LR-N12-0108, Unit 1 - License Amendment Request: Revision to Technical Specification (TS) 6.8.4.i, Steam Generator (SG) Program, and TS 6.9.1.10, Steam Generator Tube Inspection Report, for a Permanent Alternate Repair Criteria

Unit 1 - License Amendment Request: Revision to Technical Specification (TS) 6.8.4.i, Steam Generator (SG) Program, and TS 6.9.1.10, Steam Generator Tube Inspection Report, for a Permanent Alternate Repair Criteria

ML12130A169
Person / Time
Site:	Salem
Issue date:	05/08/2012
From:	Fricker C Public Service Enterprise Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LAR S12-01, LR-N12-0108
Download: ML12130A169 (34)

Text

PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, NJ 08038-0236 OPSEG Nuclear LLC 10 CFR 50.90 May 8,2012 LR-N12-0108 LAR S12-01 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Salem Generating Station - Unit 1 Renewed Facility Operating License No. DPR-70 NRC Docket No. 50-272

Subject:

license Amendment Request: Revision to Technical Specification (TS) 6.8.4.i, "Steam Generator (SG) Program," and TS 6.9.1.10, "Steam Generator Tube Inspection Report," for a Permanent Alternate Repair Criteria In accordance with 10 CFR 50.90, PSEG Nuclear, LLC (PSEG) requests an amendment to the facility operating license listed above. In accordance with 10 CFR 50.91(b)(1), a copy of this request for amendment has been sent to the State of New Jersey.

This amendment request proposes to revise Salem Unit 1 Technical Specification (TS) 6.8.4.i, "Steam Generator (SG) Program," to permanently exclude portions of the tube below the top of the steam generator tubesheet from periodic steam generator tube inspections. In addition, this amendment proposes to revise TS 6.9.1.10, "Steam Generator Tube Inspection Report" to provide permanent reporting requirements that have been previously established on an interim basis.

The proposed amendment constitutes a redefinition of the steam generator tube primary to secondary pressure boundary and defines the safety significant portion of the tube (a portion or distance designated as H*) that must be inspected or plugged. Tube flaws detected below the safety significant portion of the tube are not required to be plugged. Allowing flaws in the non-safety significant portion of the tube to remain in service minimizes unnecessary tube plugging and maintains the safety margin of the steam generators to perform the safety function to maintain the reactor coolant pressure boundary, maintain reactor coolant flow, and maintain primary to secondary heat transfer. The technical justification for this change has been prepared by Westinghouse Electric Company LLC as described in Attachment 1 to this letter. On March 12,2012, the NRC issued Amendment No. 267 for the Duke Energy Catawba station approving the H* permanent alternate repair criterion.

PSEG requests the approval of the proposed license amendment by March 22, 2013 to support implementation during the Salem Unit 1 Spring Refueling Outage 22. Once approved, the

Document Control Desk Page 2 LR-N12-0108 amendment will be implemented prior to MODE 4 entry during startup from Refueling Outage 22.

Attachments 1 through 3 of this submittal provide the Evaluation, Markup of TSs, and Proposed TS Bases changes, respectively, in support of this amendment request. Attachment 3, proposed changes to the TS Bases, is provided for information only. Final TS Bases changes will be implemented pursuant to TS 6.17, "Technical Specification (TS) Bases Control Program,"

at the time the amendment is implemented. of this submittal provides the regulatory commitments associated with this application. of this submittal provides Salem Unit 1 specific responses to NRC staff requests for information associated with similar license amendment requests for the Catawba Nuclear Station and the Surry Power Station.

If you have any questions or require additional information, please do not hesitate to contact Mr.

Paul Duke at (856) 339-1466.

I declare under penalty of perj ry that the foregoing is true and correct.

Executed on _ _-+--:--:-+:--~_ __

Attachments (5) cc: W. Dean, Regional Administrator - NRC Region I J Hughey, Project Manager - USNRC NRC Senior Resident Inspector - Salem Unit 1 and Unit 2 P. Mulligan, Manager IV, NJBNE Commitment Coordinator - Salem PSEG Commitment Coordinator - Corporate LAR S12-01 LR-N12-0108 Revision to Technical Specification (TS) 6.8.4.i, "Steam Generator (SG) Program, and TS II 6.9.1.10, "Steam Generator Tube Inspection Report," for a Permanent Alternate Repair Criteria Table of Contents

5.0 REGULATORY ANALYSIS

5.1 Applicable Regulatory Requirements/Criteria 5.2 Significant Hazards Consideration 5.3 Conclusion

7.0 REFERENCES

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1.0 DESCRIPTION

PSEG Nuclear, LLC (PSEG) proposes to revise Salem Unit 1 Technical Specification (TS) 6.8.4.i, "Steam Generator (SG) Program," to exclude portions of the tube below the top of the steam generator tubesheet from periodic steam generator tube inspections. In addition, this amendment proposes to revise TS 6.9.1.10, "Steam Generator Tube Inspection Report" to remove reference to previous interim alternate repair criteria and provide reporting requirements specific to the permanent alternate repair criteria. Application of the supporting structural analysis and leakage evaluation results to exclude portions of the tubes from inspection and repair of tube indications is interpreted to constitute a redefinition of the primary to secondary pressure boundary. The proposed changes to the TS are based on the supporting structural analysis and leakage evaluation completed by Westinghouse Electric Company LLC. The documentation supporting the Westinghouse analysis is described in Section 4.0 and provides the licensing basis for this change. Table 5-1 of WCAP 17330-P (Reference 19) provides the 95/95 whole plant H* value of 15.21 inches for plants with Model F Steam Generators which includes Salem Unit 1.

The NRC previously issued the following amendments revising steam generator tube inspection requirements for Salem Unit 1:

• Amendment Number 268 (Reference 1) which changed the existing steam generator (SG) tube surveillance program to one that is consistent with the program proposed by the TS Task Force (TSTF) in TSTF-449. These changes revised TS 1.15, "Identified Leakage," TS 1.21, "Pressure Boundary Leakage," TS 3/4.4.5, "Steam Generator (SG)

Tube Integrity," and TS 3/4.4.6.2, "Operational Leakage," and added new administrative TS 6.8.4.i, "Steam Generator (SG) Program," and TS 6.9.1.10, "Steam Generator Tube Inspection Report."

• Amendment Number 279 (Reference 2) revised TS 6.8.4.i, "Steam Generator (SG)

Program," to eliminate inspection and repair of tubes more than 17 inches below the top of the tubesheet for Refueling Outage 18 and the subsequent operating cycle.

Additionally TS 6.9.1.10 was revised to provide reporting requirements specific to Refueling Outage 18 and the subsequent operating cycle.

• Amendment Number 294 (Reference 3) revised TS 6.8.4.i, "Steam Generator (SG)

Program," to eliminate inspection and repair of tubes more than 13.1 inches below the top of the tubesheet for Refueling Outage 20 and subsequent operating cycles until the next scheduled SG tube inspection. Additionally TS 6.9.1.10 was revised to provide reporting requirements specific to Refueling Outage 18 and subsequent operating cycles until the next scheduled SG tube inspection.

Approval of the proposed license amendment is requested by March 22, 2013 to support the Salem Unit 1 Refueling Outage 22 (Spring 2013), since the one-time change approved in Amendment 294 expires at the end of the current operating cycle.

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2.0 PROPOSED CHANGE

Proposed Changes to Current TS TS 6.B.4.i.c would be revised as follows:

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 Refuel Outage 1R20 through the subsequent operating cye-l-es unm the next scheduled SG tube inspection, Tubes with service-induced flaws located greater than ~ 15.21 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 ~ 15.21 inches below the top of the tubesheet shall be plugged upon detection.

TS 6.B.4.i.d would be revised as follows:

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 Refuel Outage 1R20 through the subsequent oper~ting cye-Ies until the next scheduled SG tube inspection,. The portions of the tube below ~ 15.21 inches from the top of the tubesheet is 8Fe 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.

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 3 of 21 LAR 812-01 LR-N12-0108 remaining 50% by the refueling outage nearest the end of the period. No 8G shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any portion 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.

TS 6.9.1.10 h., 6.9.1.10 L, and 6.9.1.10 j. would be revised as follows:

.f?e.perting roqu,~rements h, i and} are applicable for Refuel Outage 1R20 through the subsequent operating cy-cfes untH the next scheduled SG tube inspection

h. 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, L The calculated accident induced leakage rate from the portion of the tubes below 4J.,.:f. 15.21 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 2.16 times the maximum operational primary to secondary leakage rate, the report should describe how it was determined,

j. The results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

3.0 BACKGROUND

Salem Unit 1 is a four loop Westinghouse designed plant with Model F steam generators having 5626 tubes in each steam generator. A total of 238 tubes are currently plugged in all four steam generators. The design of the steam generator includes Alloy 600 thermally treated tubing, full depth hydraulically expanded tubesheet joints, and stainless steel tube support plates with quatrefoil broached holes.

The steam generator inspection scope is governed by TS 6.8.4.i, "Steam Generator (SG)

Program;" Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines,"

(Reference 5); EPRI 1013706, "Pressurized Water Reactor Steam Generator Examination Guidelines," (Reference 6); EPRI 1019038, "Steam Generator Integrity Assessment 4 of 21 LAR S12-01 LR-N12-010B Guidelines," (Reference 7); PSEG SG Program procedures ER-AP-420, "Steam Generator Management Program", and ER-AP-420-0051, "Conduct of Steam Generator Management Program Activities"; and the results of the degradation assessments required by the SG Program. Criterion IX, "Control of Special Processes" of 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 existing and potential specific degradation mechanisms applicable to Salem Unit 1. The inspection techniques, essential variables and equipment are qualified to Appendix H, "Performance Demonstration for Eddy Current Examination," and Appendix I, "NDE System Measurement Uncertainties for Tube Integrity Assessments," of the EPRI Steam Generator Examination Guidelines.

Catawba Nuclear Station, Unit 2, (Catawba) reported indication of cracking following nondestructive eddy current examination of the steam generator 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 B), 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.

PSEG policies and programs, as well as TS 6.B.4.i, require the use of applicable industry operating experience in the operation and maintenance of Salem Unit 1. 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 Salem Unit 1 Westinghouse Model F steam generators were fabricated with Alloy 600 thermally treated tubes similar to the Catawba Unit 2 Westinghouse Model D5 steam generators, a potential exists for Salem Unit 1 to identify tube indications similar to those reported at Catawba within the hot leg tubesheet region.

Potential inspection plans for the tubes and tube welds underwent intensive industry discussions in March 2005. The findings in the Catawba steam generator tubes present three distinct issues with regard to the steam generator tubes at Salem Unit 1:

1) Indications in internal bulges and overexpansions within the hot leg tubesheet;

2) Indications at the elevation of the tack expansion transition; and

3) Indications in the tube-to-tubesheet welds and propagation of these indications into adjacent tube material.

Prior to each steam generator 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 Salem Unit 1 steam generators. 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 operating experience discussed above, PSEG revised the steam generator inspection plan to include sampling of bulges and overexpansions within the tubesheet region on the hot leg side in Refueling Outage 5 of 21 LAR S12-01 LR-N12-0108 1R18 (Spring 2007) and Refueling Outage 1R20 (Spring 2010). The sample is based on the guidance contained in EPRI 1013706, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 7, and TS 6.8.4.i, "Steam Generator (SG) Program." The inspection plan is expanded according to EPRI steam generator examination guidelines if necessary due to confirmed degradation in the region required to be examined (i.e. a tube crack). Degradation was not detected in the tubesheet region in 1R18 and 1R20 (no inspections were required in 1R19 and 1R21 per the SG Program).

As a result of these potential issues and to prevent the unnecessary plugging of additional tubes in the Salem Unit 1 steam generators, PSEG is proposing changes to TS 6.8.4.i to limit the steam generator tube inspection and repair (plugging) to the safety significant portion of the tubes. The safety significant portion of the tube within the tubesheet is known as the H*

distance as measured from the top of the tubesheet.

4.0 TECHNICAL ANALYSIS

Summary of Licensing Basis Analysis (H* Analysis)

On October 8, 2009, 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 10) was submitted as Attachment 4 of Salem Unit 1 license amendment request (Reference 11) to change Technical Specification (TS) 6.8.4.i, "Steam Generator (SG)

Program," and TS 6.9.1.10, "Steam Generator Tube Inspection Report." The WCAP was prepared to support a permanent alternate repair criteria; however the October 8, 2009 license amendment request was for a one-time interim change as discussed below.

The NRC had recently granted a similar interim H* amendment to Vogtle Electric Generating Plant (Reference 12). To support Reference 12, References 13 and 141 provided a Request for Additional Information (RAI) to Southern Nuclear Operating Company (SNC) related to their application for an alternate repair criterion based on WCAP-17071-P, Revision O. Since References 13 and 14 were also applicable to the PSEG application, a response to the RAls was also included as part of the October 8, 2009 including the following documents:

• Westinghouse letter LTR-SGMP-09-1 OO-P Attachment, Revision 0, "Response to NRC Request for Additional Information on H*; Model F and Model D5 Steam Generators,"

August 12, 2009 (Reference 15), and

• Westinghouse letter LTR 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 16).

1 The July 10, 2009, RAlletter (Reference 13) contained twenty-four (24) questions. As a result of a teleconference with NRC staff held on July 30, 2009, Southern Nuclear Corporation (SNC) received a second request for additional information letter on August 5, 2009. The August 5, 2009 letter (Reference 14) contained three (3) questions related to questions 4, 20 and 24 from RAlletter received on July 10, 2009. The August 5, 2009 letter also contained one (1) additional question. On August 28, 2009, SNC provided the responses to questions 1 through 24 of the July 10, 2009 letter and questions 1 through 4 of the August 5, 2009 letter.

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• Westinghouse Letter LTR-SGMP-09-144, Correction to WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)" (Reference 4)

The reason the Vogtle and Salem Unit 1 amendment requests were 'interim' versus 'permanent' was based on NRC feedback to the industry. On September 2, 2009, in a teleconference between NRC Staff and industry personnel, NRC Staff indicated that their concerns with eccentricity of the tubesheet tube bore in normal an-d accident conditions (RAI question 4 of the July 10, 2009 Vogtle RAI letter and RAI question 1 of the August 5, 2009 Vogtle RAI letter) had not been completely resolved to the satisfaction of the Staff. The Staff further indicated that there was insufficient time to resolve these issues to support approval of the permanent amendment request to support the upcoming refueling outages.

Consistent with the industry, the PSEG October 8, 2009 letter (Reference 11) also requested that the NRC Staff provide the specific questions remaining to be resolved and that the review of the amendment request for permanent (versus one-time) alternate repair criteria continue.

On December 9, 2009, the NRC provided a letter (Reference 18) documenting the currently identified and unresolved issues relating to tubesheet bore eccentricity. This letter contained 14 unresolved questions (applicable to all H* plants) which required resolution before the NRC could complete its review of a permanent amendment request. Section 1.2 of WCAP-17330-P, Revision 1 (Reference 19) provides a discussion of the action plan to respond to the 14 unresolved questions.

The following documents have been prepared by Westinghouse to provide final resolution of the remaining questions identified in the December 9, 2009 NRC letter in support of the permanent H* amendment for Salem Unit 1.

• WCAP-17330-P, Revision 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model 05)," June 2011 (Reference 19).

• LTR-SGMP-1 0-78 P-Attachment, "Effects of Tubesheet Bore Eccentricity and Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H*," September 7, 2009. This document, which is applicable to Salem Unit 1 Model F steam generators, was transmitted to the NRC by Westinghouse letter LTR-NRC-1 0-68 on November 9, 2010 (Reference 20).

• LTR-SGMP-09-111 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. This document, which is applicable to Salem Unit 1 Model F steam generators, was transmitted to the NRC by Westinghouse letter LTR-NRC-1 0-69 on November 10, 2010 (Reference 22).

• LTR-SGMP-1 0-33 P-Attachment, "H* Response to NRC Questions Regarding Tubesheet Bore Eccentricity," September 13,2010. This document, which is applicable to Salem Unit 1 Model F steam generators, was transmitted to the NRC by Westinghouse letter LTR-NRC-10-70 on November 11, 2010 (Reference 21).

Note that WCAP-17330-P, Revision 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model 05)," June 2011 (Reference 19) makes reference 7 of 21 LAR S12-01 LR-N12-0108 to Revision 2 of WCAP-17071-P and Revision 1 of LTR-SGMP-09-100 P-Attachment. As described above, PSEG has previously submitted Revision 0 of these documents. These revisions (Revisions 1 and 2 of WCAP-17071-P, Revision 1 of LTR-SGMP-09-1 00 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.

The following table provides the list of the Salem Unit 1 licensing basis documents for H*.

Document Revision Title Reference Number Number Number WCAP-17330-P 1 H*: Resolution of NRC Technical Issue 19 Regarding Tubesheet Bore Eccentricity (Model F/Model D5)

LTR SGMP-11-58 0 WCAP-17330-P, Revision 1 Erratum 24 WCAP-17071-P 0 H*: Alternate Repair Criteria for the 10 Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)

LTR-SGMP-09-100 0 Response to NRC Request for Additional 15 P-Attachment Information on H*; Model F and Model D5 Steam Generators LTR -SGMP-09-1 09 0 Response to NRC Request for Additional 16 P-Attachment Information on H*; RAI #4; Model F and Model D5 Steam Generators LTR-SG MP-09-144 0 Correction to WCAP-17071-P, "H*: Alternate 4 Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)"

LTR-SGMP-1 0-78 0 Effects of Tubesheet Bore Eccentricity and 20 P-Attachment Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H*

LTR-SGMP-10-33 0 H* Response to NRC Questions Regarding 21 P-Attachment Tubesheet Bore Eccentricity LTR-SGMMP-11-28 1 Response to USNRC Request for Additional 35 P-Attachment Information Regarding the License Amendment Requests for Permanent Application of the Alternate Repair Criterion, H*, to the Model D5 and Model F SGs In addition, the following correspondence is also applicable to the Salem Unit 1 permanent alternate repair criteria request.

• A March 28, 2011 letter from the NRC to Southern Nuclear Operating Company (Reference 25) documented the summary of a February 16, 2011 public meeting regarding 8 of 21 LAR S12-01 LR-N12-0108 steam generator tube inspection permanent alternate repair criteria. Enclosure 3 of the NRC letter provided technical NRC Staff questions developed at the meeting. Responses to these questions have been incorporated into WCAP-17330-P, Revision 1 (Reference 19).

• Section 1.3 of Reference 19 identifies revisions to the report (WCAP-17330-P, Revision 1) to address recommendations from the independent review of the H* analysis performed by MPR Associates. Related to the independent review, a May 26, 2011 letter from the NRC to Southern Nuclear Company (Reference 26) included a presubmittal review request for additional information. The response to the NRC presubmittal review request is provided in Southern Nuclear Operating Company letter NL-11-1178 (Reference 27).

On June 30, 2011, Duke Energy submitted a license amendment request (Reference 28) for permanent application of the alternate repair criterion H* at Catawba Unit 2 based on the technical justification in WCAP-17330-P, Revision 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model D5)." A supplement (Reference 29) to the license amendment request was submitted on July 11, 2011 and provided Westinghouse Electric Company LLC LTR-SGMP-11-58, "WCAP-17330-P, Revision 1 Erratum." (Reference

24) On January 5, 2012, a request for additional information (Reference 30) was transmitted electronically to Duke Energy. Duke Energy responded to the request for additional information on January 12, 2012 (Reference 31). On March 12,2012, the NRC issued Amendment No. 267 for Catawba approving the H* permanent alternate repair criterion (Reference 17).

Subsequent to the Duke Energy license amendment request, Virginia Electric and Power Company (Dominion) submitted a license amendment request (Reference 32) for permanent application of the alternate repair criterion H* for Surry Power Station Units 1 and 2. On January 18, 2012, the NRC issued a request for additional information (Reference 33).

Dominion responded to the request for additional information on February 14, 2012 (Reference 34).

Westinghouse Electric Company LLC, LTR-SGMMP-11-28 Rev.1 P-Attachment (Reference 35),

"Response to USNRC Request for Additional Information Regarding the License Amendment Requests for Permanent Application of the Alternate Repair Criterion, H*, to the Model D5 and Model F SGs," augments the responses to the Duke Energy request for additional information to include similar responses applicable to Model F steam generators (the model installed at Salem Unit 1). Additionally, LTR-SGMMP-11-28 Rev.1 P-Attachment addresses the Dominion request for additional information question 14 for the Model F steam generators. LTR-SGMMP-11-28 Rev.1 P-Attachment was docketed by letter dated March 22, 2012, as part of Southern Nuclear Operating Company (SNC) license amendment request (Reference 23) for permanent application of the alternate repair criterion H* at Vogtle Electric Generating Plant Units 1 and 2 (VEGPf 2 Note that SNC submitted both the proprietary (P) and non-proprietary (NP) versions of LTR-SGMMP-11-28 Rev.1. On March 20, 2012, Westinghouse issued an errata letter (Reference 36) for LTR-SGMMP-11-28, "LTR-SGMMP-11-28, Revision 0 and Revision 1, P- and NP-Attachment Errata."

This errata letter, also submitted by SNC, corrects the table numbering on page 39 of the non-proprietary attachment (the table number should be Table 2 instead of Table 15) and the Appendix A cover page title of both the P and Non P Attachment (title should be should be LTR-SGDA-11-87 instead of LTR-SGMP-11-87). These errors have no technical impact.

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Attachment 1 LAR S12-01 LR-N12-0108 Attachment 5 of this submittal provides Salem Unit 1 specific responses to questions 12 and 13 from the Duke Energy request for additional information and question 15 from the Dominion request for additional information.

Technical Evaluation To preclude the unnecessary plugging of tubes in the Salem Unit 1 steam generators, an evaluation was performed to identify the safety significant portion of the tube within the tubesheet necessary to maintain structural and leakage integrity in both normal and accident conditions. Tube inspections will be limited to identifying and plugging degradation in the safety significant portion of the tubes. The technical evaluation for the inspection and repair methodology is provided in the H* Analysis as described above. This 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 Salem Unit 1 Model F steam generator 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 burst and axial separation due to axial pullout forces 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 safety significant portion of the tube within the tubesheet is based upon evaluation and testing programs 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 pullout and resistance to leakage during plant operation and transients.

Primary-to-secondary leakage from tube degradation is assumed to occur in several design basis accidents: main steam line break (SLB), locked rotor3 , 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 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. Radiological dose consequences define the limiting accident condition for the H*

justification.

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 (Reference 5) and NRC Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes,"

(Reference 9) 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 accident analysis calculations have an assumption of 0.6 gpm at room temperature (gpmRT) primary-to-secondary leakage in a single SG and 1 gpm at room 3 Westinghouse Letter LTR-SGMP-09-144, Correction to WCAP-17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)" (Reference 4), clarifies that the Salem Unit 1 licensing basis does not include the reactor coolant pump locked rotor with a stuck open power operated relief valve (PORV) transient.

This does not alter any of the conclusions ofWCAP-17071-P.

10 of 21 LAR S12-01 LR-N12-0108 temperature (gpmRT) total primary-to-secondary leakage for all SGs. This apportioned primary-to-secondary leakage is used in the Main Steam Line Break and Locked Rotor accidents.

Primary-to-secondary leakage of 1 gpm at room temperature (gpmRT) from all SGs, conservatively modeled to be released from a single location to maximize control room dose consequences, is used in the Control Rod Ejection (CRE) accident. The TS operational leak rate limit is 150 gallons per day (gpd) (0.104 gpmRT). The maximum accident leak rate ratio for Salem Unit 1 is 2.16 (Revised Table 9-7, Reference 15). Consequently, this results in significant margin between the conservatively estimated accident leakage and the allowable accident leakage.

Plant-specific operating conditions are used to generate the overall leakage factor ratios that are to be 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 steam generator are contained in Section 6 of Reference 10.

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 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 viscosity change.

The increase in leakage would only be a function of the increase in primary to secondary pressure differential (Reference 10). However, per Westinghouse Letter LTR-SGMP-09-1 00 P-Attachment, Revision 0, the FLB transient was evaluated as a heatup event. The resulting leak rate ratio for the SLB and FLB events is 2.16.

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 to result in increased temperatures in the steam generator 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 a FLB, the length of time that a plant with Model F steam generators 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 ejection event can be integrated over a minute to compare 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 leakage factor by the same factor of two for the locked rotor event. Therefore, for the locked rotor event, the leakage factor of 1.55 (Revised Table 9-7, Reference 15) for Salem Unit 1 is adjusted downward to a factor of 0.78. Similarly, for the control rod ejection event, the duration of the elevated pressure differential is less than 10 seconds. Thus, the peak leakage factor may be reduced by a factor of six from 2.31 to 0.39. Due to the short duration of the transients above normal operation pressure 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 11 of 21 LAR 812-01 LR-N12-0108 presented in the Updated Final Safety Analysis Report (UFSAR) Chapter 15.0 safety analysis, indicates that the transient for a Model F steam generator exhibits a cooldown characteristic instead of a heatup 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:

• 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 steam generator, the FLB transient curve (Figure 9-5, Reference 10) 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 requirements 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 feature actuation would no longer be applicable. This would result in much earlier reactor trip and greatly increase the steam generator 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 control system (steam dump or 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 (Reference 10).

The leakage factor of 2.16 for Salem Unit 1 for a postulated SLB/FLB has been calculated as shown in revised Table 9-7 of Reference 15. Specifically, for the condition monitoring (CM) assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.16 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), the difference between the allowable leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.16 and compared to the observed operational leakage.

Reference 10 (submitted via Reference 11) redefines the primary pressure boundary. The tube-12 of 21 LAR S12-01 LR-N12-0108 to-tubesheet weld no longer functions as a portion of this boundary. The hydraulically expanded portion 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 10 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 (Reference 10), section 9.8, provides a review of leak rate susceptibility due 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. As a condition of approval of Amendment Number 294, PSEG committed to the following:

1. to monitor for tube slippage as part of the steam generator tube inspection program.

This commitment will remain in place to support the permanent alternate repair criteria request, and the results of monitoring will be reported in accordance with TS 6.9.1.10.

(refer to Attachment 4 of this submittal).

2. to perform a one-time verification of the tube expansion to locate any significant deviations in the distance from the top of the tubesheet to the bottom of the expansion transition (BET) to determine if there are any significant deviations that would invalidate assumptions in WCAP-17071-P (Reference 10). If any deviations are found, the condition will be entered into the corrective action program and dispositioned.

Additionally, PSEG committed to notify the NRC of significant deviations. PSEG has completed the validation of the tube expansion from the top of tubesheet to the BET.

Based on verification and LTR-SGMP-09-111 P-Attachment, Rev. 1 (Reference 22),

. PSEG did not identify any significant deviations from the top of tubesheet to the BET for Salem Unit 1.

5.0 REGULATORY ANALYSIS

5.1 Applicable Regulatory Requirements/Criteria Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include Technical Specifications (TSs) as part of the operating license. The TSs ensures the operational capability of structures, systems, and components that are required to protect the health and safety of the public. The U.S. Nuclear Regulatory Commission's (NRC's) requirements related to the content of the TSs are contained in Section 50.36 of the Title 10 of the Code of Federal Regulations (10 CFR 50.36) which requires that the TSs include items in the following specific categories: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements per 10 CFR 50.36(c)(3); (4) design features; and (5) administrative controls.

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 (RCPS) with respect to structural and leakage integrity.

13 of 21 LAR S12-01 LR-N12-0108 GOC 19 of 10 CFR 50, Appendix A, defines requirements for the control room and for the radiation protection of the operators working within it. Accidents involving the leakage or burst of steam generator 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.

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 steam generators as risk-significant components because they are relied upon to remain functional during and after design basis events. Steam generators are to be monitored under 10 CFR 50.65(a)(2) against industry established performance criteria. Meeting the performance criteria of Nuclear Energy Institute (NEI) 97-06, Revision 3, "Steam Generator Program Guidelines," provides reasonable assurance that the steam generator tubing remains capable of fulfilling its specific safety function of maintaining the reactor coolant pressure boundary. The NEI 97-06, Revision 2, steam generator performance criteria are:

• 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, cooldown 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 steam generator tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all steam generators and leakage rate for an individual steam generator. Leakage is not to exceed 1 gpm per steam generator, except for specific types of degradation at specific locations when implementing alternate repair criteria as documented in the Steam Generator Program technical specifications.

• The Reactor Coolant System (RCS) operational primary to secondary leakage through anyone steam generator 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 steam generator operating conditions, including the most limiting accident conditions.

14 of 21 LAR S12-01 LR-N12-010B The evaluation in this Attachment determined that degradation in tubing below the safety significant portion of the tube does not require plugging and serves as the bases for the tubesheet inspection program. As such, the Salem Unit 1 inspection program provides a high level of confidence that the structural and leakage criteria are maintained during normal operating and accident conditions.

5.2 No Significant Hazards Consideration This amendment application proposes to revise Technical Specification (TS) 6.B.4.i, "Steam Generator (SG) Program," to exclude portions of the tubes within the tubesheet from periodic steam generator inspections. In addition, this amendment proposes to revise Technical Specification (TS) 6.9.1.10, "Steam Generator Tube Inspection Report," to remove reference to previous interim alternate repair criteria and provide reporting requirements specific to the temporary alternate repair criteria. 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 portion of the tube that must be inspected and repaired. A justification has been developed by Westinghouse Electric Company, LLC 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, "Steam Generator Program," performance criteria.

PSEG 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," Part 50.92(c), as discussed below:

(1) Does the proposed change 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 steam generator inspection 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 steam generator tube inspection and repair criteria are the steam generator tube rupture (SGTR) event, the steam line break (SLB) and the feedline break (FLB) postulated accidents.

Addressing the SGTR event, the required structural integrity margins of the steam generator 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 presence of the tubesheet and constraint provided by 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, from the differential pressure between the primary and secondary side, and 15 of 21 LAR S12-01 LR-N12-010B tubesheet deflection. The structural margins against burst, as discussed in Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," and TS 6.B.4.i 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 steam generator tubes consistent with the performance criteria in TS 6.B.4.L 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 joint. 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 changes do not result in a significant increase in the consequences of a SGTR.

The consequences of a SLB or FLB are also not significantly affected by the proposed changes. The leakage analysis shows that the primary-to-secondary leakage during a SLB/FLB event would be less than or equal to that assumed in the Updated Safety Analysis Report.

Primary-to-secondary leakage from tube degradation in the tubesheet area during the limiting accidents (Le., SLB/FLB) 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 for Salem Unit 1, for a postulated SLB/FLB, has been calculated as 2.16. Specifically, for the condition monitoring (CM) assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.16 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), 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 2.16 and compared to the observed operational leakage.

The probability of an SLB/FLB is unaffected by the potential failure of a steam generator tube as the failure of the tube is not an initiator for an SLB/FLB event. SLB/FLB 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 all postulated accident conditions that model primary-to-secondary leakage (including locked rotor and control rod ejection) has been shown to remain within the accident analysis assumptions for all axial and or circumferentially orientated cracks occurring 15.21 inches below the top of the tubesheet. The accident analysis calculations have an assumption of 0.6 gpm at room temperature (gpmRT) primary-to-secondary leakage in a single SG and 1 gpm at room temperature (gpmRT) total primary-to-secondary leakage for all SGs. This apportioned primary-to-secondary leakage is used in the Main Steam Line Break and Locked Rotor accidents. Primary-to-secondary leakage of 1 gpm at room temperature (gpmRT) from all 16 of 21 LAR S12-01 LR-N12-0108 SGs, conservatively modeled to be released from a single location to maximize control room dose consequences, is used in the Control Rod Ejection (CRE) accident. The TS operational leak rate limit is 150 gallons per day (gpd) (0.104 gpmRT). The maximum accident leak rate ratio for Salem Unit 1 is 2.16 (Revised Table 9-7, Reference 15).

Consequently, this results in significant margin between the conservatively estimated accident leakage and the allowable accident leakage.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

(2) Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed change alters the steam generator inspection and reporting criteria. It 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 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 accident previously evaluated.

(3) Does the change involve a significant reduction in a margin of safety?

Response: No The proposed change alters the steam generator inspection and reporting criteria. It maintains the required structural margins of the steam generator tubes for both normal and accident conditions. NEI 97-06 and RG 1.121, are used as the bases in the development of the limited tubesheet inspection depth methodology for determining that steam generator tube integrity considerations are maintained within acceptable limits. RG 1.121 describes a method acceptable to the NRC for meeting 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, the H* Analysis documented in Section 3, 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 provides for large margins between calculated and actual leakage values in the proposed limited tubesheet inspection depth criteria.

17 of 21 LAR 812-01 LR-N12-0108 Therefore, the proposed change does not involve a significant reduction in any margin of safety.

5.3 Conclusion The safety significant portion of the tube (15.21 inches) 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 steam generating operating conditions, including the most limiting accident conditions. The H* Analysis determined that degradation in tubing 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 a 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.

6.0 ENVIRONMENTAL CONSIDERATION

PSEG 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 forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the proposed amendment.

7.0 REFERENCES

1. Letter from NRC to PSEG, "Salem Nuclear Generating Station, Unit No. 1 - Issuance of Amendment Re: Steam Generator Tube Inservice Inspection Program (TAC NO.

MC6213)," dated October 14, 2005 (ADAMS Accession No. ML052720233)

2. Letter from NRC to PSEG, "Salem Nuclear Generating Station, Unit No.1 - Issuance of Amendment Re: Steam Generator Alternate Repair Criteria (TAC NO. MD4034)," dated March 27, 2007 (ADAMS Accession No. ML070790070)

3. Letter from NRC to PSEG, "Salem Nuclear Generating Station, Unit No.1 - Issuance of Amendment Re: Steam Generator Inspection Scope and Repair Requirements (TAC NO. ME2374)," dated March 29, 2010 (ADAMS Accession No. ML100570452) 18 of 21 LAR S12-01 LR-N12-0108

4. Westinghouse LeUer LTR-SGMP-09-144, Correction to WCAP- 17071-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)

5. NEI 97-06, "Steam Generator Program Guidelines."

6. EPRI 1013706, "Steam Generator Management Program: Pressurized Water Reactor Steam Generator Examination Guidelines."

7. EPRI 1019038, "Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines."

8. NRC Information Notice 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," April 7, 2005.

9. NRC Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," August 1976.

10. Westinghouse Electric Company LLC, WCAP-17071-P, Revision 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model F)," April 2009. (ADAMS Accession No. ML091590167 (Non-Proprietary (NP version)))

11. Letter from PSEG to NRC, "License Amendment Request, Revision to Technical Specification 6.8.4.i, "Steam Generator (SG) Program," for One-Time (Interim) Alternate Repair Criteria (H*)" dated October 8,2009 (ADAMS Accession No. ML092960584)

12. Letter from NRC to Southern Nuclear Operating Company, Inc., "Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments Regarding Technical Specification (TS) Section 5.5.9, "Steam Generator Program," for Interim Alternate Repair Criteria (TAC NOS. ME1339 and ME 1340)," dated September 24,2009 (ADAMS Accession No. ML092170782)

13. Letter from D. Wright, USNRC, to M. J. Ajluni, Southern Nuclear Operating Company, Inc., "Vogtle Electric Generating Plant, Units 1 and 2, Request for Additional Information Regarding Steam Generator Program (TAC NOS. ME1339 and ME1340)", dated July 10,2009 (ADAMS Accession No. ML091880384)

14. Letter from D. Wright, USNRC, to M. J. Ajluni, Southern Nuclear Operating Company, Inc., "Vogtle Electric Generating Plant, Units 1 and 2, Request for Additional Information Regarding Steam Generator Program (TAC NOS. ME1339 and ME1340)", dated August 5,2009 (ADAMS Accession No. ML092150057)

15. LTR-SGMP-09-1 00, "LTR-SGMP-09-100 P-Attachment, "Response to NRC Requestfor Additional Information on H*; Model F and Model D5 Steam Generators," August 12, 2009. (ADAMS Accession No. ML092450095 (Non-Proprietary (NP version)))

16. LTR-SGMP-09-1 09 P-Attachment, "Response to NRC Request For Additional Information on H*; RAI #4; Model F and Model D5 Steam Generators," August 25,2009.

(ADAMS Accession No. ML092590299 (Non-Proprietary (NP version)))

19 of 21 LAR 812-01 LR-N12-0108

17. NRC Letter to Duke Energy, "Catawba Nuclear Station Units 1 and 2, Issuance of Amendment Regarding Technical Specifications Amendments for Permanent Alternate Repair Criteria for Steam Generator Tubes (TAC Nos. ME6670 and ME6671), March 12, 2012 (ADAMS Accession No. ML12054A692)

18. NRC letter from B. K. Singal, USNRC, to R. A. Muench, WCNOC, "Wolf Creek Generating Station - Transmittal of Unresolved Issues Regarding Permanent Alternate Repair Criteria for Steam Generators (TAC NO. ME1393)," December 9,2009. (ADAMS Accession No. ML093360459)

19. WCAP-17330-P, Revision 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model 05)," June 2011.

20. LTR-NRC-1 0-68, "Submittal of LTR-SGMP-1 0-78 P-Attachment and LTR-SGMP-1 0-78 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," November 9,2010.

21. LTR-NRC-1 0-70, "Submittal of LTR-SGMP-10-33 P-Attachment and LTR-SGMP-1 0-33 NP-Attachment, LTR-SGMP-1 0-33 P-Attachment, "H* Response to NRC Questions Regarding Tubesheet Bore Eccentricity," (Proprietary/Non-Proprietary) for Review and Approval," November 11, 2010.

22. LTR-NRC-10-69, "Submittal of 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," November 10, 2010. (ADAMS Accession No. ML103400083)

23. SNC Letter to the NRC, "Vogtle Electric Generating Plant - Units 1 and 2, License Amendment Request to Revise Technical Specification Sections 5.5.9, "Steam Generator (SG) Program" and 5.6.10, "Steam Generator Tube Inspection Report","

dated March 22,2012 (ADAMS Accession No. ML12087A307)

24. Westinghouse Electric Company LLC LTR LTR-SGMP-11-58, "WCAP-17330-P, Revision 1 Erratum," July 6, 2011.

25. NRC letter to Southern Nuclear Operating Company, Inc., "Summary of February 16, 2011 Meeting with Southern Nuclear Operating Company, Inc. and Westinghouse on Technical Issues Regarding Steam Generator Tube Inspection Permanent Alternate Repair Criteria (TAC NOS. ME5417 and ME5418)," March 28, 2011. (ADAMS Accession No. ML110660648)

26. NRC letter to Southern Nuclear Operating Company, Inc., "Vogtle Electric Generating Plant Units 1 and 2 - Presubmittal Consideration of Steam Generator Alternative Repair Criteria Requirements Request for Additional Information (TAC NOS. ME 5417 and ME5418)," May 26, 2011. (ADAMS Accession No. ML11140A099)

27. Southern Nuclear Operating Company, Inc. letter NL-11-1178, "Vogtle Electric Generating Plant - Response to Presubmittal Consideration of Steam Generator 20 of 21 LAR S12-01 LR-N12-0108 Alternative Repair Criteria Requirements Request for Additional Information," June 20, 2011. (ADAMS Accession No. ML111721903)

28. Duke Energy Corporation, "Proposed Technical Specifications (TS) Amendment TS 3.4.13, "RCS Operational LEAKAGE," TS 5.5.9, "Steam Generator (SG) Program," TS 5.6.8, "Steam Generator (SG) Tube Inspection Report," License Amendment Request to Revise TS for Permanent Alternate Repair Criteria," June 30, 2011. (ADAMS Accession No. ML11188A107)

29. Duke Energy Corporation, "Proposed Technical Specifications (TS) Amendment TS 3.4.13, "RCS Operational LEAKAGE," TS 5.5.9, "Steam Generator (SG) Program," TS 5.6.8, "Steam Generator (SG) Tube Inspection Report," License Amendment Request to Revise TS for Permanent Alternate Repair Criteria," July 11, 2011. (ADAMS Accession No. ML11195A067)

30. Electronic mail from NRC to Duke Energy Corporation, "Catawba Nuclear Station Unit 2 (Catawba 2), Request for Additional Information (RAI) Regarding the Steam Generator License Amendment Request to Revise Technical Specification for Permanent Alternate Repair Criteria (TAC NO. ME6671)," January 5, 2012. (ADAMS Accession No. ML120090321)

31. Duke Energy Corporation, "Proposed Technical Specifications (TS) Amendment TS 3.4.13, "RCS Operational LEAKAGE," TS 5.5.9, "Steam Generator (SG) Program," TS 5.6.8, "Steam Generator (SG) Tube Inspection Report," License Amendment Request to Revise TS for Permanent Alternate Repair Criteria," January 12, 2012. (ADAMS Accession No. ML12019A250)

32. Virginia Electric and Power Company (Dominion) letter Serial No.11-403, "License Amendment Request Permanent Alternate Repair Criteria for Steam Generator Tube Inspection and Repair," July 28, 2011. (ADAMS Accession No. ML11215A058)

33. NRC letter to Virginia Electric and Power Company (Dominion), "Surry Power Station, Unit Nos. 1 and 2 - Request for Additional Information Regarding the Steam Generator License Amendment Request to Revise Technical Specifications for Permanent Alternate Repair Criteria (TAC NOS. ME6803 and ME6804)," January 18, 2012.

(ADAMS Accession No. ML12006A001)

34. Virginia Electric and Power Company (Dominion) letter Serial No.12-028, "Response to Request for Additional Information Related to License Amendment Request for Permanent Alternate Repair Criteria for Steam Generator Tube Inspections and Repair,"

February 14, 2012. (ADAMS Accession No. ML12048A676)

35. Westinghouse Electric Company LLC, LTR-SGMMP-11-28 Rev.1 P-Attachment, "Response to USNRC Request for Additional Information Regarding the License Amendment Requests for Permanent Application of the Alternate Repair Criterion, H*, to the Model D5 and Model F SGs," February 2,2012.

36. Westinghouse Electric Company LLC, LTR-SGMMP-11-28 Errata, Rev. 1, "LTR-SGMMP-11-28, Revision 0 and Revision 1, P- and NP-Attachment Errata," March 20, 2012 21 of 21 LAR S12-01 LR-N12-010B Mark-up of Proposed Technical Specification Pages The following Technical Specifications pages for Renewed Facility Operating License DPR-70 are affected by this change request Technical Specification 6.B.4.i, "Steam Generator (SG) Program" 6-19c and d 6.9.1.10, "Steam Generator Tube Inspection Report" 6-24b 1 of 1

6DMIhilSrflAIIVE COhiIBQL.S en*

outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met

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 shail 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~$econdary 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 bUfst Of 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 prlmary-tc;..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 gallon per minute per 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.

The following alternate repair criteria shall be applied as an alternative to the 40% depth

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d. -~. 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~t et weld at the tube and that may satisfy the applicable tube repair crJteri tieb'Q' *~'-~~*.~~~~:tE "riJ*

SALEM ~ UNIT 1 Amendment No. 294

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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 shaH 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 as'sessment, to determine Which inspection methods need to be employed and at what locations.

1. Inspect 100% of the tubes in each sa during the first refueling outage foUowing 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 in service 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 refueUng outages (whichever is less) without being inspected.

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 nonwdestructive 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, SALEM - UNIT 1 6-19d Amendment No. 294

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h. The primary to secondary leakage rate observed in each SG (if it is not practical to assign the leakage to an individual S8, 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, Iculated accident induced leakage rate from the portion of the tubes below hes from the top of the tubesheet for the most limiting accident in the ost limiting SQ. In addition, if the calculated accident induced leakage rate from the most limiting accident is less than 2.16 times the maximum operational primary to secondary lea:kage rate, the report should describe how it was determined,

j. The results of monitoring for tube axial displacement (slippage). If sHppage is discovered. the implications of the discovery and corrective action shall be provided.

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the U.S. Nuclear Regulatory Commission, Document Control DeSK, Washington, D.C. 20555, with a copy to the Administrator, USNRC Region I within the time period specified for each report.

6.9,3 DELETED 6.9A When a report is required by ACTION 8 or 9 of Table 3.3-11 "Accident Monitoring Instrumentation", a report shall be submitted within the foilowing 14 days. The report shall outline the preplanned alternate method of monitoring for lnadequate core cooiing, the cause of the inoperability, and the plans and schedule for restoring the instrument channels to OPERABLE status.

SALEM - UNIT 1 6-24b Amendment No. 294 LAR S12-01 LR-N12-0108 Mark-up of Proposed Technical Specification Bases Pages The following Technical Specification Bases pages for Renewed Facility Operating License DPR-70 are affected by this change request TS Bases 3/4.4.5, "Steam Generator (8G) Tube Intergrity" B 3/4 4-2 1 of 1

REACTOR COOLANT SYSTElYl BASES 3/4.4.4 PHESSlJF:.I.ZER.

The limit on the maximum water assures that the parameter is mainta.ined Hithin the normal of operat,i.on assumed in the SAR. The limit is consistent Nith the initi.al The Surveillance is based on operating t reliabili ty, and and is contro11ed under the Surveil Control The maxirmlm ..rate::: vo1'clme a1$o ensureS that a steam bubble is y solid system. The a minimum number of heaters be OPE:RABLE, <i.S$Ur0S that the will be able to establish natural circulation.

3/4.4.5 STEl\M c;:ENERl\TOH(SG) TD}3E TNTEGRI'I'Y The I,CO be maintained. The LCO also th<lt criteria be ugged in accordance with t1'1',l StA"am ion, any repair criteria is removed f:core\ s~,rvi.ce by If a tube Has dCC:0x'w.i.nedt;o s,Cltisfy thr2 criteria but Has not plugged, the tube may stiB have 'cu.be In the context of this cation, a 50 tube is defined as the entire of the tube, the tube HaIl betl4een the tub(,,-to~tub(!~')he0t Held

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i,nch,s r)~:;lot:! the top of the tubesh.eet (10 Dot " Tubes ce-i.nciucBd. fle.w~s l.ocatf6-d in t.he portion of tl1.0 top of inchcs belov.f the 'Cop of th~ 'tutHtsn.eet: tlgged tube-to-tubesheet weld 1s not considered tube.

when it satisfies the S0 criteria are defined in Specification 6.8.4.i, "Steam Generator (5G) Proqrarc~f ff and descr:ibe aGcept:c)bl.:;;:) SG tu.l}E;~ perfor.mance" The Steam Generator also evaluation process for criter.is.~

?there ar.e three SG performance eLi tecta: st:ruGtlJral tYt accid.ent.

induced t and operational le,,,,k;,:\ge. Failure to T(.eet <,my one of these criteria is ccmsidered ftl.:l.l:vxc to meet the I,CO.

The structuraL :Lntegri cd. tedon prov:Ldes a of safety 21.ga.inst tube burst or- normal and i~cc:Ldent cond.i t:Lons, and ensures structural ty of the SG tubes under aLL anticipated transients included in the .fi<>ation.. T'j.b*e burst is d.efin-ed as, \\~I'he gross structural failure of the tube waLL. The condition typical corresponds to an unstable opening displacetnEmt (e. g. t openi.ng a:cea in response to constant pressure) acco:np21ni.ed by duct:i.1e (plastic) of tb~ tube t(\<ll teria.l at tli" ends of the ff :r*ube co.llapse 1.s defined as; "\\:t'or ,the load curve for a structure! collapse occurs at the top of the 10B.d versus displacement curve ,,,here the of the curve becomes zero." The structural criterion provides on loads that significantly affect burst or collapse. In that context, the term "significant n i8 defined as, "An accident loading condition other than differential pressure is considered ficant when the addition of such loads in the assessment of the structura,; ity criterLon could cause a Jower structural limit or burst/collapse cond.it.:Lon to be established."

SALEN! - UNI1' 1 B 3/4 4=2 Amendment No. 299 (PSEG Issued)

LAR 812-01 LR-N12-0108 LIST OF REGULATORY COMMITMENTS The following table identifies those actions committed to by PSEG in this document. Any other statements in this submittal are provided for information only purposes and are not considered to be regulatory commitments.

REGULATORY COMMITMENT Committed Commitment Type Date One- Programmatic Time (Yes/No)

Action (Yes/No)

For the condition monitoring (eM) assessment, Implementation No Yes the component of leakage from the prior cycle of Amendment from below the H* distance will be multiplied by a factor of 2.16 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the operational assessment (OA), 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 2.16 and compared to the observed operational leakage. An administrative limit will be established to not exceed the calculated value. (Salem Unit 1)

PSEG will monitor for tube slippage as part of Implementation No Yes the steam generator tube inspection program. of Amendment The results of this monitoring will be included in the report required by TS 6.9.1.1 OJ. (Salem Unit 1) 1 of 1 LAR 812-01 LR-N12-0108 ATTACHMENT 5 Response to Request for Additional Information Questions Specific to Salem Unit 1 1 of 4 LAR S12-01 LR-N12-0108 Response to Request for Additional Information Questions Specific to Salem Unit 1 On June 30, 2011, Duke Energy submitted a license amendment request (Reference 28) for permanent application of the alternate repair criterion H* at Catawba Unit 2 based on the technical justification in WCAP-17330-P, Revision 1, "H*; Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model D5)." A supplement (Reference 29) to the license amendment request was submitted on July 11, 2011 and provided Westinghouse Electric Company LLC LTR-SGMP-11-58, "WCAP-17330-P, Revision 1 Erratum." On January 5, 2012, a request for additional information (Reference 30) was transmitted electronically to Duke Energy. Duke Energy responded to the request for additional information on January 12, 2012 (Reference 31).

Subsequent to the Duke Energy license amendment request, Virginia Electric and Power Company (Dominion) submitted a license amendment request (Reference 32) for permanent application of the alternate repair criterion H* for Surry Power Station Units 1 and 2. On January 18, 2012, the NRC issued a request for additional information (Reference 33).

Dominion responded to the request for additional information on February 14, 2012 (Reference 34).

Westinghouse Electric Company LLC, LTR-SGMMP-11-28 Rev.1 P-Attachment, "Response to USNRC Request for Additional Information Regarding the License Amendment Requests for Permanent Application of the Alternate Repair Criterion, H*, to the Model D5 and Model F SGs,"

augments the responses to the Duke Energy request for additional information to include similar responses applicable to Model F steam generators. Additionally, LTR-SGMMP-11-28 Rev.1 P-Attachment addresses the Dominion request for additional information question 14 for the Model F steam generators. Provided below are Salem Unit 1 specific responses to questions 12 and 13 from the Duke Energy request for additional information and question 15 from the Dominion request for additional information. The NRC question is identified in italics.

12. BET measurements for Catawba 2, documented in Westinghouse letter LTR-SGMP 111 P-Attachment, Revision 1, range to a maximum of 0.65 inches and appear not to be a factor affecting the H* and leak rate ratio calculations. Apart from tubes with this reported range of BETs, are there any non-expanded or partially expanded tubes at Catawba 2? If so, provide revisions to the proposed technical specifications which exclude such tubes from the proposed H* provisions.

PSEG Response:

Amendment No. 294 of Facility Operating License No. DPR-70 for Salem Nuclear Generating Station Unit 1 required a commitment for a one time verification of all the expansion transition locations. PSEG measured all the hot leg (HL) and cold leg (CL) BET using historical eddy current data from 1R16 outage (tubes plugged prior to 1R16 were not included). Bottom expansion transition (BET) measurements for Salem Unit 1, documented in Westinghouse letter LTR-SGMP-09-111 P-Attachment, Revision 1, range to a maximum of 0.53 inches. Apart from tubes with this reported range of BETs, there are no non-expanded or partially expanded tubes in service at Salem Unit 1. As such, revision to the technical specifications to exclude such tubes from the proposed H* provisions is not required.

2 of 4 LAR S12-01 LR-N 12-0 108

13. Proposed TS 5.6.8.h throughj- The proposed changes contain more words than seem necessary, reducing the clarity of the proposed reporting requirements. For example, the proposed wording refers to "an inspection performed after each refueling outage" which doesn't seem to make sense. The NRC staff believes the proposed requirements can be stated more clearly and concisely as follows:

h. For Unit 2, feHel/ling cempletien ef an inspection performed during End of Cycle 17 Refueling Outage (and any inspections performed during subsequent Cyclo 18 operation),

the primary to secondary LEAKAGE rate observed in each steam generator (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,

i. For Unit 2, fefloll.t.ing completion of an inspection performed during the End of Cycle 17 Refueling Outage (and any inspections performed during subsequent Cycle 18 operation),

the calculated accident induced leakage rate from the portion of the tubes below~ 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG.

In addition, if the calculated accident leakage rate from the most limiting accident is less than 3.27 times the maximum primary to secondary LEAKAGE rate, the report shall describe how it was determined, and

j. For Unit 2, fe/!-o'IAng completion of an inspection performed during the End of Cycle 17 Refueling Outage (and any inspections performed during subsequent Cye/{) 18 operation),

the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

Provide revisions to the proposed reporting requirements as necessary to clarify their intent.

PSEG Response: The Salem Unit 1 proposed changes to technical specification (TS) 6.9.1.10 "Steam Generator Tube Inspection Report," in Attachment 2 of this submittal are consistent with the NRC staff's recommendation above.

15. Verify that regulatory commitments pertaining to monitoring for tube slippage and for primary to secondary leakage, as described in Dominion letter dated December 16, 2010 (NRC ADAMS Accession No. ML103550206), Attachment 1, page 10 of 23, remain in place. In addition, revise the proposed amendment to include a revision to technical specification limit on primary to secondary leakage from 150 gallons per day (gpd) to 83 gpd (150 divided by the proposed 1.8 leakage factor), or provide a regulatory basis for not making this change.

PSEG Response: The regulatory commitments pertaining to monitoring for tube slippage and for primary to secondary leakage as described in PSEG letter dated October 8, 2009 (Reference 11) remain in place as specified in Attachment 4 of this submittal.

The accident analysis calculations have an assumption of 0.6 gpm at room temperature (gpmRT) primary-to-secondary leakage in a single SG and 1 gpm at room temperature (gpmRT) total primary-to-secondary leakage for all SGs. This apportioned primary-to-secondary leakage is used in the Main Steam Line Break and Locked Rotor accidents. Primary-to-secondary leakage of 1 gpm at room temperature (gpmRT) from all SGs, conservatively modeled to be 3 of 4 LAR S12-01 LR-N 12-0 108 released from a single location to maximize control room dose consequences, is used in the Control Rod Ejection (CRE) accident. The TS operational leak rate limit is 150 gallons per day (gpd) (0.104 gpmRT). The maximum accident leak rate ratio for Salem Unit 1 is 2.16 (Revised Table 9-7, Reference 15). Consequently, this results in significant margin between the conservatively estimated accident leakage and the allowable accident leakage. Therefore, PSEG is not proposing any changes to the primary to secondary LEAKAGE limit as specified in TS 3.4.6.2, "RCS Operational Leakage".

4 of 4