SBK-L-11069, Response to Request for Additional Information - Set 12 and Associated License Renewal Application Changes

Response to Request for Additional Information - Set 12 and Associated License Renewal Application Changes

ML11115A116
Person / Time
Site:	Seabrook
Issue date:	04/22/2011
From:	Freeman P NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-11069, TAC ME4028
Download: ML11115A116 (72)

Text

NExTera ENERGY Al ,EABROK April 22, 2011 SBK-L- 11069 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 12

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 12," March 30, 2011. (Accession Number. ML110700018)

3. 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)

4. NextEra Energy Seabrook, LLC letter SBK-L- 10 192, "Seabrook Station License Renewal Application - Supplement 2, November 15, 2010. (Accession Number ML103210330)

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) and responses previously provided in References 3 and 4.

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.

Based on discussion with the Staff, NextEra Energy Seabrook has made changes to the License Renewal Application, which are contained in Enclosure 2 of this letter.

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

United States Nuclear Regulatory Commission SBK-L-1 1069 / Page 2 Commitment number 1 has been revised, commitment 45 withdrawn and commitment number 65 added. There are no other new or revised regulatory commitments contained in this letter. 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 # 12 and Associated LRA Changes - Changes to License Renewal Application based on NRC Staff discussions - 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-1 1069 / 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

United States Nuclear Regulatory Commission SBK-L- 11069 / Page 4 NEXTera 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

&c 2 day of ,2011 Paul 0. Freeman Site Vice President otary Public o

Enclosure 1 to SBK-L-11069 Response to Request for Additional Information Seabrook Station License Renewal Application Set 12 and Associated LRA Changes

United States Nuclear Regulatory Commission Page 2 of 43 SBK-L-1 1069 / Enclosure 1 Request for Additional Information (RAI) 2.3.3.15-1

Background:

The LRA drawing PID- 1-FP-LR20270 shows. that sprinkler systems at locations C-4 to H-4 are out of-scope (i.e., not colored in red).

In a letter dated December 3, 2010, NextEra Energy responded to RAI 2.3.3.15-1 by stating the sprinkler systems located on drawing PID- 1-FP-LR20270, locations C-4 to H-4, are not in scope of license renewal because they do not provide a function credited in the Appendix R safe shutdown analysis and do not provide a pressure boundary fuinction needed to support the Appendix R suppression systems.

Issue:

NextEra's response to RAI 2.3.3.15-1 may be inconsistent with the updated final safety analysis report (UFSAR) Revision 13, Section 9.5.1.2(c)(7), "Manually Operated Pre-Action Sprinkler Systems," which states that manually operated sprinkler systems are provided for areas containing turbine bearings and lube oil piping from turbine bearings to guard.

Request:

The fire suppression systems discussed above appear to have been credited in the approved fire protection program (UFSAR Section 9.5.1) for the fire suppression activities. Based on its review, the staff does not find the applicant's response to RAI 2.3.3.15-1 acceptable. The applicant explains that the fire protection systems in question are not credited to meet the requirements of Appendix R for achieving safe-shutdown in the event of a fire. However, the staff finds that the applicant's analysis of fire protection regulation does not completely capture the fire protection SSCs required for compliance with Title 10 of the Code of FederalRegulations (10 CFR) 50.48. The scope of structure systems and components (SSCs) required for compliance with 10 CFR 50.48 and general design criteria 3 (GDC 3) goes beyond preserving the ability to maintain safe-shutdown in the event of a fire. GDC 3 states in part, "Fire detection and fighting systems of appropriate capacity and capability shall be provided and designed to minimize the adverse effects of fires on structures, systems, and components important to safety."

Furthermore, the general requirements provided in GDC 3 to minimize the adverse effects of fires on SSCs important to safety establish a general level of protection which is afforded to all systems, not only where required to prevent a loss of safe shutdown capability. 10 CFR 50.48(a) states, "Each operating nuclear power plant must have a fire protection plan that satisfies Criterion 3 of Appendix A of this part." The term "important to safety" encompasses a broader scope of equipment than safety-related and safe-shutdown equipment. Though there is a focus on the protection of safety-related equipment or safe-shutdown equipment, this does not imply that there is any exclusion of equipment which protects non-safety related equipment.

United States Nuclear Regulatory Commission Page 3 of 43 SBK-L- 11069 / Enclosure 1 For example, in accordance with 10 CFR 50.48, some portions of suppression systems may be required in plant areas where a fire could result in the release of radioactive materials to the environment, even if no safety-related or safe-shutdown equipment is located in that particular fire area. The staff finds this contrary to the UFSAR which includes the original Seabrook Station fire protection SE as the CLB.

The staff requests that the applicant verify whether fire suppression systems discussed are in the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

NextEra Energy Seabrook Response:

In response to this follow up RAI, the sprinkler system components downstream of valves 1-FP-V-792 and 1-FP-V-800 on boundary drawing PID- 1-FP-LR20270 have been added to the scope of license renewal and the LRA has been revised as shown below.

1. In Table 3.3.2-15, on page 3.3-311, two new rows are added after the 1 st row as follows:

Pressure Copper Air-Indoor SprinkerHead Boundary Alloy Uncontrolled None None 3.2.1-53 A (EP-lO)

Spray >15% Zn (External Pressure Boure Copper Air-Indoor VF3 SprinklerHead Boundary Alloy Uncontrolled None None 3.2.1-53 A, 4 (EP- O)

Spray >15% Zn (Internal Request for Additional Information (RAI) 3.1.1.60-01/02

Background:

By letter dated January 5,2011, the staff issued two RAIs to the applicant. RAI 3.1.1 01 requested that the applicant justify not including an applicable aging management review (AMR) line item to manage loss of material due to wear in the nickel-alloy flux thimble tubes and to justify why a Flux Thimble Tube Inspection Program is not credited to manage loss of material due to wear for these nickel-alloy flux thimble tubes. RAI 3.1.1-60-02 requested that the applicant justify the use of the PWR Vessel Internals Program to manage cracking in the flux thimble tubes, considering that MRP-227 Rev. 0 does not contain recommendations for managing cracking in Westinghouse-design flux thimble tubes.

United States Nuclear Regulatory Commission Page 4 of 43 SBK-L- 11069 / Enclosure 1 In its response dated February 3, 2011, the applicant stated that its design is unique and can accommodate both fixed and movable incore detectors. The applicant also stated that since its Operating Cycle 5, the moveable incore detectors have not been used and were placed in a lay-up condition during Refueling Outage 7 (fall of 2000). The applicant also stated that since Refueling Outage 7, as part of a design change, the seal table tubing between the inner calibration tubing and the isolation valves has been removed and the inner calibration tube has been capped.

The applicant further stated that, based on the unique design features of the incore detectors, the aging effects managed by GALL AMP XI.M37, do not apply to Seabrook Station. The applicant also stated that the movable flux thimbles do not have a license renewal intended function and the line items referencing the flux thimble tubes will be deleted from LRA Tables 2.3.1-3 and 3.1.2-3.

Issue:

During its review of the applicant's responses to RAls 3.1.1-60-01 and 3.1.1-60-02, the staff noted that the flux thimbles for the moveable incore detectors, if left in a permanent lay-up condition, would not be subject to flow induced vibrations, and therefore would not be subject to wear. However the staff also noted that, under the plants CLB and design basis, the applicant has the option to place the movable incore detectors back in service and the flux thimbles will once again provide a pressure boundary function.

Request:

Since the applicant has the option to place the movable incore detectors back in service, justify the deletion of the AMR line items associated with cracking of the flux thimble tubes from LRA Table 3.1.2-3. Also, justify why an aging management program is not required to manage loss of material due to wear of the flux thimbles if the movable incore detectors were placed back into service.

NextEra Energy Seabrook Response:

Seabrook Station will make a commitment to ensure that the moveable detectors are not returned to service during the period of extended operation.

In Section A.3, the following new commitment is added:

NO. PROGRAM COMMITMENT UFSAR SCHEDULE or TOPIC LOCATION 65 Flux Implement measures to ensure that the N/A Priorto Thimble movable incore detectors are not returned enteringthe Tube to service during the period of extended period of operation. extended operation

United States Nuclear Regulatory Commission Page 5 of 43 SBK-L- 11069 / Enclosure 1 Additional Information Regarding the Design and Configuration of The Seabrook Station Incore Detector Assemblies Based on the teleconference held with the NRC on March 17, 2011, the following additional information is being provided regarding the design and configuration of the Seabrook Station incore detector assemblies.

The standard Westinghouse designed moveable incore detector system that is the subject of NRC Bulletin 88-09 consists of single walled thimble tubes into which the moveable incore detectors are inserted and withdrawn as required to obtain incore flux mapping data. The thimble tube walls serve as a RCS pressure boundary. The concern raised in this Bulletin is thimble tube wall thinning as a result of wear caused by flow induced vibration. The thimble tube wall thinning could potentially result in a degradation of the RCS pressure boundary and create a non-isolable RCS leak.

Seabrook Station's incore detector assemblies employ unique design features that provide multiple RCS pressure boundary barriers. Additionally, the tubes are fabricated from seamless Inconel 600, which is harder and more resistant to wear than stainless steel.

The following is a description of the Seabrook Station incore instrumentation system design and configuration.

Incore Detector Assembly Design OriginalIncore Detector Assembly Design:

The incore detector assembly utilizes a double-concentric tube design fabricated from seamless Inconel 600 material (see Attachment A). The incore detector assemblies consist of a thimble housing tube (outer tube) and a thimble calibrationtube (inner tube).

Incore detector assemblies are inserted into installed fuel assemblies at 58 core locations.

Installed within each incore detector assembly are five fixed self-powered flux detectors and one core exit thermocouple. The calibration tube was originally designed to provide a dry path through which a movable miniature neutron flux detector may be inserted. The five fixed self-powered incore flux detectors and one thermocouple are arranged in a spiral pattern within each incore detector assembly between the inner and outer tubes.

The incore flux detectors and core exit thermocouples are encased in seamless Inconel 600 sheathing that is continuous from the detectors and thermocouples positioned inside the reactor vessel to the secondary seal above the seal table. The movable miniature neutron flux detectors are available to scan the active length of the fuel assembly to provide remote readings of the relative flux distribution. These movable detectors are currently not being used, as discussed below.

United States Nuclear Regulatory Commission Page 6 of 43 SBK-L- 11069 / Enclosure 1 During normal power operation, the incore detector assemblies are fully inserted and stationary. They are manually retracted only under depressurized conditions during refueling or maintenance when the reactor vessel water level is below the vessel flange.

It is necessary to withdraw the incore detector assemblies about 14 feet to remove, reload, or shuffle fuel assemblies during the -refueling process and about 25 feet (below the bottom of the reactor vessel) in order to work on the vessel internals and for periodic in-service inspections.

When the incore detector assembly is inserted, the thimble housing tube (outer tube) provides the RCS pressure boundary to keep the incore detector assembly internal volume dry. Failure of this boundary will not affect the Class 1E core exit thermocouples as the core exit thermocouple sheath has been hydrostatically tested at RCS pressure and will prevent wetting of the thermocouple. The thimble calibration tube (inner tube),

although considered a RCS pressure boundary, is not in contact with reactor coolant or with reactor vessel components. In a single wall design, the thimble calibration tube is in contact with reactor vessel components, making it susceptible to wear. In the Seabrook Station double wall design, a failure of both the thimble housing tube and the thimble calibration tube would be required before reactor coolant could enter the thimble dry path (moveable detector path).

Layup of the OriginalMoveable Incore Detectors The movable miniature neutron flux detectors are currently not used and were placed in layup during Refueling Outage 7 (Fall of 2000). As part of the engineering change, the seal table tubing between the thimble calibration tube (inner tube) and the movable detector insertion path isolation valves was removed and the thimble calibration tubes were capped to provide a qualified reactor coolant system pressure boundary. All 58 incore detector assemblies were modified utilizing this design. Under this laid-up condition, in addition to failure of the thimble housing tube and the thimble calibration tube, this qualified pressure boundary cap would also have to fail before a non-isolable reactor coolant leak could occur (see Attachment A). The electronics of the fixed incore neutron detection portion of the system, along with the core exit thermocouples, were not affected by this engineering change and remain fully functional.

New Incore Detector Assembly Design:

The original fixed incore detector assemblies were not designed for the life of the plant and, therefore, a replacement program was developed. During Refueling Outage 13 (October 2009), two of the incore detector assemblies were replaced with an improved design. Replacement incore detector assemblies retain the double walled design and replicate the physical characteristics, specifications, and qualification of the original

United States Nuclear Regulatory Commission Page 7 of 43 SBK-L- 11069 / Enclosure 1 incore detector assemblies. However, there is one notable improvement in the new design. The replacement incore detector assembly thimble calibration tubes (inner tubes) are solid from the seal table to below the core support plate (i.e. there is no movable detector dry path). This design improvement eliminates the possibility of RCS leakage through the movable detector dry path. Seabrook Station plans to continue to replace the incore detector assemblies using this improved design until all 58 incore detector assemblies have been replaced.

Performance Monitoring of the Incore Detectors

1. A failure of the fixed incore detector system could result in the inability to meet incore power distribution mapping requirements. However, in accordance with the Seabrook Station Technical Requirements, only 75% of the detector locations, with a minimum of two detector locations per quadrant, need to be functional for the purpose of monitoring core power distribution.

Since there are 58 incore detector locations, the station must be able to map at least 44 locations with at least 2 in each core quadrant for the incore detector system to be considered functional.

Seabrook Station Technical Specifications contains core power distribution limiting conditions for operation and associated surveillance requirements. Heat Flux Hot Channel Factor and Nuclear Enthalpy Hot Rise Hot Channel Factor surveillance requirements require core power distribution mapping and analysis every 31 effective full power days (EFPD). If the surveillance requirements are not met, then the plant would be placed in Mode 2 (Startup) until the condition is corrected.

Seabrook Station Technical Specification also require the Power Range Neutron Flux Detectors be demonstrated operable every 31 EFPD when the power level is greater than 50% by performance of an Incore/Excore comparison and every 92 EFPD when power level is greater than 75% by performance of an Incore/Excore calibration. If the surveillance requirements are not met, then the plant would have to reduce power to 50% where the surveillance requirements do not apply. Because the limiting condition would be the power distribution limits, the plant would have to decrease power to less than 5%, Mode 2.

2. Core exit thermocouples (58 total) are used to provide post accident monitoring indications that are used for accident mitigation. Seabrook Station Technical Specifications require 8 core exit thermocouples per core- quadrant to support operability of the RCS subcooling margin monitor and a total of 44 core exit thermocouples to support operability of Reactor Vessel Level Indication System (RVLIS).

United States Nuclear Regulatory Commission Page 8 of 43 SBK-L-l 1069 / Enclosure I Seabrook Station Technical Specifications require that the core exit thermocouples be demonstrated operable every 31 days by performance of a channel check and every 18 months by performance of a channel calibration. During this surveillance, the number of thermocouples that are available in each quadrant is determined. If the minimum channels requirement are not met or restored in seven days, then the plant would be placed in Mode 4 (Hot Shutdown) until the condition is corrected.

Summary The design of the Seabrook Station Incore Detector Assemblies does not provide a potential path for a non-isolable RCS leak as presented in NRC Bulletin 88-09. The double wall characteristics of the design prevent the inner tubing, designed to allow insertion of movable incore neutron flux detectors, from contacting reactor vessel components. Such contact in single wall designs has shown to lead to wear and possible through wall leakage.

Although other plants also utilize a similar double wall design, the inner most tubing in those designs is used to accommodate the use of movable incore detectors. With movable incore detectors in place in the reactor vessel, a potential RCS leakage path exists if both the tubes (outer thimble housing tube and inner thimble calibration tube) develop through wall leaks. Leakage from this pathway would only be isolated by withdrawing the movable incore detectors and closing an in-line instrument valve at the seal table. By a design change implemented in 2000, Seabrook Station has placed the movable incore detector portion of this system in dry layup and capped the thimble calibration tubes (inner tubes) at the seal table, eliminating the possibility of a non-isolable RCS leak from this path.

The new design, when fully implemented, will permanently remove the potential RCS leak pathway as the hollow thimble calibration tube will be replaced with a solid rod from the seal table to a point inside the reactor vessel.

With both the current incore detector assembly configuration and the new design assemblies, the core exit thermocouples will remain functional even in the event of a through wall leak ih both the thimble housing tube and the thimble calibration tube. Each core exit thermocouple is encased in a seamless Inconel 600 sheath that has been pressure tested to RCS pressure. In the unlikely event of wear through both of the concentric tube walls followed by wear through the Inconel sheathing, the associated thermocouple would fail; however, such an event is not considered to affect multiple incore detector assemblies at the same time. Seabrook Station design allows for loss of up to 25% of the total number of thermocouples before the system function would be jeopardized.

United States Nuclear Regulatory Commission Page 9 of 43 SBK-L- 11069 / Enclosure 1 Conclusion The double wall design and the capping of all thimble calibration tubes at the seal table provides reasonable assurance that a potential for a non-isolable RCS leakage pathway does not exist from the incore detector assemblies. Additionally, the frequent verification (performance monitoring) of the availability of the incore detector assemblies provides reasonable assurance that the flux detectors and core exit thermocouples will perform such that the intended functions are maintained consistent with the current licensing basis during the period of extended operation.

United States Nuclear Regulatory Commission Page 10 of 43 SBK-L- 11069 / Enclosure 1 Attachment A Incore Detector Assembly Core Exit For illustrative purposes only; not to scale Pressure-retaining Thermocouple Cap

"/ 5 SPDF cables

& 1 TIC cable Electrical Connector Dry Path Cross Section Guide tube CONAX type Thimble N 4 'Electrical Seal housing Thimble dry path Thimble (movable detector path) tube Calibration Tube Thimble q(- High Pressure calibration Seal tube Compensation lead KP lead - Emitter lead Thimble KN lead, Self Powered Detector Housing lead (1 of 5)

Tube Core Exit Thermocouple Emitter at leading end Seal Table (Type K) cable of Self Powered Detector cable /I (seamless Inconel 600 sheath) Seal Table Typical W-* Section of Nozzle Guide Tube (welded to seal Self Powered table nozzle)

Fission Detector (SPFD) Emitter at NJNW--*

U about 10' Core Height U

United States Nuclear Regulatory Commission Page 11 of 43 SBK-L- 11069 / Enclosure 1 Request for Additional Information (RAI) 3.3.2.3.4-1

Background:

In its response to RAI 3.3.2.3.4-1, the applicant stated that the fiberglass piping components in the chlorination system exposed to raw water (LRA Table 3.3.2-4) are not subject to aging because they are constructed of either an epoxy resin or vinyl ester type of material for which the system's design temperature is below the aging limit of 170F.

Issue:

The staff noted that based on an independent review of corrosion data, chlorine can cause aging in either epoxy resin or vinyl ester based fiberglass components. The staff noted that the applicant's 2009 Environmental Monitoring Report (ADAMS Accession No. ML1033602980) states that the sodium hypochlorite level used for the circulating water system is 15%; however, the staff recognizes that the chlorine level in the in-scope fiberglass piping may not be as high as that in the storage tank, or the in-scope piping may not be associated with the sodium hypochlorite injection source. The staff cannot make a determination of no aging effects without knowing the chlorine level in the in-scope fiberglass piping.

Request:

State the chlorine concentration, in ppm, for in-scope piping components in the chlorination system and state why no aging effect will occur or propose an aging management program for the components.

NextEra Energy Seabrook Response:

Samples taken from the Chlorination system have shown chlorine levels of up to 5400 ppm.

This is the result of a 15% sodium hypochlorite injection into the sea water stream from either the discharge of the circulating water pumps or the discharge of the screen wash pumps. During normal power operation, the sea water temperature in these lines is below 65 'F and the pH is >_10.

With the exception of a segment of cement lined carbon steel pipe, the material selected for the piping within the scope of License Renewal that is exposed to chlorine is fiberglass reinforced vinyl ester or bisphenol-A polyester. Numerous vendor websites were searched for information on the suitability of the fiberglass reinforced vinyl ester or bisphenol-A polyester pipe in this service. A table on the Ashland Chemical website (Derakane Chemical Resistance Guide) for chlorine water, pH >9, with a concentration shown as "Sat'd C12" (saturated chlorine) showed that all brands in the table were suitable for use up to 150 *F or greater. Even for an environment of 0-10 weight percent hypochlorous acid (a deleterious product of the breakdown of sodium hypochlorite), maximum service temperature was at least 100 'F. Most of the available information was product line specific; however, information on vinyl ester or bisphenol-A materials generally shows that these fiberglass reinforced products are a good choice for chlorine service. The Fiberbond website provided the following for its product line for use in sodium hypochlorite (up to 15%): "Bis-A epoxy vinyl ester, such as Derakane 411 or Hetron 922, will perform better

United States Nuclear Regulatory Commission Page 12 of 43 SBK-L-1 1069 / Enclosure 1 than a novolac epoxy vinyl ester. Good up to 180F." The Fiber Glass Systems website also provides a product related chemical resistance guide. The maximum recommended service temperature for their fiberglass reinforced vinyl ester product in "chlorine water, saturated" is 180'F; in "sodium hypochlorite, 10-15%" the maximum recommended service temperature is 150 'F.

Based on these searches, these materials (fiberglass reinforced vinyl ester or bisphenol-A polyester) are appropriate for chlorination service, regardless of concentration, in systems operating at less than 150 'F. This conclusion was validated by a discussion with the Applications Engineering Manager for Fiber Glass Systems, the company that supplies much of the fiberglass and fiberglass reinforced pipe products to Seabrook Station.

The Application Engineering Manager for Fiber Glass Systems confirmed that the pipe specified for this system at Seabrook Station is appropriate for this application. During this discussion, the Applications Engineering Manager provided the following information.

- Chlorine levels in the delivery system (outside of the storage tank) in the range of 5 weight percent active chlorine would not adversely affect the piping.

- Factors that cause the sodium hypochlorite to break down to a hypochlorous acid are high temperature (above 150 TF), low pH (below 9), and exposure to direct sunlight/UV radiation.

- Hypochlorous acid can attack the epoxy based resins in fiberglass reinforced materials; however, the vinyl ester resins are less susceptible to attack from chlorine breakdown than the epoxy resin based fiberglass products.

- Given the materials and operating conditions, that exist at Seabrook Station (temperatures less than 65 'F, pH >9, no direct UV exposure), there is no reason to conclude that this is a potential aging effect at Seabrook Station.

Experience with the use of these materials in the Seabrook Station Chlorination System support this statement and point to these specific materials as being the appropriate material for this service and provides reasonable assurance that they will have no aging effects.

United States Nuclear Regulatory Commission Page 13 of 43 SBK-L- 11069 / Enclosure I Request for Additional Information (RAI) 4.3-1b

Background:

In its response to RAI 4.3-1 the applicant stated that the fatigue conformance of ASME Class 1 valves was demonstrated by performing an "umbrella" fatigue analysis of the piping system containing the valves (i.e., in accordance with ASME Section III, Subsection NB-3650). However, UFSAR Section 3.9(N).1.4(e) states that the pressure boundary portions of Class 1 valves in the reactor coolant system were designed and analyzed according to the valve design requirements of ASME Section III, NB-3500 (edition 1971 including 1972 Addenda).

Issue:

It is not clear why the fatigue analyses of Class 1 valves was performed in accordance with ASME Section III Subsection NB-3650, "Analysis of Piping Products," instead of the requirements of Subsection NB-3 500 as indicated in UFSAR Section 3.9(N). 1.4(e).

Request:

Clarify and explain why Class 1 valve fatigue conformance was demonstrated by performing an "umbrella" fatigue analysis using ASME Section III Subsection NB-3650 instead of Subsection NB-3500. Justify that the "umbrella" fatigue analysis using ASME Section III Subsection NB-3650 is equivalent to or more conservative than the NB-3500 analysis.

NextEra Energy Seabrook Response:

The pressure boundary portion of the ASME Class 1 valves in the reactor coolant system were designed and analyzed and qualified for service (including fatigue) in accordance with the rules of ASME Section III Subsection NB-3500, as stated in the UFSAR Section 3.9(N). 1.4(e). The Class 1 valves were also included as piping components in the piping analyses performed for the piping system in which the valves are installed. In this piping analysis, the piping rules of ASME Section III Subsection NB-3650 are used to design and analyze and qualify the piping system including piping components. Part of this piping analysis is an umbrella fatigue analysis which is performed using the maximum moment ranges that produce a computed fatigue usage value of 1.0 and then actual computed moment ranges for each load combination are demonstrated to be of equal or lower magnitude than the umbrella moment ranges, thus demonstrating that the fatigue usage is less than 1.0.

United States Nuclear Regulatory Commission Page 14 of 43 SBK-L- 11069 / Enclosure I Request for Additional Information (RAI) 4.3.1-lb

Background:

In its response to RAI 4.3.1-1, the applicant stated that in LRA Table 4.3.1-3, the rows for Unit Loading Between 0% and 15% Power and Unit Unloading Between 15% and 0%

Power were revised, and the 60-year projected cycles for Unit Loading and Unloading are 70 and 65, respectively.

Issue:

The revised values for the 60-year projected cycles for Unit Loading and Unloading between 0% and 15% Power are inconsistent with the projected values for the other transients. In LRA Table 4.3.1-3, all the projected values for other transients have been linearly extrapolated from 18.6-year to 60-year operation with a ratio of 3.22 or higher (the ratio between 60-year projected cycle and current number of cycle is 3.22). For Unit Loading and Unit Unloading transients, the ratios between 60-year projected cycle and current number of cycle are 2.6 and 2.5, respectively.

Request:

Provide the basis and justify the 60-year projected values for the Unit Loading and Unit Unloading transients.

NextEra Energy Seabrook Response:

In establishing the accumulated number of cycles through Q 12009 for the Unit Loading and Unloading between 0% and 15% Power transients, the manual cycle records used in the original baseline analysis showed lower than reasonable counts for these events. Thus, the number of Unloading between 0% and 15% Power events was increased to match the number of RCS heatup or cooldown events. A revised manual count based on actual cycle performance has determined that there have been 48 of each of the two events (Unit Loading between 0% and 15% Power and Unit Unloading between 15% and 0% Power) during the 13 operating cycles between the start of plant operation and October 2009 (18.6 years). A linear projection to 60 years has been made by applying the same ratio of counts to date for the first 18.6 years to the 60-year period. The 60 year projected counts of 155. is less than the design basis of 500.

The Unit Loading Between 0% and 15% Power and Unit Unloading Between 15% and 0%

Power transients will be identified and counted separately in the Fatigue Management Program to provide improved 60-year projections on an on-going basis.

Count of Events for the 13 cycles from start of plant operation to October 2009:

Unit Loading Between 0% and 15% Power = 48 Unit Unloading Between 15% and 0% Power = 48

United States Nuclear Regulatory Commission Page 15 of 43 SBK-L- 11069 / Enclosure 1 60-year projections:

Unit Loading Between 0% and 15% Power = 155 Unit Unloading Between 15% and 0% Power = 155 LRA Table 4.3.1-3 lines for Unit Loading Between 0% and 15% Power" and Unit Unloading Between 15% and 0% Power previously modified in response to RAI 4.3.1-1 provided in SBK-L-11015 (Reference 3) is revised as follows:

Current Cycles (through 60-Year NSSS Design Transient 4/1/2009 - 18.6 Projected Cycles Years of Cycles Operation)

Unit Loading Between 0% and 15% 2-7 -70 500 Power 48 155 Unit Unloading Between 15% and -26 6500 0% Power 48 155 Request for Additional Information (RAI) 4.3.1-2 Background and Issue:

For the "Feedwater Heaters Out of Service" transient in LRA Table 4.3.1-3, the number of nuclear steam supply system (NSSS) Design Cycles is "2000" with footnote (5) indicating that the original design analysis number is assumed to be the anticipated number of cycles at the end of the period of extended operation. However, the number of 60-year projected cycles for this transient is listed as "39" in the Table 4.3.1-3.

LRA Table 4.3.1-2 identified three Emergency Transients that are reactor coolant system design transients. The applicant did not provide the number of current cycles and the number of 60-year projected cycles for these three Emergency Transients in LRA Table 4.3.1-3.

Request:

(1) For consistency, revise LRA Table 4.3.1-3 to reflect the proper 60-year projected cycles for the "Feedwater Heaters Out of Service" transient or justify why footnote (5) is not applicable to this transient.

(2) Provide the number of current cycles and the number of 60-year projected cycles for the three Emergency Transients in LRA Table 4.3.1-3 or justify why cycle projections are not needed. Clarify whether these transients will be monitored under

United States Nuclear Regulatory Commission Page 16 of 43 SBK-L- 11069 / Enclosure 1 the Metal Fatigue of Reactor Coolant Pressure Boundary Program or justify why the transients need not be monitored.

NextEra Energy Seabrook Response:

(1) Table 4.3.1-3 shows the design number of nuclear steam supply system (NSSS) design cycles as 120 for the" Feedwater Heaters out of service" transient. This event is counted in the Fatigue Management Program and Footnote (5) has been removed.

Table 4.3.1-3 also shows the design number of nuclear steam supply system (NSSS) design cycles as 2,000 for the 'Feedwater Cycling at Hot Shutdown" transient. The Current Cycles (through 4/1/2009 - 18.6 Years of Operation) and 60-Year Projected Cycles are revised as shown below. This event is counted in the Fatigue Management Program and Footnote (5) has been removed.

LRA Table 4.3.1-3 as shown on page 4.3-10; lines for "Feedwater Heaters Out of Service" and "Feedwater Cycling at Hot Shutdown" is revised as follows:

Current Cycles (through 60-Year NSSS Design Transient 4/112009 - 18.6 Projected Cycles Years of Cycles Operation)

Feedwater Heaters out of service 12 39 120

• Feedwater Cycling at Hot 622-0--OO0 2,0000 Shutdown 192 (o 620 Footnotes:

(1) Prorated en the basis ef-as the ratio of four "Feedwater Heater out of service transients" to one "Unit Loading between 0% and 15% Power" transients, on the basis of the ratio of design numbers of 2,000 for the "Feedwater Cycling at Hot Shutdown" transient and 500 for the "Unit Loading between 0% and 15% Power" transient. -ef-the-design number-of events oeeuffing in 60 years-.

(5) The plant does not moiniter- these events. The original design analysis number-i assumed to be .yles anticipatcd number of at the end f the per-iod of extended operation. Cyeles shown in the curffent cc*les colum.n (.elun*2) represent a review of (2) The three Emergency transients are not part of the fatigue design basis for Seabrook, are thus not included in the Fatigue Management Program and were not included in Table 4.3.1-3. These three Emergency transients have not occurred to-date and are not expected to occur during the life of the plant. The current cycles for each of them is zero and the 60-year projected number of cycles for each of them is 1.

United States Nuclear Regulatory Commission Page 17 of 43 SBK-L- 11069 / Enclosure 1 Request for Additional Information (RAI) 4.3.3-lb

Background:

In its response to RAI 4.3.3-1 the applicant stated that the intent is to disposition fatigue of the vessel internals using 10 CFR 54.21 (c}(1}(i). The applicant added that, based on generic and plant-specific analyses, the following were identified as fatigue limiting locations: lower support columns, core barrel nozzle, lower core plate, and upper core plate. The fatigue cumulative usuage factor (CUFs) for these locations were all shown to be less than 1.0. The applicant further stated that the effects of fatigue at these locations will also be monitored by cycle counting under its Metal Fatigue of Reactor Coolant Pressure Boundary Program to verify that the number of design cycles assumed in the analyses will not be exceeded during the period of extended operation.

Issue:

The applicant did not update LRA Section 4.3.3 and applicable LRA Appendix A section reflecting that these TLAA have been dispositioned in accordance with 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1}(iii) using the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

Request:

For consistency in the LRA, revise LRA Section 4.3.3 indicating that, for the reactor vessel internal components, the TLAA disposition is in accordance with 10 CFR 54.21 (c}(l)(i) and 10 CFR 54.21 (c)(1)(iii) using the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

NextEra Energy Seabrook Response:

Based on the response to RAI 4.3.3-1 provided in SBK-L-11015, dated February 3, 2011 (Reference 3); LRA section 4.3.3 page 4.3-17 is revised as follows:

Fatigue Fatigue is defined as the structural deterioration that can occur as the result of repeated stress/strain cycles caused by fluctuating loads and temperatures. After repeated cyclic loading of sufficient magnitude, microstructural damage can accumulate, leading to macroscopic crack initiation at the most highly affected locations. Subsequent mechanical or thermal cyclic loading can lead to growth of the initiated crack.

Corrosion fatigue is included in the degradation description.

Low-cycle fatigue is defined as cyclic loads that cause significant plastic strain in the highly stressed regions, where the number of applied cycles is increased to the point where the crack eventually initiates. When the cyclic loads are such that significant plastic deformation does not occur in the highly stressed regions, but the loads are of such increased frequency that a fatigue crack eventually initiates, the damage accumulated is said to have been caused by high-cycle fatigue. The aging effects of

United States Nuclear Regulatory Commission Page 18 of 43 SBK-L- 11069 / Enclosure 1 low-cycle fatigue and high-cycle fatigue are additive. Fatigue crack initiation and growth resistance is governed by a number of material, structural and environmental factors, such as stress range, loading frequency, surface condition and presence of deleterious chemical species. Cracks typically initiate at local geometric stress concentrations, such as notches, surface defects, and structural discontinuities. The aging effect is cracking.

For design purposes, the American Society of Mechanical Engineers (ASME) Code Section III fatigue design procedures use a design fatigue curve that is a plot of alternatingstress range (SG) versus the number of cycles to failure (NI). The design fatigue curve is based on the unnotchedfatigue propertiesof the material,modified by reduction factors that account for various geometric and moderate environmental effects.

The fatigue usage factor (U) is defined by Miner's rule as the summation of the damage over the total number of design basis transient types (X), as given by the ratio of expected cycles of that type (n) to the allowable number of cycles (Nd for the stress ranges associatedwith that transient:

U = I ni X

i=1 Ni ForASME Code design acceptance, the cumulative usagefactor (CUF)calculatedin this manner cannot exceed unity (1.0) for the design lifetime of the component.

In accordance with the ASME Code at the time, CUF values were not calculatedfor the vessel internals as part of the originaldesign basis. However, generic analyses of Westinghouse-designed internals components have shown that the fatigue usage factors of the internals components are low and the number of fatigue sensitive locations is limited. In addition, a plant-specificfatigue analyses for the limiting vessel internals locations has been performedfor the Seabrook plant during power uprate, and from this analysis, the Seabrook plant limiting fatigue locations are:

Lower Support Columns, Core Barrel Nozzle, Lower Core Plate and Upper Core Plate. The effects of fatigue on these limiting locations will be monitored by cycle counting under the Seabrook Station FatigueMonitoringProgram during the period of extended operation to validate that the number of design cycles assumed in the analyses will not be exceeded.

Based on the response to RAI 4.3.3-1 provided in SBK-L-11015, dated February 3, 2011 (Reference 3); The disposition shown in LRA section 4.3.3 on page 4.3-19 is revised as follows to clarify the metal fatigue program will be used in conjunction with the Reactor Vessel Internals program to monitor the various effects of aging for the Reactor Vessel Internals.

United States Nuclear Regulatory Commission Page 19 of 43 SBK-L- 11069 / Enclosure 1 Disposition Validation, 10 CFR 54.21(c)(1)(i) - The Metal Fatigue of Reactor Coolant Pressure Boundary Program,B.2.3.1 will monitor the number of design cycles assumed in the Fatigue Analysis to assure that these will not be exceeded during the period of extended Operation.

~Aging Management, 10 CF-R 54.21(c)(1)(iii) The PAIR Vessel internals Progaram-,

B.2. 1.7 will manage the aging effcets ineluding changes in dimensions, cracking, loss of ffaetr-e"

... ÷ ... h .... , les

.... ef pfeea

• ^. ef.the Reate ,^ Vesse inteffias emponents fr,,-

In SBK-L-10192 dated November 15, 2010 (Reference 4); the disposition in Table 4.1-1 "Reactor Vessel Internal Aging Management" was changed from §54.21(c)(1)(iii) to

§54.21(c)(1)(i) to reflect the disposition Listed in Section 4.3.3. Based on the discussion above, Table 4.1-1 on page 4.1-5 is revised as follows:

Table 4.1-1 Time-Limited Aging Analyses Applicable to Seabrook Station TLAA Category Description Disposition LRA TLACteoyDscIto Method(s) Section

2. Metal Fatigue Of Piping And Components 4.3 Nuclear Steam Supply System (NSSS) Pressure Vessel and §54.21 (c)(1)(i) 4.3.1 Component Fatigue Analyses Supplementary ASME Section III, Class 1 Piping and Component §54.21(c)(1)(i) 4.3.2 Fatigue Analyses Absence of a TLAA for Thermal Stresses in Piping Connected to Reactor Coolant Systems: NRC Bulletin 88-08 NRC Bulletin 88-11, Pressurizer Surge Line Thermal Stratification §54.21 (c)(1)(i) 4.3.2.2 Reactor Vessel Internal Aging Management §54.21(c)(1)(i) 4*3.

Environmentally-Assisted Fatigue Analyses §54.21 (c)(1)(ii) 4.3.4

§54.21 (c)(1)(iii)

Steam Generator Tube, Loss of Material and Fatigue from Flow- §54.21 (c)(1)(i) 4.3.5 Induced Vibration Absence of TLAAs for Fatigue Crack Growth, Fracture Mechanics Stability, or Corrosion Analyses Supporting Repair of Alloy 600 N/A 4.3.6 Materials Non-Class 1 Component Fatigue Analyses §54.21(c)(1)(i) 4.3.7 Request for Additional Information (RAI) 4.1-1b

Background:

In its response to RAI 4.1-1, the applicant stated that a flow-induced vibration (FIV) analysis is not part of the CLB for its reactor vessel internal (RVI) components. Also, in its response to RAI 4.1-2, the applicant indicated that fluence-dependent reduction of fracture toughness of vessel internals is not analyzed as part of the current licensing design basis.

United States Nuclear Regulatory Commission Page 20 of 43 SBK-L- 11069 / Enclosure 1 Issue:

Part 1 -LRA Table 4.1-3 still indicates that an FIV analysis and loss of fracture toughness (ductility reduction) analysis are part of the CLB, and being TLAAs, for the RVI components and these analyses are addressed in LRA Section 4.3.3. The applicant did not revise LRA Table 4.1-3 to indicate that FIV and ductility reduction/loss of fracture toughness analyses are not TLAA. Furthermore, the staff noted that LRA Section 4.3.3 does not include any discussion regarding how the FIV and ductility reduction/loss of fracture toughness analyses factor into the CUF calculations for the RVI core support structure components.

Part2 -The response to RAI 4.1-1 indicated that there are "further analyses performed for the Seabrook Station reactor internals" for FIV of the RVI components. However, the applicant's response did not provide any comparison of these FIV analyses to the NRC's six criteria for time-limited aging analysis (TLAAs) in 10 CFR 54.3. Therefore, the staff cannot determine whether these further analyses need to be identified as TLAA for the LRA.

Request:

Part 1 -For consistency in the LRA, the staff requests that the applicant either revise LRA Table 4.1-3 to identify that FIV and ductility reduction/loss of fracture toughness analyses are not TLAAs and provide the justification for making these changes to LRA Table 4.1-3; or amend LRA Section 4.3.3 to clarify how the CUF calculations account for and bound any considerations of FIV in the RVI core support structures and/or reduction in ductility or fracture toughness properties for the materials that the core support structures are fabricated from.

Part2 -Provide the basis and justify why these further analyses for the RVI components not conform to the definition of a TLAA in 10 CFR 54.3.

NextEra Energy Seabrook Response:

Part1 LRA Table 4.1-2 as shown on page 4.1-7 is revised as follows to indicate that FIV and ductility reduction/loss of fracture toughness are not a TLAA requiring aging management as discussed in response to Part 2 of this RAI . However as detailed in LRA Appendix A and associated Commitment #1, The PWR Vessel Internals Program, B.2.1.7 will manage the aging effects including changes in loss of fracture toughness of the Reactor Vessel Internals components for the period of extended operation.

As discussed in response to RAI 4.3.3-1b, the Metal Fatigue of Reactor Coolant Pressure Boundary Program, B.2.3.1 will monitor the number of design cycles assumed in the Fatigue Analysis to assure that these will not be exceeded during the period of extended operation.

United States Nuclear Regulatory Commission Page 21 of 43 SBK-L- 11069 / Enclosure 1 Table 4.1-2 Review of Analyses Listed in NUREG-1800 Tables 4.1-2 and 4.1-3 LRA NUREG-1800 Examples N Seabrook to Applicability Section NUREG-1800, Table 4.1 Additional Examples of Plant-Specific TLAAs Flow-induced vibration endurance limit, for the reactor No vessel internals Transient cycle count assumptions for the reactor vessel Yes 4.3.3 internals Ductility reduction of fracture toughness for the reactor No vessel internals Part2 The evaluation of TLAA's for FIV and loss of fracture toughness of internals (from §54.3) is as follows:

Criteria for time-limited aging analyses for FIV of internals:

1) Involve systems, structures and components (SSCs) within the scope of license renewal - Yes

2) Consider the effects of aging - Yes

3) Involve time-limited assumptions defined by the current operating term (e.g., 40 years) - No

4) Were determined to be relevant by the licensee in making a safety determination

- No

5) Involve conclusions (or provide the basis for conclusions) regarding the capability of the SSCs to perform its intended functions - Yes

6) Are incorporated by reference in the CLB - No Therefore, FIV of internals is not a TLAA because it does not meet all six criteria.

Criteria for time-limited aging analyses for ductility reduction of fracture toughness of internals:

1) Involve systems, structures and components (SSCs) within the scope of license renewal - Yes

2) Consider the effects of aging - Yes

3) Involve time-limited assumptions defined by the current operating term (e.g., 40 years) - No

4) Were determined to be relevant by the licensee in making a safety determination

- No

5) Involve conclusions (or provide the basis for conclusions) regarding the capability of the SSCs to perform its intended functions - Yes

6) Are incorporated by reference in the CLB - No

United States Nuclear Regulatory Commission Page 22 of 43 SBK-L- 11069 / Enclosure 1 Ductility reduction of fracture toughness does not meet all six criteria. As discussed in Part 1 above, LRA Table 4.1-2 as shown on page 4.1-7 has been revised to indicate that FIV and ductility reduction/loss of fracture toughness is not a TLAA requiring aging management.

However, as detailed in LRA Appendix A and associated Commitment #1, the PWR Vessel Internals Program, B.2.1.7 will manage the aging effects including changes in loss of fracture toughness of the Reactor Vessel Internals components for the period of extended operation.

Request for Additional Information (RAI) 4.3.4-lb

Background:

In its response to RAI 4.3.4-1 request (1), the applicant clarified that the hot leg surge nozzle-to-pipe weld was evaluated to be the limiting location in the surge line. The staff notes that the surge nozzle-to-pipe weld consists of nozzle, nozzle-to-safe end weld, safe end, safe end-to-pipe weld, and the pipe.

Issue:

It is not clear to the staff whether the fatigue limiting CUF evaluations were performed for the nozzle-to-safe end weld or the safe end-to-pipe weld. In footnote (1) of Table 1 of the applicant's response to RAI 4.3-1, the highest fatigue usage location is identified as nozzle transition and safe end, whereas in Table 2 of the applicant's response to RAI 4.3.2-1 the highest fatigue usage location is identified as nozzle safe end-to pipe weld.

Furthermore, the staff notes that there are inconsistencies in the values of CUF listed in various tables:

- In LRA Table 4.3.4-1, for the hot leg surge nozzle-to-pipe weld, the 60-year CUFs is 0.2844 in air and 3.428 in reactor coolant environment. Fen is 12.05.

- In RAI 4.3.4-1 response, for the hot leg surge nozzle safe-end, the 60-year CUFs is 0.2844 in air and 3.2848 in reactor coolant environment. Fen is 11.55.

Request:

(1) Resolve or justify the inconsistencies in the reported values of CUF. Revise the LRA sections and Tables accordingly.

(2) Clarify the fatigue limiting location of the hot leg surge nozzle. Revise the LRA sections and Tables accordingly.

NextEra Energy Seabrook Response:

(1) Table 4.3.4-1 stated that the 60-year ASME air curve CUF for the hot leg surge nozzle-to-pipe weld is 0.2844 and the 60-year EAF-adjusted CUF is 3.428. The response to RAI 4.3.4-1 included an error in the value of the 60-year EAF-adjusted CUF. The incorrect value was 3.2848, instead of the correct value of 3.428. The LRA section and Table 4.3.4-1 are correct for both CUF and Fen.

United States Nuclear Regulatory Commission Page 23 of 43 SBK-L- 11069 / Enclosure 1 (2) The fatigue limiting location in the hot leg surge nozzle is the hot leg surge nozzle-to-surge line weld. There is no safe-end for this all-stainless steel configuration. The hot leg surge nozzle FEM is shown below. It includes the hot leg surge nozzle and nozzle-to- surge line weld.

LRA Table 4.3.4-1 as shown on page 4.3-22 is revised as follows

United States Nuclear Regulatory Commission Page 24 of 43 SBK-L-1 1069 / Enclosure 1 Request for Additional Information ('RAI) 4.3.5-lb

Background:

In LRA Section 4.3.5, the applicant described the TLAA for steam generator tube fatigue in the U-bend region resulting from flow-induced vibrations (FIV). In its response to RAI 4.3.5-1, the applicant amended its LRA Section 4.3.5. The amendment separated the original TLAA description into two LRA Sections: 4.3.5 to deal with fatigue and a new Section 4.7.15 to deal with wear -both caused by FIV. The applicant also changed the disposition of Section 4.3.5 to 10 CFR 54.2 1(c)(1)(iii).

Issue:

The staff notes that the applicant did not remove wear-related (loss of material) discussion in the amended Section 4.3.5. The staff also notes that the title of Section 4.3.5 remains unchanged, which still indicated the loss of material as part of the TLAA of Section 4.3.5.

With regard to the fatigue issue, the staff does not find the applicant's change of disposition of TLAA for steam generator tube fatigue due to the FIV acceptable. The staff notes that, with the existing fatigue evaluation in Section 4.3.5, the applicant demonstrated that the CUF is well below the acceptance value of 1.0 for the period of extended operation. The staff finds the 10 CFR 54.21 (c)(1 )(i) disposition appropriate for steam generator tube fatigue. The staff noted that the Steam Generator Tube Integrity Program cannot be substituted for an ASME Code Section III fatigue evaluation unless justifications are provided to demonstrate that the Steam Generator Tube Integrity Program addresses the fatigue-related CUF analysis.

The staff also could not confirm the adequacy of UFSAR supplement summary of the TLAA in Section 4.3.5 because the applicant did not amend the applicable UFSAR supplement description.

Request:

(a) Revise Section 4.3.5 and move the wear-related (loss of material) discussion to Section 4.7.15. Limit the title and discussion in Section 4.3.5 to the fatigue issue. Revise Table 4.1-1 to make it consistent with the revised text of 4.3.5.

(b) Justify the TLAA disposition of the steam generator tube fatigue due to FIV in accordance with 10 CFR 54.21 (c)(1)(iii), or revise the TLAA disposition of the steam generator tube fatigue TLAA due to FIV in accordance with 10 CFR 54.21 (c)(1 }(i).

(c) Provide an updated UFSAR supplement section LRA Appendix A consistent with the amended TLAA Section 4.3.5.

United States Nuclear Regulatory Commission Page 25 of 43 SBK-L-1 1069 / Enclosure 1 NextEra Energy Seabrook Response:

(a )&(b)

1) Based on response to RAI 4.3.5-1 and 4.3.5-2 provided in SBK-L-l11015 (Reference

3) and the addition of LRA Section 4.7.15; LRA Section 4.3.5 is revised as follows:

4.3.5 STEAM GENERATOR TUBE, LOSS OF MATERIAL AN FATIGUE USAGE FROM FLOW-INDUCED VIBRATION Summary Description The Seabrook Station Model F steam generators were evaluated with respect to flow induced vibration (tube wear and fatigue usage) for the power increases that were implemented as part of the Seabrook Station Power Uprates. The analysis of the effects of steam generator flow-induced vibration on tube wear and fatigue usage assumed 40 years of operation.

Analysis The m u peted tube wall wear- for-a 10 year . per-ating life was 0.032 inch for- the pr-e power- uprate conditions. As a result of the 560%4 incr-ease in the tube wear- r-ate as a result of the power-upr-ates, the maximumf 40 year tube wall wear is less than 0.0050 inch. The maximumn 60 year tube wall wear is 0.0075.

inch (- 20-0% through wall wear-). This -amfoluntof tube wall wear is less than the limnit of acceptability of 400% of wall thieleness and is deemed not to signifieantly affeet tueitgty Confirmation of the validity of the analyses to determine tube wear- is provided i the. eddy eufr-ent inspection program described in the Steam Generator Tube intcgrity Pr-ogramn (LRA Appendix B.2. 1.10). Steam Gener-ator tube inspection scope and frequency, pluggingo ear and leakage moeniteoring are in accor-dance with the Seabrooký S-tation Steam Generater- Tube Integr-ity Program implemented in accor-dance with NEI 97 06. As stated in the NRC Safety Evaluation for-Amendmnent No. 101 for- the Seabrooek Station, Unit No. 1, 5.20%4 Power Uprate,(Adams Accession No. .LO5

.110153),

-an.yincease in wear would progress over many cycles and would be readily obsern'ed dur-ing routinie eddy euFfent inspectios The evaluation showed that significant levels of tube vibration will not occur-from either-the fluidelastic or-tur-bulent mechanisms above those asseciated with the pre uprated condition.

United States Nuclear Regulatory Commission Page 26 of 43 SBK-L- 11069 / Enclosure I Low-cycle fatigue usage for the most limiting tube in the most limiting power-uprated operating condition resulting from the flow-induced vibration tube bending stress is 0.2 ksi. This value is well below the fatigue endurance limit of 20 ksi at lE+I 1 cycles, resulting in a computed fatigue usage of 0.0. High-cycle fatigue usage of U-bend tubes was evaluated. One of the prerequisites for high-cycle U-bend fatigue is a dented support condition at the upper plate. Seabrook Station steam generator tube support plates are manufactured from stainless steel therefore there is no potential for the necessary conditions to occur. It was concluded that the support condition leading to a dented support condition necessary for high-cycle fatigue cannot occur in the Model F steam generators.

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

~Aging Management, 10 CFR 54.2 1(c)(1)(iii) The effects of aging onth intended funetion(s) will be adequAtely managed for the period of exEtended oper-ation by the Steam Generator Tube integrity Program (B.2. 1.10), which manages the aging effects offlosso material due to wall thinning from flow.

accelerated ofrrosion of the Steam Generator eomponients.

2) Based on response to RAI 4.3.5-1 and 4.3.5-2 provided in SBK-L-1 1015 (Reference

3) and the addition of LRA Section 4.7.15; Table 4.1-1 page 4.1-5, is revised as follows:

Table 4.1-1 Time-Limited Aging Analyses Applicable to Seabrook Station TLAA Description Disposition LRA Category Method(s) Section

2. Metal Fatigue Of Piping And Components 4.3

§54.21 (c) (1)(i Steam Generator Tube, Loss.... ....... §54.2 ) , ,,ii 4.3.5 and-Fatigue from Flow-Induced Vibration * ..... -(ii 4.3.

(c)

1) Based on the revisions for LRA section 4.3.5 provided in (a) above, LRA Section A.2.4.2.4 as shown on page A-28 is revised as follows.

A.2.4.2.4. Steam Generator Tube, Loss of Material and Fatigue Usage from Flow-Induced Vibration The Seabrook Station Model F steam generators were evaluated with respect to flow induced vibration (tube wear- and fatigue usage) for the power increases that were implemented as part of the Seabrook Station Power Uprates. The analysis of the effects of steam generator flow-induced vibration on tube wear and fatigue usage

United States Nuclear Regulatory Commission Page 27 of 43 SBK-L- 11069 / Enclosure 1 assumed 40 years of operation Low-cycle fatigue usage for the most limiting tube in the most limiting poweruprated operating condition resulting from the flow-induced vibration tube bending stress is 0.2 ksi. This value is well below the fatigue endurance limit of 20 ksi at 1E+lI cycles, resulting in a computed fatigue usage of 0.0. cycle fatigue usage of U-bend tubes was evaluated. One of the prerequisites for high-cycle U-bend fatigue is a dented support condition at the upper plate. Seabrook Station steam generator tube support plates are manufactured from stainless steel therefore there is no potential for the necessary conditions to occur. It was concluded that the support condition leading to a dented support condition necessary for high-cycle fatigue cannot occur in the Seabrook Station Model F steam generators.

2) Based on the revisions for LRA section 4.3.5 provided in a) above, a new LRA Appendix A section A.2.4.5.12 is provided as follows:

A.2.4.5.12 STEAM GENERATOR TUBE WALL WEAR FROM FLOW-INDUCED VIBRATION The maximum predicted tube wall wear for a 40-year operating life was 0.0032 inch for the pre-uprate conditions. As a result of the 56% increase in the tube wear rate as a result of the power uprate analysis to 3659 MWth,, the maximum 40-year tube wall wear is less than 0.0050 inch. The maximum 60-year tube wall wear is 0.0075 inch (-20% through-wall wear) based on a linear time projection.

This amount of tube wall wear is less thian the limit of acceptability of 40% of wall thickness and is deemed not to significantlyaffect tube integrity.

The evaluation showed that significantlevels of tube vibration will not occurfrom either the fluidelastic or turbulent mechanisms above those associated with the pre-upratedcondition, thus justifying the linearprojection.

Request for Additional Information (RAI) 4.7.15-1

Background:

In its response to RAI 4.7.15-1, the applicant dispositioned the steam generator tube wear TLAA in accordance with 10 CFR 54.21(c)(1)(i). The applicant stated that the basis for its disposition of the wear TLAA was the stretch power uprate (SPU), from 3411 MWt to 3587 MWt, previously approved in staff s SER (ADAMS Accession No. ML050140453). The staff noted that the applicant received a 1.7% Measurement Uncertainty Recapture approval, from 3587 MWt to 3648 MWt, on May 22, 2006 (ADAMS Accession No. ML061360034).

United States Nuclear Regulatory Commission Page 28 of 43 SBK-L- 11069 / Enclosure 1 Issue:

The staff noted that the SPU approved in the staffs SER (ADAMS Accession No.

ML050140453) is for 5.2% power increase and it was discussed in the revised LRA Section 4.3.5. However, Section 4.7.15 indicated that the power uprate is 7.4%. It is not clear if the actual power uprate is for 5.2% or for 7.4%. The staff noted that, in the staff's SER for the SPU, tube wear increased from approximately 0.003 inches to approximately 0.005 inches at the 5.2% up rated condition.

The staff could not confirm the adequacy of UFSAR supplement summary for the TLAA for the Steam Generator Tubes wear due to FIV for Section 4.7.15 because the applicant did not add a new section in LRA Appendix A for LRA Section 4.7.15.

Request:

(a) Clarify or reconcile the actual power uprate applicable for the period of extended operation and amend LRA Sections 4.3.5 and 4.7.15 accordingly.

(b) Provide an updated UFSAR supplement section in LRA Appendix A consistent with the added TLAA Section 4.7.15.

NextEra Energy Seabrook Response:

(a) The power uprate referred to as the 5.2% stretch power uprate was based on an analysis for 3659 MW thermal. The thermal power achieved after the stretch and measurement uncertainty power uprates were implemented and the current licensed power for Seabrook Station Unitl is 3648 megawatts thermal. Revisions for LRA sections 4.3.5 and LRA Appendix A are provided in response to RAI 4.3.5-1b.

1) LRA section 4.7.15 previously provided in SBK-L-11015 is revised as follows.

4.7.15 STEAM GENERATOR TUBE WALL WEAR FROM FLOW-INDUCED VIBRATION Summary Description As previously discussed in Section 4.3.5, the Seabrook Station Model F steam generators were evaluated for tube wear from flow-induced vibration for the 7.41% p,;er .ncrea.e 3659 MW thermal. that was implemented as part of the Seabrook Station Power Uprates. The thermal power achieved after the stretch and measurement uncertainty power uprates were implemented and the current licensed power for Seabrook Station Unitl is 3648 megawatts thermal. The analysis of the effects of steam generator flow-induced vibration on tube wear assumed 40 years of operation.

United States Nuclear Regulatory Commission Page 29 of 43 SBK-L- 11069 / Enclosure I Analysis The maximum predicted tube wall wear for a 40-year operating life was 0.0032 inch for the pre-uprate conditions. As a result of the 56% increase in the tube wear rate as a result of the 7-.4% power uprate, the maximum 40-year tube wall wear is less than 0.0050 inch. The maximum 60-year tube wall wear is 0.0075 inch (-20% through-wall wear) based on a linear time projection. This amount of tube wall wear is less than the limit of acceptability of 40% of wall thickness and is deemed not to significantly affect tube integrity.

The evaluation showed that significant levels of tube vibration will not occur from either the fluidelastic or turbulent mechanisms above those associated with the pre-uprated condition, thus justifying the linear projection.

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

(b) Revisions for LRA sections 4.3.5 and LRA Appendix A are provided in response to RAI 4.3.5-lb.

Request for Additional Information (RAI) 4.3.7-lb

Background:

In its respond to RAI 4.3.7-1, the applicant stated that there are B3 1.1 piping, piping components, and piping elements that are within the scope of the license renewal.

Issue:

The applicant did not amend LRA Section 4.3.7 to include piping and piping components that were designed in accordance with B3 1.1 rules as part of the non-class 1 components.

The staff noted that that only ASME Section III Class 2 and 3 piping and piping components are considered as non-class 1 in LRA Section 4.3.7.

Request:

For consistency, revise LRA Section 4.3.7 and applicable LRA Appendix A Section indicating that piping and piping components that were designed in accordance with B3 1.1 rules are included as part of the Non-class 1 piping and piping components.

United States Nuclear Regulatory Commission Page 30 of 43 SBK-L- 11069 / Enclosure 1 NextEra Energy Seabrook Response:

For consistency with response provided in SBK-1 1015 (Reference 3), the following changes have been made to the License Renewal Application:

1) LRA Section 4.3.7 Non-Class 1 Component Fatigue Analyses as shown on page 4.3-27 is revised as follows.

Analysis In order to evaluate these TLAAs for 60 years, the number of cycles expected to occur within the 60-year operational period should be compared to the numbers of cycles that were originally considered in the design of these components. If the number of expected cycles does not exceed 7,000 cycles, the minimuim maximum number of cycles required that would not result in reduction of the allowable stress range, then there is no impact from the added years of service and the original analyses remain valid. If the total number of cycles exceeds 7,000 cycles, then additional evaluation is required.

The 60-year transient projection results shown in Table 4.3.1-3 for Seabrook Station show that even if all of the projected operational transients are added together, the total number of cycles projected for 60 years will not exceed 7,000 cycles.

Therefore, there is no impact upon the implicit fatigue analyses used in the component design for the systems designed to ASME Section III Class 2 and 3 requirements.

The Sample System thermal cycles do not trend along with operational cycles because sampling is required on a periodic basis, as opposed to an operational basis.

However, only the portion of the sampling lines that constitutes piping (and not tubing) need be considered here. In this case that the piping portion t'ma* out toebe is a very short section of piping directly connected to the RCS loop piping. Since this section of piping has no isolation valve and no bends, it is assumed to always to be exposed to primary loop temperature and pressure conditions. Similarly since there are no other external piping connections (only the tubing connection exits), the line will not experience any other externally applied loads. Therefore, that section of the sampling line that constitutes ASME Section III Class 2 and 3 piping will only experience the RCS loop transients which have already been shown to be less than 7,000 cycles and the line is, therefore, acceptable.

As shown in UFSAR Table 3.2-2 there are several sections of ANS Safety Class NNS (Non-Nuclear Safety) piping which the principaldesign code is B31.1 and are seismic Category L These piping, piping components or piping elements are within the scope of license renewal for a(2) as a failure could affect an a(1) classified component.

United States Nuclear Regulatory Commission Page 31 of 43 SBK-L- 11069 / Enclosure 1 The 60-year transientprojection results shown in LRA Table 4.3.1-3 for Seabrook Station show that even if all of the projected operational transients are added together, the total number of cycles projectedfor 60 years will not exceed the 7,000 cycles limit requiring reduction of the allowable thermal moment range in ASME Section III Class 2 and 3 and B31.1 rules. Therefore, there is no impact upon the implicitfatigue analyses used in the component design for the systems designed to ASME Section III Class 2 and 3 requirements. The same argument applies to the cyclic thermal cycles on the non-nuclear safety classified components (including B31.1) of these systems that are within the scope of license renewal.

2) LRA Section A.2.4.2.5 Non-Class 1 Component Fatigue Analyses as shown on page A-29 is revised as follows.

A.2.4.2.5 Non-Class 1 Component Fatigue Analyses This section describes fatigue-related TLAAs arising within design analyses of the Non-Class 1 piping and components. These piping and tubing components can be designed in accordance with ASME Section III Class 2 and 3.

The following non-Class 1 Seabrook Station systems that are in scope for license renewal were designed in accordance with ASME Section III Class 2 and 3, requirements: Reactor Coolant System (including primary loop piping and pressurizer surge line piping), Chemical and Volume Control System, Safety Injection System, Primary Component Cooling Water, Service Water, Sample System, Residual Heat Removal System, Main Steam System, Main Condensate and Feedwater, and the Steam Generator Blowdown System.

In order to evaluate these TLAAs for 60 years, the number of cycles expected to occur within the 60-year operational period should be compared to the numbers of cycles that were originally considered in the design of these components. If this number does not exceed 7,000 cycles, the maximum minimum number of cycles fequifed that would not result in reduction of the allowable stress range, then there is no impact from the added years of service and the original analyses remain valid. If the total number of cycles exceeds 7,000 cycles, then additional evaluation is required.

The 60-year transient projection results for Seabrook show that even if all of the projected operational transients are added together, the total number of cycles projected for 60 years will not exceed 7,000 cycles. Therefore, there is no impact upon the implicit fatigue analyses used in the component design for the systems designed to ASME Section III Class 2 and 3, requirements.

The Sample System thermal cycles do not trend along with operational cycles because sampling is required on a periodic basis, as opposed to an operational basis.

However, only the portion of the sampling lines that constitutes piping need be considered here. In this case that portion turs at te is a very short section of piping directly connected to the Reactor Coolant System (RCS) loop piping. Since

United States Nuclear Regulatory Commission Page 32 of 43 SBK-L- 11069 / Enclosure 1 this section of piping has no isolation valve and no bends, it is assumed to always be exposed to primary loop temperature and pressure condition. Similarly since there are no other external piping connections (only the tubing connection exits), the line will not experience any other externally applied loads. Therefore, that section of the sampling line that constitutes ASME Section III Class 2 and will only experience the RCS loop transients which have already been shown to be less than 7,000 cycles and the line is, therefore, acceptable.

As shown in UFSAR Table 3.2-2 there are several sections of ANS Safety Class NNS (Non-NuclearSafety) piping which the principal design code is B31.1 and are seismic Category I. These piping,piping components or piping elements are within the scope of license renewal for a(2) as a failure could affect an a(])

classified component.

As specified in LRA 4.3.7, the 60-year transientprojection results shown in LRA Table 4.3.1-3 for Seabrook Station show that even if all of the projected operationaltransients are added together, the total number of cycles projectedfor 60 years will not exceed the 7,000 cycles limit requiringreduction of the allowable thermal moment range in ASME Section III Class 2 and 3 and B31.1 rules.

Therefore, there is. no impact upon the implicit fatigue analyses used in the component design for the systems designed to ASME Section III Class 2 and 3 requirements. The same argument applies to the cyclic thermal cycles on the non-nuclear safety classified components (including B31.1) of these systems that are within the scope of license renewal.

The analyses remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

Request for Additional Information (RAI) 4.7.9-1b

Background:

In its response to RAI 4.7.9-1, the applicant stated that there is no specific aging effect identified for canopy seal clamp assemblies. The applicant stated that there is an aging effect identified for the Head Adapters since a fatigue analysis was developed using design transients over the current operating term. In LRA Section 4.7.9, the applicant stated that the canopy seal clamp assemblies were designed for a 40-year design life on the basis of meeting stress limits.

Issue:

From the review of LRA Table 3.1.2-2, the staff did not find an AMR line item that addresses head adapters and the associated aging effect. Furthermore, in the revised LRA Section 4.7.9, the applicant stated that the canopy seal clamp assemblies were designed for a 40-year design life and fatigue analysis is performed for the head adapters. The applicant has not identified, in the LRA, the relationship between the canopy seal clamp assemblies and the head adapters. The applicant also has not demonstrated how the head adapter's 60-

United States Nuclear Regulatory Commission Page 33 of 43 SBK-L-1 1069 / Enclosure 1 year evaluation support the canopy seal clamp assemblies design life basis of meeting stress limits. Furthermore, the UFSAR Supplement Appendix A.2.4.5.7 was not revised to reflect the change made to LRA Section 4.7.9 summary description.

Request:

(1) Identify the AMR line item, in the LRA Section 3 Tables, that is applicable to the head adapters or justify that an AMR line item is not needed for the head adapters.

(2) Clarify and explain how the head adapters' 60-year TLAA evaluation support the canopy seal clamp assemblies design life basis of meeting stress limits.

(3) Provide an updated UFSAR supplement section in LRA Appendix A consistent with the change in LRA Section 4.7.9.

NextEra Energv Seabrook Response:

(1) Head Adaptors as referenced in the subject calculation are also commonly referred to as the Canopy Seal Pressure Housing within Seabrook Design documents and are reflected in the AMR Table 3.1.2-2 REACTOR VESSEL on page 3.1-69 as reflected below.

anopy eal Pressure Stainless Reactor Reco Cumulative ressure Stail Coolant uuaieIV.A2-21 Fatigue TLAA (R-219) 3.1.1 ressure Boundary Steel (Internal) Damage lousing (2) In the revision to LRA 4.7.9 provided in response to RAI 4.7.9-1 in SBK-11015 (Reference 3), NextEra Energy Seabrook did not adequately reflect that the Head Adaptors (a/k/a Canopy Seal Pressure Housing ) were designed for a forty year life.

LRA Section 4.7.9 Analysis previously provided in the previous response to RAI 4.7.9-1 is further revised as follows.

4.7.9 CANOPY SEAL CLAMP ASSEMBLIES PRESSURE HOUSINGS Analysis In order to determine if the design analyses remain valid for 60 years of operation, the number of seismic cycles for 60 years has been projected. As of January 2010, the Seabrook Station Canopy Seal Clamps PressureHousings have been exposed to zero (0) Operating Basis Earthquake (OBE) cycles. It is projected that 1 OBE of 10 cycles would occur for Seabrook Station in 60 years of operation. Therefore, since the number of cycles in 60 years is well below the 20 sets of seismic movement.

cycles analyzed for these clamps, these design analyses remain valid for the period of extended operation.

United States Nuclear Regulatory Commission Page 34 of 43 SBK-L-1 1069 / Enclosure 1 LRA Table 4.1-1 as shown on page 4.1-6 is revised as follows.

Table 4.1-1 Time-Limited Aging Analyses Applicable to Seabrook Station TLAA Description Disposition LRA Category Method(s) Section

6. Plant-Specific Time Limited Aging Analyses 4.7 Canopy Seal Clamp A..semblis §54.21(c)(1)(i) 4.7.9 PRESSURE HOUSINGS (3) LRA Section A.2.4.5.7 on page A-34 of the LRA is revised as follows A.2.4.5.7 Canopy Seal Clamp Asscmblics PressureHousings The canopy seal clamp assemblies were designed for a 40 year design life on the basis of meeting stress limits. The original fatigue analysis considered the forces that would be applied to the center of the Canopy Seal-PressureHousings (a/k/a head adapter) which maximized the moments on the J-Grove weld and moment along the length of the adapter. The fatigue analysis for the Canopy Seal Clamps Pressure Housings is based on the consideration of 400 cycles consisting of 20 occurrences of the Operating Basis Earthquake, each occurrence having 20 cycles of maximum response. This design analysis is a TLAA requiring evaluation for the period of extended operation.

It is projected that 1 OBE would occur for Seabrook Station in 60-years of operation.

Since the number of occurrences projected for 60-years is below the plant design limit of 5 occurrences of 10 cycles the design analysis remains valid for the period of extended operation.

The analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

Request for Additional Information (RAI) 4.7.11-1b

Background:

In its response to RAI 4.7.11 dated February 3, 2011, the applicant stated that only normal service radiation exposure was subjected to a TLAA. The applicant clarified that it has a calculation of total integrated radiation dose design values for a 60-year plant life for various enviromnental zones and the calculation has been used to evaluate the 60-year dose impact on equipment in their respective zones. The applicant stated that the 60-year design dose values were compared to the current design dose limits of the equipment and it was determined that the 60-year dose limits are bounded by the existing equipment design dose limits. The applicant's disposition of this TLAA in accordance with 10 CFR 54.21 (c)(1)(ii)

United States Nuclear Regulatory Commission Page 35 of 43 SBK-L- 11069 / Enclosure 1 indicates that the effect of aging on the intended functions of equipment have been projected to be bounded by existing equipment design limits. The staff finds the disposition not acceptable because the existing analyses (equipment design dose limits) has not been revised and extended.

Issue:

While the applicant stated that the 60-year dose limits are bounded by the existing equipment design dose limit, it has not provided the projected 60-year doses for all the zones and the dose limits of the equipment within the scope of mechanical equipment qualification (MEQ). Without such information, the staff cannot evaluate the adequacy of the TLAA of normal service radiation exposure in MEQ. LRA Section 4.7.11, as amended by letter dated February 3, 2011, does not discuss the detail regarding the calculated dose limits and equipment design dose limits for normal service radiation exposure. Furthermore, the applicant did not amend Commitment No. 45. Commitment No. 45, as its currently stated, did not identify what portion of the MEQ files will be revised and what is the acceptance criteria of such revision.

The applicant demonstrated that the existing analyses (equipment design dose limits) are bounding for the projected 60-year doses for all zones. The staff noted that this demonstration of the normal service radiation exposure is consistent with a disposition in accordance with 10 CFR 54.21 (c)(1)(i). SRP-LR Section 4.7.3.1.1 states that for the disposition of 10 CFR 54.21 (c)(1)(i), the existing analyses should be shown to be bounding during the period of extended operation.

Request:

(1) Provide the design dose limits of the equipment within the scope of MEQ and the calculated total integrated radiation dose 60-year doses for all the zones to justify that TLAA of normal service radiation exposure in MEQ has been properly dispositioned.

(2) Amend LRA Section 4.7.11 and provide sufficient detail to support the TLAA disposition of normal service radiation exposure in MEQ. Revise Commitment No. 45 to identify the information to be revised and the acceptance criteria of the revision or justify why the existing Commitment No. 45 is acceptable.

(3) Amend the disposition of TLAA of normal service radiation exposure to MEQ to 10 CFR 54.21 (c)(1)(i) or justify why the existing TLAA disposition is acceptable. If LRA Section 4.7.11 is amended as a result of RAI 4.7.11-1b, provide an updated UFSAR supplement section in LRA Appendix A consistent with the revisions.

United States Nuclear Regulatory Commission Page 36 of 43 SBK-L-1 1069 / Enclosure 1 NextEra Energy Seabrook Response:

(1) For equipment within the scope of MEQ, the MEQ File No., component type, radiation limiting Environmental Zone, calculated 60 year total integrated dose and the MEQ qualified design dose limit for the equipment are tabulated in the following summary.

The calculated total integrated radiation 60 year doses are bounded by the existing equipment design dose limits.

United States Nuclear Regulatory Commission Page 37 of 43 SBK-L- 11069 / Enclosure 1 Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 1 045-02-01M FANS PB- Il 7.28E+6 1.9E+7 BOUNDED 2 173-0 I-01M VALVE BODIES PCE-2, PCW-2 9.95E+4 NOT SENSITIVE BOUNDED 3 173-01-01M ACTUATOR/OVERRIDE ASSEMBLY PCE-2, PCW-2 9.95E+4 4.OE+6 BOUNDED 4 173-01-O0M FILTER REGULATORS PCE-2, PCW-2 9.95E+4 5.OE+6 BOUNDED 5 173-01-01M PNEUMATIC POSITIONERS PCE-2, PCW-2 9.95E+4 9.23E+6 BOUNDED 6 173-01-02M PRESSURE REGULATORS PCE-3, PCW-3 9.95E+4 4.89E+6 BOUNDED 7 173-05-OIM PISTON ACTUATORS PB-I I *7.28E+6 1.5E+7 BOUNDED 8 173-05-01M BUTTERFLY VALVES PB-I l 7.28E+6 1.5E+7 BOUNDED 9 173-05-OIM PNEUMATIC POSITIONERS PB-I l 7.28E+6 9.23E+6 BOUNDED 10 173-05-01M FILTER REGULATORS PCE-2, PCW-2 9.95E+4 5.OE+6 BOUNDED 11 173-05-02M CONTROL VALVES PCE-2, PCW-2 9.95E+4 1.0E+6 BOUNDED 12 225-03-01M DAMPERS PB-I l 7.28E+6 NOT SENSITIVE BOUNDED 13 225-03-01M ACTUATORS PB-I l 7.28E+6 1.5E+7 BOUNDED 14 225-03-01M ACTUATORS CE-1 4.3E+6 5.OE+6 BOUNDED 15 225-05-OIM DAMPER ASSEMBLIES PB-II 2.32E+3 2.32E+3 BOUNDED/I

United States Nuclear Regulatory Commission Page 38 of 43 SBK-L- 11069 / Enclosure I Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 16 236-11-01M DAMPERS CS-13 1.43E+8 1.43E+8 BOUNDED/2 17 236-11-01M DAMPERS CE-i 4.3E+6 1.OE+7 BOUNDED 18 236-11-02M FANS CS-13 1.43E+8 NOT SENSITIVE BOUNDED 19 236-11-03M FAN ASSEMBLIES CE-i 4.3E+6 1.5E+7 BOUNDED 20 238-03-01M PUMPS EV-1A, EV-IB 3.41E+6 1.5E+7 BOUNDED 21 238-03-OIM MECHANICAL SEALS EV-IA, EV-1B 1.91E+7 1.OE+8 BOUNDED 22 238-03-OIM COUPLINGS EV-1A, EV-IB 2.07E+6 5.OE+6 BOUNDED 23 238-05-OIM PUMPS PB-il 2.32E+3 5.OE+6 BOUNDED 24 238-10-OiM FEEDWATER PUMPS EFW-1 1.5E+3 1.5E+3 BOUNDED/I 25 238-15-OIM PUMPS FSB-I 1.5E+3 I.OE+4 BOUNDED 26 248-05-01M PISTON ACTUATORS PB-8 1.5E+3 1.5E+4 BOUNDED 27 248-05-OIM BUTTERFLY VALVES PB-i I 7.28E+6 5.8E+7 BOUNDED 28 248-07-01M THERMAL RELIEF VALVES CS-10, CS-12 1.43E+8 NOT SENSITIVE BOUNDED 29 248-29-01M PLUG VALVE/BETTIS ACTUATOR PB-I l 2.32E+3 4.89E+6 BOUNDED 30 248-30-OIM DIAPHRAGM VALVES PB-9 2.2E+3 1.9E+7 BOUNDED

United States Nuclear. Regulatory Commission Page 39 of 43 SBK-L-1 1069 / Enclosure 1 Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 31 248-31-OIM VALVES PCE-3, PCW-3 9.95E+4 NOT SENSITIVE BOUNDED 32 248-36-OIM VALVE BODIES PCE-1, PCW-I 9.95E+4 NOT SENSITIVE BOUNDED 33 248-36-01M VALVE ACTUATORS PCE-1, PCW-1 9.95E+4 1.OE+6 BOUNDED 34 248-37-OIM CHECK VALVES CS-9, CS-10 4.4E+7 5.OE+7 BOUNDED 35 248-37-02M VALVES MPA-1 1.45E+8 NOT SENSITIVE BOUNDED 36 248-37-02M VALVES CS-12 1.43E+8 NOT SENSITIVE BOUNDED 37 248-37-02M VALVES PCE-2, PCW-2 9.95E+4 NOT SENSITIVE BOUNDED 38 248-37-02M VALVES PCW-3 9.95E+4 NOT SENSITIVE BOUNDED 39 248-37-02M PNEUMATIC OPERATORS PCE-2, PCW-2 9.95E+4 4.OE+6 BOUNDED 40 248-37-03M ACTUATORS CS-13 1.43E+8 1.43E+8 BOUNDED/2 41 248-37-03M ACTUATORS EV-5A, EV-5B 7.91 E+7 7.9 1E+7 BOUNDED/2 42 248-37-03M VALVE BODIES CS-10, CS-12, CS-13 1.43E+8 NOT SENSITIVE BOUNDED 43 248-37-04M GLOBE VALVES CS-10 1.43E+8 1.43E+8 BOUNDED/2 44 248-38-01M GLOBE VALVES PCE-I, PCW-I 9.95E+4 2.OE+8 BOUNDED 45 248-41-01M CHECK VALVES PB-I l 7.28E+6 NOT SENSITIVE BOUNDED

United States Nuclear Regulatory Commission Page 40 of 43 SBK-L- 11069 / Enclosure 1 Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 46 248-41-02M GATE VALVES MPA-I 1.45E+8 NOT SENSITIVE BOUNDED 47 248-41-03M GATE VALVES PB-9 2.2E+3 NOT SENSITIVE BOUNDED 48 248-45-01M BUTTERFLY VALVES CS-12 1.43E+8 2.0E+8 BOUNDED 49 248-45-OIM BUTTERFLY VALVES EV-5B1 7.91E+7 I.OE+8 BOUNDED 50 248-45-01M VALVE ACTUATORS CS-12 1.43E+8 1.43E+8 BOUNDED/2 51 248-45-O1M QUICK EXHAUST VALVES CS-10, CS-12 3.OE+7 3.5E+7 BOUNDED 52 248-58-OIM RELIEF VALVES CS-10 1.43E+8 NOT SENSITIVE BOUNDED 53 248-65-01M GATE VALVES PCE-2, PCW-2 9.95E+4 NOT SENSITIVE BOUNDED 54 248-65-01M GLOBE VALVES PCE-2, PCW-2 9.95E+4 NOT SENSITIVE BOUNDED 55 248-85-01M CHECK VALVES PCE-I, PCW-1 9.95E+4 NOT SENSITIVE BOUNDED 56 248-96-01M CHECK VALVES CS-10 4.4E+7 5.OE+7 BOUNDED 57 248-96-0 IM CHECK VALVES CS-13 1.34E+8 1.34E+8 BOUNDED/3 58 522-01-O0M AIR COOLERS CE-I 4.3E+6 6.0E+6 BOUNDED 59 600-00-01M CHECK VALVES CS-9 1.43E+8 NOT SENSITIVE BOUNDED 60 600-07-01M CHECK VALVES PB-8 1.5E+3 4.OE+6 BOUNDED

United States Nuclear Regulatory Commission Page 41 of 43 SBK-L-I 1069 /Enclosure I Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 61 600-09-01 M RUPTURE DISCS CS-13 1.43E+8 NOT SENSITIVE BOUNDED 62 DCR-91-059 CHECK VALVES CS-b0 4.4E+7 5.0E+7 BOUNDED 63 ECA 98118306 DAMPERS CE-1 4.3E+6 NOT SENSITIVE BOUNDED 64 N/A BUTTERFLY VALVES PB-8 1.5E+3 5.8E+7 BOUNDED 65 NSS-205-01M PUMPS PB-20A, PB-20B 4.21E+7 2.OE+8 BOUNDED 66 NSS-205-0IM PUMP SEALS PB-20A, PB-20B 4.2 1E+7 5.OE+7 BOUNDED 67 NSS-205-01M PUMP COUPLINGS PB-20A, PB-20B 1.47E+7 1.5E+7 BOUNDED 68 NSS-205-0IM SPEED INCREASING GEARS PB-20A, PB-20B 1.17E+7 3.37E+7 BOUNDED 69 NSS-205-02M PUMPS EV-3A, EV-3B 6.3 1E+7 6.3 1E+7 BOUNDED/3 70 NSS-205-03M PUMPS EV-4A, EV-4B 4.3 1E+7 2.OE+8 BOUNDED 71 NSS-205-03M PUMP SEALS EV-4A, EV-4B 4.3 1E+7 5.OE+7 BOUNDED 72 NSS-205-03M PUMP COUPLINGS EV-4A, EV-4B 1.37E+7 1.5E+7 BOUNDED 73 NSS-220-01M BUTTERFLY VALVES EV-6A, EV-6B 7.9 1E+7 NOT SENSITIVE BOUNDED 74 NSS-220-01M ACTUATORS EV-6A, EV-6B 7.9 1E+7 7.9 1E+7 BOUNDED/2 75 NSS-220-01M FILTER REGULATORS EV-6A, EV-6B 7.91E+7 7.91E+7 BOUNDED/2

United States Nuclear Regulatory Commission Page 42 of 43 SBK-L- 11069 / Enclosure 1 Mechanical Equipment Qualification Summary RAI 4.7.11 EQF RAD 60 YR TOTAL EQF CONCLUSION EQ FILE NO. COMPONENTS LIMITING ENV INTEGRATED QUALIFIED NOTE ZONE DOSE (RADS) DOSE (RADS) 76 NSS-220-01 M FILTERS EV-6A, EV-6B 7.91E+7 7.91E+7 BOUNDED/2 77 NSS-220-02M SWING CHECK VALVES CS-9, CS-l10 1.43E+8 NOT SENSITIVE BOUNDED 78 NSS-220-03M GATE VALVES CS-10 1.43E+8 NOT SENSITIVE BOUNDED 79 NSS-220-04M DIAPHRAGM ACTUATORS CS-10 1.43E+8 1.43E+8 BOUNDED/2 80 NSS-220-04M GLOBE VALVES CS-10 1.43E+8 NOT SENSITIVE BOUNDED 81 NSS-220-04M FILTER REGULATORS CS-10 1.43E+8 1.43E+8 BOUNDED/2 CS-5, CS-10, CS- 1l, CS-82 NSS-220-05M SAFETY/RELIEF VALVES 12 1.43E+8 1.43E+8 BOUNDED/2 83 NSS-220-05M RELIEF VALVES PB-I I 7.28E+6 3.OE+7 BOUNDED 84 NSS-220-06M GLOBE VALVES CS-10 1.43E+8 NOT SENSITIVE BOUNDED 85 NSS-220-07M RELIEF VALVES CS-11 1.43E+8 NOT SENSITIVE BOUNDED Note 1: Design dose values constitute a mild environment. No further material evaluation from an MEQ radiation qualification standpoint is required.

Note 2: These are fail-safe components such as pneumatic actuators, filters and filter regulators, all supplied with non-safety grade instrument air. As already concluded and documented in the MEQ files, the failure of the elastomers and other non-metallic items was determined to not affect accomplishment of the safety function of the component. On this basis, the MEQ file concluded that the qualified dose was equal to the design dose. The LR evaluation followed this methodology.

Note 3: Evaluation of these components was done using multiple sources of radiation qualification data, e.g. 2E 8 rads for similar material used in Valcor and ASCO solenoids. In lieu of establishing a specific higher value, the MEQ file simply concluded the qualified dose was at least equal to the design dose. The LR evaluation followed this methodology.

United States Nuclear Regulatory Commission Page 43 of 43 SBK-L- 11069 / Enclosure 1 (2) LRA Section 4.7-11 is to be revised as shown below, to Validation, 10 CFR 54.21(c)(1)(i) - The analysis remains valid for the period of extended operation.

Commitment No. 45 is being deleted, as the updating of MEQ files to reflect this validation is an internal design control commitment and will be tracked via the internal commitment tracking system.

(3) The disposition of this TLAA in LRA Section 4.7-11 is to be revised as shown below, to Validation, 10 CFR 54.21(c)(1)(i) - The analysis remains valid for the period of extended operation.

Based on the above discussion, the following changes are made to the LRA, as previously amended by SBK-L-11015, dated February 3, 2011, Enclosure 2, pages 36 & 37 of 47.

(Reference 3)

1) On page 4.1-6, Table 4.1-1, line item for Mechanical Equipment Qualification, is revised as follows:

Table 4.1-1 Time-Limited Aging Analyses Applicable to Seabrook Station TLAA Disposition Categor Description Method(s) LRA Section Mechanical Equipment Qualification §54.21lc 1I(ii)(i) I 4.7.11

2) On page 4.7-13, in Section 4.7.11, "Disposition" is revised as follows:

Disposition Revisien Validation, 10 CFR 54.21(c)(1)(ii)(i) - The effects of aging on the intended function(s) of equipment included under Mechanical Equipment Qualification have-been prejeeted-tbare bounded by existing equipment design limits, for the period of extended operation. G lte ... -< .................. ..

r..vised prior to entering the period

.per..Ai.n.

of extended

3) On page A-35, 5th paragraph in Section A.2.4.5.9 is revised as follows:

The effects of aging on the intended function(s) of equipment included under Mechanical Equipment Qualification have been projeeted to be are bounded by existing equipment design limits, in accordance with 10 CFR 54.21(c)(l)(ii)(i), for the period of extended operation. fale"latirns for Meehanie;l ipment

. "lige+; . .1 rcx'ised prior-to enter-ing the period of extended epcr-ation.

4) On page A-43, Commitment No. 45 is revised as follows.

45___.h_

_ __.__...

_ Revise e-chha*ni.-cal Equipment

,.

Mechanical E Qualification File.. Not Used A-.2-.4-69 P.-,r totc pertiod.o

[Withdrawn in letter SBK-L-11069] ........ oa.

Enclosure 2 to SBK-L- 11069 Changes to the Seabrook Station License Renewal Application Associated with NRC Staff Discussions

United States Nuclear Regulatory Commission Page 2 of 12 SBK-L-1 1069/ Enclosure 2 Changes to Section A.2.4.4 and 4.6.2 of the LRA Based on discussion with the Staff, containment penetration fatigue analysis has been clarified.

1) Section A.2.4.4 regarding Containment Penetrations, Page A-30 is revised as follows:

A.2.4.4 Fatigue of the Containment Liner and Penetrations The original design analysis for the Seabrook Station containment liner plate determined that all of the criteria specified in ASME Section III Article NE-3221.5(d) required for exemption from the requirement to perform a cyclic operation analysis were met. To address these 40-year cycles during the period of extended operation, a re-evaluation of the six fatigue exemption requirements utilizing anticipated 60-year stress cycles was performed. The result of this analysis determined that the specified conditions through the period of extended operation continue to satisfy the requirement for exemption from analysis for cyclic operation in accordance with in ASME Section III Article NE-3221.5(d). The analysis has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

Specific cyclic evaluations are listed in the Seabrook Station UFSAR Section 3.8.2.3 for the Personnel Airlock, Equipment Hatch and Fuel Transfer Tube therefore TLAAs are considered. The analyses for the Personnel Airlock, Equipment Hatch and Fuel Transfer Tube remains valid for the period of extended operation as the anticipated number of cycles anticipated during the period of extended operation is bounded by the originaldesign in accordancewith 10 CFR 54.21 (c)(1) (i).

2) The title of Section 4.6.2 as shown on page 4.6.2 is revised as follows 4.6.2.1 PRESSURIZATION PRESSU-RIZTAION CYCLES: PERSONNEL AIRLOCK, EQUIPMENT HATCH AND FUEL TRANSFER TUBE ASSEMBLY ABSENCE OF TLAA FOR CONTAINMENT PENETRATIONS

United States Nuclear Regulatory Commission Page 3 of 12 SBK-L-1 1069/ Enclosure 2 Change to Commitment No. 1 in Section A.3 of the LRA Based on discussion with the Staff, schedule for submitting the PWR Vessel Internals inspection plan to the NRC has been revised.

1) In Section A.3, Commitment No. I is revised as follows:

PROGRAM UFSAR No. PrOGRA or TOPIC COMMITMENT LOCAR LOCATION SCHEDULE I. PWR An inspection plan for A.2.1.7 Program to be implemented prior to Vessel Reactor Vessel Internals the period of extended operation.

Internals will be submitted for NRC Inspection plan to be submitted to review and approval at-least NRC not laterthan 2 years after twenty four m.onths prior to receipt of the renewed license or not

.ntr.ing the pe.i.d oe less than 24 months prior to the period extended epea...... ;of extended operation, whichever comes first.

Change to NextEra Energy Seabrook response to RAI 2.1-2 provided in letter SBK-L-11015 dated February 3, 2011 The following NextEra Energy Seabrook response replaces the response to RAI 2.1-2 provided in letter SBK-L- 11015 dated February 3, 2011.

Based on the teleconference held with the NRC on April 8, 2011, the tail pipes for the non-safety related relief valves have been added to the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction as follows:

1. Auxiliary Steam System (AS)

PID-1-AS-LR20569:

- Tail pipe for AS-V-74 at coordinate F-5 This is a drawing change only and does not affect the text or tables in the LRA.

2. Auxiliary Steam Condensate System (ASC)

PID-1-ASC-LR20926:

- Tail pipe for ASC-V-1394 at coordinate F-11 This is a drawing change only and does not affect the text or tables in the LRA.

3. Chemical and Volume Control System (CS)

PID-1-CS-LR20724:

- Tail pipe for CS-V-655 at coordinate F-5 Included in the scope of license renewal is the continuation of the tailpipe to the release recovery tank as shown on PID-1-RR-LR20061 at location F-3. Additionally,

United States Nuclear Regulatory Commission Page 4 of 12 SBK-L- 11069/ Enclosure 2 vent valve RR-V-23 (PID- 1-RR-LR20061 at location F-4), check valve NG-V-205 (PID- 1-RR-LR20061 at location E-5), and the one inch piping downstream of NG-V-205 are also in scope. Furthermore, relief valve RR-V-24 and the piping upstream and downstream of the relief valve is also in scope. Also included in scope is the continuation of the tail pipe for RR-V-24 as shown on PID-1-WLD-LR20223 at location G-8.

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

a) In Section 2.3.3.32, on page 2.3-222, the in-scope boundary description is revised as follows:

Release Recovery PID-1-RR-LR20061, PID-1-CS-LR20724, PID WLD-LR20223:

The Release Recovery license renewal scoping boundary consists of the Release Recovery tank and internal piping, a drain line and valve, and level instrument connections. Discharge piping from the letdown degasifier relief valve to the Release Recovery tank is in scope as well as NG-V-205 and the one inch piping downstream of NG-V-205. Relief valve RR-V-24 and the piping upstream and downstream of the relief valve is also in scope. the gas vent line and valves to the Chemical and Volume Controel Systcmf..

b) In Table 3.3.2-24, on page 3-3-382, the 1st and 2 nd rows are revised as follows:

Leakage Boundary (Spatial)

Air-Indoor External Piping and Pressure Steel Uncontrolled Loss of Surfaces VII-1-8 3.3.1-58 B Fittings Boundary (External) Material Monitoring (A-77)

Program Structural Integrity (Attached)

Leakage Boundary (Spatial)

Air With Boric Acid Piping and Pressure Steel Borated Water Loss of Corrosion V1I.1-10 3.3.1-89 A Fittings Boundary Leakage Material (A-79)

(External) Program Structural Integrity (Attached)

United States Nuclear Regulatory Commission Page 5 of 12 SBK-L-1 1069/ Enclosure 2 c) In Table 3.3.2-24, on page 3.3-382, the following new row is added after the 4 th row as follows:

Water Chemistry Piping and Leakage Treated Water Loss of Program VI.E-34 Fittings Boundary Steel (Internal) Material (S-O) 3.4.1-4 A (Spatial) One Time Inspection Program d) In Table 3.3.2-24, on page 3.3-384, the 2nd and 3rd rows are revised as follows:

Leakage Boundary (Spatial)

Air-Indoor External Valve Body Pressure Steel Uncontrolled Loss of Surfaces VII.1-8 3.3.1-58 B Boundary (External) Material Monitoring (A-77)

Program Structural Integrity (Attached)

Leakage Boundary (Spatial)

Air With Boric Acid Pressure Borated Water Loss of Corrosion VII.10 Valve Body sBoundar Steel Leakage Material Coram (A-79) 3.3.1-89 A (External) Program Structural Integrity (Attached) e) In Table 3.3.2-24, on page 3.3-384, the following new row is added after the 5 th row as follows:

Water Chemistry Leakage Treated Water Loss of Program VJILE-34 Valve Body Boundary Steel (Internal) Material One Time.(S-JOA (Spatial) One Time Inspection Program f) In Section 3.3.2.1.24, on page 3.3-39, the following environment is added to the list of environments after Treated Borated Water as follows:

0 Treated Water

United States Nuclear Regulatory Commission Page 6 of 12 SBK-L-l 1069/ Enclosure 2 g) In Section 3.4.2.2.2, on page 3.4-13, the 1 st full paragraph is revised as follows:

Seabrook Station will implement the One-Time Inspection Program, B.2.1.20, to verify the effectiveness of the Water Chemistry Program, B.2.1.2, to manage the loss of material due to general, pitting, and crevice corrosion in steel piping components exposed to treated water in the Auxiliary Steam, Auxiliary Steam Condensate, Chemical and Volume Control Condensate, Demineralized Water, Feedwater, Hot Water Heating, Nitrogen Gas, Primary Component Cooing Water, Reactor Make-Up Water, Release Recovery, Sample, and Steam Generator Blowdown systems. The Water Chemistry and One-Time Inspection Programs are described in Appendix B.

h) On Table 3.4.1, on page 3.4-22, line item 3.4.1-4 is revised as follows:

3.4.1-4 Steel piping, Loss of material Water Yes, Components in the Chemical and piping due to general, Chemistry and detection Volume Control, Demineralized components, pitting and One-Time of aging Water, Hot Water Heating, Primary and piping crevice Inspection effects is Component Cooling Water, Reactor elements corrosion to be Make-Up Water, Release Recovery, exposed to evaluated and Sample systems have been treated water aligned with this line number based on material, environment, and aging effect.

Consistent with NUREG-1801. The One-Time Inspection Program, B.2.1.20, will be used to verify the effectiveness of the Water Chemistry Program, B.2.1.2 to manage loss of material due to general, pitting, and crevice corrosion in steel piping components exposed to treated water in the Auxiliary Steam, Auxiliary Steam Condensate, Chemical and Volume Control, Condensate, Demineralized Water, Feedwater, Hot Water Heating, Nitrogen Gas, Primary Component Cooling Water, Reactor Make-Up Water, Release Recovery, Sample, and Steam Generator Blowdown systems.

See Subsection 3.4.2.2.2.1.

United States Nuclear Regulatory Commission Page 7 of 12 SBK-L- 11069/ Enclosure 2

4. Plant Floor Drain System (DF)

PID- 1-DF-LR20196:

- Tail pipe for DF-V-68 at coordinate D-10

- Tail pipe for DF-V-69 at coordinate D-3 The boundary includes the 4" pipe from the trench until it leaves the Diesel Generator Building.

This is a drawing change only and does not affect the text or tables in the LRA.

5. Diesel Generator System (DG) a) PID-1-DG-LR20461:

- Tail pipe for DG-V-271 at coordinate E-5 b) PID-1-DG-LR20466:

- Tail pipe for DG-V-272 at coordinate E-5 These are drawing changes only and do not affect the text or tables in the LRA.

6. Dewatering System (DW)

PID- 1-DW-20600:

- Tail pipe for DW-V-98 at coordinate G-8 This is a drawing change only and does not affect text or tables in the LRA.

7. Hot Water Heating System (HW)

Tail pipes for the following relief valves:

a) PID- 1-HW-LR20051:

- HWS-V- 146 at coordinate F- 12

- HWR-V-780 at coordinate D-12

- HWS-V-17 at coordinate F-9

- HWS-V- 111 at coordinate E-9

- HWS-V-20 at coordinate D-9

- HWS-V-25 at coordinate at C-9

- HWS-V-35 at coordinate B-9 b) PID-1-HW-LR20053:

- HWS-V-133 at coordinate F-6

- HWS-V-139 at coordinate E-6

- HWS-V-148 at coordinate D-6

- HWS-V-302 at coordinate D-8

- HWS-V- 160 at coordinate B-9

- HWS-V-166 at coordinate B-8

- HWS-V-173 at coordinate B-7

United States Nuclear Regulatory Commission Page 8 of 12 SBK-L- 11069/ Enclosure 2 c) PID-1-HW-LR20056:

- HWR-V-779 at coordinate G-12

- HWS-V-328 at coordinate G-10

- HWS-V-347 at coordinate F-7

- HWS-V-346 at coordinate F-7 These are drawing changes only and do not affect the text or tables in the LRA.

8. Steam Generator Blowdown System (SB)

PID-1-SB-LR20626:

- Tail pipe for SB-V-271 at coordinate G-7

- Tail pipe for SB-V-34 at coordinate G-6 Included in the scope of license renewal for 10 CFR 54.4(a)(2) is the continuation of the piping from both relief valves to WLD drain 262 as shown on PID- 1-WLD-LR20222 at location E- 10.

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

a) In Table 2.3.4-8, on page 2.3-315, the following new row is added after the 2 nd row as follows:

Drip Pan Leakage Boundary (Spatial) b) On Table 3.4.2-8, on page 3.4-100, the following new rows are added after the 4h row as follows:

9. Screen Wash System (SCW)

PID-1-SCW-LR20709:

- Tail pipe for SCW-V-54 at coordinate F-11 This is a drawing change only and does not affect the text or tables in the LRA.

United States Nuclear Regulatory Commission Page 9 of 12 SBK-L- 11069/ Enclosure 2

10. Spent Fuel Pool Cooling System (SF)

PID- 1-SF-LR20483

- Tail pipe for SF-V-205 at coordinate A-9 This is a drawing change only and does not affect the text or tables in the LRA.

11. Sample System (SS)

Tail pipes for the following relief valves:

a) PID-1-SS-LR20519

- SS-V-761at coordinate H-6

- SS-V-760 at coordinate H-7

- SS-V-827 at coordinate H-7 Included in the scope of license renewal for 10 CFR 54.4(a)(2) is the continuation of the piping up to and including valves SS-V-777 and SS-V-778 as shown on PID SS-LR20518 at location B-5.

b) PID-1-SS-LR20521

- SS-V-94 at coordinate H-10

- SS-V-95 at coordinate H-10

- SS-V-96 at coordinate H-Il

- SS-V-97 at coordinate H- 11

- SS-V-790 at coordinate H-5

- SS-V-791 at coordinate G-5

- SS-V-792 at coordinate F-5

- SS-V-793 at coordinate F-5 Included in the scope of license renewal for 10 CFR 54.4(a)(2) is the continuation of the piping to WLD drain 256 as shown on PID-1-WLD-LR20222 at location E-10.

These are drawing changes only and do not affect the text or tables in the LRA.

Change to NextEra Energy response to RAI 2.2.3.45-02 provided in letter SBK-L-11015 dated February 3, 2011 The following NextEra Energy response replaces the response to RAI 2.2.3.45-02 provided in letter SBK-L-1 1015 dated February 3, 2011:

Based on the teleconference held with the NRC on April 8, 2011, the tailpipe downstream of non-safety related relief valve WLD-V-83 as shown on PID-1-WLD-LR20218 (location H-

6) and PID-WLD-LR20219 (location F-4) have been added to the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction. Therefore, the continuation of the tailpipe from relief valve WLD-V-83 as shown on PID-WLD-LR20219 (location F-4) is within the scope of license renewal for 10 CFR 54.4(a)(2) and will remain colored Green on the drawing.

United States Nuclear Regulatory Commission Page 10 of 12 SBK-L- 11069/ Enclosure 2 Change to NextEra Energy Seabrook response to RAI 2.3.3.45-01 provided in letter SBK-L-11015 dated February 3, 2011 The following NextEra Energy response replaces the response to RAI 2.3.3.45-01 provided in letter SBK-L-11015 dated February 3,2011:

Based on the teleconference held with the NRC on April 8, 2011, non-safety related relief valve WLD-V-83 and the piping between WLD-V-83 and the reactor coolant drain tank, including the relief valve tailpipe as shown on PID- 1-WLD-LR20218 (locations G-6 and H-

6) have been added to the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction as follows:

1. WLD-V-83 and the piping between WLD-V-83 and the reactor coolant drain tank including the tailpipe downstream of WLD-V-83 as shown on PID-1-WLD-LR20218 (locations G-6 and H-6). Also included in the boundary is the 2" branch line and WLD-V-180.

This is a drawing change only and does not affect the text or tables in the LRA.

2. Included in the scope of license renewal for 10 CFR 54.4(a)(2) is the 1" Vent Gas system piping as shown on PID-1-PID-1-WLD-LR20218 (location H-5) at the WLD/VG system interface. This line continues on to PID-1-VG-LR20780 at location B-

6. At this location, VG-V-90 and the piping upstream and downstream of VG-V-90 is in scope of license renewal for 10 CFR 54.4(a)(2). Additionally, VG-V-84 and upstream piping as shown on PID-1-VG-LR-20780 (location B-6) is in scope of license renewal for 10 CFR 54.4(a)(2).

The addition of the above listed VG system components to the scope of license renewal under 10 CFR 54.4(a)(2) resulted in the following changes to the LRA text and tables as follows:

a) In Section 2.3.3.42, on page 2.3-260, the in-scope boundary description for the Hydrogenated Vent Header section is revised as follows:

PID-1-WLD-LR20218:

Beginning at the WLD/VG interface, the line continues on to PID-1-VG-LR20780 to the hydrogenated vent header.

PID-1-VG-LR20780:

The boundary begins in the cntainment at continuesfromn the reactor coolant drain tank through the isolation valve where it joins a line from the RCS evacuationskid isolation valve. The line continues to a support and through a containment isolation valve, containment penetration and continues out of the contaimnent through a containment isolation valve into the mechanical penetration area. The line continues outside the containment ending at a pipe support anchor.

United States Nuclear Regulatory Commission Page 11 of 12 SBK-L- 11069/ Enclosure 2 b) On Table 3.3.1, on pages 3.3-121 and 122, line item 3.3.1-91 is revised as follows.

Please note that line item 3.3.1-91 was previously revised in SBK-L-10204 dated December 17, 2010.

3.3.1-91 Stainless steel and Loss of material Water No Components in the Auxiliary Steam, steel with stainless due to pitting Chemist Chemical and Volume Control steel cladding and crevice System, Sample, Spent Fuel Pool piping, piping corrosion Cooling, and Waste Processing Liquid components, and Drains systems have been aligned to piping elements this line item based on material, exposed to treated enviromnent, and aging effect.

borated water Consistent with NUREG- 1801. The Water Chemistry Program, B.2.1.2, will be used to manage loss of material due to pitting and crevice corrosion of the following stainless steel components exposed to treated borated water:

a) Stainless steel piping components exposed to treated borated water in the Auxiliary Steam, Boron Recovery, Chemical and Volume Control, Nitrogen Gas, Reactor Make-Up Water, Release Recovery, Resin Sluicing, Sample, Spent Fuel Pool Cooling, Valve Stem Leak-Off, Vent Gas, Waste Gas, and Waste Processing Liquid Drains systems, b) Stainless steel heat exchanger components exposed to treated borated water in the Chemical and Volume Control, Spent Fuel Pool Cooling, and Waste Processing Liquid Drains system, c) Stainless steel tanks exposed to treated borated water in the Chemical and Volume Control, Sample, Spent Fuel Pool Cooling, and Waste I_ Processing Liquid Drains.

c) In Section 3.3.2.1.42, on page 3.3-62, the following environment is added to the list of environments as follows:

0 Treated Borated Water d) In Section 3.3.2.1.42, on page 3.3-62, the following program is added to the list of aging management programs as follows:

0 Water Chemistry Program(B.2.1.2)

United States Nuclear Regulatory Commission Page 12 of 12 SBK-L- 11069/ Enclosure 2 e) On Table 3.3.2-42, on page 3.3-499, the following new row is added after the 5th row as follows:

f) On Table 3.3.2-42, on page 3.3-501, the following new row is added after the 1 st row as follows:

Enclosure 3 to SBK-L-11069 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-l 1069 / Enclosure 3 A.3 LICENSE RENEWAL COMMITMENT LIST No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL Program to be implemented prior to the period of extended An inspection plan for Reactor Vessel Internals will be operation. Inspection submitted for NRC review and approval at least twenty-,fo* plan to be submitted to months prior to entering the period of extended operation. A.2.1.7 NRC not laterthan 2 1,PWR Vessel Internals years after receipt of the 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 Prior to the period of

2. Water cracking, loss of material and fouling when the in-scope A.2.1.12 Prirntotheperiod 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 LightA21.3etndoprin Load (Related to Enhance the program to list additional cranes for Prior to the period of 4.

Refueling) Handling monitoring. extended operation Systems ompressed Air Enhance the program to include an annual air quality test Prior to the period of

5. Coring requirement for the Diesel Generator compressed air sub A.2.1.14 extended operation Monitoring extendedopensystem.

United States Nuclear Regulatory Commission Page 3 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL

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. Enhance the program to include the performance of visual Prior to the period of Fire Protection inspection of fire-rated doors by a fire protection qualified A.2.1.15 extended operation.

inspector.

Enhance the program to include NFPA 25 guidance for

9. t Swhere 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-l 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL 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 Fire Water System a representative number of inspections have been A.2.1.16 the period of extended performed prior to the period of extended operation. If a representative number of inspections have not been operation.

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 Prior to the period of

12. Aboveground Steel effects required by the Aboveground Steel Tanks. A.2.1.17 extended operation.

Tanksexeddoeain

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

.Fuel Oil Chemistry tank at least once per quarter and to remove water as extended operation.

necessary. I

United States Nuclear Regulatory Commission Page 5 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL Enhance the program to require draining, cleaning and Prior to the period of

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

frequency of at least once every ten years. extended operation.

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

placed in storage.

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 the period 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.

United States Nuclear Regulatory Commission Page 6 of 13 SBK-L-l 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL 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.

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 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.

24. Buried Piping And Tanks Implement the Buried Piping And Tanks Inspection Within ten years prior to Inspection Program. A.2.1.22 entering the period of 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 one-Time A.2.1.23 the period of extended SmE Code-Classg 1 Small Bore-Piping Program.operation.

United States Nuclear Regulatory Commission Page 7 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL 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.

Inspection of Internal 2.Surfaces in Pirt h eido

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

Components

28. Enhance the program to add required equipment, lube oil Prior to the period of Lubricating Oil Analysis analysis required, sampling frequency, and periodic oil A.2.1.26 extended 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 Prirntotheperiodo collection tanks. collctin taks.extended operation.

Enhance the program to require the performance of a one-

30. Lubricating Oil Analysis time ultrasonic thickness measurement of the lower portion A.2.1.26 Prior to the period 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 Prior to the period of Program locations, inspection frequency and ultrasonic test A.2.1.31 extended operation.

requirements.

United States Nuclear Regulatory Commission Page 8 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL

33. Structures Monitoring Enhance procedure to include inspection of opportunity Prior to the period of Program when planning excavation work that would expose A.2.1.31 extended operation.

inaccessible concrete.

Electrical Cables and Connections Not Subject Implement the Electrical Cables and Connections Not

34. to 10 CFR 50.49 Prior to the period of Environmental Subject to 10 CFR 50.49 Environmental Qualification A.2.1.32 extended operation.

Qualification Requirements program.

Requirements 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 Prirntotheperiodo 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 I th I P Prior to the period of Environmental 10 CFR 50.49 Environmental Qualification Requirements A.2.1.34 extended operation.

Qualification program.

Requirements

37. A.2.1.35 Prior to the exte period of e perion.

Metal Enclosed Bus Implement the Metal Enclosed Bus program.

extended operation.

38. Fuse Holders Implement the Fuse Holders program. A.2.1.36 Prior exte to the period of e perion.

extended operation.

United States Nuclear Regulatory Commission Page 9 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL Electrical Cable Connections Not Subject Implement the Electrical Cable Connections Not Subject to

39. to 10 CFR 50.49 10 CFR 50.49 Environmental Qualification Requirements A.2.1.37 extended operation.

Environmental porm xeddoeain Qualification program.

Requirements

40. 345 KV SF Bus Implement the 345 KV SF 6 Bus program. A.2.2.1 Prior to the exte period of e perion.

6 I 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.

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.

Boundary components.

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 CFR 50 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 Environmentally- have been evaluated for the effects of the reactor coolant At least two years prior to

44. Assisted Fatigue environment on fatigue usage are the limiting components A.2.4.2.3 entering the period of Analyses (TLAA) for the Seabrook plant configuration. If more limiting extended operation.

components are identified, the most limiting component will be evaluated for the effects of the reactor coolant environment on fatigue usage. If the limiting location

United States Nuclear Regulatory Commission Page 10 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE identified consists of nickel alloy, the environmentally-assisted fatigue calculation for nickel alloy will be performed using the rules of NUREG/CR-6909.

(1) Consistent with the Metal Fatigue of Reactor Coolant Pressure Boundary Program Seabrook Station will update the fatigue usage calculations using refined fatigue analyses, if necessary, to determine acceptable CUFs (i.e.,

less than 1.0) when accounting for the effects of the reactor water 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, 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).

hanial Equipment se hanEquipmet Qualifiation Files. Not Pri9 tothe period of QulfaenUsed [Withdrawn in letter SBK-L- 11069] J_______ extended operation.

United States Nuclear Regulatory Commission Page' 1I of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION SHDL 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 Coang Coating Equipment needed for limited to, flashlight, inspection spotlights, may include, marker but not be pen, mirror, Prior to the prto period of Pr.otetoivean A.2.1.38 etne Maintenance measuring tape, magnifier, binoculars, camera with or extended operation without wide angle lens, and self sealing polyethylene sample bags."

Protective Coating Prior

48. Monitoring and Enhance the program to include a review of the previous Arior exte to the period of e perion

48. Maintenance two monitoring reports. A.2.1.38 extended operation 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.

Perform UT testing of the containment liner plate in the A.2.1.27 No later than December

50. ASME Section Xl, vicinity of the moisture barrier for loss of material. 31, 2015 and repeated at intervals of no more than Subsection IWE five refueling outages ASME Section Xl, Perform confirmatory testing and evaluation of the Prior to the period of

51. Subsection IWL Containment Structure concrete A.2.1.28 extended operation ASME Section XI, Implement measures to maintain the exterior surface of the

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

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

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

ksi with ones that do not exceed 150 ksi. extendedoperation.

United States Nuclear Regulatory Commission Page 12 of 13 SBK-L-l 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR 'SCHEDULE LOCATION SHDL 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

54. Steam Generator Tube eliminate PWSCC-susceptible tube-to-tubesheet welds, A.2.1.10 to NRC at least 24 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.

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 Revise the station program documents to reflect the EPRI Prior to entering the Closed-Cycle Cooling

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

Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the

57. Water System Guideline operating ranges and Action Level values for A.2.1.12 periodof 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 Nickel Alloy Nozzles and The Nickel Alloy Aging Nozzles and Penetrations program Prior to the period of

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

staff accepted industry guidelines.

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

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

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

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

United States Nuclear Regulatory Commission Page 13 of 13 SBK-L-1 1069 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSARTIO LOCATION SHDL 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.

Ensure that the quarterly CVCS Charging Pump testing is continued during the PEO. Additionally, add a precaution to

63. Flow Induced Erosion the test procedure to state that an increase in the CVCS N/A Prior to the period of Charging Pump mini flow above the acceptance criteria extended operation may be indicative of erosion of the mini flow orifice as described in LER 50-275/94-023.

Soil analysis shall be performed prior to entering the period of extended operation to determine the corrosivity of the Prior to entering the

64. Buried Piping and Tanks soil in the vicinity of non-cathodically protected steel pipe A.2.1.22 period of extended Inspection within the scope of this program. If the initial analysis operation.

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

Implement measures to ensure that the movable incore Priorto entering the

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