ML110330202

Seabrock - License Amendment Request 10-06, to Revise Technical Specification (TS) Section 6.7.6.k, Steam Generator (SG) Program, & TS 6.8.1.7, Steam Generator Tube Inspection Report, for Temporary Alternate Repair Criteria

ML110330202
Person / Time
Site:	Seabrook
Issue date:	01/27/2011
From:	Freeman P NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-0234
Download: ML110330202 (36)

Text

SEXTeraB ENER(---7Y Y_ .January 27, 2011 10 CFR 50.90 SBK-L-10234 Docket No. 50-443 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Seabrook Station License Amendment Request 10-06 License Amendment Request to Revise Technical Specification (TS)Sections 6.7.6.k, "Steam Generator (SG) Program," and TS 6.8.1.7, "Steam Generator Tube Inspection Report," for Temporary Alternate Repair Criteria In accordance with the provisions of Section 50.90 of Title 10 of the Code of Federal Regulations (10 CFR), NextEra Energy Seabrook, LLC (NextEra) is submitting License Amendment Request (LAR) 10-06 for an amendment to the Technical Specifications (TS) for Seabrook Station. NextEra proposes to revise TS 6.7.6.k, "Steam Generator (SG) Program," to exclude portions of the SG tubes below the top of the SG tubesheet from periodic inspections during refueling outage 14 (OR14) in the spring of 2011 and the subsequent inspection cycle. In addition, this amendment request proposes to revise TS 6.8.1.7 "Steam Generator Tube Inspection Report." The scope of SG tube inspections planned for OR14 is limited to +/-3 inches from the top of the tubesheet on the hot leg side to detect outside diameter stress corrosion cracking (ODSCC).However, if the inspection in OR14 detects the presence of primary water stress corrosion cracking (PWSCC) in the tubesheet region, then an expansion to the full depth of the tube sheet would be required unless an alternate repair criterion is approved by the NRC.In a conference call on November 9, 2010, the NRC staff discussed that approval of the requested amendment would first require confirmation that the condition of the tubes within the tubesheet is consistent with the condition of tubes at other plants that have been granted a similar temporary license amendment.

Consequently, the enclosed evaluation of the proposed change discusses NextEra's plan to perform full depth tube inspections to provide additional support for the requested amendment if required.

If PWSCC is detected during the limited SG tube NextEra Energy Seabrook, LLC, P.O. Box 300, Lafayette Road, Seabrook, NH 03874 United States Nuclear Regulatory Commission SBK-L-10234

/ Page 2 inspections scheduled for OR14, NextEra will perform additional full depth tube inspections and request approval of the proposed change by April 15, 2011, and implementation within 30 days.The Enclosure to this letter provides NextEra's evaluation of the change and a markup of the TS showing the proposed change. As discussed in the evaluation, the proposed change does not involve a significant hazards consideration pursuant to 10 CFR 50.92, and there are no significant environmental impacts associated with the change. A copy of this LAR has been forwarded to the New Hampshire State Liaison Officer pursuant to 10 CFR 50.91 (b). The Station Operation Review Committee has reviewed this LAR.On October 13, 2009, the NRC issued Amendment No. 123 to the Seabrook Station TS, which provided one-time alternate repair criteria for portions of the SG tubes within the tubesheet.

As discussed in the request for this amendment, NextEra met the following commitments during refueling outage 13 in the fall of 2009: 1. NextEra Energy Seabrook, LLC commits to monitor for tube slippage as part of the steam generator tube inspection program. Slippage monitoring will occur for each inspection of the Seabrook Station Steam Generators.

2. For the Condition Monitoring assessment, the component of operational leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.50 and added to the total accident leakage from any other source and compared to the allowable accident induced leakage limit. For the Operational Assessment, the difference between the allowable accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.50 and compared to the observed operational leakage. An administrative operational leakage limit will be established to not exceed the calculated value.Commitment 1 regarding slippage monitoring is deleted for OR14 due to the limited SG tube inspections.

Commitment 2 Will remain in effect.Should you have any questions regarding this letter, please contact Mr. Michael O'Keefe, Licensing Manager, at (603) 773-7745.Sincerely, NextEra Energy Seabrook, LLC Paul Freeman Site Vice President United States Nuclear Regulatory Commission SBK-L-10234

/ Page 3

Enclosure:

NextEra Energy Seabrook's Evaluation of the Proposed Change cc: NRC Region I Administrator G*. E. Miller, NRC Project Manager W. J. Raymond, NRC Senior Resident Inspector 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 Mr. John Giarrusso, Jr., Nuclear Preparedness Manager The Commonwealth of Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399 ENERGX SEABROOK AFFIDAVIT The following information is enclosed in support of this License Amendment Request:* NextEra Energy Seabrook's Evaluation of the Proposed Change I, Paul Freeman, Site Vice President of NextEra Energy Seabrook, LLC hereby affirm that the information and statements contained within this license amendment request are based on facts and circumstances which are true and accurate to the best of my knowledge and belief.Sworn and Subscribed bef _me this grv day of -k, LLO 2011 Notary Public Paul Freeman Site Vice President Enclosure

Subject:

License Amendment Request to Revise Technical Specification (TS) Sections 6.7.6.k, "Steam Generator (SG) Program," and TS 6.8.1.7, "Steam Generator Tube Inspection Report," for Temporary Alternate Repair Criteria 1.0

SUMMARY

DESCRIPTION

2.0 DETAILED

DESCRIPTION

3.0 TECHNICAL

EVALUATION

4.0 REGULATORY EVALUATION

4.1 Applicable

Regulatory Requirements/Criteria

4.2 Significant

Hazards Consideration

4.3 Conclusion

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

ATTACHMENT 1 -Markup of the Technical Specifications 1

1.0

SUMMARY

DESCRIPTION NextEra Energy Seabrook, LLC (NextEra) proposes to revise Seabrook Station Technical Specification (TS) 6.7.6.k, "Steam Generator (SG) Program," to exclude portions of the SG tubes below the top of the SG tubesheet from periodic inspections during refueling outage 14 (OR14) in the spring of 2011 and the subsequent inspection cycle. In addition, this amendment request proposes to revise TS 6.8.1.7,"Steam Generator Tube Inspection Report." The scope of SG tube inspections planned for OR14 is limited to +3 inches from the top of the tubesheet on the hot leg side to detect outside diameter stress corrosion cracking (ODSCC). However, if the inspection in OR14 detects the presence of primary water stress corrosion cracking (PWSCC) in the tubesheet region during the planned inspections, then an expansion to the full depth of the tube sheet would be required unless an alternate repair criterion is approved by the NRC. As a result, approval of this amendment application is requested by April 15, 2011 if PWSCC is detected during the limited tube inspections planned for OR14.The proposed changes to the TS are based on supporting structural analysis and leakage evaluations completed by Westinghouse Electric Company, LLC (Westinghouse).

The documentation supporting the Westinghouse analysis, which is described in section 3.3, provides the technical basis for this change. Westinghouse WCAP -17330-P, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity," November 2010 [Reference 8], Table 5-1, provides the 95/95 whole plant H* value of 15.2 inches for plants with Model F steam generators, which includes NextEra.The NRC has previously issued NextEra the following amendments related to SG inspection and repair requirements: " Amendment Number 112 [Reference 1] excluded the need to plug SG tubes with degradation found in the portion of the tubes below 17 inches from the top of the hot leg tubesheet during refueling outage 11 and the subsequent operating cycles.* Amendment Number 123 [Reference 2] revised TS 6.7.6.k "Steam Generator (SG) Program," to exclude portions of the SG tubes within the tubesheet from periodic inspections (established alternate repair criteria).

In addition, this amendment revised TS 6.8.1.7, "Steam Generator Tube Inspection Report," to provide reporting requirements specific to refueling outage 13 and the inspection required by TS 6.7.6.k.d.

The proposed change will prevent unnecessarily plugging tubes in the Seabrook Station SGs by limiting application of the SG tube inspection and repair criteria to the portion of the tubes from the top of the tubesheet to 15.2 inches below the top of the 2 tubesheet, the safety significant portion of the tubes. The analysis of this change provides a high level of confidence that the structural and leakage performance criteria of the safety significant portion of the tubes are maintained during nonrnal operating and accident conditions.

NextEra committed to monitor for tube slippage as part of the SG tube inspection program in refueling outage 13 [Reference 2]. This commitment has been deleted for OR14 based on the limited tube inspection plan.2.0 DETAILED DESCRIPTION The proposed changes to the TS are shown below (deleted text is struck through and added text is italicized):

TS 6.7.6.k.c.

Provisions for SG tube repair criteria.

Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.The following alternate tube repair criteria shall be applied as an alternative to the 40% depth based criteria: 1. For refueling outage 1-3 14 and the subsequent inspection cycle, if the number of tubes with service-induced flaws located greater than 15.2 inches below the top of the tubesheet is less than or equal to 5% of the total tubes inspected, then tubes with service-induced flaws located greater than 1-34 15.2 inches below the top of the tubesheet do not require plugging.

Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 1-34 15.2 inches below the top of the tubesheet shall be plugged upon detection.

2. For refueling outage 14 and the subsequent inspection cycle, if the number of tubes with flaws located below 15.2 inches from the top of the tubesheet is greater than 5% of the total tubes inspected in any SG, the following applies to the affected SG: a. Tubes with flaws having a circumferential component greater than 203 degrees found in the portion of the tube below 15.2 inches from the top of the tubesheet and one inch from the bottom of the tubesheet shall be removedfrom service. When more than one flaw with circumferential components is found in the portion of the tube below 15.2 inches from the top of the tubesheet and above one inch from the bottom of the tubesheet 3 with the total of the circumferential components greater than 203 degrees and an axial separation distance of less than one inch, then the tube shall be removedfrom service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

b. When one or more flaws with circumferential components are found in the portion of the tube within one inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service. When one or more flaws with circumferential components are found in the portion of the tube within one inch from the bottom of the tubesheet and within one inch axial separation distance of a flaw above one inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

3. For refueling outage 14 and the subsequent inspection cycle, tubes with axial crack indications located greater than 15.2 inches below the top of the tubesheet do not require plugging.TS 6.7.6.k.d Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria.

For refueling outage 4-3 14 and the subsequent inspection cycle, the portion of the tube below 4-34 15.2 inches from the top of the tubesheet is excluded from this requirement.

The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d. 1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection.

An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

4 TS 6.8.1.7 i. For refueling outage 4-3 14 and the subsequent inspection cycle, the primary to secondary leakage rate observed in each SG (if it is not practical to assign the leakage to an individual SG, the entire primary to secondary leakage should be conservatively assumed to be from one SG)during the cycle preceding the inspection which is the subject of the report, j. For refueling outage 1-3 14 and the subsequent inspection cycle, the calculated accident induced leakage rate from the portion of the tubes below 4-34 15.2 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 2.50 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, k. For- r ,efueling outage 13, the results of for- tu.be axial displacement (slippage).

if slippage is discover-ed, the implications of the discover-y and corrective action shall be provided-.

3.0 TECHNICAL

EVALUATION

3.1 Background

Seabrook Station is a four loop Westinghouse designed plant with Model F SGs having 5626 tubes in each SG. A total of 173 tubes are currently plugged in all four SGs. The design of the SG includes Alloy 600 thermally treated tubing, full depth hydraulically expanded tubesheet joints, and stainless steel tube support plates with broached hole quatrefoils.

The SG inspection scope is governed by TS 6.7.6.k, Steam Generator (SG)Program; Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines

[Reference 3]; EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines

[Reference 4]; EPRI 1012987, Steam Generator Integrity Assessment Guidelines

[Reference 5]; Seabrook Station"Steam Generator Management Reference Manual"; and the results of the degradation assessments required by the SG Program. Criterion IX, "Control of Special Processes," in 10 CFR Part 50, Appendix B, requires in part that nondestructive testing be accomplished by qualified personnel using qualified procedures in accordance with the applicable criteria.

The inspection techniques and equipment are capable of reliably detecting the known and potential specific degradation mechanisms applicable to Seabrook Station.The inspection techniques, essential variables, and equipment are qualified to 5 Appendix H, "Performance Demonstration for Eddy Current Examination" of the EPRI Steam Generator Examination Guidelines

[Reference 4].Catawba Nuclear Station, Unit 2, (Catawba) reported indication of cracking following nondestructive eddy current examination of the SG tubes during their fall 2004 outage. NRC Information Notice (IN) 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," [Reference 6], provided industry notification of the Catawba issue.IN 2005-09 noted that Catawba reported crack like indications in the tubes approximately seven inches below the top of the hot leg tubesheet in one tube, and just above the tube-to-tubesheet welds in a region of the tube known as the tack expansion in several other tubes. Indications were also reported in the tube-end welds, also known as tube-to-tubesheet welds, which join the tube to the tubesheet.

NextEra's policies and programs, as well as TS 6.7.6.k, require the use of applicable industry operating experience in the operation and maintenance of Seabrook Station. The experience at Catawba, as noted in IN 2005-09, shows the importance of monitoring all tube locations (such as bulges, dents, dings, and other anomalies from the manufacture of the steam generators) with techniques capable of finding potential forms of degradation that may be occurring at these locations (as discussed in Generic Letter 2004-001,"Requirements for Steam Generator Tube Inspections").

Since the Seabrook Station Westinghouse Model F SGs were fabricated with Alloy 600 thermally treated tubes similar to the Catawba Unit 2 Westinghouse Model D5 SGs, a potential exists for Seabrook Station to identify tube indications similar to those reported at Catawba within the hot leg tubesheet region if similar inspections are performed during OR14. -Potential inspection plans for the tubes and tube welds underwent intensive industry discussions in March 2005. The findings in the Catawba SG tubes present two distinct issues with regard to the SG tubes at Seabrook Station: 1) Indications in internal bulges and overexpansions within the hot leg tubesheet, and 2) Indications at the elevation of the tack expansion transition.

Prior to each SG tube inspection, a degradation assessment, which includes a review of operating experience, is performed to identify degradation mechanisms that have a potential to be present in the Seabrook Station SGs.A validation assessment is also performed to verify that the eddy current techniques utilized are capable of detecting those flaw types that are identified in the degradation assessment.

Based on the Catawba operating experience, NextEra revised the SG inspection plan for the fall 2006 refueling outage 6 (ORI 1) to include sampling of bulges and over expansions within the tubesheet region down to 17 inches from the top of the tubesheet on the hot leg side. The sample was based on the guidance contained in EPRI 1003138,"Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 7, and TS 6.7.6.k, Steam Generator (SG) Program. According to EPRI SG examination guidelines, the inspection plan is expanded if necessary due to confirmed degradation in the region required to be examined (i.e. a tube crack). PWSCC was not detected during the OR 1I examination.

In refueling outage 13 (fall 2009), the SG inspection plan included a sampling of bulges and over expansions within the tubesheet region on the hot leg side down to the depth of 13.1 inches below the top of the tubesheet.

PWSCC was not detected in the tubesheet region in outage 13.As a result of these potential issues and the possibility of unnecessarily plugging tubes in the Seabrook Station SGs during the OR14 inspections, NextEra is proposing changes to TS 6.7.6.k to limit the steam generator tube inspection and repair (plugging) to the portion of tubing from the top of the tubesheet to 15.2 inches below the top of the tubesheet.

3.2 SG Inspections During Refueling Outage 14 (OR14) in the Spring 2011 At the conclusion of the fall 2009 refueling outage, NextEra had met all periodic SG inspection requirements for the current 90 effective full power month's inspection period. During the 2009 inspection, however, a single ODSCC indication was detected at the top of tubesheet in one tube in SG-C.As a result of this condition, TS 6.7.6.k.d.3 reduces the maximum interval between inspections from two operating cycles to one operating cycle, and the TS requires inspection for the specific degradation mechanism that caused the crack indication (i.e., ODSCC). The scope of tube inspections planned for OR14 is limited to +3 inches from the top of the tubesheet on the hot leg to detect ODSCC. However, if the inspection in OR14 detects the presence of PWSCC in the tubesheet region during the planned inspection, then an expansion to the full depth of the tube sheet would be required unless an alternate repair criterion is approved by the NRC.In a phone call with the NRC on November 9, 2010, NextEra discussed its plans for limited SG inspections during OR14 and the potential need for a temporary amendment if PWSCC is detected.

The NRC stated that a full depth inspection of a portion of tubes within the tubesheet would be required to confirm that the condition of the tubes within the tubesheet is consistent with the condition of tubes at other plants that have been granted a similar temporary license amendment.

7 Based on the January 10, 2011 public conference call regarding this proposed change, this request proposes an alternate repair criteria for crack indications below the H* depth of 15.2" from the top of the tubesheet.

This repair criteria would be invoked for crack-like flaws below the H* depth only if the total number of tubes with crack indications is greater than 5% of the tubes inspected.

The NRC previously approved such alternate repair criteria, which is referred to as the Interim Alternate Repair Criteria (IARC), for use at Vogtle, Millstone 3, and Wolf Creek, plants with steam generators similar to Seabrook.

The IARC technical bases did not rely on contact pressure for the H* depth; however, this submittal justifies the use of contact pressure between the tube and tubesheet.

Therefore, applying the IARC repair criteria for cracks below the H* depth of 15.2 inches below the top of the tubesheet is conservative.

To provide additional support for approval of the requested amendment, NextEra proposes to expand the scope of SG inspections and repair as outlined below if PWSCC is detected during SG inspections in OR14.a. If PWSCC is detected in the expanded area of the tubing within the tubesheet on the hot leg side, then tube inspections will expand to 15.2 inches below the top of the tubesheet in 100% of the tubes on the hot leg side in the affected SG and in 20% of the tubes on the hot leg side in each unaffected SG.In addition, if PWSCC is detected in the expanded area of the tubing within the tubesheet on the hot leg side, a 20% sample of tubes will be inspected full depth from top of tubesheet to the end of the tube on the hot leg side in all steam generators.

b. If cracks are detected below the H* depth of 15.2 inches from the top of the tubesheet on the hot leg side in more than 5% of the tubes inspected, then full depth inspections will expand to 100% of the tubes on the hot leg side in the affected steam generator.

c. For crack indications located below 15.2 inches from the top of the tubesheet:

1. Tubes with axial cracks do not require plugging.2. If cracks are detected in less than or equal to 5% of the tubes inspected in a steam generator, then the tubes do not require plugging.3. If cracks are detected in greater than 5% of the tubes inspected, the tubes will be removed from service as required by the criteria proposed in the change to TS 6.7.6.k.c.2.

8

3.3 Licensing

Basis Analysis (H*Analysis)

On May 28, 2009, NextEra submitted Westinghouse WCAP-17071-P, Revision 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F),"[Reference 9] as Attachment 4 of a request to change TS 6.7.6.k, "Steam Generator (SG) Program," to support implementation of a permanent alternate repair criterion for steam generator tubes [Reference 17].On August 13, 2009, NextEra received a request for additional information (RAI) regarding the SG program [Reference 14], which contained 24 questions.

On September 1, 2009, NextEra received a second RAI [Reference 15], which clarified previously received RAI questions

1. 4, #21, and #24, and added RAI #25.On September 16, 2009, NextEra provided responses

[Reference 18] to questions 1 through 25 of the August 13, 2009 and September 1, 2009 letters and included the following documents:

Westinghouse letter LTR-SGMP-09-100 P-Attachment, Revision 0,"Response to NRC Request for Additional Information on H*; Model F and Model D5 Steam Generators," August 12, 2009 [Reference 10], and Westinghouse letter SGMP-09-109-P Attachment, Revision 0"Response to NRC Request for Additional Information on H*; RAI#4; Model F and Model D5 Steam Generators," August 25, 2009[Reference 11].On September 18, 2009, NextEra submitted a request [Reference 19] to revise the permanent alternate repair criteria amendment request [Reference 17] to a one-time change applicable to refueling outage 13 and the subsequent inspection cycle. This request was made in response to a September 2, 2009 teleconference between NRC staff and industry personnel, in which the NRC staff indicated that their concerns with eccentricity of the tube sheet tube bore in normal and accident conditions (RAI question 4 of the September 1, 2009 letter) have not been resolved.On December 23, 2009, the NRC provided a letter documenting the currently identified and unresolved issues relating to tubesheet bore eccentricity

[Reference 16]. This letter contained 14 questions which required resolution before the NRC could complete its review of a permanent amendment request.WCAP-17330-P, Rev. 0, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity, November 2010 [Reference 8]; LTR-SGMP 9 78 P-Attachment, "Effects of Tubesheet Bore Eccentricity and Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H*," September 7, 2009 [Reference 13]; and LTR-SGMP-10-33 P-Attachment,"H* Response to NRC Questions Regarding Tubesheet Bore Eccentricity," September 13, 2010 [Reference 12] have been prepared by Westinghouse to provide final resolution of the remaining questions identified in the December 23, 2009 NRC letter in support of a permanent H* amendment request. LTR-SGMP-10-78 P-Attachment was submitted to the NRC by Westinghouse in letter LTR-NRC-10-68 on November 9, 2010. LTR-SGMP-10-33 P-Attachment was submitted to the NRC by Westinghouse in letter LTR-NRC-10-70 on November 11, 2010.WCAP-17330-P, Rev. 0, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity, November 2010 [Reference 8] makes reference to Revision 2 of WCAP- 17071-P and Revision 1 of LTR-SGMP-09-100 P-Attachment.

As described above, NextEra previously submitted Revision 0 of these documents.

These revisions (Revisions 1 and 2 of WCAP- 17071 -P, Revision 1 of LTR-SGMP-09-100 P-Attachment) were created to resolve editorial comments.

The technical information contained in WCAP-17071-P, Revision 0 and LTR-SGMP-09-100 P-Attachment, Revision 0, remains valid and provides part of the licensing basis for the requested amendment.

As a condition for approving Amendment No. 123 to the Seabrook Station TS[Reference 2], the NRC required a commitment to measure the location of the bottom of the expansion transition (BET) relative to the top of the tubesheet (TTS) and report any significant deviations from the constant 0.3 inch value already included in the calculated value(s) of H*. LTR-SGMP-09-1 11 P-Attachment, Rev. 1, "Acceptable Value of the Location of the Bottom of the Expansion Transition (BET) for Implementation of H*" was prepared to support plant determinations of BET measurements and their significant deviation assessment.

LTR-SGMP-09-1 11 P-Attachment was submitted to the NRC by Westinghouse in letter LTR-NRC- 10-69 on November 10, 2010[Reference 20].A summary of the H* licensing bases documents is provided in Table 1 below.Table 1 Document Revision Title Reference Number Number Number WCAP- 0 H*: Alternate Repair Criteria for the Tubesheet 9 17071-P Expansion Region in Steam Generators with 10 Hydraulically Expanded Tubes (Model F)," LTR- 0 Response to NRC Request for Additional Information 10 SGMP on H*; Model F and Model D5 Steam Generators 100 P-Attachment LTR -0 Response to NRC Request for Additional Information 11 SGMP on H*; RAI #4; Model F and Model D5 Steam 109-P Generators Attachment WCAP- 0 H*: Resolution of NRC Technical Issue Regarding 8 17330-P Tubesheet Bore Eccentricity LTR- 0 Effects of Tubesheet Bore Eccentricity and Dilation on 13 SGMP Tube-to-Tubesheet Contact Pressure and Their 78 Relative Importance to H*LTR- 0 H* Response to NRC Questions Regarding Tubesheet 12 SGMP Bore Eccentricity 33 P-Attachment

3.4 Evaluation

To preclude unnecessarily plugging tubes in the Seabrook Station SG, tube inspections will be limited to identifying and plugging degradation in the portion of the tube within the tubesheet necessary to maintain structural and leakage integrity in both normal and accident conditions.

The technical evaluation for the inspection and repair methodology is provided in the H*analysis provided in Section 3.3. The evaluation is based on the use of finite element model structural analysis and a bounding leak rate evaluation based on contact pressure between the tube and the tubesheet during normal and postulated accident conditions.

The limited tubesheet inspection criteria were developed for the tubesheet region of the Seabrook Station Model F SG considering the most stringent loads associated with plant operation, including transients and postulated accident conditions.

The limited tubesheet inspection criteria were selected to prevent tube pull out from the tubesheet due to axial end cap loads acting on the tube and to ensure that the accident induced leakage limits are not exceeded.

The H* analysis provides technical justification for limiting the inspection in the tubesheet expansion region to less than the full depth of the tubesheet.

The basis for determining the portion of the tube which requires eddy current inspection within the tubesheet is based upon evaluation and testing programs 11 that quantified the tube-to-tubesheet radial contact pressure for bounding plant conditions as described in the H* analysis.

The tube-to-tubesheet radial contact pressure provides resistance to tube pull out.Primary-to-secondary leakage from tube degradation in the tubesheet area is assumed to occur in several design basis accidents:

feedwater line break (FLB), steam line break (SLB), locked rotor, and control rod ejection.

The radiological dose consequences associated with this assumed leakage are evaluated to ensure that they remain within regulatory limits (e.g. 10 CFR Part 100, 10 CFR 50.67, GDC 19). The accident induced leakage performance criteria are intended to ensure the primary-to-secondary leak rate during any accident does not exceed the primary-to-secondary leak rate assumed in the accident analysis.

The limiting leakage ratio of 2.50 is independent of the H*distance defined in the H* analysis.The constraint that is provided by the tubesheet precludes tube burst for cracks within the tubesheet.

The criteria for tube burst described in NEI 97-06 and NRC Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," [Reference 7] are satisfied due to the constraint provided by the tubesheet.

Through application of the limited tubesheet inspection scope as described below, the existing operating leakage limit provides assurance that excessive leakage (i.e., greater than accident analysis assumptions) will not occur. The assumed accident induced leak rate limit is 500 gallons per day (gpd) through the faulted steam generator and 940 gpd for the remaining three SGs for SLB. The accident induced leak rate is 1 gallon per minute (gpm) for the rod ejection and locked rotor events. Thus, the limiting accident is SLB. Based upon the limiting leak rate factor of 2.50, an operational leak rate of less than 200 gpd would be required to prevent exceeding the assumed accident induced leak rate limit of 500 gpd.Therefore, the technical specification leak rate limit of 150 gpd provides significant added margin against the 500 gpd accident analysis leak rate assumption.

Plant-specific operating conditions are used to generate the overall leakage factor ratios that are used in the condition monitoring and operational assessments.

The plant-specific data provide the initial conditions for application of the transient input data. The results of the analysis of the plant-specific inputs to determine the bounding plant for each model of SG and to assure that the design basis accident contact pressures are greater than the normal operating pressure contact pressure are contained in section 6 of WCAP-17071-P

[Reference 9].The leak rate ratio (accident induced leak rate to operational leak rate) is directly proportional to the change in differential pressure and inversely proportional to the dynamic viscosity.

Since dynamic viscosity decreases 12 with an increase in temperature, an increase in temperature results in an increase in leak rate. However, for both the postulated SLB and FLB events, a plant cool down event would occur and the subsequent temperatures in the reactor coolant system (RCS) would not be expected to exceed the temperatures at plant no load conditions.

Thus, an increase in leakage would not be expected to occur as a result of the temperature change. The increase in leakage would only be a function of the increase in primary-to-secondary pressure differential.

The resulting leak rate ratio for the SLB and FLB events is 2.50.The other design basis accidents, such as the postulated locked rotor event and the control rod ejection event, are conservatively modeled using the design specification transients that result in increased temperatures in the SG hot and cold legs for a period of time. As previously noted, dynamic viscosity decreases with increasing temperature.

Therefore, leakage would be expected to increase due to decreasing viscosity and increasing differential pressure for the duration of time that there is a rise in RCS temperature.

For transients other than a SLB and FLB, the length of time that a plant with model F SGs will exceed the normal operating differential pressure across the tubesheet is less than 30 seconds. As the accident induced leakage performance criteria is defined in gallons per minute, the leak rate for a locked rotor event can be integrated over a minute for comparison to the limit. Time integration permits an increase in acceptable leakage during the time of peak pressure differential by approximately a factor of two because of the short duration (less than 30 seconds) of the elevated pressure differential.

This translates into an effective reduction in the leakage factor by the same factor of two for the locked rotor event. Therefore, for the locked rotor event, the leakage factor of 1.74 (Table 9-7, Reference

10) for Seabrook is adjusted downward to a factor of 0.87.Similarly, for the control rod ejection event, the duration of the elevated pressure differential is less than 10 seconds. Thus, the peak leakage factor is reduced by a factor of six, from 2.65 to 0.44. Due to the short duration of the transients above NOP differential, no leakage factor is required for the locked rotor and control rod ejection events (i.e., the leakage factor is under 1.0 for both transients).

The plant transient response following a full power double-ended main feedwater line.rupture corresponding to "best estimate" initial conditions and operating characteristics, as generally presented in steam generator design transients and in the UFSAR Chapter 15.0 safety analysis, indicates that the transient for a Model F SG exhibits a cool down characteristic instead of a heat-up transient.

The use of either the component design specification transient or the Chapter 15.0 safety transient for leakage analysis for FLB is overly conservative because: 13

• The assumptions on which the FLB design transient is based are specifically intended to establish a conservative structural (fatigue) design basis for RCS components; however, H* does not involve component structural and fatigue issues. The best estimate transient is considered more appropriate for use in the H* leakage calculations." For the Model F SG, the FLB transient curve (Figure 9-5, Reference 9)represents a double-ended rupture of the main feedwater line concurrent with both station blackout (loss of main feedwater and reactor coolant pump coast down) and turbine trip.* The assumptions on which the FLB safety analysis is based are specifically intended to establish a conservative basis for minimum auxiliary feedwater (AFW) capacity and combines worst case assumptions, which are exceptionally more severe when the FLB occurs inside containment.

For example, environmental errors that are applied to reactor trip and engineered safety features actuation would no longer be applicable.

This would result in much earlier reactor trip and greatly increase the SG liquid mass available to provide cooling to the RCS.A SLB event would have similarities to a FLB except that the break flow path would include the secondary separators, which could only result in an increased initial cooldown (because of retained liquid inventory available for cooling) when compared to the FLB transient.

A SLB could not result in more limiting temperature conditions than a FLB.In accordance with plant operating procedures, the operator would take action following a high energy secondary line break to stabilize the RCS conditions.

The expectation for a SLB or FLB with credited operator action is to stop the system cooldown through isolation of the faulted steam generator and control of temperature by the AFW system. Steam pressure control would be established by either the steam generator safety valves or the atmospheric relief valves. For any of the steam pressure control operations, the maximum temperature would be approximately the no load temperature and would be well below normal operating temperature.

Since the best estimate FLB transient temperature would not be expected to exceed the normal operating temperature, the viscosity ratio for the FLB transient is set to 1.0.The leakage factor of 2.50 for Seabrook Station for a postulated SLB/FLB has been calculated as shown in Table 9-7 of Reference

10. Specifically, for the condition monitoring assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.50 and added to the total leakage from any other source and compared to the 14 allowable accident induced leakage limit. For the operational assessment, the difference between the allowable leakage and the accident induced leakage'from sources other than the tubesheet expansion region will be divided by 2.50 and compared to the observed operational leakage.Reference 17 redefines the primary pressure boundary.

The tube to tubesheet weld no longer functions as a portion of this boundary.

The hydraulic expansion of the tube into the tubesheet over the H* distance now functions as the primary pressure boundary in the area of the tube and tubesheet, maintaining the structural and leakage integrity over the full range of steam generator operating conditions, including the most limiting accident conditions.

The evaluation in Reference 17 determined that degradation in tubing below this safety significant portion of the tube does not require inspection or repair (plugging).

The inspection of the safety significant portion of the tubes provides a high level of confidence that the structural and leakage performance criteria are maintained during normal operating and accident conditions.

WCAP-17071-P, section 9.8, provides a review of leak rate susceptibility to tube slippage and concluded that the tubes are fully restrained against motion under very conservative design and analysis assumptions such that tube slippage is not a credible event for any tube in the bundle. NextEra committed to monitor for'tube slippage as part of the steam generator tube inspection program in refueling outage 13. This commitment has been deleted for OR14 based on the limited tube inspection plan.

4.0 REGULATORY EVALUATION

4.1 Applicable

Regulatory Requirements/Criteria General Design Criteria (GDC) 1, 2, 4, 14, 30, 31, and 32 of 10 CFR 50, Appendix A, define requirements for the reactor coolant pressure boundary (RCPB) with respect to structural and leakage integrity.

GDC 19 of 10 CFR 50, Appendix A, defines requirements for the control room and for radiation protection of the operators working within it.Accidents involving the leakage or burst of SG tubing comprise a challenge to the habitability of the control room.10 CFR 50, Appendix B, establishes quality assurance requirements for the design, construction, and operation of safety related components.

The pertinent requirements of this appendix apply to all activities affecting the safety related functions of these components.

These requirements are described in Criteria IX, XI, and XVI of Appendix B and include control of special processes, inspection, testing, and corrective action.15 10 CFR 100, Reactor Site Criteria, establishes reactor site criteria, with respect to the risk of public exposure to the release of radioactive fission products.

Accidents involving leakage or tube burst of SG tubing may comprise a challenge to containment and therefore involve an increased risk of radioactive release.10 CFR 50.67, Accident Source Term, establishes limits on the accident source term used in design basis radiological consequence analyses with regard to radiation exposure to members of the public and to control room occupants.

Under 10 CFR 50.65, the Maintenance Rule, licensees classify SGs as risk significant components because they are relied upon to remain functional during and after design basis events. SGs are to be monitored under 10 CFR 50.65(a) (2) against industry established performance criteria.

Meeting the performance criteria of NEI 97-06, Revision 2, provides reasonable assurance that the SG tubing remains capable of fulfilling its specific safety function of maintaining the reactor coolant pressure boundary.

The NEI 97-06, Revision 2, SG performance criteria are: " All in-service SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, cool down, and all anticipated transients included in the design specification) and design basis accidents.

This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials.

Apart from the above requirements, additional loading conditions associated with the design and licensing basis shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse.

In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial loads.* The primary-to-secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG, except for specific types of degradation at specific locations when implementing alternate repair criteria as documented in the Steam Generator Program technical specifications.

16

• The RCS operational primary-to-secondary leakage through anyone SG shall be limited to 150 gallons per day.The safety significant portion of the tube is the length of tube that is engaged in the tubesheet from the secondary face that is required to maintain structural and leakage integrity over the full range of SG operating conditions, including the most limiting accident conditions.

The evaluation in the H* analysis determined that degradation in tubing below safety significant portion of the tube does not require plugging and serves as the bases for the SG tube inspection program. As such, the Seabrook Station inspection program provides a high level of confidence that the structural and leakage criteria are maintained during normal operating and accident conditions.

4.2 Significant

Hazards Consideration This amendment application proposes to revise Seabrook Station TS 6.7.6.k,"Steam Generator (SG) Program," to exclude portions of the SG tubes below the top of the SG tubesheet from periodic inspections during OR14 in the spring of 2011 and the subsequent inspection cycle. In addition, this amendment request proposes to revise TS 6.8.1.7, "Steam Generator Tube Inspection Report." Application of the structural analysis and leak rate evaluation results to exclude portions of the tubes from inspection and repair is interpreted to constitute a redefinition of the primary-to-secondary pressure boundary.The proposed change defines the safety significant portion of the tube that must be inspected and repaired.

A justification has been developed by Westinghouse to identify the specific inspection depth below which any type of axial or circumferential primary water stress corrosion cracking can be shown to have no impact on Nuclear Energy Institute (NEI) 97-06 Rev. 2[Reference 3], "Steam Generator Program Guidelines," performance criteria.NextEra has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. The proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Response:

No The previously analyzed accidents are initiated by the failure of plant structures, systems, or components.

The proposed change that alters the 17 SG inspection and reporting criteria does not have a detrimental impact on the integrity of any plant structure, system, or component that initiates an analyzed event. The proposed change will not alter the operation of, or otherwise increase the failure probability of any plant equipment that initiates an analyzed accident.Of the applicable accidents previously evaluated, the limiting transients with consideration to the proposed change to the SG tube inspection and repair criteria are the steam generator tube rupture (SGTR) event, the steam line break (SLB), and the feed line break (FLB) postulated accidents.

During the SGTR event, the required structural integrity margins of the SG tubes and the tube-to-tubesheet joint over the H* distance will be maintained.

Tube rupture in tubes with cracks within the tubesheet is precluded by the constraint provided by the presence of the tubesheet and the tube-to-tubesheet joint. Tube burst cannot occur within the thickness of the tubesheet.

The tube-to-tubesheet joint constraint results from the hydraulic expansion process, thermal expansion mismatch between the tube and tubesheet, and from the differential pressure between the primary and secondary side, and tubesheet rotation.

Based on this design, the structural margins against burst, as discussed in Regulatory Guide (RG)1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," and Technical Specification 6.7.6.k, are maintained for both normal and postulated accident conditions.

The proposed change has no impact on the structural or leakage integrity of the portion of the tube outside of the tubesheet.

The proposed change maintains structural and leakage integrity of the SG tubes consistent with the performance criteria of TS 6.7.6.k. Therefore, the proposed change results in no significant increase in the probability of the occurrence of a SGTR accident.At normal operating pressures, leakage from tube degradation below the proposed limited inspection depth is limited by the tube-to-tubesheet crevice. Consequently, negligible normal operating leakage is expected from degradation below the inspected depth within the tubesheet region.The consequences of an SGTR event are not affected by the primary-to-secondary leakage flow during the event as primary-to-secondary leakage flow through a postulated tube that has been pulled out of the tubesheet is essentially equivalent to a severed tube. Therefore, the proposed change does not result in a significant increase in the consequences of a SGTR The consequences of a SLB are also not significantly affected by the proposed changes. During a SLB accident, the reduction in pressure 18 above the tubesheet on the shell side of the steam generator creates an axially uniformly distributed load on the tubesheet due to the reactor coolant system pressure on the underside of the tubesheet.

The resulting bending action constrains the tubes in the tubesheet thereby restricting primary-to-secondary leakage below the midplane.Primary-to-secondary leakage from tube degradation in the tubesheet area during the limiting accident (i.e., a SLB) is limited by flow restrictions.

These restrictions result from the crack and tube-to-tubesheet contact pressures that provide a restricted leakage path above the indications and also limit the degree of potential crack face opening as compared to free span indications.

The leakage factor of 2.50 for Seabrook Station, for a postulated SLB/FLB, has been calculated as shown in Table 9-7 of Reference 10.For the condition monitoring assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.50 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment, the difference in the leakage between the allowable leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.50 and compared to the observed operational leakage The probability of a SLB is unaffected by the potential failure of a steam generator tube as the failure of the tube is not an initiator for a SLB event.SLB leakage is limited by leakage flow restrictions resulting from the leakage path above potential cracks through the tube-to-tubesheet crevice.The leak rate during postulated accident conditions (including locked rotor) has been shown to remain within the accident analysis assumptions for all axial and or circumferentially orientated cracks occurring 15.2 inches below the top of the tubesheet.

The assumed accident induced leak rate for Seabrook Station is 500 gallons per day (gpd) during a postulated steam line break in the faulted loop. Using the limiting leak rate factor of 2.50, this corresponds to an acceptable level of operational leakage of 200 gpd. Therefore, the TS leak rate limit of 150 gpd provides significant added margin against the 500 gpd accident analysis leak rate assumption.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated 2. The proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

Response:

No 19 The proposed change that alters the SG inspection and reporting criteria does not introduce any new equipment, create new failure modes for existing equipment, or create any new limiting single failures.

Plant operation will not be altered, and all safety functions will continue to perform as previously assumed in accident analyses.Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3. The proposed changes do not involve a significant reduction in the margin of safety.Response:

No The proposed change that alters the SG inspection and reporting criteria maintains the required structural margins of the SG tubes for both normal and accident conditions.

Nuclear Energy Institute 97-06, Rev. 2 "Steam Generator Program Guidelines," and NRC Regulatory Guide (RG) 1.121,"Bases for Plugging Degraded PWR Steam Generator Tubes," are used as the bases in the development of the limited hot leg tubesheet inspection depth methodology for determining that SG tube integrity considerations are maintained within acceptable limits. RG 1.121 describes a method acceptable to the NRC for meeting General Design Criteria (GDC) 14,"Reactor Coolant Pressure Boundary," GDC 15, "Reactor Coolant System Design," GDC 31, "Fracture Prevention of Reactor Coolant Pressure Boundary," and GDC 32, "Inspection of Reactor Coolant Pressure Boundary," by reducing the probability and consequences of a SGTR. RG 1.121 concludes that by determining the limiting safe conditions for tube wall degradation, the probability and consequences of a SGTR are reduced. This RG uses safety factors on loads for tube burst that are consistent with the requirements of Section III of the American Society of Mechanical Engineers (ASME) Code.For axially oriented cracking located within the tubesheet, tube burst is precluded due to the presence of the tubesheet.

For circumferentially oriented cracking, Westinghouse WCAP-17071-P defines a length of degradation-free expanded tubing that provides the necessary resistance to tube pullout due to the pressure induced forces, with applicable safety factors applied. Application of the limited hot and cold leg tubesheet inspection criteria will preclude unacceptable primary-to-secondary leakage during all plant conditions.

The methodology for determining leakage as.described in WCAP-17071-P provides significant margin 20 between the accident-induced leakage assumption and the technical specification leakage limit during normal operating conditions when the proposed limited tubesheet inspection depth criteria is implemented.

Therefore, the proposed change does not involve a significant reduction in any margin of safety.Based on the above, NextEra Energy Seabrook concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and, accordingly, a finding of"no significant hazards consideration" is justified.

4.3 Conclusion

The safety significant portion of the tube is the length of tube that is engaged within the tubesheet to the top of the tubesheet (secondary face) that is required to maintain structural and leakage integrity over the full range of SG operating conditions, including the most limiting accident conditions.

The H*analysis determined that degradation below the safety significant portion of the tube does not require plugging and serves as the basis for the limited tubesheet inspection criteria, which are intended to ensure the primary to secondary leak rate during any accident does not exceed the leak rate assumed in the accident analysis.Based on the considerations above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public 5.0 ENVIRONMENTAL CONSIDERATION NextEra Energy Seabrook has evaluated the proposed amendment for environmental considerations.

The review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, and would change an inspection or surveillance requirement.

However, the proposed amendment does not involve (I) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii)a significant increase in individual or cumulative occupational radiation exposure.Accordingly, the proposed amendments meet the eligibility criterion for categorical exclusion set for in 10 CFR 51.22(c) (9). Therefore, pursuant to 10 CFR 51.22(b), 21 no environmental impact statement or environmental assessment needs to be prepared in connection with the proposed amendment.

6.0 REFERENCES

1. NRC Letter "Seabrook Station, Unit 1 -Issuance of Amendment RE: Limited Inspection of the Steam Generator Tube Portion within the Tubesheet (TAC NO.MC85544)," September 29, 2006 (ML062630450)

2. NRC Letter "Seabrook Station, Unit 1 -Issuance of Amendment RE: Changes to the Steam Generator Inspection Scope and Repair Requirements (TAC NO.ME1386)," October 13, 2009 (ML092460184)

3. NEI 97-06, "Steam Generator Program Guidelines" Revision 2, May 2005 4. EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 7 5. EPRI 1012987, Steam Generator Integrity Assessment Guidelines

6. NRC Information Notice 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," April 7, 2005 7. NRC Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," August 1976 8. Westinghouse Electric Company LLC, WCAP-17330-P, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity," Rev. 0, November 2010 9. Westinghouse Electric Company LLC, WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)" 10. Westinghouse Electric Company LLC, LTR-SGMP-09-100, "LTR-SGMP-09-100 P-Attachment, "Response to NRC Request for Additional Information on H*;Model F and Model D5 Steam Generators," August 12, 2009 11. Westinghouse Electric Company LLC, LTR-SGMP-09-109 P-Attachment,"Response to NRC Request for Additional Information on H*; RAI #4; Model F and Model D5 Steam Generators," August 25, 2009.12. Westinghouse Electric Company LLC, LTR-SGMP-10-33 P-Attachment and LTR-SGMP-10-33 NP-Attachment, LTR-SGMP-10-33 P-Attachment, "H*22 Response to NRC Questions Regarding Tubesheet Bore Eccentricity," (Proprietary/Non-Proprietary) for Review and Approval," September 13, 2010 13. Westinghouse Electric Company LLC, LTR-SGMP-10-78 P-Attachment and LTR-SGMP-10-78 NP-Attachment, "Effects of Tubesheet Bore Eccentricity and Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H*," (Proprietary/Non-Proprietary) for Review and Approval," September 7, 2010 14. NRC Letter dated August 13, 2009 "Seabrook Station, Unit NO. 1 -Request for Additional Information (RAI) Regarding Steam Generator Program (TAC NO.ME 1386)" (ML092100324)

15. NRC Letter dated September 1, 2009 "Seabrook Station, Unit NO. 1 -Second Request for Additional Information (RAI) Regarding Steam Generator Program (TAC NO. ME1386)" (ML 092400135)

16. NRC Letter dated December 23, 2009 "Seabrook Station, Unit NO. 1, Transmittal of Unresolved Issues Regarding Permanent Alternate Repair Criteria for Steam Generators (TAC NO. ME2628)" (ML 09342186)17. SBK-L-09118, "License Amendment Request 09-03, Revision to Technical Specification 6.7.6.k, "Steam Generator (SG) Program," for Permanent Alternate Repair Criteria (H*)," May 28, 2009 (ML091530539)

18. SBK-L-09168, "Response to Request for Additional Information Regarding Permanent H* Alternate Repair Criteria for Steam Generator Inspections," September 16, 2009 (ML092650369)

19. SBK-L-09196, "License Amendment Request to Revise Technical Specification (TS) Sections 6.7.6.k, Steam Generator (SG) Program" and TS 6.8.1.7, "Steam Generator Tube Inspection Report" for One-Time Alternate Repair Criteria," September 18, 2009 (ML 09270883)20. Westinghouse Electric Company LLC, LTR-SGMP-09-111 P-Attachment, Rev. 1 and LTR-SGMP-09-111 NP-Attachment, Rev. 1, "Acceptable Value of the Location of the Bottom of the Expansion Transition (BET) for Implementation of H*," (Proprietary/Non-Proprietary) for Review and Approval," September 1, 2010 23 Attachment 1 Mark-up of the Technical Specifications (TS)The attached markups reflect the currently issued version of the TS and Facility Operating License. At the time of submittal, the Facility Operating License was revised through Amendment No. 124.Listed below are the license amendment requests that are awaiting NRC approval and may impact the currently issued version of the Facility Operating License affected by this LAR.LAR Title, NextEra Energy Date Seabrook Letter Submitted Revision to Technical Specification SBK-L-09118 05/28/2009 LAR 09-03 6.7.6.k, "Steam Generator (SG)Program," for Permanent Alternate Repair Criteria (H*)LAR 10-02 Application for Change to the SBK-L-10074 05/14/2010 Technical Specifications for the Containment Enclosure Emergency Air Cleanup System LAR 10-03 Relocation of Technical SBK-L-10097 06/28/2010 Specification 3.8.4.2, Containment Penetration Conductor Overcurrent Protective Devices and Protective Devices for Class lE Power Sources Connected To Non-Class lE Circuits LAR 10-04 Amendment to the Facility SBK-L-101 19 07/26/2010 Operating License and Submittal of the Seabrook Station Cyber Security Plan The following TS pages are included in the attached markup:

Technical Page Specification Title TS 6.7.6.k Steam Generator (SG) Program 6-11 (Info only)6-12 (Info only)6-13 6-14 (Info only)6.8.1.7 Steam Generator Tube Inspection Report 6-21 6-21a ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS 6.7.6 (Continued)

j. Technical Specification (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. A change in the TS incorporated in the license or 2. A change to the updated FSAR (UFSAR) or Bases that requires NRC approval pursuant to 10 CFR 50.59.c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.d. Proposed changes that meet the criteria of Specification 6.7.6j.b above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71 (e).k. Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained.

In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments.

Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.SEABROOK -UNIT 1 6-11 Amendment No. 34, 55, 67, 88, 104, 115 PROCEDURES AND PROGRAMS 6.7.6 (Continued)

b. Performance criteria for SG tube integrity.

SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.1. Structural integrity performance criterion:

All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents.

This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials.

Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse.

In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.2. Accident induced leakage performance criterion:

The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm total or 500 gpd through any one SG.3. The operational LEAKAGE performance criterion is specified in LCO 3.4.6.2,"Reactor Coolant System Operational Leakage." c. Provisions for SG tube repair criteria.

Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.SEABROOK -UNIT 1 6-12 Amendment No. 34, 39, 104, 115 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS 6.7.6 (Continued)

The following alternate tube repair criteria shall be applied as an alternative to the 40% depth based criteria: For refueling outage 13 and the subseuent inspection cycletubes with service-ind, ws located than 13.1 inchýe ow the top of e tube et do not require ging. Tubes with ice-induced fla ocated in the portion of the from the top oft besheetto 13.1 ches below the top of the tubesheet shall be plugged upon detection.

A , d. Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-Sto-tubesheet weld at the tubo~utlet, and that may satisfy the applicable tube repairFor refueling outage -and the subsequent inspection cycle, the portion (i of the tube belo inches from the top of the tubesheet is excluded from this.requirement.

T e tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection.

An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.

2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less)without being inspected.

SEABROOK -UNIT 1 6-13 Amendment No. 34, 104, 109, INSERT 1. For refueling outage 14 and the subsequent inspection cycle, if the number of tubes with service-induced flaws located greater than 15.2 inches below the top of the tubesheet is less than or equal to 5% of the total tubes inspected, then tubes with service-induced flaws located greater than 15.2 inches below the top of the tubesheet do not require plugging.

Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 15.2 inches below the top of the tubesheet shall be plugged upon detection.

2. For refueling outage 14 and the subsequent inspection cycle, if the number of tubes with flaws located below 15.2 inches from the top of the tubesheet is greater than 5% of the total tubes inspected in any SG, the following applies to the affected SG: a. Tubes with flaws having a circumferential component greater than 203 degrees found in the portion of the tube below 15.2 inches from the top of the tubesheet and one inch from the bottom of the tubesheet shall be removed from service. When more than one flaw with circumferential components is found in the portion of the tube below 15.2 inches from the top of the tubesheet and above one inch from the bottom of the tubesheet with the total of the circumferential components greater than 203 degrees and an axial separation distance of less than one inch, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

b. When one or more flaws with circumferential components are found in the portion of the tube within one inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service. When one or more flaws with circumferential components are found in the portion of the tube within one inch from the bottom of the tubesheet and within one inch axial separation distance of a flaw above one inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service.When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

3. For refueling outage 14 and the subsequent inspection cycle, tubes with axial crack indications located greater than 1.5.2 inches below the top of the tubesheet do not require plugging.

PROCEDURES AND PROGRAMS 6.7.6 (Continued)

3. If crack indications are found in portions of the SG tube not excluded above, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.e. Provisions for monitoring operational primary to secondary leakage.1. Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Makeup Air and Filtration System (CREMAFS), CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge.

The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident.

The program shall include the following elements: a. The definition of the CRE and the CRE boundary.b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.

c. Requirements for (i) determining the unfiltered air in-leakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors," Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.SEABROOK -UNIT 1 6-14 Amendment No. 34, 78, 104, 115, 123 ADMINISTRATIVE CONTROLS 6.8.1.6.c The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as SHUTDOWN MARGIN, and transient and accident analysis limits) of the safety analysis are met. The CORE OPERATING LIMITS REPORT for each reload cycle, including any mid-cycle revisions or supplements thereto, shall be provided upon issuance, to the NRC Document Control Desk with copies to the Regional Administrator and the Resident Inspector.

STEAM GENERATOR TUBE INSPECTION REPORT 6.8.1.7 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.7.6.k, Steam Generator (SG) Program. The report shall include: a. The scope of inspections performed on each SG, b. Active degradation mechanisms found, c. Nondestructive examination techniques utilized for each degradation mechanism, d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, e. Number of tubes plugged during the inspection outage for each active degradation mechanism, f. Total number and percentage of tubes plugged to date, g. The results of condition monitoring, including the results of tube pulls and in-situ testing, h. The effective plugging percenta for all plugging in each SG.i. For refueling outageý nd the subsequent inspection cycle, the primary to secondary leakage rate observed in each SG (if it is not practical to assign the leakage to an individual SG, the entire primary to secondary leakage should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subjectof the report, For refueling outage~and the subsequent inspection cycle, theQal~culated accident induced leakage rate from the portion of the tubes below inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 2.50 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined, and N SEABROOK -UNIT I 6-21 Amendment No. 22, 66, 88, 104, 107, 115,42 ADMINISTRATIVE CONTROLS 6.8.1.7 (Continued)

/,'/. ' or rfuling out 3, the res monitoýri -otube axi L/~'lc~en,= k. Fosrppage).

ýi _jf ippage issIn-"vered, th/mSications o t/be'discov.,e"9 and k,.. J orrectiveraction shallt:fe provided.SPECIAL REPORTS 6.8.2 Special reports shlall be submitted to the U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, Attn: Document Control Desk, with a copy to the NRC Regional Administrator within the time period specified for each report.6.9 (THIS SPECIFICATION NUMBER IS NOT USED)SEABROOK -UNIT I 6-21 a Amendment No.-423-1I