ML092150464

Proposed License Amendment Request Permanent Alternate Repair Criteria for Steam Generator Tube Repair

ML092150464
Person / Time
Site:	Surry
Issue date:	07/28/2009
From:	Price J Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
09-455
Download: ML092150464 (52)

Text

PROPRIETARY INFORMATION-WITHHOLD UNDER 10 CFR 2.390 VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 July 28, 2009 10 CFR 50.90 U.S. Nuclear Regulatory Commission Serial No.09-455 Attention: Document Control Desk SPS LIC/CGL RO Washington, D.C. 20555 Docket Nos.

50-280 50-281 License No.

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

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 Pursuant to 10 CFR 50.90, 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 tube inspections. The proposed change is based on the supporting structural analysis and leakage evaluation contained in Westinghouse Electric Company, LLC WCAP-17092-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51 F)," Revision 0, June 2009. This amendment request also proposes to revise TS 6.6.A.3, "Steam Generator Tube Inspection Report," as well as TS 3.1.C and TS 4.13, "RCS Operational Leakage." Associated revisions to the Bases for TS 3.1.C and TS 4.13 are also included for the NRC's information.

A discussion of the proposed amendment request is provided in Attachment 1.

The marked-up and proposed Technical Specifications and Bases pages are provided in Attachments 2 and 3, respectively. Attachment 4 provides a list of regulatory commitments associated with the amendment request; these commitments are also identified below.

Proprietary and non-proprietary versions of WCAP-17092-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51 F)," are provided in Attachments 5 and 6, respectively.

Enclosed in is Westinghouse letter CAW-09-2605, "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 7 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 10 CFR 2.390 of the Commission's regulations. Accordingly, it is respectfully requested that the information, which is proprietary to Westinghouse, be ATTACHMENT 5 CONTAINS PROPRIETARY INFORMATION THAT IS BEING WITHHELD FROM PUBLIC DISCLOSURE UNDER 10 CFR 2.390. UPON SEPARATION OF ATTACHMENT 5, THIS PAGE IS DECONTROLLED.

ADD, v--a

Serial No.09-455 Docket Nos. 50-280/50-281 Page 2 of 4 withheld from public disclosure in accordance with 10 CFR 2.390. Correspondence with respect to the copyright or proprietary aspects of Attachment 5 or the supporting Westinghouse affidavit should reference letter CAW-09-2605 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.

We have evaluated the proposed license amendment request and have determined that it does not involve a significant hazards consideration as defined in 10 CFR 50.92. The basis for that determination is provided in Attachment 1. We have also determined that operation with the proposed change will not result in any significant increase in the amount of effluents that may be released offsite and no significant increase in individual or cumulative occupational radiation exposure.

Therefore, the proposed amendment is eligible for categorical exclusion as set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change. The basis for that determination is also provided in.

Approval of this license amendment request for the permanent alternate repair criteria is requested by October 16, 2009 with a 30-day implementation period to support the Surry Unit 2 Refueling Outage 22 (Fall 2009), since the Unit 2 existing one-cycle TS Amendment -

-/258 expires at the end of the current operating cycle.

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

Sincerely, J.

rice Vic esident - Nuclear Engineering COMMONWEALTH OF VIRGINIA

)

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 "TI Q

2009.

My Commission Expires:

4130113 -.

I ON=GE L.

ALL*GMO 31OW4

Serial No.09-455 Docket Nos. 50-280/50-281 Page 3 of 4 This transmittal makes the following commitments, which are listed in Attachment 4:

" Dominion commits to monitor for tube slippage as part of the SG tube inspection program.

" Dominion commits to perform a one-time verification of tube expansion to locate any significant deviations from the top of tubesheet to the beginning of expansion transition. If any significant deviations are found, the condition will be entered into the plants corrective action program and dispositioned.

Dominion commits to plug three Unit 1 tubes and eleven Unit 2 tubes that have been identified as not being expanded into the tubesheet in either the hot leg or the cold leg.

Attachments:

1. Discussion of Change

2. Marked-up Technical Specifications and Bases Pages

3. Proposed Technical Specifications and Bases Pages

4. List of Regulatory Commitments

5. 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)" (Proprietary)

6. Westinghouse Electric Company LLC WCAP-17092-NP, Revision 0, "H*:

Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51F)" (Non-proprietary)

7. Westinghouse Electric Company LLC LTR-CAW-09-2605, "Application for Withholding Proprietary Information from Public Disclosure," dated June 26, 2009

Serial No.09-455 Docket Nos. 50-280/50-281 Page 4 of 4 cc:

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia (30303 NRC Senior Resident Inspector Surry Power Station State Health Commissioner Virginia Department of Health James Madison Building - 7 th Floor 109 Governor Street Room 730 Richmond, Virginia 23219 Ms. K. Cotton NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 16E15 11555 Rockville Pike Rockville, Maryland 20852

Serial No.09-455, Docket No. 50-280/50-281 Discussion of Change Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

Serial No.09-455 Docket Nos. 50-280/50-281 Attachment I Discussion of Change Table of Contents 1.0 Summary Description 2.0 Detailed Description

3.0 Background

4.0 Technical Evaluation 5.0 Regulatory Evaluation 5.1 Applicable Regulatory Requirements I Criteria 5.2 No Significant Hazards Consideration

5.3 Precedents

5.4 Conclusion 6.0 Environmental Considerations 7.0 References Page 1 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 DISCUSSION OF CHANGE 1.0 Summary Description Virginia Electric and Power Company (Dominion) proposes to revise the Surry Power Station Units 1 and 2 Technical Specifications (TS) 6.4.Q, "Steam Generator (SG)

Program," to exclude portions of the SG tube below the top of the SG 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. The proposed changes to the TS are based on the supporting structural analysis and leakage evaluation contained in Westinghouse Electric Company, LLC WCAP-17092-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51F)," Revision 0, June 2009 (Reference 1).

WCAP-17092-P recommends the 95/50 H* value of 13.14 inches.

Dominion has chosen to use an H* value of 16.7 inches for additional conservatism. Adoption of this H* value and the permanent alternate repair criteria does not require SG tube inspection greater than 16.7 inches below the top of the tubesheet, nor plugging of service-induced flaws located greater than 16.7 inches below the top of the tubesheet. Inclusion of the permanent alternate repair criteria in TS 6.4.Q permits deletion of the previous Units 1 and 2 interim alternate repair criteria (IARC) requirements, as well as the modified IARC for the Unit 1 B SG.

This amendment request also proposes to revise TS 6.6.A.3, "Steam Generator Tube Inspection Report" to remove reference to previous Units 1 and 2 IARC requirements, as well as the modified IARC for.the Surry Unit 1 B SG, and provides reporting requirements specific to the permanent alternate repair criteria. In addition, changes to TS 3.1.C and TS 4.13 are proposed to delete the primary to secondary LEAKAGE limitation of 20 gallons per day (gpd) for the Unit 1 B SG for the Unit 1 Operating Cycle 23; the limitation was included as part of the modified IARC for the Surry Unit 1 B SG. The commitment to use a 4.7 leakage factor, which was made as part of the Unit 1 B SG modified IARC, is also being deleted. Associated revisions to the Bases for TS 3.1.C and TS 4.13 are included for the NRC's information.

The NRC previously issued the following amendments for Surry revising SG tube inspection and repair requirements:

TS Amendment --/258 (Reference 2), which approved an IARC for the Unit 2 Refueling Outage 21 and the subsequent operating cycle for Unit 2 (Reference 3). The IARC requires full-length inspection of the tubes within the tubesheet but does not require plugging tubes if any circumferential cracking observed in the region greater than 17 inches from the top of the tubesheet is less than a value sufficient to permit the remaining circumferential ligament to transmit the limiting axial loads.

TS Amendment 263/-- (Reference 4), which approved an IARC for the Unit 1 Refueling Outage 22 and the subsequent operating cycle for Unit 1

Page 2 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 (Reference 5). The IARC requires full-length inspection of the tubes within the tubesheet but does not require plugging tubes if any circumferential cracking observed in the region greater than 17 inches from the top of the tubesheet is less than a value sufficient to permit the remaining circumferential ligament to transmit the limiting axial loads.

TS Amendment 264/-- (Reference 6), which approved a modified IARC for the Unit 1 B SG for the Unit 1 Refueling Outage 22 and the subsequent operating cycle for Unit 1 (Reference 7). The modified IARC does not require plugging of Unit 1 B SG with permeability variation indications that may mask flaws in the bottom one inch of the tubesheet. In addition, the TS requirement for primary to secondary operational leakage is limited to 20 gallons per day for the Unit 1 B SG for the Unit 1 Operating Cycle 23. Supplemental information regarding an estimated mean value of H*, an estimated value of H* at 95% probability at 50%

confidence, and an evaluation of the maximum potential tube slippage under a set of bounding assumptions was provided in support of the modified IARC'for the Unit 1 B SG (Reference 8).

Approval of this license amendment request for the permanent alternate repair criteria is requested by October 16, 2009 to support the Surry Unit 2 Refueling Outage 22 (Fall 2009), since the Unit 2 existing one-cycle TS Amendment --/258 expires at the end of the current operating cycle.

2.0 Detailed Description of Proposed Changes to Current TS TS 3.1.C l.d currently states:

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG), with the following exception.

The primary to secondary LEAKAGE for the Unit 1 B steam generator will be limited to 20 gallons per day during Operating Cycle 23.

TS 3.1.C.1.d is being revised as follows:

I

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

TS 3.1.C Basis-APPLICABLE SAFETY ANALYSES currently states in part:

APPLICABLE SAFETY ANALYSES -

Except for the primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from all steam generators (SGs) is 1 gpm or increases to Page 3 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 1 gpm as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

Due to the permeability variatidn indications in the Unit 1 B steam generator found during Refueling Outage 22, the primary to secondary leak rate for that steam generator is limited to 20 gallons per day for Operating Cycle 23.

This portion of the TS 3.1.C Basis - APPLICABLE SAFETY ANALYSES is being revised by deletion of the last sentence that states:

Due to the permeability Variation indications in the Unit 1 B steam generator found.

during Refueling Outage 22, the primary to secondary leak rate for that steam generator is limited to 20 gallons per day for Operating Cycle 23.

TS 3.1.C Basis - LIMITING CONDITIONS FOR OPERATION currently states in part:

d. Primary to Secondary LEAKAGE throucqh Any One SG The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 3). The Steam Generator Program operational leakage criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage.

The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures. Due to the permeability variation indications in the Unit 1 B steam generator found during Refueling Outage 22, the primary to secondary leak rate for that steam generator is limited to 20 gallons per day for Operating Cycle 23.

This portion of the TS 3.1.C Basis - LIMITING CONDITIONS FOR OPERATION is being revised by deletion of the last sentence that states:

Due to the permeability variation indications in the Unit 1 B steam generator found during Refueling Outage 22, the primary to secondary leak rate for that steam generator is limited to 20 gallons per day for Operating Cycle 23.

TS 4.13.B currently states:

B. Verify primary to secondary LEAKAGE is < 150 gallons per day through any one SG once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, with the following exception.

The Page 4 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 primary to secondary LEAKAGE for the Unit 1 B steam generator will be verified to be < 20 gallons per day during Operating Cycle 23.1 Note 1: Not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

TS 4*13.B is being revised as follows:

B. Verify primary to secondary LEAKAGE is < 150 gallons per day through any one SG once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.1 If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

Note 1: Not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

TS 4.13 BASES for SR 4.13.B currently states in part:

This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG, with the following exception.

The primary to secondary LEAKAGE for the Unit 1 B steam generator will be limited to 20 gallons per day during Operating Cycle 23.

Satisfying. the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.1.H, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 4. The'operational LEAKAGE rate applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG; for Unit 1 that leakage should be assumed to be through the B steam generator for Operating Cycle 23. The surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

Reference 4: EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Page 5 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 This portion of the TS 4.13 BASES for SR 4.13.B is being revised as follows:

This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.1.H, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG. The surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

Reference 4: EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

TS 6.4.Q.3 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 2 Refueling Outage 21 and the subsequent operating cycle, 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 above 1 inch from the bottom of the tubesheet do not require plugging. Tubes with flaws having a circumferential component greater than 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet shall be removed from service.

Tubes with service-induced flaws located within the region from the top of the tubesheet to 17 inches below the top of the tubesheet shall be removed from service. Tubes with service-induced axial cracks found in the portion of the tube below 17 inches from the top of the tubesheet do not require plugging.

Page 6 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 When more than one flaw with circumferential components is found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet with the total of the circumferential components greater than 203 degrees and an axial separation distance of less than 1 inch, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

When one or more flaws with circumferential components are found in the portion of the tube within 1 inch from the bottom of the tubesheet, and the total of the circumferential components found in the tube exceeds 94 degrees, then the tube shall be removed from service. When one or more flaws with circumferential components are found in the portion of.the tube within 1 inch from the bottom of the tubesheet and within 1 inch axial separation distance of a flaw above 1 inch from the bottom of the tubesheet, and the total of the circumferential components exceeds 94 degrees, then the tube shall be removed from service.

When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

b. For Unit 1 Refueling Outage 22 and the subsequent operating cycle, 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 above 1 inch from the bottom of the tubesheet do not require plugging. Tubes with flaws having a circumferential component greater than 203 degrees found in the portion of the tube below 17 inches from the top of the tubesheet and above 1 inch from the bottom of the tubesheet shall be removed from service.

Tubes with service-induced flaws located within the region from the top of the tubesheet to 17 inches below the top of the tubesheet shall be removed from service. Tubes with service-induced axial cracks found in the portion of the tube below 17 inches from the top of the tubesheet do not require plugging.

When more than one flaw with circumferential components is found in the portion of the tube below 17 inches from the top of the. tubesheet and above 1 inch from the bottom of the tubesheet with the total of the circumferential components greater than 203 degrees arid an axial separation distance of less than 1 inch, then the tube shall be removed from service. When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

Page 7 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 When one or more flaws with circumferential components are found in the portion of the tube within 1 inch from the bottom of the tubesheet, and the total of these circumferential components exceeds 94 degrees, then the tube shall be removed from service.

When one or more flaws with circumferential components are found in the portion of the tube within 1 inch from the bottom of the tubesheet and within 1 inch axial separation distance of a flaw above 1 inch from the bottom of the tubesheet, and the total of these circumferential components exceeds 94 degrees, then the tube shall be removed from service.

When the circumferential components of each of the flaws are added, it is acceptable to count the overlapped portions only once in the total of circumferential components.

c. For Unit 1 Refueling Outage 22 and the subsequent operating cycle, tubes in the B steam generator with permeability variation indications that may mask flaws in the bottom one inch of the tubesheet do not require plugging.

TS 6.4.Q.3 is being revised as follows:

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 16.7 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 16.7 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. 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 Page 8 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 6.4.Q.4 is being revised as follows:

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, from 16.7 inches below the top of the tubesheet on the hot leg side to 16.7 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria. 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.

TS 6.4.Q.4.c currently states:

c. If crack indications are found in any SG tube, 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 nondestructive 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 6.4.Q.4.c is being revised as follows:

c. If crack indications are found from 16.7 inches below the top of the tubesheet on the hot leg side to 16.7 inches below the top of the tubesheet on the cold leg side, 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 nondestructive 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.

Page 9 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 TS 6.6.A.3.g through TS 6.6.A.3.o currently state:

g. The results of condition monitoring, including the results of tube pulls and in-situ testing, and

h. The effective plugging percentage for all plugging in each SG.

i.

Following completion of a Unit 2 inspection performed in Refueling Outage 21 (and any inspections performed in the subsequent operating cycle), the number of indications and location, size, orientation, whether initiated on primary or secondary side for each service-induced flaw within the thickness of the tubesheet, and the total, of the circumferential components and any circumferential overlap below 17 inches from the top of the tubesheet as determined in accordance with TS 6.4.Q.3.a,

j.

Following completion of a Unit 2 inspection performed in Refueling Outage 21 (and any inspections performed in the subsequent operating cycle), the primary to secondary LEAKAGE rate observed in each steam generator (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report, and

k. Following completion of a Unit 2 inspection performed in Refueling Outage 21 (and any inspections performed in the subsequent operating cycle), the calculated accident leakage rate from the portion of the tube below 17 inches below the top of the tubesheet for the most limiting accident in the most limiting steam generator.

1. Following completion of a Unit 1 inspection performed in Refueling Outage 22 (and any inspections performed in the subsequent operating cycle), the number of indications and location, size, orientation, whether initiated on primary or secondary side for each service-induced flaw within the thickness of the tubesheet, and the total of the circumferential components and any circumferential overlap below 17 inches from the top of the tubesheet as determined in accordance with TS 6.4.Q.3,

m. Following completion of a Unit 1 inspection performed in Refueling Outage 22 (and any inspections performed in the subsequent operating cycle), the primary to secondary LEAKAGE rate observed in each steam generator (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one steam generator) during the cycle preceding the inspection which is the subject of the report, and Page 10 of 24

Serial No.09-455 Docket Nos. 50-280/50-281

n. Following completion of a Unit 1 inspection performed in Refueling Outage 22 (and any inspections performed in the subsequent operating cycle), the calculated accident leakage rate from the portion of the tube 17 inches below the top of the tubesheet for the most limiting accident in the most limiting steam generator.

o. Following completion of a Unit 1 inspection performed in Refueling Outage 22 (and any inspections performed in the subsequent operating cycle), for the B steam generator, the number of permeability variation indications including location and total circumferential extent.

TS 6.6.A.3.g and TS 6.6.A.3.h are being revised editorially and TS 6.6.A.3.i through TS 6.6.A.3.o are being replaced with TS 6.6.A.3.i through TS 6.6.A.3.k as follows:

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

j. The calculated accident induced leakage rate from the portion of the tubes below 16.7 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 2.03 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

k. 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 86 tubes are currently plugged on Unit 1 and 64 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.

Page 11 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 9);

EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines" (Reference 10); EPRI 1012987, "Steam Generator Integrity Assessment Guidelines" (Reference 11); ER-AP-SGP-101, Dominion Administrative Procedure titled "Steam Generator Program" (Reference 12), and the results of the degradation assessments performed in accordance with ER-AP-SGP-102, Dominion Administrative Procedure titled "Steam Generator Degradation Assessment" (Reference 13).

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 Appendix H, "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 14), 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.

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 Fall 2009 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 two distinct issues with regard to the SG tubes at Surry:

Page 12 of 24

Serial No.09-455 Docket Nos. 50-280/50-281

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

2) Indications at the elevation of the tack expansion transition.

Prior to each SG tube inspection, a degradation assessment, which includes a review of operating experience, is performed to identify degradation mechanisms that have a potential to be present in the 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.

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 (i.e., 16.7 inches below the top of the tubesheet).

4.0 Technical Evaluation To preclude unnecessarily plugging tubes in the Surry SGs, 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 WCAP-17092-P [Reference 1 (provided as )]. The evaluation is based on the use of finite element model structural analysis and a bounding leak rate evaluation based on contact pressure between the tube and the tubesheet during normal and postulated accident conditions. The limited tubesheet inspection criteria were developed for the tubesheet region of the Surry Model 51 F SGs 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.

WCAP-17092-P 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 WCAP-17092-P.

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 WCAP-17092-P 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 accident analyses. The radiological dose consequences associated with this assumed leakage for the SLB and locked rotor events are evaluated to ensure Page 13 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 14.2.3.3.2.3.5, 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, the feedwater line break is not part of the licensing basis for plants with Model 51F SGs.

This has been documented in Section 3.8.1 of Reference 15, 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 ll.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. Reference 16 responded to the NRC request for additional information and documented the results of the feedline break analysis.

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 17) 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 sufficient 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 SG, and to assure that the design basis accident contact pressures are greater than the normal operating pressure contact pressure are contained in Section 6 of WCAP-17092-P.

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.

Page 14 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 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 SG and control of temperature by the Auxiliary Feed Water System. Steam pressure control would be established by either. the SG 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.

The leakage factor of 2.03 is a bounding value for all SGs, both hot and cold legs, in Table 9-7 of WCAP-17092-P. Also 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. However, for Surry, a more conservative leakage factor of 2.03 will be applied to the normal operating leakage associated with the tubesheet expansion region in the condition monitoring (CM) assessment and the operational assessment (OA).

Specifically, for the CM assessment, the component of leakage from the prior cycle from below the H* distance will be multiplied by a factor of 2.03 and added to the total leakage from any other source and compared to the allowable accident induced leakage limit. For the 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 2.03 and compared to the observed operational leakage.

The other design basis accidents - the locked rotor event and the control rod ejection event - are conservatively modeled using design specification transients which result in increased temperatures in the SG hot and cold legs for a period of time. As previously noted, dynamic viscosity decreases with increasing temperature. Therefore, leakage would be expected to increase-due to decreasing viscosity, 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 51F SGs will exceed the normal operating differential pressure across the tubesheet is less than 30 seconds.

As the accident induced leakage performance criteria is defined in gallons per minute, the leak rate for a locked rotor event can be integrated over a minute 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 WCAP-17092-P) 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 Page 15 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 reduced by a factor of six from 2.37 to 0.40.

WCAP-17092-P 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 integrity over the full range of SG operating conditions, including the most limiting accident conditions. The evaluation in WCAP-17092-P determined that degradation in tubing below this safety significant portionof 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 WCAP-17092-P 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. However, in response to a NRC staff request, Dominion commits to monitor for tube slippage as part of the SG tube inspection program.

In addition, the NRC staff has requested that licensees perform a validation of the tube expansion from the top of tubesheet to the beginning of expansion transition to determine if there are any significant deviations that would invalidate assumptions in WCAP-17092-P. Therefore, Dominion commits to perform a one-time verification of tube expansion to locate any significant deviations from the top of tubesheet to the beginning of expansion transition. If any significant deviations are found, the condition will be entered into the plants corrective action program and dispositioned.

Dominion also commits to plug tubes that have been identified as not being expanded into the tubesheet in either the hot leg or the cold leg (refer to Attachment 4).

5.0 Regulatory Evaluation 5.1 Applicable Regulatory Requirements/Criteria SG tube inspection and repair limits are specified in Section 6.4.Q, "Steam Generator (SG) Program" of the SPS 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 that the Reactor Coolant Page 16 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 startup, operation in the power range, hot standby, cool down and all anticipated Page 17 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 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 todetermine 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." TS 3.1.C and 4.13 limit the primary to secondary leakage through any one SG to 150 gallons per day.

The proposed change defines the safety significant portion of the tube as the length of the tube that is engaged in the tubesheet to the top of the tubesheet (secondary face) that is required to maintain structural and leakage integrity over the full range of SG operating conditions, including the most limiting accident conditions. The evaluation in WCAP-17092-P determined that degradation in tubing below 13.14 inches from the top of the tubesheet does not require plugging and serves as the bases for the SG tube inspection program. Dominion has chosen to use a value of 16.7 inches for additional conservatism.

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.

5.2 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. 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.

This amendment request also proposes to revise TS 6.4.Q and TS 6.6.A.3, "Steam Generator Tube Inspection Report," to remove reference to previous Units 1 and 2 interim alternate repair criteria (IARC), as well as the modified IARC for the Surry Unit 1 B SG and provide reporting requirements specific to the permanent alternate repair criteria.

In addition, changes to TS 3.1.C and TS 4.13 are proposed to delete/the Page 18 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 primary to secondary LEAKAGE limitation of 20 gallons per day for the Unit 1 B SG, as well as to delete the 4.7 leakage factor commitment, for the Unit 1 Operating Cycle 23.

The leakage limitation and the leakage factor commitment were included as part of the modified IARC for the Surry Unit 1 B SG.

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 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 the Surry steam generator tube integrity performance criteria in TS 6.4.Q.2. The TS 6.4.Q.2 performance criteria are consistent with Nuclear Energy Institute (NEI) 97-06, Revision 2, "Steam Generator Program Guidelines," performance criteria.

Westinghouse WCAP-17092-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 51F)," recommends an H* value of 13.14 inches. Dominion has chosen to use a more conservative value of 16.7 inches.

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 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 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 presence of the tubesheet and the constraint provided by the tube-to-tubesheet joint.

Tube burst cannot occur within in thickness of the tubesheet.

The tube-to-tubesheet joint constraint results from the hydraulic' expansion process, thermal expansion mismatch between the tube and tubesheet, the differential Page 19 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 pressure between the primary and secondary side, and the tubesheet deflection.

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 and leakage integrity of the steam generator tubes consistent with the performance criteria in TS 6.4.Q.2. 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 degradation below the proposed limited inspection depth is limited by the 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 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 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 leakage factor of 2.03 is a bounding value for all SGs, both hot and cold legs, in Table 9-7 of WCAP-17092-P. Also 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.

However, for Surry, a more conservative leakage factor of 2.03 will be applied to the normal operating leakage associated with the tubesheet expansion region in the condition monitoring (CM) assessment and the operational assessment (OA).

Through the application of the limited tubesheet inspection scope, the existing operating leakage limit provides assurance that excessive leakage (i.e., greater than accident analysis assumptions) will not occur. The limiting accident induced primary to secondary leak rate-is 470 gallons per day per steam generator during a postulated steam line break.

Using the limiting leakage factor of 2.03, this corresponds to an acceptable level of operational leakage of 231.5 gallons per day. The TS operational primary to secondary leak rate limit is 150 gallons per day through any one steam generator.

Consequently, there is sufficient margin between accident induced leakage and TS allowable operational leakage.

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

Page 20 of 24

Serial No.09-455 Docket Nos. 50-280/50-281

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 and repair criteria, as well as the reporting requirements, 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 and repair criteria, as well as the reporting requirements, maintains the required structural margins of the steam generator tubes for both normal and accident conditions.

NEI 97-06, Revision 2, 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, WCAP-17092-P defines a length of degradation-free expanded tubing that provides the necessary resistance to tube pullout due to the pressure induced forces, with applicable safety factors applied. Application of the limited hot and cold leg tubesheet inspection criteria will preclude unacceptable primary to secondary leakage during all plant conditions.

The methodology for determining leakage provides for sufficient margins between calculated and actual leakage values in the.

proposed limited tubesheet inspection depth criteria.

Therefore, the proposed change does not involve a significant reduction in any margin of safety.

Page 21 of 24

Serial No.09-455 Docket-Nos. 50-280/50-281 5.3 Precedents The proposed change to Surry TS 6.4.Q and TS 6.6.A.3 is similar to the following proposed changes, which have been submitted to revise TS for permanent alternate repair criteria:

Southern Company letter NL-09-0547, dated May 19, 2009, Vogtle Electric Generating Plant 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

" NextEra Energy letter SBK-L-09118, dated May 28, 2009, Seabrook Station License Amendment Request 09 Revision to Technical Specification 6.7.6.k, "Steam Generator (SG) Program," for Permanent Alternate Repair Criteria (H*)

" Wolf Creek Nuclear Operating Corporation letter ET 09-0016, dated June 2, 2009, Docket No. 50-482: Revision to Technical Specifications 5.5.9, "Steam Generator (SG) Program," and TS 5.6.10, "Steam Generator Tube Inspection Report," for a Permanent Alternate Repair Criteria

" Luminant Power letter Log # TXX-09075, dated June 8, 2009, Comanche Peak Steam Electric Station (CPSES) Docket Nos. 50-445 and 50-446 -

License Amendment Request 09-007, Model D5 Steam Generator Alternate Repair Criteria Exelon Generation Company letter RS-09-071, dated June 24, 2009, Braidwood Station Units 1 and 2 and Byron Station Units 1 and 2 -

License Amendment Request to Revise Technical Specifications (TS) for Permanent Alternate Repair Criteria 5.4 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. WCAP-17092-P 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.

Page 22 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 6.0 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.

7.0 References

1.

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

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 TS Amendment --/258]

3.

Virginia and Electric Power Company to NRC letter Serial No.08-0207, dated April 14, 2008, Surry Power Station Unit 2 -

Proposed License Amendment Request - Interim Alternate Repair Criteria (IARC) for Steam Generator (SG) Tube Repair

4.

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 TS Amendment 263/--]

5.

Virginia and Electric Power Company to NRC letter Serial No.08-0521, dated October 14, 2008, Surry Power -Station Unit 1 - Proposed License Amendment Request - Interim Alternate Repair Criteria (IARC) for Steam Generator (SG) Tube Repair

6.

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 TS Amendment 264/--]

Page 23 of 24

Serial No.09-455 Docket Nos. 50-280/50-281

7.

Virginia and Electric Power Company to NRC letter Serial No.09-295, dated May 5, 2009, Surry Power Station Unit 1 -

Proposed Emergency License Amendment Request - Modified Interim Alternate Repair Criteria for Unit 1 B Steam Generator Tube Repair

8.

Virginia and Electric Power Company to NRC letter Serial No.09-295A, dated May 6, 2009, Surry Power Station Unit 1 - Additional Information in Support of Proposed Emergency License Amendment Request Regarding Modified Interim Alternate Repair Criteria for Steam Generator B

9.

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

10.

EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines"

11.

EPRI 1012987; "Steam Generator Integrity Assessment Guidelines"

12. ER-AP-SGP-101, Dominion Administrative Procedure titled "Steam Generator Program"

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

14.

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

15. 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

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

Additional Information Related to NUREG-0737, Item ll.D.1 Performance Testing of Relief and Safety Valves

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

Page 24 of 24

Serial No.09-455 Docket Nos. 50-280/50-281 Marked-up Technical Specifications and Bases Pages Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

TS 3.1-13 C.

RCS Operational LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200'F (200 degrees Fahrenheit).

Specifications

1.

RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gprn unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG),

~it the fo *owing bcep.!4nT-lhe timary, sec/on~llry LEAkAGF`

Sfor *he.Ui~tB 1Btean enerar'r Ia /e lined to, 0 gal0s per d ddu, i*g

] *perati.i yld2.

2.a. If RCS operational LEAKAGE is not within the limits of 3.1.C. 1 for reasons other than pressure boundary LEAKAGE. or primary to secondary LEAKAGE, reduce LEAKAGE to within the specified limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

b. If the LEAKAGE is not reduced to within the specified limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

3.

If RCS pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within the limit specified in 3.1.C. 1.d,. the unit shall be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

Amendment Nos. >(and^'

TS 3.1-14a This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

APPLICABLE SAFETY ANALYSES - Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary. LEAKAGE from all steam generators (SGs) is I gpm or increases to I gpm as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis ue to t e perme ility v ation in icationyn-

[th.nit 12stea ' gene ator fo nd dur~i*g Ref ing ( /tage 22 te Pri ZrY to s.y*ondaryleak) 17te for atse enator is/imited t6 20 ga/In

_o tda 7~,p~ai*Cyce*3.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a main steam line break (MSLB) accident. Other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The UFSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The MSLB is less limiting for site radiation releases than the SGTR. The safety analysis for the MSLB accident assumes 1 gpm total primary to secondary LEAKAGE, including 500 gpd leakage into the faulted generator. The dose consequences resulting from the MSLB and the SGTR accidents are within the limits defined in the plant licensing basis.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LIMITING CONDITIONS FOR OPERATION - RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Amendment Nos. K and

TS 3.1-14b

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day per SG'is based on the operational LEAKAGE performance criterion in NET 97-06, Steam Generator Program Guidelines (Ref. 3). The

'Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.d e to e

pe eabi ty v ationj dicatio s in th Unit 1 stea genera r foun du ciRefu ng tage 2, th prim to sec ndary/eak rat/for th steam g'nerat is likted to 0 7gallo s per ay for_

peratin Cycl23 -

APPLICABILITY - In REACTOR OPERATION conditions where Tavg exceeds 200'F, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In COLD SHUTDOWN and REFUELING SHUTDOWN, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.1.C.5 measures leakage through each individual pressure isolation valve (PIV) and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is Ieaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

Amendment Nos.ýý(and,*

TS 4.13-1 4.13 RCS OPERATIONAL LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever Tag (average RCS temperature) exceeds 200'F (200 degrees Fahrenheit).

Objective To verify that RCS operational LEAKAGE is maintained within the allowable limits.

Specifications A.

Verify RCS operational LEAKAGE is within the limits specified in TS 3.1.C by performance of RCS water inventory balance once every 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s-1, B.

Verify primary to secondary _LEAKAGE is <5 150 gallons

' SG once every 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sw Yh the/)otlo*Angg %6*ptof 1/

[LEýKAIG~for th/Unit I/ ste/arn ge tr~o/vl belerifi E dj*duffni/g Opeygting C ¢le 23* _

Notes:

1.

Not required to be completed until 12 houlafrestablishment of steady state operation.

ho-0

(

h

2.

Not applicable to primary to secondary LEAKAGE.

,.SSj

+*e..

.AKA-*tE

--To BASESA d156) da Ia I Ithe..

SURVEILLANCE REQUIREMENTS (SR) skoul. I-c s e LyA)<AC)4

• hoalt

/..Con sevvt~.-h~t,4_l SR 4.13.A aSsqm ed -f-o be, -

0,-

5C-,

Verifying RCS LEAKAGE to be within the Limiting Condition for Operation (LCO) limits ensures the integrity, of the reactor coolant pressure boundary (RCPB) is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by -

performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The surveillance is modified by two notes.

Note 1 states that this SR is not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishing steady state operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance provides sufficient time to collect and process all necessary data after stable unit conditions are established.

Amendment Nos.'

and

• TS 4.13-2 Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.,It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in the TS 3.1.C Bases.

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 4.13.B This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG, wi$ theollow g exc tion.he priylary to conda LEAKA91A for Me*1 it I ste.b genator ill btlimit?4 to 27gallonl per da durin"perati Cyc123.l Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.1.H, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG.

If it is not'practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SGI,,for *lýit 1,t at leayge youlm I bpasomed/o b~e p*roug&K theAl stearr/geney,*tor for,/Operatin/g Cy~e 23' IThe surveillanee is" modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The surveillance frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 4).

Amendment Nos.X andy

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:

scy4 be-5 urd AQ

-Muoas-s Ioca-Ied

ýr-eule-.f +kca,"

14.7 %rnches bedow 4hkeJp o f i4be 4ubesheeh-dokno rgqo-i-p hj-Icj TAbes7 LWift seyJuce-i'd~e 4f1 aws I oakeca iý +he~por4ýTor of fi-he-4-kbe mf~t -hbe~shPiee+

h-I G 7 %rnctes belowu 4-he4vpofý 4+,e- ý vb esh ee.+

shall bepIufj~eA a

For Uyt2 Refueli Outage 2a nd the subs quent oper ng cycle, tuyes with flaw having a rcumferentfI componel than equal to 2, degrees find in the

'rion of the be below inches fr the top of e tubesheet and above inch from t e bottom othe tubes et do not re ire pluggi Tubes w' flaws havi a circum ential co onent greate han 203 de ees found in the portion f the tube elow 17 i hes from the op of the tu sheet an bove I inc rom the ttom of e tubesheet s all be remo ed from S vice.

Tubes with ervice-in ced flaw ocated within e region fr the top of tubeshee to 17 inc sobelow e top f he t esheet shal e removedom servic. Tubes w* service nduced axial racks foun n the portio of the tu elow 17i *ches fro the top of the ubesheet do ot require pl ging.

hn mor than one aw with cir inferential omponents found in the poton the tub elow 17 inc from the p of the tub beet and abo 1 inc rom the ottom of the besheet w' the total of e circumfer tial co ponents eater than 20 degrees an an axial sep ation distanc of less an 1 in

, then the t e shall b rem oved f m service, hen the circumf ential compo ents of eac of the flaws e added, it is cceptable t coun the overlap d portions nly once i the total of 'rcumfere al co ponents.

hen one more flaws ith circum rential comp ents are fo d in the portion o he tube with' 1 inch fro e bottom of e tubeshee nd the total of the circumferen I componen exceeds 94 grees, then tube shale re oved from vice. Whe one or mor flaws with ircumfere tial omponents ar ound in the rtion of the be within 1 i ch from the ottom of the tubes et and withi inch axial paration dis nce of a fla above 1 inch fro e bottom o he tubeshe and the tot of these cir inferential AmendmentNos.X 4

)I

)

(

(

(

()()

)

I

TS 6.4-13 comp 9ents exceed 4cegrees, tlen the tub Chall be removed fro service.

W n the circu 0*erential ciponents of,each of the flaws ar gadded, it is

"):ceptable t count the verlapped ortions only one n the total of

/ circumfe tial componts"/..

Fo r IRfe utg 2

hesb equn r'eating cycle, tubes#

fla* having a rumern' omonn less flan or equal to 203

• rees f

n nte rio ft ebeo 7icsfrom the top of the besheet an bv ic fo ebto o

h ehe do not re

. e plugging.

Tue t lw an icmee opnn reat an 203 degrees

/ service./

/

Tubes ith service-in ced flaws locate ithin the region f the top of the tubhe o.7i sbeo h

o tetbsheet s*

be removed from rvc.Tbe ihsrvc-n dailcrcs d in the portion of the tube below inches from thop of the tubeshe t/o not require plugginj When r

hn one wit w

icrne i

oponents is fnmd in the POIo fte ue o

7ichsfote opo the tubes* and above I chfo h

tmo h ub twt hettlo circumferential than Il'ch, hntetesalb eoe rom service.

en the cic frnilcm e

f aho h r de, it.

cceptable to un th vr dprtosol n

thetotl*

mirc ronfeeni

/ components..

po ftetb ihnic rmte o

fte tubes, t, and the t~otal these circumferen opnns es9 eres, en the tube shale removed from rvice.

hn eo oefa ith circumfe ential componet on nte 6ton of the mtube in I inch fro vffe bottom of h s tadwi' nhails tion disanc flw above 1 inc rom the botto.of the tubes~heft d the.total oft se circumferen.' I mpnnse es9 eres h hll rmoved from s ice.

When the ufrnilc nnso ~c he flaws are a e~td, it is acceptle t on h elpe ot s only once i

'e total of cirm feren tial comp nt s.

/

B steam ge ator with perme ity variation if,,d'tions that may fask flaws.

in the b"om one inch of t tubesheet do not ~uire plugging.

Amendmen

TS 6.4-13a

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 prese ng

"- ýb 01 (P,,7 the ngth6f tF tub, fro the obe-t!-tube eet /eld atfie tul inleyo t e inc) es bdoA) ftu-to-/bes eet ld at e ubouet,[and that may satisfy the applicable tube

+h-c. 4"bp of repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to

+-1ie-itbesheeP meeting the requirements of 4.a, 4.b, and 4.c below, the inspection scope, onW "c.. he+-

inspection methods, and inspection intervals shall be such as to ensure that SG I e~~ $ Ik

"+

tube integrity is maintained until the next SG inspection. An assessment of 1(0 17 wa Ces degradation shall be performed to determine the type and location of flaws to b* W q-**

which the tubes may be susceptible and, based on this assessment, to determine

--u

• C 4v which inspection methods need to be employed and at what locations.

4Yb eS hee-f"

a. Inspect 100% of the tubes in each SG during the first refueling outage r) '-

following SG replacement.

[.$ id&

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 4o 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.

k

ý<c.

M'cra:iný

'catiop<ar ounV/n arp SC t*u t en the next inspection for each t d n d; CO..-hI S

SG for the degradation mechanism that caused the crack indication shall not aret f*ut.o d

exceed 24 effective full power months or one refueling outage (whichever is r

14,7 T1 M e

less). If definitive information, such as from examination of a pulled tube, W OWt 4I-)e., +

diagnostic non-destructive testing, or engineering evaluation indicates that a

+-crack-like indication is not associated with a crack(s), then the indication need oý A t h-not be treated as a crack.

4n

• e,. hol

-~e.* sc~e.

5. Provisions for monitoring operational primary to secondary LEAKAGE.

dbeie 4-A b

• 1C,,-7 r es o

+-he.. 4ubesh e--"

On +Pe cold Amendment No.

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,,amd-

h. The effective plugging percentage for all plugging in each SG4

i. FoOWingqompletion/f a U nit* inspectioK performft in Re in Outa Si(an ny insp tions pe ormed in e subse.ent oper ing cycle the nu er of i ications d locatio size, or

tation, ether init ted on mary secondar side for ea service*- duced fl within th thicknes of th ubesheet and the tot of the c' cumfere jal compo nts and ny ci umferentt overlap low 17 i hes fro he top of e tubes et as determine in accordan with TS 4.Q.3.a, fM$ERT-",5, AdZ 1A omen Pdm T,

3 o

Amendment Nos.

TS 6-6-3a

.j. F61ollonig completin of a Unit 2 'nspection per n-ed in Refuel*g Outage-i imary to se *ndary LEA IGE rate ob, ed in each stea enerator (if it is

/not pract' al to assign akage to arndividual SG, trf entire primaryJ second LE.AKAG should be c servatively assu*Z to be from one earn gen ator).durin e cycle prec ~fing the inspectio which is the sub'ct of the

• ort, and//

/'/

k. Fllowin ompeimPonf~

o' Unit 2 inspectio /performed in fueling Outage 21 (an ayinspctins performed in t~a subsequent,,c*rating cycle), the

• }low the to cf the tubesheet f the most l~i ing accident in the ost Slimiting stec generator.

1. Followi completion of a nit I inspectfi performed in Refuing Outage 22 (, d any inspection performed in e subsequent oper ng, cycle), the n

aber of indicatio s and locatio, size, orientation, ether initiated on primary or secon ry side for eag service-induced fld within the thickne*

of the tubes et, and the to,' of. the circumfer ial components a gany circumfe ntial overlap,Clow 17.inches *fr the top of the tub ~heet as dete

-ned i n accorda e. with TS 6.4.Q3

m. F,9owing compl on of a Unit I in ection performed inefueling Outage 22(and any ipections perfofrd in the subsequent perating cycle),

e

• primary econdary LE.A Erate observedin e_ steam generator 'it is not ctical to assign I tkage to an individ I SG; the entire fimary to ondary LEA KAG tshould be conservaiely assumed to be"omn one steam gene rator) durinhe cycle preceding e inspection whichithe subject of t~

report,

///

n. Foltowi/

completion of a U t I inspection pe med in Refuelin/

utage 22 nd any inspections rformed in the su Cequent operatin dycle), the alculated accident le age rate from the p

'on of the tube Iinches below the top of the tub heet for the most li iting acciden t in e most limiting steam generator nd' Amendment Nos.* and.*

TS 6.6-3b

o.

Fol wing comple on of a Unit inspection pe ormed in Re eling Outage 2-2/

nd any other*

spectionspe ormed in the bsequento ating cycle), fo e

B steam ge rator, the n br of perme ility variati indications inc ding location nd total circ ferential ext t.

bs T ey.

p'WrdX

-iv se41aA LSAA§ Y

v0-t p fr &Z

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L A

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+e-t-i<C-&o G0,i LilGNVikoLUcLQ-SC*,

+he.

- en-o p rio-o.ry 4-t.x.I.Anot-LGAkA4*_ skould b,

"$pe-Cý 1. W Ikt. i5 11-./ 5 JýeC-tpov+, a.;.

- l -, '-

".M Il d u -

L E A W -A Ge-tQ&a+-e4 aýA)d en-f idttcuL LGAW14E rak--

-Frarnq 44h&e vyos 4- (rf acWJad9+

4,5 less

-[;£na*

+,o rr'm-S 4.-i...

vra4dY)m-LVY ope adv

• pii'or¢j slv c~c~nd b -Ph*,*o §4 rdoas+C-dVý eb-nn 4-Vb, c4eArkm in'ed,

k.

res cc) ts of-P-4 rV-Y" nq~-

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crsplaztmen+- (S :ljp ta-]". I.*

SI;pp

,4 Is co v erV-d, re-I e.-

at-,b AI shod I be.-

S YSov,

.Amendment Nos.

Serial No.09-455 Docket Nos. 50-280/50-281 Proposed Technical Specifications and Bases Pages Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

TS 3.1-13 C.

RCS Operational LEAKAGE Applicability The following specifications are applicable to RCS'operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200'F (200 degrees Fahrenheit).

Specifications

1.

RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

2.a. If RCS operational LEAKAGE is not within the limits of 3.1.C.1 for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE, reduce LEAKAGE to within the specified limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

b. If the LEAKAGE is not reduced to within the specified limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

3.

If RCS pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within the limit specified in 3.1.C.1.d, the unit shall be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

Amendment Nos.

TS 3.1-14a This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

APPLICABLE SAFETY ANALYSES - Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from all steam generators (SGs) is 1 gpm or increases to 1 gpm as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a main steam line break (MSLB) accident. Other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The UFSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The MSLB is less limiting for site radiation releases than the SGTR. The safety analysis for the MSLB accident assumes 1 gpm total primary to secondary LEAKAGE, including 500 gpd leakage into the faulted generator. The dose consequences resulting from the MSLB and the SGTR accidents are within the limits defined in the plant licensing basis.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LIMITING CONDITIONS FOR OPERATION - RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Amendment Nos.

TS 3.1-14b

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System., Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 3). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion

'in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

APPLICABILITY - In REACTOR OPERATION conditions where Tavg exceeds 200'F, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In COLD SHUTDOWN and REFUELING SHUTDOWN, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.1.C.5 measures leakage through each individual pressure isolation valve (PIV) and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

Amendment Nos.

TS 4.13-1 4.13 RCS OPERATIONAL LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200'F (200 degrees Fahrenheit).

Objective To verify that RCS operational LEAKAGE is maintained within the allowable limits.

Specifications A.

Verify RCS operational LEAKAGE is within the limits specified in TS 3.1.C by performance of RCS water inventory balance once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. 1, 2 B.

Verify primary to secondary LEAKAGE is _< 150 gallons per day through any one SG once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.1 If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

Notes:

1.

Not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

2.

Not applicable to primary to secondary LEAKAGE.

BASES SURVEILLANCE REQUIREMENTS (SR)

SR 4.13.A Verifying RCS LEAKAGE to be within the Limiting Condition for Operation (LCO) limits ensures the integrity of the reactor coolant pressure boundary (RCPB) is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The surveillance is modified by two notes.

Note 1 states that this SR is not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishing steady state operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance provides sufficient time to collect and process all necessary data after stable unit conditions are established.

Amendment Nos.

TS 4.13-2 Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in the TS 3.1.C Bases.

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 4.13.B This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.1.H, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG. The surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The surveillance frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 4).

Amendment Nos.

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 16.7 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 16.7 inches below the top of the tubesheet shall be plugged upon detection.

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, from 16.7 inches below the top of the tubesheet on the hot leg side to 16.7 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria. 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.

Amendment Nos.

TS 6.4-13

c. If crack indications are found from 16.7 inches below the top of the tubesheet on the hot leg side to 16.7 inches below the top of the tubesheet on the cold leg side, 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 beincluded 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

j.

The calculated accident induced LEAKAGE rate from the portion of the tubes below 16.7 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 2.03 times the maximum operational primary to secondary LEAKAGE rate, the report should describe how it was determined.

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

Amendment Nos.

Serial No.09-455 Docket Nos. 50-280/50-281 List of Regulatory Commitments Surry Power Station Units I and 2 Virginia Electric and Power Company (Dominion)

Serial No.09-455 Docket Nos. DPR 50-280/50-281 List of Regulatory Commitments The following table identifies those actions committed by Dominion in this document for Surry Units 1 and 2. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.

7 Commitment Due Date/Event Dominion commits to monitor for tube slippage as part of Starting with Unit 2 the SG tube inspection program.

Refueling Outage 22 Dominion commits to perform a one-time verification of Prior to the startup tube expansion to locate any significant deviations from following Unit 2 Refueling the top of tubesheet to the beginning of expansion Outage 22 and Unit 1 transition. If any significant deviations are found, the Refueling.Outage 23 condition will be entered into the plants corrective action program and dispositioned.

Dominion commits to plug eleven Unit 2 tubes that have During the Unit 2 been identified as not being expanded within the Refueling Outage 22 tubesheet in either the hot leg or cold leg.

Dominion commits to plug three Unit 1 tubes that have During the Unit 1 been identified as not being expanded within the Refueling Outage 23 tubesheet in either the hot leg or cold leg.