ML11215A058

License Amendment Request Permanent Alternate Repair Criteria for Steam Generator Tube Inspection and Repair

ML11215A058
Person / Time
Site:	Surry
Issue date:	07/28/2011
From:	Price J Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
11-403
Download: ML11215A058 (36)

Text

PROPRIETARY INFORMATION - WITHHOLD UNDER I OCFR2.390 VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 July 28, 2011 10CFR50.90 U.S. Nuclear Regulatory Commission Serial No.11-403 Attention: Document Control Desk SPS/LIC-CGL RO Washington, D.C. 20555 Docket Nos.

50-280/281 License Nos.

DPR-32/37 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2 LICENSE AMENDMENT REQUEST PERMANENT ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE INSPECTION AND REPAIR Pursuant to 10CFR50.90, Virginia Electric and Power Company (Dominion) requests an amendment of the Facility Operating License in the form of a change to the Technical Specifications (TS) to Facility Operating License Numbers DPR-32 and DPR-37 for Surry Power Station Units 1 and 2, respectively. This amendment request proposes to permanently revise TS 6.4.Q, "Steam Generator (SG) Program," to exclude portions of the SG tube below the top of the SG tubesheet from periodic inspections.

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.

Inclusion of the permanent alternate repair criteria in TS 6.4.Q permits deletion of the previous one-time alternate repair criteria for Surry Unit 1, as well as the previous temporary alternate repair criteria for Surry Unit 2.

In addition, this amendment request proposes to revise TS 6.6.A.3, "Steam Generator Tube Inspection Report," to remove references to the previous Unit 1 one-time and Unit 2 temporary alternate repair criteria and provides reporting requirements specific to the permanent alternate repair criteria. 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 of, including WCAP-17345-P, "H*:

Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51 F), Revision 2, June 2011. provides the basis for the proposed change, including a detailed description, technical and regulatory evaluations, environmental considerations, and Dominion's determination that the proposed change does not involve a significant hazards consideration.

The marked-up and proposed TS pages are provided in Attachments 2 and 3, respectively.

Copies of WCAP-17345-P, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)" (Proprietary), and WCAP-17345-NP, "H*:

Resolution of ATTACHMENT 4 CONTAINS PROPRIETARY INFORMATION THAT IS BEING WITHHELD FROM PUBLIC DISCLOSURE UNDER 10CFR2.390.

UPON SEPARATION OF ATTACHMENT 4, THIS PAGE IS DECONTROLLED. 4o7

Serial No.11-403 Docket Nos. 50-280/281 Permanent Alternate Repair Criteria Page 2 of 3 NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)"

(Non-proprietary),

are provided in Attachments 4 and 5, respectively. is Westinghouse letter CAW-11-3187, "Application for Withholding Proprietary Information from Public Disclosure," with accompanying affidavit. contains information proprietary to Westinghouse Electric Company LLC, and it is supported by the affidavit in Attachment 6 signed by Westinghouse, the owner of the information.

The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10CFR2.390 of the Commission's regulations. Accordingly, it is respectfully requested that the information, which is proprietary to Westinghouse, be withheld from public disclosure in accordance with 10CFR2.390.

Correspondence with respect to the copyright or proprietary aspects of Attachment 4 or the supporting Westinghouse affidavit should reference letter CAW-1 1-3187 and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P. 0. Box 355, Pittsburgh, PA 15230-0355.

Approval of this amendment request for the Units 1 and 2 permanent alternate repair criteria is requested by April 2, 2012 with a 30-day implementation period to support the Surry Unit 1 Refueling Outage 24 (Spring 2012), since the existing Unit 1 one-time alternate repair criteria approved by Unit 1 Amendment 267 expires at the end of the current operating cycle.

This amendment will be implemented prior to the 200 degree F mode change during startup following the Unit 1 Refueling Outage 24.

If you have any questions or require additional information, please contact Mr. Gary Miller at (804) 273-2771.

Sincerely, J.Al ce VICK! L. HULL Notary Public Vic Pp.*ident - Nuclear Engineering Commonwealth of Virginia 140542 COMMONWEALTH OF VIRGINIA

)

Commlsion Expires May 31, 2014 COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by J. Alan Price who is Vice President - Nuclear Engineering, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this.

day of 2011.

My Commission Expires:

-3/- /

Notary Public

Serial No.11-403 Docket Nos. 50-280/281 Permanent Alternate Repair Criteria Page 3 of 3 Attachments:

1. Discussion of Change

2. Marked-up Technical Specifications Pages

3. Proposed Technical Specifications Pages

4. Westinghouse Electric Company LLC WCAP-17345-P, "H*:

Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)" (Proprietary),

Revision 2, June 2011

5. Westinghouse Electric Company LLC WCAP-17345-NP, "H*:

Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)" (Non-proprietary), Revision 2, June 2011

6. Westinghouse Electric Company LLC Letter CAW-11-3187, "Application for Withholding Proprietary Information from Public Disclosure," June 20, 2011 Commitments made in this letter: None cc:

U.S. Nuclear Regulatory Commission, Region II Marquis One Tower 245 Peachtree Center Avenue NE, Suite 1200 Atlanta, Georgia 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building - 7th floor 109 Governor Street, Suite 730 Richmond, Virginia 23219 NRC Senior Resident Inspector Surry Power Station Ms. K. R. Cotton NRC Project Manager - Surry U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852 Mr. R. E. Martin NRC Project Manager - North Anna U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852

Serial No.11-403 Docket Nos. 50-280/281 ATTACHMENT 1 DISCUSSION OF CHANGE LICENSE AMENDMENT REQUEST PERMANENT ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE INSPECTION AND REPAIR VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS I AND 2

Serial No.11-403 Dockets Nos. 50-280/281 Discussion of Change Table of Contents 1.0 Introduction 2.0 Detailed Description of Proposed Revisions 3.0

Background

4.0 Summary of Licensing Basis Analysis (H* Analysis) 5.0 Technical Evaluation 6.0 Regulatory Evaluation 6.1 Applicable Regulatory Requirements/Criteria 6.2 No Significant Hazards Consideration 6.3 Precedents 6.4 Conclusion 7.0 Environmental Considerations 8.0 References 1 of 22

Serial No.11-403 Dockets Nos. 50-280/281 DISCUSSION OF CHANGE 1.0 Introduction Virginia Electric and Power Company (Dominion) proposes to revise the Surry Power Station Technical Specifications (TS) 6.4.Q, "Steam Generator (SG) Program," to permanently exclude portions of the steam generator tubes below the top of the steam generator tubesheet from periodic tube inspections.

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. Inclusion of the permanent alternate repair criteria in TS 6.4.Q permits deletion of the previous one-time alternate repair criteria for Surry Unit 1, as well as the previous temporary alternate repair criteria for Surry Unit 2.

In addition, this amendment request proposes to revise TS 6.6.A.3, "Steam Generator Tube Inspection Report," to remove references to the previous Unit 1 one-time and Unit 2 temporary alternate repair criteria and provides reporting requirements specific to the permanent alternate repair criteria. 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 Westinghouse WCAP-17345-P, Revision 2 (Reference 1) provides the 95/95 whole plant H* value of 17.89 inches for plants with Model 51F Steam Generators (Surry Units 1 and 2).

In addition, based on WCAP-17092-P, Revision 0 (Reference 6), a leakage factor of 1.80 will be applied for Surry Units 1 and 2.

The NRC previously issued the following Surry amendments revising steam generator tube inspection and repair requirements:

" Amendment Number --/258 (Unit 2) (Reference 2) approved an interim alternate repair criteria for Unit 2 Refueling Outage 21 and the subsequent operating cycle that required full-length inspection of the tubes within the tubesheet; tubes with flaws having a circumferential component less than or equal to 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and 1 inch from the bottom of the tubesheet, as well as tubes with service induced axial cracks found in the portion of the tube below 17 inches from the top of the tubesheet, did not require plugging.

" Amendment Number 263/-- (Unit 1) (Reference 3) approved an interim alternate repair criteria for Unit 1 Refueling Outage 22 and the subsequent operating cycle that required full-length inspection of the tubes within the tubesheet; tubes with flaws having a circumferential component less than or equal to 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and 1 inch from the bottom of the tubesheet, as well as tubes with service induced axial cracks found in the portion of the tube below 17 inches from the top of the tubesheet, did not require plugging.

" Amendment Number 264/-- (Unit 1) (Reference 4) approved a modified interim alternate repair criteria that did not require plugging of Unit 1 B SG tubes with permeability variation indications.

2 of 22

Serial No.11-403 Dockets Nos. 50-280/281

" Amendment Numbers 267/266 (Units 1 and 2, respectively) (Reference 5) approved a one-time alternate repair criteria for Unit 2 Refueling Outage 22, for Unit 1 Refueling Outage 23, and the subsequent operating cycles that did not require plugging tubes with service induced flaws located greater than 16.7 inches below the top of the tubesheet.

" Amendment Number --/273 (Unit 2) (Reference 29) approved a temporary alternate repair criteria for Unit 2 Refueling Outage 23 and the subsequent operating cycle that did not require plugging tubes with service induced flaws located greater than 17.74 inches below the top of the tubesheet.

Approval of this amendment application is requested by April 2, 2012 to support the Surry Unit 1 Refueling Outage 24 (Spring 2012), since the existing one-time alternate repair criteria approved by Unit 1 Amendment 267/-- (Reference 5) expires at the end of the current operating cycle.

2.0 Detailed Description of Proposed Revisions The following specific revisions to the Surry Units 1 and 2 TS are proposed:

TS 6.4.Q.3.a. currently states:

3. 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:

a. For Unit 1 during Refueling Outage 23 and the subsequent operating cycle and for Unit 2 during Refueling Outage 23 and the subsequent operating cycle, tubes with service-induced flaws located greater than 16.7 and 17.74 inches, respectively, 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 16.7 (Unit 1)/17.74 (Unit 2) inches below the top of the tubesheet shall be plugged upon detection.

This section would be revised as follows, as noted in bold italic type:

3. 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:

3 of 22

Serial No.11-403 Dockets Nos. 50-280/281 oper-ating Gk-,-"

Tubes with service-induced flaws located greater than 17.89 16.7 and 17-.74 inches,,.spe-tivey, 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 17.89 16.7 (Unit V7-)7.74 (Unit 2) inches below the top of the tubesheet shall be plugged upon detection.

TS 6.4.Q.4. currently states:

4. 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 Unit 1 during Refueling Outage 23 and the subsequent operating cycle and for Unit 2 during Refueling Outage 23 and the subsequent operating cycle, portions of the tube greater than 16.7 and 17.74 inches, respectively, below the top of the tubesheet are excluded from this requirement.

The tube-to-tubesheet weld is not part of the tube.

In addition to meeting the requirements of 4.a, 4.b, and 4.c 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.

This section.would be revised as follows, as noted in bold italic type:

4. 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, Unit m

during Rfucing Outage 23 and the subsequent opcrating cycic and for- "nt 2 during Refueling Outage 23 and the subseq.unt op.rating

.yc..

, Portions of the tube greater than 17.89 464 and41A4inches,. eapee.ivy-,, below the top of the tubesheet are excluded from this requirement. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 4.a, 4.b, and 4.c below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure 4 of 22

Serial No.11-403 Dockets Nos. 50-280/281 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.

TS 6.6.A.3.i., 6.6.A.3.j., and 6.6.A.3.k. currently state:

i. For Unit 1 during Refueling Outage 23 and the subsequentoperating cycle and for Unit 2 during Refueling Outage 23 and the subsequent operating 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; and

j. For Unit I during Refueling Outage 23 and the subsequent operating cycle and for Unit 2 during Refueling Outage 23 and the subsequent operating cycle, the calculated accident induced leakage rate from the portion of the tubes below 16.7 and 17.74 inches, respectively, 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 2.03 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

k. For Unit 1 during Refueling Outage 23 and the subsequent operating cycle and for Unit 2 during Refueling Outage 23 and the subsequent operating cycle, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided.

These sections would be revised as follows, as noted in bold italic type:

cycle and for-Unit 2 during Refueling Outage 23 and the subsequent

-p-rating 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; and

j. For Unit 1 during Refueging Outag 23 and the subsequent operating cy and for-Unit 2 durng Refueling Outage 23 and the subs ct'"g

.perating c*yle.,

The calculated accident induced leakage rate from the portion of the tubes below 17.89 16.7 and 17-.7* inches,.r..peG6o-""- from the top of the tubesheet for the most limiting accident in the most limiting SG.

5 of 22

Serial No.11-403 Dockets Nos. 50-280/281 In addition, if the calculated accident induced LEAKAGE rate from the most limiting accident is less than 1.80 2,03 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

k. F*"- Uit.,

1 dur.ing. R^e.^,..-,n.....

Outag 2.. and

.... susqun i.

cycic and for Unit 2 during Refueling Outage 23 and the sub~scgucnt operating cycle, 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

Surry Power Station consists of two three-loop Westinghouse designed plants with Model 51F SGs, having 3342 tubes in each SG. A total (for all three SGs per unit) of one hundred six (106) tubes are currently plugged on Unit 1 and ninety four (94) tubes on Unit 2.

The design of the SG includes Inconel 600 (generically referred to as Alloy 600) thermally treated tubing, full depth hydraulically expanded tubesheet joints, and Type 405 stainless steel tube support plates with broached hole quatrefoil.

The SG inspection scope is governed by TS 6.4.Q, "Steam Generator (SG) Program;"

Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines" (Reference 23); EPRI 1013706, "Pressurized Water Reactor Steam Generator Examination Guidelines" (Reference 24); EPRI 1019038, "Steam Generator Integrity Assessment Guidelines" (Reference 25); ER-AP-SGP-101, Dominion Administrative Procedure titled "Steam Generator Program" (Reference 26), and the results of the degradation assessments performed in accordance with ER-AP-SGP-102, Dominion Administrative Procedure titled "Steam Generator Degradation Assessment" (Reference 27).

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 known and potential specific degradation mechanisms applicable to Surry.

The inspection techniques, essential variables and equipment are qualified to Appendices H and I, "Performance Demonstration for Eddy Current Examination," of the EPRI Steam Generator Examination Guidelines.

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 28) 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 6 of 22

Serial No.11-403 Dockets Nos. 50-280/281 reported in the tube-end welds, also known as tube-to-tubesheet welds, which join the tube to the tubesheet.

Dominion policies and programs require the use of applicable industry operating experience in the operation and maintenance of Surry.

The recent 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 SGs) 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 Surry Westinghouse Model 51F SGs were fabricated with Inconel 600 thermally treated tubes similar to the Catawba Unit 2 Westinghouse Model D5 SGs, a potential exists for Surry to identify tube indications similar to those reported at Catawba within the hot leg tubesheet region if similar inspections are performed during the Spring 2012 refueling outage.

Potential inspection plans for the tubes and tube welds underwent intensive industry discussions in March 2005.

The findings in the Catawba SG tubes present three distinct issues with regard to the SG tubes at Surry:

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 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 Surry 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.

At Surry, tube indications within the tubesheet have only been found at the hot leg tube ends. Approximately 26,000 tube ends have been inspected since 2008 at Surry.

Approximately two hundred twenty (220) indications have been reported.

These indications were located within 1 inch of the tube end and are associated with residual stress conditions at the tube ends. Twelve (12) tubes in Unit 1 and six (6) tubes in Unit 2 were plugged for tube end cracks.

In addition, over 50% of the overexpansion/bulge indications within the tubesheet have been inspected in both Unit 1 and Unit 2 with no degradation found.

Based on these inspections, no indications of a 360 degree sever have been detected in any steam generator at Surry. Consequently, the level of degradation in the Surry steam generators is very limited compared to the assumption of "all tubes severed" that was utilized in the development of the permanent H* value. Thus, structural integrity will 7 of 22

Serial No.11-403 Dockets Nos. 50-280/281 be assured for this permanent alternate repair criteria for the operating period between inspections allowed by TS 6.4.Q, "Steam Generator (SG) Program."

As a result of these potential issues and the possibility of unnecessarily plugging tubes in the Surry SGs, Dominion is proposing changes to TS 6.4.Q to limit the SG tube inspection and repair (plugging) to the safety significant portion of the tubes.

4.0 Summary of Licensing Basis Analysis (H* Analysis)

On July 28, 2009, Westinghouse WCAP-17092-P, Revision 0 (Reference 6) was submitted as Attachment 5 of the Dominion request to change Technical Specification (TS) 6.4.Q, "Steam Generator (SG) Program," and TS 6.6.A.3, "Steam Generator Tube Inspection Report," to support implementation of a permanent alternate repair criterion for steam generator tubes (by letter Serial No.09-455 - Reference 7).

On August 28, 2009, Southern Nuclear Company submitted (by letter NL-09-1317 -

Reference 8) Westinghouse letter LTR-SGMP-09-104-Attachment, "White Paper on Probabilistic Assessment of H*," (Reference 9) as supplemental information for the Vogtle permanent alternate repair criteria.

As stated in Reference 8, supplemental information (in Reference 9) is also applicable to Surry's Model 51 F SGs.

On September 16, 2009, Dominion provided a response (by letter Serial No. 09-455A -

Reference 10) to an August 14, 2009 NRC request for additional information (Reference 11). The September 16, 2009 Dominion response included Westinghouse LTR-SGMP-09-108-P-Attachment, "Response to NRC Request for Additional Information on H*; Model 44F and Model 51F Steam Generators" (Reference 12).

On September 30, 2009, Dominion submitted a request (by letter Serial No. 09-455B -

Reference 13) to revise the July 28, 2009 amendment request to be a one-time change applicable to Surry Unit 2 during the Fall 2009 Refueling Outage 22 and the subsequent operating cycle and to Unit 1 during Fall 2010 refueling outage 23 and the subsequent operating cycle. This request was made in response to a September 2, 2009 teleconference between NRC Staff and industry personnel, during which the NRC Staff indicated that their concerns with eccentricity of the tube sheet tube bore in normal and accident conditions have not been resolved.

The September 30, 2009 letter also requested that the NRC staff provide the specific questions remaining to be resolved with respect to the tubesheet bore eccentricity issue (RAI Question 4) which must be resolved to support a permanent alternate repair criteria amendment request.

On January 6, 2010, the NRC provided a letter (Reference 14) documenting the currently identified and unresolved issues relating to tubesheet bore eccentricity. This 14-question request for additional information identified the information needed for the NRC to complete the review of any future requests for a permanent amendment.

Section 1.2 of WCAP-17345-P, Revision 2 (Reference 1) provides a discussion of the action plan to respond to the NRC 14-question request for additional information.

8 of 22

Serial No.11-403 Dockets Nos. 50-280/281 The following documents have been prepared by Westinghouse to provide final resolution of the remaining questions identified in the January 6, 2010 NRC letter in support of the permanent H* amendment for Surry:

WCAP-17345-P, Revision 2, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)" (Reference 1).

This document is contained in this transmittal.

LTR-SGMP-10-78-P-Attachment, "Effects of Tubesheet Bore Eccentricity and Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H`*

(Reference 15). This document, which is applicable to Surry's Model 51F SGs, was transmitted to the NRC by Westinghouse letter LTR-NRC-10-68 (Reference 16).

LTR-SGMP-09-1 11-P-Attachment, Revision 1, "Acceptable Value of the Location of the Bottom of the Expansion Transition (BET) for Implementation of H*," (Reference 17) was prepared to support plant determinations of BET measurements and their significant deviation assessment. This document, which is applicable to Surry's Model 51F SGs, was transmitted to the NRC by Westinghouse letter LTR-NRC-10-69 (Reference 18).

LTR-SGMP-10-33-P-Attachment, "H* Response to NRC Questions Regarding Tubesheet Bore Eccentricity" (Reference 19). This document, which is applicable to Surry's Model 51F SGs, was transmitted to the NRC by Westinghouse letter LTR-NRC-10-70 (Reference 20).

Note that the technical information contained in WCAP-17092-P, Revision 0

(Reference 6) remains valid and provides part of the licensing basis for the requested amendment change.

The following table provides the list of the Surry licensing basis documents for H*.

Document Number Revision Title Reference Number Number WCAP-1 7345-P 2

H*:

Resolution of NRC Technical Issue Regarding 1

Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51F)

WCAP-17092-P 0

H*: Alternate Repair Criteria for the Tubesheet Expansion 6

Region in Steam Generators with Hydraulically Expanded Tubes (Model 51F)"

LTR-SGMP-09-108-0 Response to NRC Request for Additional Information on H*

12 P-Attachment Model 44F and Model 51 F Steam Generators LTR-SGMP-09-108 Errata:

Responses to NRC Request for Additional 34 Errata Information on H*; Model 44F and Model 51F Steam Generators LTR-SGMP-10-78-P-0 Effects of Tubesheet Bore Eccentricity and Dilation on Tube-15 Attachment to-Tubesheet Contact Pressure and Their Relativ Importance to H*

LTR-SGMP-10-33-P-0 H* Response to NRC Questions Regarding Tubesheet Bor 19 Attachment Eccentricity 9 of 22

Serial No.11-403 Dockets Nos. 50-280/281 In addition, the following correspondence is also applicable to the Surry permanent alternate repair criteria request:

• A March 28, 2011 letter from the NRC to Southern Nuclear Operating Company (Reference 30) documented the summary of a February 16, 2011 public meeting regarding steam generator tube inspection permanent alternate repair criteria. of the NRC letter provided technical NRC Staff questions developed at the meeting.

Responses to these questions have been incorporated into WCAP-17345-P, Revision 2 (Reference 1).

" Section 1.3 of Reference 1 identifies revisions in the report 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 Operating Company (Reference

31) 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-1 1-1178, dated June 20, 2011 (Reference 32).

5.0 Technical Evaluation To preclude unnecessarily plugging tubes in the Surry 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 described in Section 4.0. 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 Surry Model 51 F steam generators 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.

The faulted events considered in the technical evaluation included steam line break (SLB), locked rotor, and control rod ejection. Primary to secondary leakage from tube degradation in the tubesheet area is assumed to occur in the SLB and locked rotor 10 of 22

Serial No.11-403 Dockets Nos. 50-280/281 accident analyses. The radiological dose consequences associated with this assumed leakage for the SLB and locked rotor events are evaluated to ensure that they remain within regulatory limits. Although the control rod ejection accident analysis does not include a dose consequence analysis, as indicated in UFSAR Section 14.3.3.2.3.5, the control rod ejection event release is bounded by the release for the double-ended severance of a reactor coolant pipe (LOCA).

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.

As noted in Section 9 of WCAP-17092-P (Reference 6), the feedwater line break is not part of the licensing basis for plants with Model 51 F SGs. This has been documented in Section 3.8.1 of Reference 21, which states: "The analysis of a main feedline break accident is not described in the UFSAR since Surry Power Station was licensed prior to the issuance of Regulatory Guide 1.70, Rev. 1; this event was not included in the original licensing basis analysis.

Virginia Power analyzed the Feedline Break accident in response to an August 13, 1985 NRC request for additional information related to NUREG-0737, Item II.'D.1 -

Performance Testing of Relief and Safety Valves." This analysis was overly conservative to ensure bounding conditions at the inlet to the pressurizer safety and relief valves.

The constraint that is provided by the tubesheet precludes tube burst from 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 22) 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 induced primary to secondary leak rate limit is 470 gpd (0.33 gpm) per SG. The TS operational primary to secondary leak rate limit is 150 gpd (0.1 gpm) through any one SG. Consequently, there is significant margin between accident leakage and allowable operational 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 6.

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.

For the postulated SLB event, a plant cool down event would occur and the subsequent temperatures in the reactor coolant system (RCS) would not be expected to exceed the 11 of 22

Serial No.11-403 Dockets Nos. 50-280/281 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.

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 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 (atmospheric relief valves).

For any of the steam pressure control options, the maximum RCS temperature would be approximately the no load temperature and would be well below normal operating temperature.

As shown in Table 9-7 of Reference 6, for Surry for a postulated SLB, a leakage factor of 1.80 has been calculated. 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 1.80 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 1.80 and compared to the observed operational leakage.

The other design basis accidents - the postulated locked rotor event and the control rod ejection event - are conservatively modeled using design specification transients which 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, as well as due to the increasing differential pressure, for the duration of time that there is a rise in RCS temperature. For transients other than a SLB, the length of time that a plant with Model 51 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 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 1.66 (Table 9-7 in Reference 6) for Surry is adjusted downward to a factor of 0.83. 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 2.37 to 0.40.

Reference 6 redefines the primary pressure boundary. The tube-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 12 of 22

Serial No.11-403 Dockets Nos. 50-280/281 integrity over the full range of steam generator operating conditions, including the most limiting accident conditions. The evaluation in Reference 6 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.

Section 9.8 of Reference 6 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 Numbers 267/266 (Units 1 and 2, respectively) (Reference 5) and of Amendment Number --/273 (Unit 2) (Reference 29), Dominion committed to monitor for tube slippage as part of the steam generator tube inspection program starting with the Unit 2 Fall 2009 refueling outage. Steam generator tube slippage monitoring conducted during the Unit 2 Fall 2009 (SG A) and Spring 2011 (SGs B and C) refueling outages, as well as during the Unit 1 Fall 2010 (SGs A, B, and C) refueling outage, identified no evidence of tube slippage.

This requirement will remain in place to support the permanent alternate repair criteria request, and the results of monitoring will be reported in accordance with TS 6.6.A.3.k.

In addition, as a condition for approving the one-time alternate repair criteria for Surry Units 1 and 2 (Reference 13), the NRC staff requested that Dominion perform a validation of the tube expansion from the top of tubesheet to the beginning of expansion transition (BET) to determine if there are any significant deviations that would invalidate assumptions in Reference 6.

Dominion has completed the validation of the tube expansion from the top of tubesheet to the BET for Surry Units 1 and 2. Based on data review and LTR-SGMP-09-111, Rev. 1 (Reference 17), Dominion did not identify any significant deviations from the top of tubesheet to the BET on Surry Units 1 and 2.

6.0 Regulatory Evaluation 6.1 Applicable Regulatory Requirements/Criteria SG tube inspection and repair limits are specified in Section 6.4.Q, "Steam Generator (SG) Program," of the Surry TS. The current TS require that flawed tubes be plugged if the depths of the flaws are greater than or equal to 40 percent through wall. During the initial plant licensing of Surry Power Station Unit 1, it was demonstrated that the design of the reactor coolant pressure boundary met the regulatory requirements in place at that time.

The General Design Criteria (GDC) included in Appendix A to 10 CFR Part 50 did not become effective until May 21, 1971. The Construction Permits for Surry Units 1 and 2 were issued prior to May 21, 1971; consequently, these units were not subject to GDC requirements.

(Reference SECY-92-223 dated September 18, 1992.)

However, the following information demonstrates compliance with GDC 14, 15, 30, 31, and 32 of 10 CFR 50, Appendix A. Specifically, the GDC state 13 of 22

Serial No.11-403 Dockets Nos. 50-280/281 that the Reactor Coolant Pressure Boundary (RCPB) shall have "an extremely low probability of abnormal leakage..

. and gross rupture" (GDC 14), "shall be designed with sufficient margin" (GDCs 15 and 31), shall be of "the highest quality standards practical" (GDC 30), and shall be designed to permit "periodic inspection and testing...

to assess...

structural and leak tight integrity" (GDC 32). Structural integrity refers to maintaining adequate margins against burst, and collapse of the SG tubing. Leakage integrity refers to limiting primary to secondary leakage during all plant conditions to within acceptable limits.

The TS repair limits ensure that tubes accepted for continued service will retain adequate structural and leakage integrity during normal operating, transient, and postulated accident conditions.

The reactor coolant pressure boundary is designed, fabricated and constructed so as to have an exceedingly low probability of gross rupture or significant uncontrolled leakage throughout its design lifetime.

Reactor coolant pressure boundary components have provisions for the inspection testing and surveillance of critical areas by appropriate means to assess the structural and leaktight integrity of the boundary components during their service lifetime. Structural integrity refers to maintaining adequate margins against burst, and collapse of the SG tubing.

Leakage integrity refers to limiting primary to secondary leakage during all plant conditions to within acceptable limits.

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, Xl, and XVI of Appendix B and include control of special processes, inspection, testing, and corrective action.

10 CFR 100, Reactor Site Criteria, established reactor siting criteria.

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. Accidents involving leakage or tube burst of SG tubing may comprise a challenge to containment and therefore involve an increased risk of radioactive release.

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.

Surry TS 6.4.Q.2 states the following SG tube integrity performance criteria, which are consistent with the NEI 97-06, Revision 2, SG performance criteria:

a.

Structural integrity performance criterion:

All in-service SG tubes shall retain structural integrity over the full range of normal operating conditions (including 14 of 22

Serial No.11-403 Dockets Nos. 50-280/281 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 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.

b.

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 for all SGs.

c.

The operational leakage performance criterion is specified in TS 3.1.C and 4.13, "RCS Operational Leakage."

[NOTE:

TS 3.1.C and 4.13 limit the primary to secondary leakage through any one SG 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.

The evaluation in this transmittal determined that degradation in tubing below 17.89 inches from the top of the tubesheet does not require plugging and serves as the bases for the tubesheet inspection program. As such, the Surry inspection program provides a high level of confidence that the structural and leakage criteria are maintained during normal operating and accident conditions.

6.2 No Significant Hazards Consideration This license amendment request proposes to revise Technical Specification (TS) 6.4.Q, "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) 6.6.A.3, "Steam Generator Tube Inspection Report,"

to remove references to previous one-time and temporary alternate repair criteria and provide reporting requirements specific to the permanent 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.

15 of 22

Serial No.11-403 Dockets Nos. 50-280/281 The proposed change defines the safety significant portion of the tube that must be inspected and repaired. A justification has been developed by Westinghouse Electric Company, LLC in WCAP-17345-P Revision 2 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 Guidelines," performance criteria. The evaluation determined that degradation in tubing below 17.89 inches from the top of the tubesheet does not require plugging and serves as the bases for the tubesheet inspection program.

Dominion 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)

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/repair criteria and the steam generator inspection 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 steam generator tube inspection and repair criteria are the steam generator tube rupture (SGTR) event and the steam line break (SLB) postulated accidents.

During 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 constraint provided by the tube-to-tubesheet joint. This 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.

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," 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 integrity of the steam generator tubes and does not affect other systems, 16 of 22

Serial No.11-403 Dockets Nos. 50-280/281 structures, components, or operational features. 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 primary water stress corrosion cracking below the proposed limited inspection depth is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tubesheet constraint. Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region.

The consequences of an SGTR event are affected by the primary to secondary leakage flow during the event.

However, primary to secondary leakage flow through a postulated broken tube is not affected by the proposed changes since the tubesheet enhances the tube integrity in the region of the hydraulic expansion by precluding tube deformation beyond its initial hydraulically expanded outside diameter. Therefore, the proposed changes do not result in a significant increase in the consequences of a SGTR.

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.

The consequences of a steam line break (SLB) are also not significantly affected by the proposed changes. During a SLB accident, the reduction in pressure 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.

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.

As shown in Table 9-7 of WCAP-17092-P, for Surry for a postulated SLB, a leakage factor of 1.80 has been calculated.

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 1.80 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 1.80 and compared to the observed operational leakage. The accident induced primary to secondary leak rate limit is 470 gpd (0.33 gpm) per SG. The TS operational primary to secondary leak rate limit of 150 gpd (0.1 gpm) times 1.80 provides significant margin between accident leakage and allowable operational leakage.

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

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Serial No.11-403 Dockets Nos. 50-280/281

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 that alters the steam generator inspection/repair criteria and the steam generator inspection 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 accident previously evaluated.

3)

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

Response: No The proposed change that alters the steam generator inspection/repair criteria and the steam generator inspection reporting criteria maintains the required structural margins of the steam generator tubes for both normal and accident conditions.

NEI 97-06, Revision 2, "Steam Generator Program Guidelines," 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 4.0 of the license amendment request, 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.

18 of 22

Serial No.11-403 Dockets Nos. 50-280/281 Therefore, the proposed change does not involve a significant reduction in any margin of safety.

6.3 Precedents The proposed change to Surry TS 6.4.Q and TS 6.6.A.3 is similar to the following proposed change, which has been submitted to revise TS for permanent alternate repair criteria:

Duke Energy Carolinas, LLC letter, dated June 30, 2011, Catawba Nuclear Station, Units 1 and 2 - Proposed Technical Specifications (TS) Amendment-TS 3.4.13, "RCS Operational LEAKAGE," TS 5.5.9, "Steam Generator (SG) Program" and TS 5.6.8, "Steam Generator Tube Inspection Report" - License Amendment Request to Revise TS for Permanent Alternate Repair Criteria (Reference 33).

6.4 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 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 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.

7.0 Environmental Considerations Dominion has evaluated the proposed amendment for environmental considerations.

The review has resulted in the determination 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 need be prepared in connection with the proposed amendment.

19 of 22

Serial No.11-403 Docket Nos. 50-280/281 8.0 References

1.

WCAP-17345-P, Rev. 2, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (3-Loop Model 44F/Model 51IF)," June 2011

2.

NRC to Virginia Electric and Power Company letter, dated May 16, 2008, Surry Power Station Unit No. 2 - Issuance of Exigent Amendment re: Interim Alternate Repair Criteria for Steam Generator Tube Repair (TAC No. MD8504) [Unit 2 Amendment --/258]

3.

NRC to Virginia Electric and Power Company letter, dated April 8, 2009, Surry Power Station Unit No. 1 - Issuance of Amendment Request - Interim Alternate Repair Criteria for Steam Generator Tube Repair (TAC No. MD9976) [Unit 1 Amendment 263/--]

4.

NRC to Virginia Electric and Power Company letter, dated May 7, 2009, Surry Power Station Unit No. 1 - Issuance of Amendment Regarding Modified Interim Alternate Repair Criteria for B Steam Generator Tube Repair (TAC No. ME1191)

[Unit 1 Amendment 264/--]

5.

NRC to Virginia Electric and Power Company letter, dated November 5, 2009, Surry Power Station Unit Nos. 1 and 2 - Issuance of Amendments Regarding License Amendment Request for Alternate Repair Criteria for Steam Generator Tubesheet Expansion Region (TAC Nos. ME1783 and ME1784) [Units 1 and 2 Amendments 267/266]

6.

Westinghouse Electric Company LLC, WCAP-17092-P, Revision 0, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51 F)," June 2009

7.

Virginia and Electric Power Company to NRC letter Serial No.09-455, dated July 28, 2009, Surry Power Station Units 1 and 2 - Proposed License Amendment Request - Permanent Alternate Repair Criteria for Steam Generator Tube Repair for Units 1 and 2

8.

Southern Nuclear Operating Company, Inc. (SNC) to NRC letter NL-09-1317, Vogtle Electric Generating Plant -

Supplemental Information for License Amendment Request to Revise Technical Specification (TS) Sections 5.5.9, "Steam Generator (SG) Program" and TS 5.6.10, "Steam Generator Tube Inspection Report" for Permanent Alternate Repair Criteria, August 28, 2009

9.

Westinghouse Electric Company LLC LTR-SGMP-09-104-P-Attachment, "White Paper on Probabilistic Assessment of H*," August 13, 2009

10. Virginia and Electric Power Company to NRC letter Serial No. 09-455A, dated September 16, 2009, Surry Power Station Units 1 and 2 - Response to Request for Additional Information - Proposed License Amendment Request - Permanent Alternate Repair Criteria (PARC) for Steam Generator Tube Repair for Units 1 and 2 20 of 22

Serial No.11-403 Docket Nos. 50-280/281

11.

NRC to Dominion August 14, 2009 Communication - Surry Clarifications regarding H* PARC (ADAMS Accession No. ML092290359)

12. Westinghouse Electric Company LLC LTR-SGMP-09-108-P-Attachment, "Response to NRC Request for Additional Information on H*; Model 44F and Model 51 F Steam Generators," August 27, 2009

13. Virginia and Electric Power Company to NRC letter Serial No. 09-455B, dated September 30, 2009, Surry Power Station Units 1 and 2 -

Proposed License Amendment Request - One-time Alternate Repair Criteria for Steam Generator Tube Inspection/Repair for Units 1 and 2 °

14.

NRC to Virginia Electric and Power Company letter, dated January 6, 2010, Surry Power Station Unit Nos. 1 and 2 (Surry Units 1 and 2) - Request for Additional Information (RAI) Regarding the Permanent Alternate Repair Criteria License Amendment Request (TAC Nos. ME1783 and ME1784)

15. Westinghouse Electric Company LLC LTR-SGMP-10-78-P-Attachment, "Effects of Tubesheet Bore Eccentricity and Dilation on Tube-to-Tubesheet Contact Pressure and Their Relative Importance to H*," September 7, 2010

16. Westinghouse Electric Company LLC to NRC letter LTR-NRC-10-68, "Submittal of LTR-SGMP-10-78-P-Attachment... for Review and Approval," November 9, 2010

17. Westinghouse Electric Company LLC LTR-SGMP-09-111, Rev. 1, "Acceptable Value of the Location of the Bottom of the Expansion Transition (BET) for Implementation of H*," September 2010

18. Westinghouse Electric Company LLC to NRC letter LTR-NRC-10-69, "Submittal of LTR-SGMP-09-111-P-Attachment, Rev. 1 for Review and Approval,"

November 10, 2010

19. Westinghouse Electric Company LLC LTR-SGMP-10-33-P-Attachment, "H*

Response to NRC Questions Regarding Tubesheet Bore Eccentricity," September 2010

20. Westinghouse Electric Company LLC to NRC letter LTR-NRC-10-70, "Submittal of LTR-SGMP-1 0-33-P-Attachment for Review and Approval,"

November 11, 2010

21.

Virginia and Electric Power Company to NRC letter Serial No.94-509, dated August 30, 1994, Surry Power Station Units 1 and 2 -

Proposed Technical Specification Changes to Accommodate Core Uprating

22. Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," dated August 1976, (ADAMS Accession No. ML003739366)

23.

NEI 97-06, Rev. 2, "Steam Generator Program Guidelines," May 2005 21 of 22

Serial No.11-403 Docket Nos. 50-280/281

24. EPRI 1013706, "Pressurized Water Reactor Steam Generator Examination Guidelines"

25. EPRI 1019038; "Steam Generator Integrity Assessment Guidelines"

26. ER-AP-SGP-1 01, Dominion Administrative Procedure titled "Steam Generator Program"

27. ER-AP-SGP-102, Dominion Administrative Procedure titled "Steam Generator Degradation Assessment"

28. NRC Information Notice (IN) 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds"

29. NRC to Virginia Electric and Power Company letter, dated May 20, 2011, Surry Power Station Unit 2 - Issuance of Amendment Regarding Technical Specification Change to Sections 6.4.Q and 6.6.A.3 (TAC No.

ME5368)

[Unit 2

Amendment --/273]

30. NRC to Southern Nuclear Operating Company, Inc. letter, dated March 28, 2011, Vogtle Electric Generating Plant Units 1 and 2 - 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 (ADAMS Accession No. ML110660648)

31.

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

32. Southern Nuclear Operating Company, Inc. to NRC letter NL-11-1178, dated June 20, 2011, Vogtle Electric Generating Plant -

Response to Presubmittal Consideration of Steam Generator Alternative Repair Criteria Requirements Request for Additional Information

33.

Duke Energy Carolinas, LLC letter, dated June 30, 2011, Catawba Nuclear Station, Units 1 and 2 - Proposed Technical Specifications (TS) Amendment - TS 3.4.13, "RCS Operational LEAKAGE," TS 5.5.9, "Steam Generator (SG) Program" and TS 5.6.8, "Steam Generator Tube Inspection Report" -

License Amendment Request to Revise TS for Permanent Alternate Repair Criteria

34. Westinghouse Electric Company LLC LTR-SGMP-09-108

Errata, "Errata:

Responses to NRC Request for Additional Information on H*; Model 44F and Model 51F Steam Generators," September 8, 2009 [This letter identifies that on page 49 of both attachments to LTR-SGMP-09-108 P-Attachment (Reference 12) and LTR-SGMP-09-108 NP-Attachment the header that reads "RAI#20 References" should be corrected to read "RAI#18 References".]

22 of 22

Serial No.11-403 Docket Nos. 50-280/281 ATTACHMENT 2 MARKED-UP TECHNICAL SPECIFICATIONS PAGES PROPOSED TECHNICAL SPECIFICATION CHANGE PERMANENT ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE INSPECTION AND REPAIR VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

TS 6.4-12

c. The operational LEAKAGE performance criterion is specified in TS 3. L.C and 4.13, -RCS Operational LEAKAGE."

3. 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:

a.

FoUnt 1 during RefelingOetage 23 and ths 6413606uHnR opeprat'ng ryjo-and.

fa; UI 4t 2 d ring Rafmoling Getage 23 ftfd th-Au n

pRAt~ingc Abes with service-induced flaws located greater thaini4-2l

--.4 inchesA r.aseeg....below the top of the tubesheet do not require plugging. Tubes with servc ed flaws located in the portion of the tube from the top of the tubesheet to-- *.7 (Unit l)! 17.74 (Unit 2) inches below the top of the tubesheet shall be plugged upon detection.

Amendment Nos. 264 and -25"3

TS 6.4-13

4. 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 U4,4t 1 Jur-ing fling Outagc,23 and

,'te-sb.c*

,t op'crating "~cadf:Unit 2 for ReA'uzling Gmseps 21 afid he subaguzte

-Per-attg

.*,ortions of the tube greater than inche" 4-r-eespeevw!k below the top of the tubesheet are excluded from this requirement.

4 The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 4.a, 4.b, and 4.c 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.

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

b. 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.

c. If crack indications are found in the 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.

5. Provisions for monitoring operational primary to secondary LEAKAGE.

Amendment Nos. 6:. and-2-+

TS 6.6-3

b. The results of specific activity analysis in which the primary coolant exceeded the limits of Specification 3.1.D.4. In addition, the information itemized in Specification 3.1.D.4 shall be included in this report.

3. Steam Generator Tube Inspection Report A report shall be submitted within 180 days after Tavg exceeds 200°F following completion of an inspection performed in accordance with the Specification 6.4.Q, 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 percentage for all plugging in each SG,

i. For U-it I an

.d sub ivue a

i, LY fig; Unit 2 during R"f""'l" Ou. age 23 and Me subsequ=ltt up',afti1g c*,ke 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, and Amendment Nos. 247 and 47

TS 6.6-3a jQ. Fr Urit 1 dur-ing Refueling flntage' a~ind the suhoeguetit operating cylcl and-for TI Iit I) urhing Refueling Outage 23 and the

.ubse..nt epert",ng cyc4e,&e A

calfdtc accident induced LEAKAGE rate from the portion of the tubes (t*7.09) belo a

inchesArespeeti,'ely 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 I.

0 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

k.

For Unit 1 daring Refueling u.tag. 23 and the

.ubs.q....

operating cycle an

.F Unit 2 du.in.g Ref

..li.g O

,.ta 23.and the*,

n znc*

,peratng,....e ý.

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

Amendment Nos.--2&" and@-3"

Serial No.11-403 Docket Nos. 50-280/281 ATTACHMENT 3 PROPOSED TECHNICAL SPECIFICATION PAGES PROPOSED TECHNICAL SPECIFICATION CHANGE PERMANENT ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE INSPECTION AND REPAIR VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

TS 6.4-12

c. The operational LEAKAGE performance criterion is specified in TS 3.1.C and 4.13, "RCS Operational LEAKAGE."

3. 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:

a. Tubes with service-induced flaws located greater than 17.89 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 17.89 inches below the top 'f the tubesheet shall be plugged upon detection.

Amendment Nos.

TS 6.4-13

4. 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. Portions of the tube greater than 17.89 inches below the top of the tubesheet are excluded from this requirement. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 4.a, 4.b, and 4.c 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.

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

b. 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.

c. If crack indications are found in the 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.

5. Provisions for monitoring operational primary to secondary LEAKAGE.

Amendment Nos.

TS 6.6-3

b. The results of specific activity analysis in which the primary.coolant exceeded the limits of Specification 3.1.D.4. In addition, the information itemized in Specification 3.1.D.4 shall be included in this report.

3. Steam Generator Tube Inspection Report A report shall be submitted within 180 days after Tavg exceeds 200'F following completion of an inspection performed in accordance with the Specification 6.4.Q, 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 percentage for all plugging in each SG,

i. 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, and Amendment Nos.

TS 6.6-3a

j.

The calculated accident induced LEAKAGE rate from the portion of the tubes below 17.89 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 1.80 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

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

Amendment Nos.