SBK-L-11207, License Renewal Application, Response to Request for Additional Information - Set 16

License Renewal Application, Response to Request for Additional Information - Set 16

ML11308A025
Person / Time
Site:	Seabrook
Issue date:	11/02/2011
From:	Freeman P NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-11207
Download: ML11308A025 (31)

Text

NEXTeraM EN ERG27Y&

November 2, 2011 SBK-L-1 1207 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 16

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 for the Review of the Seabrook Station License Renewal Application" (TAC NO. ME4028) - Request for Additional Information Set 16," October 7, 2011. (Accession Number ML11278A069)

3. NextEra Energy Seabrook, LLC letter SBK-L-11069, "Seabrook Station Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application - Set 12," April 22, 2011. (Accession Number ML1 111 5Al116)

4. 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 ML110380081)

5. NextEra Energy Seabrook, LLC letter SBK-L-11154, "Seabrook Station Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application - Set 15," August 11, 2011. (Accession Number MLI 1227A023)

6. NextEra Energy Seabrook, LLC letter SBK-L-11173, "First Annual Update to the Seabrook Station License Renewal Application,"

August 25, 2011.

(Accession Number ML11241A142)

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.

NextEra Energy Seabrook, LLC, P.O. Box 300, Lafayette Road, Seabrook, NH 03874 0,,Q

United States Nuclear Regulatory Commission SBK-L-11207/ Page 2 In Reference 2, the NRC requested additional information in order to complete its review of the License Renewal Application (LRA). The requests are a follow-up to responses provided in References 3 and 4. Enclosure 1 contains NextEra's response to the Set 16 request for additional information, revised response to RAI 4.3.1 (Reference 4) and associated changes made to the LRA. For clarity, deleted LRA text is highlighted by strikethroughs and inserted texts highlighted by bold italics.

In Reference 5, NextEra Energy Seabrook provided a response to RAI Follow-up B.2.1.31-4.

Based on discussions with the staff during an inspection visit the week of September 26, 2011, NextEra Energy Seabrook is providing clarification to the previous RAI Follow-up B.2.1.31-4 response. Enclosure 2 contains the revised response and changes made to associated commitment number 68.

As noted above, commitment number 68 is revised as a result of changes made in this letter. In Reference 6, NextEra Energy Seabrook provided the First Annual Update to the Seabrook Station License Renewal Application. In Enclosure 1, page 28, of Reference 6, item number 60 identified a change to commitment number 29, however, the associated cover letter incorrectly stated there were no new or revised regulatory commitments. Changes to commitment number 29 and 68 have been reflected in the revised LRA Appendix A - Final Safety Report Supplement Table A.3, License Renewal Commitment List, contained in Enclosure 3 to this letter. There are no other new or revised regulatory commitments contained in this letter.

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

United States Nuclear Regulatory Commission SBK-L-1 1207/ Page 3

Enclosures:

Response to Request for Additional Information Seabrook Station License Renewal Application Set 16, and Associated LRA Changes Revised NextEra Energy Seabrook response to RAI Follow-up B.2.1.31-4 provided in letter SBK-L-1 1154 dated August 11, 2011 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.

cc:

W.M. Dean, G. E. Miller, W. J. Raymond, R. A. Plasse Jr.,

M. Wentzel, NRC Region I Administrator NRC Project Manager, Project Directorate 1-2 NRC Resident Inspector NRC Project Manager, License Renewal 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

United States Nuclear Regulatory Commission SBK-L-11207/ Page 4 NEXTera ENERG-7Yl 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 o

_day of November, 2011 Paul 0. Freeman Site Vice President Notary Public to SBK-L-11207 Response to Request for Additional Information Seabrook Station License Renewal Application Set 16 and Associated LRA Changes

United States Nuclear Regulatory Commission Page 2 of 11 SBK-L-11207/ Enclosure 1 Request for Additional Information (RAI) Follow-up 3.1.1.60-02:

Background

By letter dated January 5, 2011, the staff issued two requests for additional information (RAls) to the applicant, RAI 3.1.1-60-01 and RAI 3.1.1. 60-02.

In its response to these RAls dated February 3, 2011, the applicant stated that its design is unique in that the flux thimble tube is a double walled concentric tube design with a capped inner tube and does not provide a pressure boundary function. During its review of the applicant's response, the staff noted that the applicant has the option to place the movable incore detectors back in service and questioned the exclusion of the flux thimble tube as a pressure boundary. A follow-up RAI 3.1.1-60-01/02 was asked on March 30, 2011. In its response dated April 22, 2011, the applicant provided additional bases-for not including the flux thimbles as part of its reactor coolant system (RCS) pressure boundary.

Issue Following its review of the applicant's responses to the RAIs, the staff seeks clarification as to where exactly the RCS pressure boundary is for the applicant's replacement detector assemblies and the original capped detector assemblies.

Request Verify the RCS pressure boundaries for the replacement and original capped incore detector assemblies. Specifically, identify components that constitute the RCS pressure boundary from the reactor vessel penetration to the seal table and any extensions beyond the seal table. Provide AMR items for the components which are in scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an aging management review and any applicable aging management program(s).

NextEra Energy Seabrook Response Each incore detector assembly consists of an incore instrument guide tube which houses a flux thimble tube. This flux thimble tube, in turn, houses the fixed incore detectors, a core exit thermocouple and, in the case of the original assembly design, a calibration tube. The incore instrument guide tubes are welded to the reactor vessel bottom instrument penetrations and continue up through the seal table to a high pressure instrument connection.

With the original incore detector assembly design, the incore instrument guide tube and flux thimble tube terminate at the high pressure instrument connection but the calibration tube extends above this connection to provide a pathway for movable incore detectors.

These movable incore detectors are no longer utilized and the calibration tube end is capped. The RCS pressure boundary for the original design consists of the reactor vessel

United States Nuclear Regulatory Commission Page 3 of 11 SBK-L-11207/ Enclosure 1 bottom instrument penetration, the incore instrument guide tube, the high pressure instrument connection, the portion of the calibration tube that extends above the high pressure instrument connection, and the pressure retaining cap.

The replacement incore detector assembly design replaces the calibration tube with a solid Inconel 600 rod that does not extend beyond the high pressure instrument connection.

The pressure retaining cap is no longer required, and the RCS pressure boundary consists of the reactor vessel bottom instrument penetration, the incore instrument guide tube, and the high pressure instrument connection only.

The above items are located in the LRA as noted below.

" High Pressure Instrument Connection and Cap for Calibration Tube - Listed under component type "Piping and Fittings" on Table 3.1.2-1, line items 3, 4, and 5 on page 3.1-48.

" Reactor Vessel Bottom Instrument Penetrations - Listed under component type "Reactor Vessel Bottom Instrument Tube" on Table 3.1.2-2, line items 3, 4, 5 and 6 on page 3.1-71 and line item 1 on page 3.1-72.

" Incore Instrument Guide Tube - Listed under component type "Incore Instrument Guide Tube" on Table 3.1.2-1, line items 3, 4, and 5 on pages 3.1-46 and line item I on page 3.1-471.

" Calibration Tube - As part of the response to this RAI, new line items are added under component type "Calibration Tube" to Table 3.1.2-1, on page 3.1-44, after component type "Bolting (Class 1)".

Based on the above discussion the LRA is changed as follows:

1) On Page 2.3-5, the boundary description for PID-1-RC-20845 is revised as follows:

PID-1-RC-LR20845.

The Reactor Coolant System scoping boundary includes the Reactor Vessel head vent piping from the vessel head nozzle to the Pressurizer Relief Tank.

The scoping boundary includes the Reactor Vessel Level Instrumentation System (RVLIS) line beginning at the restricting orifice located at the upper head penetration and on to the reference leg instrument, to capillary tubing through a containment penetration, and termination at a level transmitter. The sensing line for-R-t, S begins at the lower-head instr~umcntatien nozzle to guide tube weld, passes through the seal table, and terminates at the level dc;iees. The boundary5 continues from the level device via eapillary5 lines to the contaimmcnt penetr-ation, and termfinates at both level and pressurc transffittcr-s. Also included in the boundar-y are the ineere instrument.

-. e tubes.

The scoping boundary also includes fifty eight incore instrument guide tubes welded to individual reactor vessel bottom instrument penetrations. Each incore

United States Nuclear Regulatory Commission Page 4 of 11 SBK-L-11207/ Enclosure 1 instrument guide tube terminates above the seal table at a high pressure instrument connection seaL From two of the Incore Instrument Guide Tubes, a sensing line is provided for RVLIS which terminates at the level devices. The scoping boundary continues from the level device via capillary lines to the containment penetration, and terminates at both level and pressure transmitters.

The incore instrument guide tubes contain a flux thimble tube which runs from inside the reactor vessel to the seal table at the high pressure instrument connection. A high pressure seal is utilized where the instrument cabling exits the guide tube. The flux thimble tube contains fixed incore detectors and core exit thermocouples. The original incore detector assembly flux thimble tubes also contain a flux thimble calibration tube ("calibration tube") that was designed to provide a pathwayfor movable incore detectors. These movable incore detectors are no longer utilized. The movable flux detector drive system is in a laid-up condition and the calibration tube end is capped to form a RCS pressure boundary. The scoping boundary extends beyond the incore instrument guide tube to include the high pressure instrument connection, the portion of the calibration tube that extends above the high pressure instrument connection and associated cap.

The replacement incore detector assembly thimble tubes (5 out of 58) are not capped as they have a solid Inconel 600 rod in place of the calibration tube. This design eliminates the need for the terminating pressure retaining cap and the RCS pressure boundary extends only to the high pressure seal. The portions of the new incore detector assemblies that are part of the RCS pressure boundary are Safety Class 1 and conform to ASME Section III, Class 1, requirements.

The drain lines from the inner and outer head flange O-ring seals begin at the vessel nozzles welds, through pipes and valve terminating at the Reactor Coolant drain tank.

2) On Table, 3.1.1, on page 3.1-41, line item 3.1.1-85 is revised as follows:

3.1.1-85 Nickel alloy None None NA -

Consistent with NUJREG-1801. Nickel alloy piping, piping No components exposed to air-indoor uncontrolled components, and AEM (external) are contained in the Reactor Coolant system, piping elements or Reactor Vessel, Reactor Vessel Internals, and Steam exposed to air-AMP Generator.

indoor uncontrolled Components having the same internal/external (external) environments, have the same aging effects on both internal/external surfaces. As shown in NUREG-1801 VoL 2 line item IV.E-1 NickelAlloy in an indoor uncontrolled air (External) environment exhibits no aging effect and that the component or structure will therefore remain capable ofperforming its intended functions consistent with the CLB for the Ieriod of extended oDeration.

United States Nuclear Regulatory Commission SBK-L-1 1207/ Enclosure I Page'5 of 11

3) On page 3.1-44, added line items 3, 4, and 5 for the calibration tubes:

Intended Aging Effect Aging N1REG Table Component Type Function Material Environment Requiring Management~

8V01.

2 3.X.1 Note Management Program Item Item Air With Bolting Pressure Reactor Loss of Bolting IV.C2-8 (Class )

Bosundary Steel Coolant Preload Integri 3.1.-52 (Class 1)

Boundary Leakage Program (R12)

(External)

System Bolting Pressure Temperature Cumulative IV.C2-(Class P)eBoudre Steel up Fatigue TLAA 10 3.1.1-7 A

(Class 1)

Boundary to 3400C Damage (R-18)

(644-F)

Pressure Nickel Air-IndoorIV.E-1 Calibration Tube Uncontrolled None None IVEI 3.1.1-85 A Boundary Alloy (External)

(RP-03)

Air With Pressure Nickel Borated Calibration Tube Water None None None None G, 1 Boundary ALeakage (External)

Pressure Nickel Air-IndoorIV.E-Calibration Tube Uncontrolled None None 1VE1 3.1.1-85 A, 5 Boundary Alloy (Internal)

(RP-03)

Leakage Boundary Air-Indoor Flexible Hose (Spatial)

Stainless Uncontrolled None None IV.E-2 3.1 1-86 A

Steel (Exteral)

(RP-04)

Pressure Boundary Leakage Boundak y

Air With Boundary Borated Flexible Hose (Spatial)

Stainless Water None None IV.E-3 3 1 1-86 A

Steel Leakage (RP-05)

PressureLekg Boundary (External)

4) Add a new plant specific note 5 as follows on Page 3.1-69 (note: 4 was added in SBK-L-11123, dated June 2, 2011, in response to RAI 3.2.2.2.4.2-1A).

5. Components having the same internal/external environments have the same aging effects on both internal/external surfaces. As shown in NUREG-1801 Vol. 2 line item IV.E-1, NickelAlloy in an indoor uncontrolled air (External) environment exhibits no aging effect and the component or structure will therefore, remain capable of performing its intended functions consistent with the CLBfor the period of extended operation.

United States Nuclear Regulatory Commission Page 6 of 11 SBK-L-11207/ Enclosure 1 Request for Additional Information (RAI) Follow-up 4.3-1c:

Background

By letter dated April 22, 2011, the applicant responded to RAI 4.3-lb stating that the pressure boundary portion of the American Society of Mechanical Engineers (ASME)

Class I valves were designed, analyzed, and qualified for service (including fatigue) in accordance with the rules of ASME Code Section III Subsection NB-3500. Updated final safety analysis report (UFSAR) Table 5.2-1 identifies the code edition and addenda applicable to the design of the following types of Class 1 valves: pressurizer safety valves, motor-operated valves, manual valves, control valves, and pressurizer spray valves in the reactor coolant systems. UFSAR Table 5.4-13 also identifies the valves that are included in the reactor coolant pressure boundary.

Issue The staff noted that, in the 1971 and later editions of the ASME Section III Code, paragraphs NB-3545.3 and NB-3550 required fatigue analyses for valves that have an inlet piping connection larger than 4 inches nominal pipe size unless the exemption requirements of NB 3222.4(d) are met. It is not clear to the staff if the fatigue analyses for all Class 1 valves, has been dispositioned as. time-limited aging analysis (TLAA) in accordance with 10 CFR 54.21 (c)(1).

Request If fatigue analysis were performed for Class 1 valves that have an inlet piping connection larger than 4 inches nominal pipe size as part of the design-basis, amend the license renewal application (LRA) to provide and justify the TLAA disposition for these analyses. Or justify that the fatigue analyses for these Class 1 valves need not to be identified as a TLAA in accordance with 10 CFR 54.21 (c)(1).

If fatigue analyses were not performed for any Class 1 valves that have an inlet piping connection larger than 4 inches nominal pipe size, amend the LRA to identify these valves. Justify why fatigue analyses were not required for these Class 1 valves in accordance with the ASME Section III Code or the ASME Draft Pump and Valve Code, with reference to the applicable sections of the design code.

NextEra Energy Seabrook Response A fatigue analysis was performed for Class 1 valves that have an inlet piping connection larger than 4 inches nominal pipe size as part of the original design in accordance to ASME NB-3500. Fatigue analyses of Class 1 valves are considered a TLAA as part of the fatigue analyses of NSSS components discussed in LRA Section 4.3.1 and were

United States Nuclear Regulatory Commission Page 7 of 11 SBK-L-11207/ Enclosure 1 validated under 10 CFR 54.21 (c)(1)(i) as the 40-year design transients bound the numbers of cycles projected to occur during 60 years of plant operations at Seabrook Station. Therefore, the NSSS Class 1 fatigue analyses that are based upon the 40-year design transients remain valid for the period of extended operation. (Reference LRA page 4.3-11)

1) To clarify that the fatigue analysis of Class 1 valves constitute a TLAA, LRA section 4.3.1 as shown on page 4.3-2 is amended as follows:

Summary Description Nuclear Steam Supply System (NSSS) pressure vessels and primary components, including Class 1 valves and piping for Seabrook Station were designed in accordance with ASME Section III, Class 1 requirements and are required to have explicit analyses of cumulative fatigue usage.

Table 4.3.1-1 identifies the applicable design codes for these components.

2) In addition Table 4.3.1-1 as shown on page 4.3-3 is amended as follows:

Reactor Vessel ASME Section III, Class I Editfi'n/ddendum 1971 with Addenda through Summer 1972 Reactor Vessel Closure ASME Section III, Class 1 1971 with Addenda through Head Summer 1972 Pressurizer ASME Section III, Class 1 1971 with Addenda through Summer 1972 Steam Generators ASME Section III, Class 1 1971 with Addenda through Summer 1972 Reactor Coolant Pump ASME Section III, Class 1 1971 with Addenda through Casings Summer 1972 Reactor Coolant Class 1 ASME Section III, Class 1 1974 with Addenda through Valves Winter 1975 Reactor Coolant Class 1 ASME Section III, Class 1 1971 with Addenda through Piping I

Summer 1972

3) In addition in NextEra's response to RAI 4.3-1 contained in letter SBK-L-11015 dated February 3, 2011 previously stated "'A search by NextEra Ener' Seabrook did not find any Class 1 valves with separately computed cumulative usage factors since the original stress and fatigue analysis was performed " Since this response was submitted NextEra has identified the specific analysis performed for Class I piping and valves. The response previously submitted in SBK-L-11015 Enclosure 2, page 8

United States Nuclear Regulatory Commission Page 8 of 11 SBK-L-11207/ Enclosure 1 of 47 is revised as follows and Table 1 is replaced in its entirety as follows:

Revised Response to RAI 4.3.1 provided in SBK-L-11015; Enclosure 2 The original design basis 40-yr CUF values for all components and/or critical locations that are applicable to the dispositions in LRA Sections 4.3.1, 4.3.2, and 4.3.3 are provided in Table 1.

Evaluation of ASME Class 1 valves, that have an inlet piping connection larger than 4 inches, was considered in the original stress and fatigue analyses as part of the original design of Seabrook Station in accordance to ASME NB-3500.

Evaluation cf ASME Class I valves was considerfed inl th-e orfiginal1 stress and fatiguc analyses of the Class 1 piping for Seabrook Station. Fatigue conformance for the Class 1 piping systems containing the valves of these valve was demonstrated through the performance of a fatigue analysis for-the piping System

.ntai..ng.the val-ves. In the piping fatigue analyses, allowable moment ranges were developed for all transient loading combinations so that the ASME Section III, Subsection NB-3650, Equation 12 expansion stress requirement is met and CUF is less than 1.0.

Then actual computed moment ranges for each line are compared to the allowable moment range for all significant transient combinations (transients which give a usage factor greater than or equal to 0.02) the line can experience. If the calculated moment range is less than the allowable moment range for each transient combination, then the cumulative usage factor is less than 1.0 and Equation 12 is met.

The Equation 13 stress range is also computed, and if shown acceptable, fatigue conformance of the analyzed piping valves is demonstrated. If one or more allowable moment ranges is exceeded by the actual moment range for the given transient conditions, a more detailed fatigue analysis would-be was performed and a unique cumulative usage factor weuld-be was reported fef-that*valve.

A search by Nextra Energy Seabo.o d-d not find any Class 1 valves with separately

.omputed cumulative uisage facter-s since the or-iginial stress and fatigue analysis was performfed.

Thus, it can only be stated that the Class 1 valves aehieved fatigue usage valules less-than 1.0 for-all analyzed transients.

All design-basis plant transients listed in Table 4.3.1-2 were considered in these tmbf'ella the fatigue analyses in terms of severity and number of occurrences.

Because it has been projected that the original design-basis number of design transients will not be exceeded during the 60 ye, r period of extended operation, analyses for these components will be dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

United States Nuclear Regulatory Commission SBK-L-1 1207/ Enclosure 1 Table 1: List of Fatigue Usage Values Page 9 of 11 Design Fatigue Component Location Usage RPV Outlet Nozzle.

0.1077 RPV Outlet Nozzle Vessel Support Pad 0.0211 RPV Inlet Nozzle 0.0795 RPV Inlet Nozzle Vessel Support Pad 0.027 RPV Head Flange 0.0155 RPV Vessel Flange 0.0196 RPV Closure Studs 0.4780 RPV Vessel Wall Transition 0.0105 RPV Bottom Head-to-Shell Juncture 0.0070 RPV CRDM Housings 0.1093 RPV Bottom Head Instrument Tubes (pos. 1) 0.0014 RPV Bottom Head Instrument Tubes (pos. 2) 0.3184 RPV Core Support Lugs 0.0627 RPV Head Adapter Lugs 0.0036 Internals Lower Support Columns 0.271 Internals Core Barrel Nozzle 0.410 Internals Lower Core Plate 0.0744 Internals Upper Core Plate 0.183 Pressurizer Valve Support Bracket 0.102 Pressurizer Surge Nozzle (Path6A, Inside) (3) 0.6325 Pressurizer Spray Nozzle (Path8A9) (3) 0.981 Pressurizer Safety/Relief Nozzle (Pipe) )

0.0030 Pressurizer Lower Head 0.116 Pressurizer Heater Well 0.128 Pressurizer Upper Head/Upper Shell 0.906 Pressurizer Lower Head/Support Skirt 0.736 Pressurizer Manway 0.875 Pressurizer Instrument Nozzle 0.166 Pressurizer Immersion Heater 0.122 Pressurizer Trunnion/Shell Buildup 0.063 S/G Divider Plate 0.997 S/G Tubesheet and Shell Junction 0.846 S/G Tube to Tubesheet Weld 0.459 S/G' Tubes 0.902 S/G Main Feedwater Nozzle 0.921 Piping Pressurizer Surge Line (3) 0.6 Piping Pressurizer Spray Line ()

0.990 Piping Pressurizer Safety and Relief Valve 0.820

United States Nuclear Regulatory Commission SBK-L-11207/ Enclosure 1 Page 10 of 11 Component Location Design Fatigue Usage Piping Auxiliary Spray Line (3) 0.554 Piping ()

2-iiieh fessevef-beg Drain Line (4 )

78 Pipiig(4) 2 ineh Celd beg RT-DT0"7-7 pipin (4)"

1 and 2 in He Leg TDT4 07900 Piping (4) 3 inch Crossover L*g,T(4)--

0,7-0 Piping 2-inch Crossover Leg Loop 1, 2, 4 Drain(3 )

0.395 Piping 1.5-inch Boron Injection (BIT) Lines ()

0.990 Piping 10-inch Accumulator Lines 0) 0.900 Piping 6-inch Low Head Safety. Injection to Accumulator 0.800 Lines(3)

Piping 2-inch High Head Safety Injection to Accumulator 0.800 Lines(3)

Piping 6-inch Safety Injection Loop 2(3) 0.125 Piping 6-inch Safety Injection Loop 3(3) 0.330 Piping 12-inch RHR Loop 1 and 4 Suction(3 )

0.99 Piping 3-inch Normal (Loop 1) and Alternate (Loop 4) 0.440 Charging (3)

Piping 3-inch Normal Letdown(3) 0.990 Nozzle 3/4-inch Bosses (pressure taps, etc.) All Loops 0.81 Nozzle 3/4-inch Hot Leg Sampling Connection 0.98 Nozzle 14-inch Hot Leg Surge Nozzle (

0.6 Nozzle 4-inch Cold Leg Pressurizer Spray Nozzles 0.4 Nozzle 2-1/2-inch Hot and Cold Leg Thermowells 0.81 Nozzle 3-inch Cold Leg Loop 1 Normal Charging Nozzle 0.99 Nozzle 3-inch Cold Leg Loop 4 Alternate Charging nozzle 0.99 Nozzle 6-inch SIS Loops 2 and 3 Hot Leg Nozzle 0.01 Nozzle 3-inch Cold Leg (All Loops) Boron Injection Nozzle 0.99 Nozzle 10-inch Cold Leg Accumulator Nozzle (All Loops) 0.95 Nozzle 1-inch Cold Leg Loop 3 Excess Letdown 0.99 Nozzle 3-inch Crossover Leg Normal Letdown Nozzle 0.20 Nozzle 1-inch Hot Leg RTD 0.60 Nozzle 2-inch Cold Leg RTD 0.70 Nozzle 3-inch Crossover Leg Return RTD 0.40 Nozzle 2-inch Crossover Leg Loops 1, 2, 4 Drain 0.116 Nozzle 12-inch Hot Leg RHR Nozzle 0.92 Valve Pressurizer Spray (Butt Welded) 0.07 Valve Auxiliary Spray (Socket Welded) (maximum value) 0.554 Val.ve (4)

RTD L-.ps 1/2/3 (So+ket Welded) (maximum al.).(4)

Valve(4 )

RT.D Loops 1//','3 (But Welded) (ma.xJium value)v*

4 03-300 V-alve(4)

Rt_

4 Lp(Scket Welded) (maximum a....).

@,7800 Va*he( 4)

RTD Ltop 41 (But4 Welded) (maximum val.

4) 0-.300

United States Nuclear Regulatory Commission SBK-L-11207/ Enclosure 1 Page 11 of 11 Component Location Design Fatigue Usage Valve RC Drain Line Loops 1/2/3/4 (Socket-Welded) 0.819 Valve Boron Injection Line Loops 1/2/3/4 (Socket-Welded) 0.85 Valve Boron Injection Line Loops 1/2/3/4 (Butt-Welded) 0.010 Valve Accumulator Line Loops 1/2/3/4 (Socket Welded) 0.40 Valve Accumulator Line Loops 1/2/3/4 (Butt Welded) 0.40 (maximum value)

Valve SI Lines (Hot Leg Recirculation) (Socket Welded) 0.05 Valve SI Lines (Hot Leg Recirculation) (Butt Welded) 0.09 Valve RHR Loops 1/4 (Socket Welded) 0.700 Valve RHR Loops 1/4 (Butt Welded) (maximum value) 0.300 Valve CVCS Charging Line Loops 1 /4 (Butt Welded) 0.440 (maximum value)

Valve CVCS Normal Letdown Line (Socket Welded) 0.819 Valve CVCS Normal Letdown Line (Butt Welded) (maximum 0.098 value)

Valve Class I Valves > 4 inches

< 1.00 Notes for Table 1:

(1)

The highest reported fatigue usage of 0.6 is at the Reactor Coolant Loop Nozzle Transition and Safe End (2) 6-in x 4-in reducer, the most limiting location in the Pressurizer Spray lines (3)

Usage taken from most limiting location in the corresponding stress report (4)

Component(s) removed via Engineering Change to SBK-L-11207 Revised NextEra Energy Seabrook response to RAI Follow-up B.2.1.31-4 provided in letter SBK-L-11154 dated August 11, 2011

United States Nuclear Regulatory Commission Page 2 of 5 SBK-L-1 1207/ Enclosure 2 In NextEra Energy Seabrook, LLC letter SBK-L-11154 (Reference 5), NextEra Energy Seabrook provided a response to RAI Follow-up B.2.1.31-4. Based on discussions with the staff during an inspection visit the week of September 26, 2011, NextEra Energy Seabrook is providing clarification to the previous RAI Follow-up B.2.1.31-4 response.

The following revises response to Follow-up RAI B2.1.31-4:

Revised Response to (RAI) Follow-up B.2.1.31-4

1. Seabrook Station does not have continuous borated water leakage from the spent fuel pool. Currently, any leakage from the spent fuel pool collects in a steel catch basin installed in the sump and does not come in contact with concrete.

NextEra Energy Seabrook commits to confirm the absence of embedded steel corrosion by performing a shallow core sample in an area subjected to wetting of borated water during the time frame of the spent fuel pool leakage. The core samples will be examined for degradation of concrete from borated water and also expose rebar to detect any degradation such as loss of material.

As demonstrated by examination of concrete cores from the Connecticut Yankee spent fuel pool and Salem Nuclear Generating Station referenced in the "Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station Units 1 and 2" (ADAMS Accession Number ML11164A051), the structural capacity will not be significantly affected by exposure to borated water. In addition, borated water is not in continuous contact with concrete at Seabrook Station. Hence performing a confirmatory core bore and exposing rebar by December 31, 2015 is adequate.

2.

Seabrook Station currently performs hydro-lazing of the spent fuel pool leakoff lines at a 4 '/2 year frequency and will maintain this throughout the period of extended operation. Leak-off is recorded once a month on a spent fuel pool leakage spread sheet. The System Engineer monitors the leak-off telltale drains via the spread sheet for unusual leakage or lack thereof, which could be an indicator of blockage.

Monitoring will continue throughout the period of extended operation.

3. The Spent Fuel Pool, Cask Handling and Fuel Transfer canal areas, have nine zones that collect leakage and there are seven sample points. The Spent Fuel Pool, where spent fuel is stored, is separated from the Cask Handling and Fuel Transfer Canal area by a gate. Zones 1, 2, 3 and 4 leak collection zones are under the Spent Fuel Pool area in a quadrant configuration. Each Spent Fuel Pool quadrant has a separate leak collection sample line. There have been no incidents of leakage from the Spent Fuel Pool area. To date, the only incidents of leakage have been from the Cask Handling and Fuel Transfer Canal area. Leak collection Zones 8 and 9 are under the Fuel Transfer Canal, with the north end monitored by Zone 8 and the

United States Nuclear Regulatory Commission Page 3 of 5 SBK-L-11207/ Enclosure 2 south end by Zone 9. Each Fuel Transfer Canal Zone has a separate leakage collection sample line. Leak collection Zones 5, 6 and 7 are from the cask handling area. Any leakage from cask handling area Zones 5, 6 and 7 are combined into the Zone 6 leakage collection sample line. Zone 6 is the only leakage collection sample line that routinely has water flow. The majority of water in Zone 6 sample line is from groundwater in leakage, Currently the spent fuel peel leakoff collection is analyzed for gamma and tritium activity monthly. On April 6, 2011, tritium activity concentration measured in SpefA FuelPool-*(SF P) the Cask Handling area zone 6 tell-tale leakage collection pipe indicated a step increase from 2.58E-5 -LCi/ml to 7.87E-3 ptCi/ml.

Typically the Zone 6 leakoff collection tritium activity concentration is approximately 2 to 9E-05 uCi/mL. The Cask Handling area water tritium activity concentration is 1 E-01,uCi/mL. The Cask Handling area leak rate is determined by a simple calculation, based on ratio of the Cask Handling area water tritium concentration, the Zone 6 leakoff collection sample tritium concentration and the Zone 6 leakoff water flow rate.

The increased leak rate in the Spring of 2011 occurred coincident with refilling of the cask handling area leading pool which had previously been drained to support maintenance and testing of the spent fuel transfer system equipment. The Zone 6 leakoff sample tritium activity concentration increased by about a factor of 300 and the calculated peel Cask Handling area leak rate was 1.2 gpd. Subsequent measurements identified the leak rate peaked at approximately 2.57 gpd on 4/10/2011, after which leakage decreased to the current level of 0.016 gpd (approximately 2oz. per day) by 5/9/2011.

On average, about 10 gallons per day of groundwater leaks out of the zone 6 tell tale leakoff collection pipe. This groundwater has background contamination from tritium that is diffusing out of the concrete that was originally contaminated from the-peel Cask Handling and Fuel Transfer Canal area leakage identified in 1999.. That leakage was terminated in 2004 with the application of the first non-metallic liner.

Groundwater leakage is monitored by the Structures Monitoring Program.

Fuel peel volutmetr-ic leakage is estimated by taking the r-atio of the leak off line tritium concentr-ation to the pool tr-itiumf conccntration and multiplying that value by the affount of zcnc 6 leakage pumffped eut from the collection tank. in this particular instance, the only leak off line that indicated any leakage was zone 6.

There are several potential causes for the increased leakage, and each is discussed below. Those include:

A new SS liner plate leak in an area not lined with the non-metallic liner.

A failure in the new non-metallic liner at the same location as a SS liner failure.

United States Nuclear Regulatory Commission Page 4 of 5 SBK-L-1 1207/ Enclosure 2 A skimmer pit leak Corrective actions are being implemented and are on going, such as:

Determining if the skimmer pit(s) are the source of the current leakage.

Verifying integrity of cask loading area non-metallic liner through drain down and inspection.

Revising procedures for cask filling to limit pool level; Revising the maintenance work order for removal sequence of the weir gate, or reduce the height of the weir gate.

Determining whether the current design of skimmer pits is appropriate and what changes need to be made to prevent leakage out of the pit.

Perform a qualified visual inspection of the weld at the skimmer plate to discharge line interface to determine whether there is actually a seal weld.

The above corrective actions are scheduled to be completed by 12/_31/2011.5/31/2012.

As explained in response #2, the leakoff lines are hydro-lazed every 4 1/2 years and the System Engineer monitor's the leak-off telltale drains via a collection spread sheet for unusual leakage conditions.

Currently the, spnt fu'l peel leakoff collection is analyzed for gamma and tritium monthly. The program will be enhanced to perform sampling for chlorides, sulfates, pH and iron for. f

,r quarters (fer

,asenal va.iati.ns) of one y.a.

.n..

,vry 5 years every three months. These samples will be trended and reviewed once every five years for signs of concrete degradation (as reported in LRA section 3.5.2.2.1.1 groundwater sample are in the aggressive range). The effects of the groundwater and concrete degradation are presently being monitored by the Seabrook Station Engineering Staff. Information from these samples will be incorporated into the Structures Monitoring Program assessments.

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

1) License Renewal Application Appendix B, Section B.2.1.31, page B-169, is revised to add Enhancement 1 d and 3 as follows:

1.

d Perform a confirmatory core bore and expose rebar in an area under the catch basin in spent fuel pool leakage sump.

3.

Enhance procedure to perform chemistry sample of the spent-fiael-p leakoff collection points.

United States Nuclear Regulatory Commission SBK-L-1 1207/ Enclosure 2 Page 5 of 5

a.

Procedure CP 3.1, "Primary Chemistry Control Program" will be enhanced to include chemistry sampling of the spent1 fel -pe,.

leakoff collection points for chlorides, sulfates, pH and iron for-fý"..

• qa*terS e on.y... ever.y 5 year, s once every three months.

2) License Renewal Application Appendix A, Section A.3,, is revised to add commitments as follows:

No.

PROGRAM or COMMITMENT UFSAR SCHEDULE TOPIC LOCATION Perform one shallow core bore in an area that Structures was continuously wetted from borated water No later than 67 Monitoring Program to be examined for concrete degradation and A.2.1.31 December 31, 2015 also expose rebar to detect any degradation such as loss of material.

Perform sampling at the spent fuel ool leakoff collection points for chlorides, Starting January 68 Structures sulfates, pH and iron for four quarters of one A.2.1.31 2014 Monitoring Program year once e-vely 5 years once every three 2014 months.

to SBK-L-1 1207 LRA Appendix A - Final Safety Report Supplement Table A.3 License Renewal Commitment List

United States Nuclear Regulatory Commission SBK-L-11207 / Enclosure 3 A.3 LICENSE RENEWAL COMMITMENT LIST Page 2 of 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Program to be implemented prior to the period of extended operation. Inspection plan to be An inspection plan for Reactor Vessel Internals will be

'submitted to NRC not later than 1

PWR Vessel Internals submitted for NRC review and approval.

2 years after receipt of the A.2.1.7 renewed license or not less than 24 months prior to the period of extended operation, whichever comes first.

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

2.

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

Inspection of Overhead Heavy Enhance the program to monitor general corrosion on the crane Prior to the period of extended

3.

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

Handling Systems Inspection of Overhead Heavy Prior to the period of extended

4.

Load and Light Load Enhance the program to list additional cranes for monitoring.

A.2.1.13 operation (Related to Refueling)

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

5.

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 penetration seals by a fire protection qualified inspector.

operation.

United States Nuclear Regulatory SBK-L-1 1207 / Enclosure 3 Commission Page 3 of 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Enhance the program to add inspection requirements such as Prior to the period of extended

7.

Fire Protection spalling, and loss of material caused by freeze-thaw, chemical A.2.1.15 operation.

attack, and reaction with aggregates by qualified 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 guidance for "where sprinklers have been in place for 50 years, they shall be Prior to the period of extended

9.

Fire Water System replaced or representative samples from one or more sample A.2.1.16 operation.

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 of NFPA 25.

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 a representative number of

11.

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

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 effects

12.

Tanks required by the Aboveground Steel Tanks.

A.2.1.17 Prior to the period of extended Tabovgrun Seloperation.

13.

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

period of extended operation.

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 4 of 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Enhance program to add requirements to 1) sample and

14.

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

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 at A.2.1.18 operation.

least once per quarter and to remove water as necessary.

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, Prior to the period of extended

17.

Fuel Oil Chemistry cleaning and inspection of the Diesel Generator fuel oil storage A.2.1.18 operation.

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

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

18.

Surveillance capsules, unless discarded before August 31, 2000, are placed A.2.1.19 operation.

in storage.

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

19.

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

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

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 5 of 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE 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

20.

Reactor Vessel capsule receives a neutron fluence that meets the schedule A.2.1.19 Prior to the period of extended Surveillance requirements of 10 CFR 50 Appendix H and ASTM El 85-82 operation.

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,

21.

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

including during the period of extended operation.

Within ten years prior to the

22.

One-Time Inspection Implement the One Time Inspection Program.

A.2.1.20 perio tended prion.

period of extended operation.

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

23.

Materials components where selective leaching has not been identified A.2.1.21 Witin fiexyea priort and periodic inspections of selected components where period of extended operation.

selective leaching has been identified.

Buried Piping And Implement the Buried Piping And Tanks Inspection Program.

Within ten years prior to

24.

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

25.

of ASME Code Class pl n h n-ieIseto fAM oeCas1A.2.

1.23 1 Sma Bore-Piping Small Bore-Piping Program.

period of extended operation.

1 Small Bore-Piping Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects of

26.

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

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

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 6 of I 1 No.

PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL Inspection of Internal Surfaces in Implement the Inspection of Internal Surfaces in Miscellaneous Prior to the period of extended

27.

Miscellaneous Piping o

.A.2.1.25 and Ducting Piping and Ducting Components Program.

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

28.

LUbricating Oil analysis required, sampling frequency, and periodic oil A.2.1.26 operation.

Analysis

~changes.oeain

29.

Lubricating Oil Enhance the program to sample the oil for the SWmtchyard SF6 A.2.1.26 Prior to the period of extended Analysis compressors and the Reactor Coolant pump oil collection tanks.

operation.

Enhance the program to require the performance of a one-time.

30.

Lubricating Oil ultrasonic thickness measurement of the lower portion of the A.2.1.26 Prior to the period of extended Analysis Reactor Coolant pump oil collection tanks prior to the period of operation.

extended operation.

31.

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

operation.

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

32.

locations, inspection frequency and ultrasonic test A.2.1.31 Peraton.

Program requirements.

operation.

Structures Monitoring Enhance procedure to include inspection of opportunity when Prior to the period of extended

33.

Program planning excavation work that would expose inaccessible A.2.1.31 operation.

Progm I concrete.

operation.

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 7 of 11 U FSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Electrical Cables and Connections Not CoSubjectis tot 1Implement the Electrical Cables and Connections Not Subject 34 50.49 Environmental to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.32 operation.

Qualification program.

Requirements Electrical Cables and Connections Not Subject to 10 CFR Implement the Electrical Cables and Connections Not Subject 50.49 Environmental pm the ElecricalnCal anCoction Noqubject Prior to the period of extended Qualification t

F Eaualification Requirements A.2.1.33 C

operation.

Requirements Used Used in Instrumentation Circuits program.

in Instrumentation Circuits Inaccessible Power Cables Not Subject to

36.

10 CFR 50.49 Implement the Inaccessible Power Cables Not Subject to 10 A.2.1.34 Prior to the period of extended Environmental CFR 50.49 Environmental Qualification Requirements program.

operation.

Qualification Requirements Prior to the period of extended

37.

Metal Enclosed Bus Implement the Metal Enclosed Bus program.

A.2.1.35 operaton.

operation.

Prior to the period of extended

38.

Fuse Holders Implement the Fuse Holders program.

A.2.1.36 operaton.

I operation.

Electrical Cable Connections Not

39.

Subject to 10 CFR Implement the Electrical Cable Connections Not Subject to 10 A.2.1.37 Prior to the period of extended 50.49 Environmental CFR 50.49 Environmental Qualification Requirements program.

operation.

Qualification Requirements Prior to the period of extended

40.

345 KV SF6 Bus Implement the 345 KV SF6 Bus program.

A.2.2.1 operaton.

I I

Ioperation.

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 8 of I 1 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Metal Fatigue of Enhance the program to include additional transients beyond Prior to the period of extended

41.

Reactor CoolantA.31 PRessur Bound those defined in the Technical Specifications and UFSAR.

operation.

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

42.

Reactor Coolant count transients to monitor cumulative usage on selected A.2.3.1 operation.

Pressure Boundary components.

Pressure -

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

43.

including Low LTOP limits to the NRC at the appropriate time to comply with A.2.4.1.4 time to comply with 10 CFR 50 Overpressure 10 CFR 50 Appendix G.

Appendix G, Fracture Protection 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-assisted fatigue calculation for nickel alloy will be performed Environmentally-using the rules of NUREG/CR-6909.

At least two years prior to

44.

Assisted Fatigue (1) Consistent with the Metal Fatigue of Reactor Coolant A.2.4.2.3 entering the period of extended Analyses (TLAA)

Pressure Boundary Program Seabrook Station will update the operation.

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).

(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,

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 9 of I 1 No.

PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION 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).

45.

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

46.

Monitoring and Inspector Coordinator and an Inspection Results Evaluator.

A.2.1.38 operation

______Maintenance Enhance the program by including, "Instruments and Equipment Protective Coating needed for inspection may include, but not be limited to, Prior to the period of extended

47.

Monitoring and flashlight, spotlights, marker pen, mirror, measuring tape, A.2.1.38 operation Maintenance magnifier, binoculars, camera with or without wide angle lens,.

andself sealing polyethylene sample bags."

Protective Coating Prior to the period of extended

48.

Monitoring and Enhance the program to include a review of the previous two A.2.1.38 operation Maintenance monitoring reports.

Protective Coating Enhance the program to require that the inspection report is to Prior to the period of extended Monitoring and be evaluated by the responsible evaluation personnel, who is to A.2.1.38 operation Maintenance prepare a summary of findings and recommendations for future surveillance or repair.

Within the next two refueling ASME Section XI, Perform UT testing of the containment liner plate in the vicinity A.2.1.27 outages, ORat oriORl6, and Subsection IWE of the moisture barrier for loss of material.

than five refueling outages

51.

Number Not Used

United States Nuclear Regulatory Commission SBK-L-1 1207 / Enclosure 3 Page 10 of 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE ASME Section Xl, Implement measures to maintain the exterior surface of the

52.

Subsection IWL Containment Structure, from elevation -30 feet to +20 feet, in a A.2.1.28 By 2013 dewatered state.

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

53.

from the bar that has a yield strength > 150 ksi with ones that A.2.1.3 operation.

Closure Studs do not exceed 150 ksi.

operation._

Unless an alternate repair criteria changing the ASME code boundary is permanently approved by the NRC, or the Program to be submitted to Steam Generator Seabrook Station steam generators are changed to eliminate NRC at least 24 months prior to

54.

Te Inerity PWSCC-susceptible tube-to-tubesheet welds, submit a plant-A.2.1.10 the period of extended Tube Integrity specific aging management program to manage the potential operiond aging effect of cracking due to PWSCC at least twenty-four operation.

months prior to entering the Period of Extended Operation.

55.

Steam Generator Seabrook will perform an inspection of each steam generator to A.2.1.10 Prior to entering the period of Tube Integrity assess the condition of the divider plate assembly.

extended operation Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the period of

56.

Water SystemGuideline operating ranges and Action Level values for A.2.1.12 extended operation.

Water System hydrazine and sulfates.

exedeprain 57 Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the period of Wae 9

Guideline operating ranges and Action Level values for Diesel A.2.1.12 rSystem Generator Cooling Water Jacket pH.

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 XI.M30 Rev 1 The Nickel Alloy Aging Nozzles and Penetrations program will Prior to the period of extended

59.

Nickel Alloy Nozzles implement applicable Bulletins, Generic Letters, and staff A.2.2.3 operation.

and Penetrations accepted industry guidelines.

operation.

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

60.

Tanks Ipin Boiler supply piping with a pipe-within-pipe configuration with A.2.1.22 extended operation.

sInspection leak indication capability.

withtheDieel GnertorWithin ten years prior to

61.

Compressed Air Replace the flexible hoses associated with the Diesel'Generator entering the period of extended Monitoring Program air compressors on a frequency of every 10 years.

p. eration.

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

62.

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

exceeded.

extendedoperation.

United States Nuclear Regulatory SBK-L-1 1207 / Enclosure 3 Commission Page I Iof 11 UFSAR No.

PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Ensure that the quarterly CVCS Charging Pump testing is continued during the PEO. Additionally, add a precaution to the

63.

Flow Induced Erosion test procedure to state that an increase in the CVCS Charging N/A Prior to the period of extended Pump mini flow above the acceptance criteria may be indicative operation 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

64.

Buried Piping and vicinity of non-cathodically protected steel pipe within the scope A.2.1.22 Prior to entering the period of 64.Buiedping and of this program. If the initial analysis shows the soil to be non-extended operation.

Tanks Inspection corrosive, this analysis will be re-performed every ten years thereafter.

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

65.

Flux Thimble Tube detectors are not returned to service during the period of N/A extended operation extended operation.

Enhance the current station operating experience review process implemented in response to NUREG 0737 Task I.C.5 Procedures for Feedback of Operating Experience to Plant Staff Operating Experience (UFSAR 101.9.1) to include future reviews of plant-specific and Within ten years prior to

66.

Reviews industry operating experience in order to confirm the N/A entering the period of extended effectiveness of the license renewal aging management operation.

programs and to determine the need for programs to be enhanced or the need to develop new aging management programs.

Perform one shallow core bore in an area that was continuously

67.

Structures Monitoring wetted from borated water to be examined for concrete A2131 No later than December 31, Program degradation and also expose rebar to detect any degradation 2015 such as loss of material.

Perform sampling at the speRntfuel pool leakoff collection points

68.

Structures Monitoring for chlorides, sulfates, pH and iron for four. quaters of one year A.2.1.31 Starting January 2014 Program once every 5 years, once every three months.