coat: 5.0 to 12.0 mils Clean Up Solvent: KL3700 Apply only when air, product and surface temperatures are at least 50OF (100C) and surface temperature is at least 55F (30C) above the dewpoint.

Store materials at temperatures between 50°F (100C) and 85°F (29.400).

Permissible substrate temperature during application Is 50OF (1000) and 120'F (490C).

Read all label and Material Safety Data Sheet (MSDS) information prior to use. MSDS are available by calling 1-800-238-8596.

Not intended for residential use.

Spray equipment must be handled with due care and in accordance with manufacturer's recommendation.

High-pressure injection of coatings into the skin by airless equipment may cause serious injury, requiring immediate medical attention at a hospital.

WARNING! Ifyou scrape, sand, or remove old paint, you may release lead dust or fumes. LEAD IS TOXIC.

EXPOSURE TO LEAD DUST OR FUMES CAN CAUSE SERIOUS ILLNESS, SUCH AS BRAIN DAMAGE, ESPECIALLY INCHILDREN. PREGNANT WOMEN SHOULD ALSO AVOID EXPOSURE. Wear a properly fitted NIOSH-approved respirator and prevent skin contact to control lead exposure. Clean up carefully with a HEPA vacuum and a wet mop. Before you start, find out how to protect yourself and your family by contacting the USEPA National Lead Information Hotline at 1-800-424-LEAD or log on to www.epa.gov/lead. In Canada contact a regional Health Canada office. Follow these Instructions to control exposure to other hazardous substances that may be released during surface preparation.

The statement and methods presented in this bulletin tre based upon the best available data and practices known to PPO/Kceler & Long at the present time. They areno[

represenitations or warranties ofperfornanec, results or cossprehensiveness ofsucs data. Since PPO /Keeler & Long is constantly improving its coatings and paint formulas, future technical data may vary somew*at from what was available when this bulletin was printed. Contact your PPO/Keeler & Long SR1esRepresentative for the mrost up-to-date informationi.

F.100 May, 2004

United States Nuclear Regulatory Commission Page 25 of 25 SBK-L- 11062 / Enclosure 1 Request for Additional Information (RAI) B.2.1.22-5

Background:

In LRA Supplement 2 dated November 15, 2010, the applicant revised LRA Table 3.3.2-37 to include copper-alloy (with> 15% zinc) valves and bolting exposed to raw water in the submerged underground vault for service water piping. The applicant stated that the components will be managed for aging by the Buried Piping and Tanks Inspection Program.

Issue:

The applicant did not revise LRA Section B.2.1.22 to reflect inclusion of this material nor to provide inspection frequencies.

Request:

Revise LRA Section B.2.1.22 to reflect inclusion of copper-alloy (>15% zinc) and state the number of planned inspections of these components.

NextEra Energy Seabrook Response:

In Section B.2.1.22, as submitted in Supplement 1 dated October 29, 2010 (SBK-L-10179), in Enclosure 1, on page 13 of 18, the Inaccessible Submerged Piping Inspection Locations table is revised as follows:

Material Type System HAZMAT Cathodically Applied Inspections per Protected Coatings 10-Year Period 2

Steel SW No Yes Yes 21 Copper alloy >15% zinc SW3 No No No 2 GENERAL NOTES:

1. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet.

2. The Service Water vault located north of the cooling tower contains four 24" lines approximately 15' long. The valve pit located north of the cooling tower contains one 32" line less than 10' long.

3. Drain valves on the spools in the Service Water vault and valve pit are constructedof aluminum bronze (categorizedas "copper alloy >15% zinc") with aluminum bronze body to bonnet bolting.

These components will be inspectedfor loss of materialwhen the respective Service Water spool piping is inspected by this program.

Enclosure 3 to SBK-L-11062 LRA Appendix A - Final Safety Report Supplement Table A.3 License Renewal Commitment List

United States Nuclear Regulatory Commission Page 2 of 13 SBK-L-1 1062 / Enclosure 3 A.3 LICENSE RENEWAL COMMITMENT LIST UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Program to be implemented prior to the An inspection plan for Reactor Vessel internals will be period of extended submitted for NRC review and approval at least twenty-four operation. Inspection

1. PWR Vessel Internals months prior to entering the period of extended operation. A.2.1.7 peato Plan Inspetoto to be submitted NRC not less than 24 months prior to the period of extended operation.

Closed-Cycle Cooling Enhance the program to include visual inspection for Prior to the period of

2. Water cracking, loss of material and fouling when the in-scope A.2.1.12 extended operation systems are opened for maintenance.

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

3. Load (Related to crane and trolley structural components and the effects of A.2.1.13 extended operation Refueling) Handling wear on the rails in the rail system.

Systems Inspection of Overhead Heavy Load and Light Enhance the program to list additional cranes for Prior to the period of

4. Load (Related to monitoring. A.2.1.13 extended operation Refueling) Handling Systems Enhance the program to include an annual air quality test 5 Compressed Air requirement for the Diesel Generator compressed air sub Prior to the period of Monitoring system. A.2.1.14 extended operation

United States Nuclear Regulatory Commission Page 3 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION

6. Fire Protection Enhance the program to perform visual inspection of A.2.1.15 Prior to the period of penetration seals by a fire protection qualified inspector, extended operation.

Enhance the program to add inspection requirements such

7. Fire Protection as spalling, and loss of material caused by freeze-thaw, A. 2.1.15 Prior to the period of chemical attack, and reaction with aggregates by qualified extended operation.

inspector.

8. Fire Protection Enhance inspectionthe program to of fire-rated include doors by athe fireperformance of visual protection qualified A.2.1.15 Prior to theoperation.

extended period of inspector.

Enhance the program to include NFPA 25 guidance for Fr "where sprinklers have been in place for 50 years, they Prior to the period of Fire Water System shall be replaced or representative samples from one or A.2.1.16 extended operation.

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

10. Enhance the program to include the performance of Prior to the period of Fire Water System periodic flow testing of the fire water system in accordance A.2.1.16 extended operation.

with the guidance of NFPA 25.

United States Nuclear Regulatory Commission Page 4 of 13 SBK-L-1 1062 / Enclosure 3 U FSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 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. These inspections will be documented and trended to determine if Within ten years prior to

11. a representative number of inspections have been Fire Water System A.2.1.16 the period of extended performed prior to the period of extended operation. If a operation.

representative number of inspections have not been performed prior to the period of extended operation, focused inspections will be conducted. These. inspections will be performed within ten years prior to the period of extended operation.

Enhance the program to include components and aging

12. Aboveground Steel effects required by the Aboveground Steel Tanks. A.2.1.17 Prior to the period of Tanks extended operation.

13. Aboveground Steel Enhance the program to include an ultrasonic inspection Within ten years prior to Tanks and evaluation of the internal bottom surface of the two Fire A.2.1.17 the period of extended Protection Water Storage Tanks. operation.

Enhance program to add requirements to 1) sample and

14. analyze new fuel deliveries for biodiesel prior to offloading Prior to the period of Fuel Oil Chemistry to the Auxiliary Boiler fuel oil storage tank and 2) A.2.1.18 extended operation.

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

Enhance the program to add requirements to check for the

15. presence of water in the Auxiliary Boiler fuel oil storage A.2.1.18 Prior to the period of tank at least once per quarter and to remove water as extended operation.

necessary.

United States Nuclear Regulatory Commission Page 5 of 13 SBK-L-I 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION

16. Fuel Oil Chemistry Enhance inspectionthe program of at theleast tofire diesel require pumpdraining, fuelyears.cleaning oil day tanks and on a A.2.1.18 Prior to theoperation.

extended period of frequency of once every ten Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10-year

17. Fuel Oil Chemistry draining, cleaning and inspection of the Diesel Generator A.2.1.18 Prior to the period of fuel oil storage tanks, Diesel Generator fuel oil day tanks, extended operation.

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

18. Reactor Vessel Enhance the program to specify that all pulled and tested Prior to the period of Su.RveianctrVessel capsules, unless discarded before August 31, 2000, are A.2.1.19 exte e peration.

Surveillance. placed in storage. extended operation.

Enhance the program to specify that if plant operations exceed the limitations or bounds defined by the Reactor

19. Reactor Vessel Vessel Surveillance Program, such as operating at a lower Prior to theperiod of Surveillance cold leg temperature or higher fluence, the impact of plant A.2.1.19 extended 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

20. Reactor Vessel outage in which the capsule receives a neutron fluence that Prior to the period of Surveillance meets the schedule requirements of 10 CFR 50 Appendix A.2.1.19 extended operation.

H and ASTM 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.

United States Nuclear Regulatory Commission Page 6 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to ensure that any capsule removed,

21. Reactor Vessel without the intent to test it, is stored in a manner which A.2.1.19 Prior to the period of Surveillance maintains it in a condition which would permit its future use, extended operation.

including during the period of extended operation.

22. Within ten years prior to One-Time Inspection Implement the One Time Inspection Program. A.2.1.20 the period of extended operation.

Implement the Selective Leaching of Materials Program.

The program will include a one-time inspection of selected Within five years prior to

23. Selective Leaching of Materials components where selective leaching has not been A.2.1.21 the period of extended identified and periodic inspections of selected components operation.

where selective leaching has been identified.

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

24. Buried Piping And Tanks Program. A.2.1.22 entering the period of Inspection extended operation One-Time Inspection of Implement the One-Time Inspection of ASME Code Class Within ten years prior to

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

Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects

26. External Surfaces of interest, the refueling outage inspection frequency, the Prior to the period of Monitoring inspections of opportunity for possible corrosion under A.2.1.24 extended operation.

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

United States Nuclear Regulatory Commission Page 7 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Inspection of Internal

27. Surfaces in Implement the Inspection of Internal Surfaces in Prior to the period of and Ducting Miscellaneous Piping and Ducting Components Program. A.2.1.25 extended operation.

Components Enhance the program to add required equipment, lube oil

28. Lubricating Oil Analysis analysis required, sampling frequency, and periodic oil A.2.1.26 Prior to the period of changesextended operation.

changes.

29. Enhance the program to sample the oil for the Switchyard Prior to the period of Lubricating Oil Analysis SF 6 compressors and the Reactor Coolant pump oil A.2.1.26 collection tanks. extended operation.

Enhance the program to require the performance of a one-

30. Oil Analysis time ultrasonic thickness measurement of the lower portion A.2.1.26 exto thedperiod of of the Reactor Coolant pump oil collection tanks prior to the extended operation.

period of extended operation.

31. ASME Section Xl, Enhance procedure to include the definition of A.2.1.28 Prior to the period of Subsection IWL "Responsible Engineer". extended operation.

32. Structures Monitoring Enhance procedure to add the aging effects, additional Program locations, inspection frequency and ultrasonic test A.2.1.31 Prior to the period of Program requirements. extended operation.

Enhance procedure to include inspection of opportunity Program when planning excavation work that would expose A.2.1.31 extended operation.

inaccessible concrete.

Electrical Cables and Connections Not Subject,

34. to 10 CFR 50.49 Implement the Electrical Cables and Connections Not Prior to the period of Environmental Subject to 10 CFR 50.49 Environmental Qualification A.2.1.32 extended operation.

Qualification Requirements program.

Requirements

United States Nuclear Regulatory Commission Page 8 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Electrical Cables and' Connections Not Subject

35. to 10 CFR 50.49 Implement the Electrical Cables and Connections Not Prior to the period of Environmental Subject to 10 CFR 50.49 Environmental Qualification A.2.1.33 extended operation.

Qualification Requirements Used in Instrumentation Circuits program.

Requirements Used in Instrumentation Circuits Inaccessible Power Cables Not Subject to Implement the Inaccessible Power Cables Not Subject to

36. 10 CFR 50.49 Pirt h eido Environmental 50.4910 Environmental' CFR 50.49 Environmental Qualification Requirements A.2.1.34 period of Prior to theoperation.

extended Qualification program.

Requirements

37. Metal Enclosed Bus Implement the Metal Enclosed Bus program. A.2.1.35 Prior to the period of extended operation.

38. Fuse Holders Implement the Fuse Holders program. A.2.1.36 Prior to the period of extended operation.

Electrical Cable Connections Not Subject Implement the Electrical Cable Connections Not Subject to Prior to the period of

39. to610 CFR 50.49 10 CFR 50.49 Environmental Qualification Requirements A.2.1.37 exte e perion.

Environmental extended operation.

Qualification program.

Requirements

40. KV SF Bus Implement the 345 KV SF6 Bus program. 2345 A.22.1 Prior to the period of extended operation.

41. Metal Fatigue of Reactor Enhance the program to include additional transients Prior to the period of Coolant Pressure beyond those defined in.the Technical Specifications and A.2.3.1 extended operation.

Boundary UFSAR.

United States Nuclear Regulatory Commission Page 9 of 13 SBK-L- 11062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Metal Fatigue of Reactor Enhance the program to implement a software program, to Prior to the period of

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

components. extended____________n.

Boundary The updated analyses will Pressure -Temperature be submitted at the

43. Limits, including Low Seabrook Station will submit updates to the P-T curves and appropriate time to Temperature LTOP limits to the NRC at the appropriate time to comply A.2.4.1.4 comply with 10 CFR50 Overpressure Protection with 10 CFR 50 Appendix G. Appendix G, Fracture Limits Toughness Requirements.

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-Environmentally- assisted fatigue calculation for nickel alloy will be At least two years prior to

44. Assisted Fatigue performed using the rules of NUREG/CR-6909. A.2.4.2.3 entering the period of Analyses (TLAA) (1) Consistent with the Metal Fatigue of Reactor Coolant extended operation.

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 environment. This includes applying the appropriate Fen factors to valid CUFs determined from an existing fatigue 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).

United States Nuclear Regulatory Commission Page 10 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION (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).

Mechanical Equipment Revise Mechanical Equipment Qualification Files. A.2.4.5.9 Prior to the period of Qualification extended operation.

Protective Coating Enhance the program by designating and qualifying an Prior to the period of

46. Monitoring and Inspector Coordinator and an Inspection Results Evaluator. A.2.1.38 extended operation Maintenance Enhance the program by including, "Instruments and Protective Coating Equipment needed for inspection may include, but not be Coan g limited to, flashlight, spotlights, marker pen, mirror, A.2.1.38 Prior to the period of

47. Monitoring and measuring tape, magnifier, binoculars, camera with or extended operation without wide angle lens, and self sealing polyethylene sample bags."

Protective Coating Prior to the period of 48ronctring Coatnd Enhance the program to include a review of the previous Ario 13 te e perion

48. Monitoring and Maintenancetwmoioigrpts A.2.1.38 extended operation

United States Nuclear Regulatory Commission Page 1 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Protective Coating Enhance the program to require that the inspection report Prior to the period of

49. Monitoring and is to be evaluated by the responsible evaluation personnel, A.2.1.38 extended operation Maintenance who is to prepare a summary of findings and recommendations for future surveillance or repair.

ASME Section XI, Perform testing of the containment liner plate for loss of A.2.1.17 Prior to the period of

50. Subsection IWE material. extended operation.

ASME Section XI, Perform confirmatory testing and evaluation of the A.2.1.28 Prior to the period of

51. Subsection IWL Containment Structure concrete extended operation ASME Section X Implement measures to maintain the exterior surface of the Prior to the period of

52. SubsectioneiwL Containment Structure, from elevation -30 feet to +20 feet, A.2.1.28 extended operation Subsection IWL in a dewatered state. etne prto Replace the spare reactor head closure stud(s) Prior to the period of

53. Studsor Head Closure manufactured from the bar that has a yield strength > 150 A.2.1.3 extended operation.

Studs ~~~~ksi with ones that do not exceed 150 ksi. xeddoeain Unless an alternate repair criteria changing the ASME code boundary is permanently approved by the NRC, or the Seabrook Station steam generators are changed to Program to be submitted Steam Generator Tube eliminate PWSCC-susceptible tube-to-tubesheet welds, A.2.1.10 to NRC at least 24

54. Integrity submit a plant-specific aging management program to months prior to the period manage the potential aging effect of cracking due to of extended operation.

PWSCC at least twenty-four months prior to entering the Period of Extended Operation.

United States Nuclear Regulatory Commission Page 12 of 13 SBK-L-1 1062 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Steam Generator Tube Seabrook will perform an inspection of each steam Prior to entering the

55. Integrity generator to assess the condition of the divider plate A.2.1.10 period of extended assembly. operation Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the

56. WaserSystem CGuideline operating ranges and Action Level values for A.2.1.12 period of extended Water System hydrazine and sulfates. operation.

Revise the station program documents to reflect the EPRI Prior to entering the 5 Water System Guideline operating ranges and Action Level values for A.2.1.12 period of extended Diesel Generator Cooling Water Jacket pH. operation.

Update Technical Requirement Program 5.1, (Diesel Fuel Prior to the period of

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

and ASTM D4057-95 required by the GALL.XI.M30 Rev 1 The Nickel Alloy Aging Nozzles and Penetrations program will implement applicable Bulletins, Generic Letters, and A.2.2.3 Prior to the period of .

Nickel Alloy Nozzles and Penetrations staff accepted industry guidelines, extended operation.

Buried Piping and Tanks Implement the design change replacing the buried Auxiliary Prior to entering the

60. Burieiiong Boilerleak supply with a pipe-within-pipe configuration piping capability, A.2.1.22 period of extended Inspection with indication operation.

Compressed Air Replace the flexible hoses associated with the Diesel Within ten years prior to Monitoring Program Generator air compressors on a frequency of every 10 A.2.1.14 entering the period of years. extended operation.

Enhance the program to include a statement that sampling Prior'to entering the

62. Water Chemistry frequencies are increased when chemistry action levels are A.2.1.2 period of extended exceeded. operation.

United States Nuclear Regulatory Commission Page 13 of 13 SBK-L-1 1062 / Enclosure 3 I UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Ensure that the quarterly CVCS ChargingPump testing Priorto the period of is continued during the PEO. Additionally, add a extended operation Flow Induced Erosion precautionto the test procedureto state that an N/A

63. increase in the CVCS ChargingPump mini flow above the acceptance criteriamay be indicative of erosion of the mini flow orifice as describedin LER 50-275/94-023.

Buried Piping and Soil analysis shall be performed prior to entering the A.2.1.22 Priorto entering the Tanks Inspection periodof extended operation to determine the period of extended corrosivity of the soil in the vicinity of non-cathodically operation.

64. protectedsteel pipe within the scope of this program.

If the initial analysis shows the soil to be non-corrosive, this analysis will be re-performed every ten years thereafter.