ML090860735

Issuance of Amendment Regarding Proposed License Amendment Request - Interim Alternate Repair Criteria for Steam Generator Tube Repair

ML090860735
Person / Time
Site:	Surry
Issue date:	04/08/2009
From:	David Wright Plant Licensing Branch II
To:	Christian D Virginia Electric & Power Co (VEPCO)
Wright D, NRR/DORL, 301-415 -1864
References
TAC MD9976
Download: ML090860735 (22)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 April 8, 2009 Mr. David A. Christian President and Chief Nuclear Officer Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711 SUB~IECT:

SURRY POWER STATION, UNIT NO.1, ISSUANCE OF AMENDMENT REGARDING PROPOSED LICENSE AMENDMENT REQUEST - INTERIM ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE REPAIR (TAC NO. MD9976)

Dear Mr. Christian:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 263 to Renewed Facility Operating License No. DPR-32 for the Surry Power Station, Unit No.1 (Surry 1).

The amendment changes the Technical Specifications (TSs) in response to your application dated October 14, 2008, as supplemented February 20, 2009.

The amendment revises TS 6.4.Q, "Steam Generator (SG) Program," and TS 6.6.A.3, "Steam Generator Tube Inspection Report," to incorporate an interim alternate repair criterion into the provisions for SG tube repair for use during the Surry 1 2009 spring refueling outage (R-22) and the subsequent operating cycle.

A copy of the Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, p~~

Donna N. Wright, Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-280

Enclosures:

1. Amendment No. 263 to DPR-32

2. Safety Evaluation cc w/encls: See next page

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 VIRGINIA ELECTRIC AND POWER COMPANY DOCKET NO. 50-280 SURRY POWER STATION, UNIT NO.1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 263 Renewed License No. DPR-32

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Virginia Electric and Power Company (the licensee) dated October 14, 2008, as supplemented February 20,2009, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

- 2

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 3.B of Renewed Facility Operating License No. DPR-32 is hereby amended to read as follows:

(B)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 263

, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented prior to increasing reactor coolant system temperature above 200 of during startup of Surry Unit 1 from refueling outage 22.

FOR THE NUCLEAR REGULATORY COMMISSION Lj{~L.tJ~

Melanie C. Wong, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to License No. DPR-32 and the Technical Specifications Date of Issuance:

Apr i 1 8, 2009

ATTACHMENT TO LICENSE AMENDMENT NO. 263 RENEWED FACILITY OPERATING LICENSE NO. DPR-32 DOCKET NO. 50-280 Replace the following pages of the License and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Pages Insert Pages License License License No. DPR-32, page 3 License No. DPR-32, page 3 TSs TSs TS 6.4-13 TS 6.4-13 TS 6.4-13a TS 6.6-3a TS 6.6-3a

-3

3. This renewed license shall be deemed to contain an9 is sUbject to the conditIons specified in the following Commission regulations: 10 CFR Part 20, Section 30.34 of 10 CFR Part 30, Section 40.41 of 10 CFR Part 40, Sections 50.54 and 50.59 of 10 CFR Part 50, and Section 70.32 of 10 CFR Part 70: and is subject to all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified below:

A. Maximum Power Level The licensee is authorized to operate the faCility at steady state reactor core power levels not in excess of 2546 megawatts (thermal).

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 263 I are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

C. Reports The licensee shall make certain reports in accordance with the requirements of the Technical Specifications.

D. Records The licensee shall keep facility operating records in accordance with the requirements of the Technical Specifications.

E.. Deleted by Amendment 65 F. Deleted by Amendment 71 G. Deleted by Amendment 227 H. Deleted by Amendment 227 I. FirF! Protection The licensee shall implement and maintain in effect the provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report and as approved in the SER dated September 19, 1979, (and Supplements dated May 29, 1980, October 9, 1980, December 18, 1980, February 13, 1981, December 4,1981, Apri/27, 1982, November 18,1982, January 17, 1984, February 25, 1988, and SURRY UNIT 1 Renewed License No. DPR-32

TS 6.4-13 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 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 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.

Amendment Nos. 263

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 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 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 shaIl operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.

c. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shaIl 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. 263

TS 6.6-3a J. Following completion of a Unit 2 inspection perfonned 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 perfonned 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 perfonned 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 perfonned 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

n. Following completion of a Unit 1 inspection perfonned 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.

Amendment Nos. 263

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 263 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-32 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION, UNIT NO.1 DOCKET NO. 50-280

1.0 INTRODUCTION

By letter dated October 14, 2008 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML083510162), as supplemented February 20,2009 (ADAMS Accession No. ML090560200, Virginia Electric and Power Company (the licensee) submitted a request for changes to the Surry Power Station, Unit NO.1 (Surry 1), Technical Specifications (TSs). The requested changes would revise the repair requirements of TS Section 6.4.Q, "Steam Generator (SG) Program," and the reporting requirements of TS Section 6.6.A.3, "Steam Generator (SG) Tube Inspection Report." The supplement dated February 20,2009, provided clarifying information that did not change the scope of the original application and he initial proposed no significant hazards consideration determination The proposed changes would establish alternate repair criteria for portions of the SG tubes within the tubesheet, and would be applicable to Surry 1 during refueling outage 22 (1 R22), scheduled for spring 2009 and the subsequent operating cycle.

By letter dated October 14, 2008, the licensee submitted Westinghouse Electric Corrpany LLC (WEC) Topical Reports, LTR-CDME-08-11 P-Attachment, "Interim Alternate Repair Criterion (ARC) for Cracks in the Lower Region of the Tubesheet Expansion Zone," dated January 31,2008, LTR-CDME-08-43 P-Attachment, "Response to NRC Request for Additional Information Relating to LTR-CDME-08-11 P-Attachment," dated March 18, 2008, Westinghouse Electric Company LLC, LTR-CDME-08-25, "Errata for LTR-CDME-08-11, 'Interim Alternate Repair Criterion (ARC) for Cracks in the Lower Region of the Tubesheet Expansion Zone, '" dated February 12, 2008, and Westinghouse Electric Company LLC, LTR-CDME-08-85, "Applicability of LTR-CDME-08-11 and LTR-CDME-08-043 to Surry Unit 1 and Unit 2," dated April 9,2008. Because the topical reports contained proprietary information, the submission included affidavits dated April 9, 2008, signed by WEC, requesting that the NRC withhold the proprietary information from the public.

The NRC staff previously approved the withholding of the proprietary information from the public, in accordance with Title 10 of the Code of Federal Regulations (10 CFR), paragraph 2.390(b)(5) and Section 103(b) of the Atomic Energy Act of 1954, as amended, by letter dated May 13, 2008 (ADAMS Accession No. ML081200924). However, this letter only referenced US3 with Surry 2.

After further review of the information, it was noted that the affidavits dated April ~ 2008, are applicable for use with both Surry 1 and 2.

- 2 This clarifies that the NRC staffs proprietary determination dated May 13, 2008, is also applicable for use of the information with Surry 1. Therefore, the submitted information marked as proprietary in the application dated October 14, 2008, will continue to be withheld from public disclosure pursuant to 10 CFR 2.390(b)(5) and Section 103(b) of the Atomic Energy Act of 1954, as amended. This safety evaluation (SE) does not contain proprietary information.

2.0 BACKGROUND

Surry 1 has three Westinghouse Model 51 F SGs. There are 3342 thermally treated Alloy 600 tubes in each SG, each with an outside diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. The tubes are hydraulically expanded for the full depth of the tubesheet at each end and are welded to the tubesheet at the bottom of each expansion.

Until the fall of 2004, no instances of stress corrosion cracking (SCC) affecting the tubesheet region of thermally treated alloy 600 tubing had been reported at Surry 1 or other nuclear power plants (NPPs) in the United States. As a result, most plants, including Surry 1, had been using bobbin probes for inspecting the length of tubing within the tubesheet. Since bobbin probes are not capable of reliably detecting SCC in the tubesheet region, supplementary rotating coil probe inspections were used in a region extending from 3 inches above the top of the tubesheet (TTS) to 3 inches below the TTS. This zone includes the tube-expansion transition, which contains significant residual stress, and was considered a likely location for SCC to develop.

In the fall of 2004, crack-like indications were found in tubes in the tubesheet region of Catawba Nuclear Station, Unit 2 (Catawba), which has Westinghouse Model D5 SGs. Like Surry 1, the Catawba SGs employ thermally treated alloy 600 tubing that is hydraulically expanded against the tubesheet. At the time of cracking, Catawba had accumulated 14.7 effective full power years (EFPY) of service. The service experience of the Surry 1 SGs is significantly more than the Catawba SGs, but the hot-leg operating temperature at Surry 1 is significantly lower than at Catawba. The crack-like indications at Catawba were found in overexpansions (OXPs) in the tubesheet region, in the tack expansion region, and near the tube-to-tubesheet weld. An OXP is created when the tube is expanded into a region of the tubesheet that is not perfectly round. This out-of-round condition results from anomalies in the tubesheet drilling process (e.g., drill bit wandering). The tack expansion is an approximately 1-inch long expansion at each tube end.

The purpose of the tack expansion is to facilitate performing the tube-to-tubesheet weld, which is made prior to the hydraulic expansion of the tube over the full tubesheet depth.

As a result of the Catawba findings, the licensee expanded the scope of rotating coil inspections to include OXPs and a greater portion of the tubesheet thickness during the spring 2006 and fall 2007, Surry 1 refueling outages. The licensee reported that the inspections revealed no indications of cracking in the Surry 1 SGs.

3.0 REGULATORY EVALUATION

Section 50.36 of Title 10 of the Code of Federal Regulations (10 CFR), establishes the regulatory requirements related to the content of the TSs. Pursuant to 10 CFR 50.36, TSs are required to include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation (LCOs); (3) surveillance requirements; (4) design features; and (5) administrative controls. The regulation does not specify the particular requirements to be included in a plant's TSs.

- 3 In 10 CFR 50.36(c)(5), administrative controls are stated to be, "the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure the operation of the facility in a safe manner." This also includes the programs established by the licensee and listed in the administrative controls section of the TSs for the licensee to operate the facility in a safe manner. For Surry 1, the requirements for performing SG tUbe inspections and repair are in TS 3.1.H and TS 6.4.0, while the requirements for reporting the SG tube inspections and repair are in TS 6.6.A.3.

The TSs for all pressurized-water reactor (PWR) plants require that a SG program be established and implemented to ensure that SG tube integrity is maintained. For Surry 1, SG tube integrity is maintained by meeting specified performance criteria (TS 6.4.0.2) for structural and leakage integrity, consistent with the plant design and licensing basis. TS 6.4.0.1 requires that a condition monitoring assessment be performed during each outage in which the SG tubes are inspected, to confirm that the performance criteria are being met. TS 6.4.0 also includes provisions regarding the scope, frequency, and methods of SG tube inspections. Of relevance to the subject license amendment request, these provisions require that the inspections be performed with the objective of detecting flaws of any type that may be present along the length of a 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 (except as indicated in the amendment request regarding the application of a limited inspection scope in the tubesheet region). The applicable tube repair criteria, specified in TS 6.4.0.3, are the tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40-percent of the nominal wall thickness, shall be plugged, except if permitted to remain in service through application of the alternate repair criteria provided in TS 6.4.0.3.a.

The SG tubes function as an integral part of the reactor coolant pressure boundary (RCPB) and, in addition, isolate fission products in the primary coolant from the secondary coolant and the environment. For the purposes of this SE, SG tube integrity means that the tubes are capable of performing these safety functions in accordance with the plant design and licensing basis.

The General Design Criteria (GOC) in Appendix A to 10 CFR Part 50 provide regulatory requirements which state that the RCPB shall have "an extremely low probability of abnormal leakage...and gross rupture" (GOC 14), "shall be designed with sufficient margin" (GOCs 15 and 31), shall be of "the highest quality standards practical" (GOC 30), and shall be designed to permit "periodic inspection and testing...to assess...structural and leaktight integrity" (GOC 32).

Additionally, 10 CFR 50.55a specifies that components which are part of the RCPB must meet the requirements for Class 1 components in Section III of the American Society of Mechanical Engineers, Boiler and Pressure Vessel Code (ASME Code). Section 50.55a further requires, in part, that throughout the service life of a pressurized-water reactor (PWR) facility like Surry 1, ASME Code Class 1 components meet the requirements (except design and access provisions; and pre-service examination requirements in Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components") of the ASME Code to the extent practical. This requirement includes the inspection and repair criteria of Section XI of the ASME Code. The Section XI requirements pertaining to inservice inspection of SG tubing are augmented by additional requirements in the TSs.

As part of the plant-licensing basis, applicants for PWR licenses are required to analyze the consequences of postulated design-basis accidents (DBA) such as a SG tube rupture and a main steam line break (MSLB). These analyses consider primary-to-secondary leakage that may occur

- 4 during these events and must show that the offsite radiological consequences do not exceed the applicable limits of the 10 CFR Part 100 guidelines for offsite doses, GOC 19 criteria for control room operator doses, or some fraction thereof as appropriate to the accident, or the NRC-approved licensing basis (e.g., a small fraction of these limits). No accident analysis for Surry 1 is being changed because of the proposed amendment and, thus, no radiological consequences of any accident analysis are being changed. The proposed changes to TS 6.4.0 stay within the GOC requirements for the SG tubes and maintain the accident analysis and consequences that the NRC staff has reviewed and approved for the postulated OBAs for SG tubes.

The proposed amendment is applicable to refueling outage 22 and the subsequent operating cycle of Surry 1. This license amendment request is the same as those approved in 2008 for Surry 2 and other NPPs, but differs from previous one-cycle amendments related to SG tube inspections that were approved prior to 2008 for other units:

1)

The lowermost 4 inches of the tubesheet would not be excluded from the TS inspection requirements in TS 6.4.0.4.c. The lowermost 4 inches would be subject to the same inspection requirements as the rest of the tubing.

2)

Any flaws found in the lowermost 4 inches of the tubesheet would not always be excluded from requirements to plug. Under the proposed amendment, flaws found in the lowermost 4 inches of tubing would be subject to specific interim alternate repair criteria (IARC) in lieu of the aforementioned 40-percent depth-based criterion; the 40-percent criterion would continue to be applicable outside of the tubesheet region.

3)

The proposed amendment would apply to both the hot-leg and cold-leg sides of the tubesheet.

4)

The proposed amendment would include new reporting requirements to allow the NRC staff to monitor the implementation of the amendment. The proposed amendment would require the plugging of all tubes found with flaws in the upper 17 inches of the tubesheet region on both the hot-leg and cold-leg sides.

4.0 TECHNICAL EVALUATION

4.1 Proposed Changes to the TS The following specific changes to the TSs are proposed:

TS 6.4.0 - Steam Generator (SG) Program TS 6.4.0.3 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:

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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.

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 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.

This criterion should be revised to add the following section, as noted in italic type:

b.

For Unit I 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 ofthe 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 ofthe tUbe below 17 inches from the top ofthe tubesheet and above 1 inch from the

- 6 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 ofeach 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 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.

3.1.2 TS 6.6.A.3 - Steam Generator Tube Inspection Report TS 6.6.A.3 currently states:

3. Steam Generator Tube Inspection Report A report shall be submitted within 180 days after Tavg exceeds 200 of following completion of an inspection performed in accordance with the Specification 6.4.0, 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 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,

- 7 and the total of the 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 6.4.0.3.

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.

TS 6.6.A.3 is revised to add the following three additional reporting criteria:

I.

Following completion of a Unit I 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 ofthe 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 6.4.0.3,

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

n.

Following completion of a Unit I 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.

4.2 NRC Staffs Technical Evaluation The tube-to-tubesheet joint consists of the tube, which is hydraulically expanded against the bore of the tubesheet; the tube-to-tubesheet weld located at the tube end; and the tubesheet. The joint was designed as a welded joint and not as a friction or expansion joint. The weld itself was designed as a pressure boundary element. It was designed to transmit the entire end-cap pressure load during normal and DBA conditions from the tube to the tubesheet with no credit taken for the friction developed between the hydraulically expanded tube and the tubesheet. In addition, the weld serves to make the joint leak tight.

- 8 The one-cycle amendments approved for other plants (such as Vogt/e Electric Generating Plant and Braidwood Station) prior to 2008, exempted the lower 4-inch portion of the tube within the 21-inch-deep tubesheet from inspection and exempted tubes with flaw indications in this region from being removed from service (Le., plugged). These one-cycle amendments, in effect, redefined the pressure boundary at the tube-to-tubesheet joint as consisting of a friction or expansion joint with the tube hydraulically expanded against the tubesheet over the top 17 inches of the tubesheet. These amendments took no credit for the lower portion of the tube or the tube-to-tubesheet weld as contributing to the structural or leakage integrity of the joint.

The proposed request for Surry 1 (and similar amendments approved in 2008 for Wolf Creek, Vogtle, Braidwood, et al.) differs fundamentally from the one-cycle amendments approved prior to 2008 and is a more conservative approach because the lower 4-inch portion is no longer exempted. Additionally, the Surry 1 proposed request treats the tube-to-tubesheet joint as a welded joint in a manner consistent with the original design basis, with no credit taken for the friction developed between the hydraulically expanded tube and the tubesheet. The proposed request is intended to ensure that the aforementioned end-cap loads can be transmitted down the tube, through the tube-to-tubesheet weld, and into the tubesheet.

4.2.1 Proposed Change to TS 6.4.0.3, "Provisions for SG tube repair criteria" The 40-percent depth-based tube repair criterion in TS 6.4.0.3 is intended to ensure, in conjunction with other elements of TS 6.4.0, that tubes accepted for continued service (Le., not plugged) satisfy the performance criteria for structural integrity in TS 6.4.0.2.a and the performance criteria for accident leakage integrity in TS 6.4.0.2.b. The criterion includes an allowance for eddy current measurement error and incremental flaw growth prior to the next inspection of the tube. The proposed IARC are an alternative to the 40-percent depth-based criterion.

4.2.1.1 Structural Integrity Considerations The 40-percent depth-based criterion was developed to be conservative for flaws located anywhere in the SG, including free span regions. In the tubesheet, however, the tubes are constrained against radial expansion by the tubesheet and, therefore, are constrained against an axial (fish-mouth) rupture failure mode. The only potential structural failure mode within the tubesheet is a circumferential failure mode, leading to tube severance.

The proposed IARC would permit tubes with 1OO-percent through-wall flaws, in the portion of the tube from 17 inches below the TTS to 1 inch above the bottom of the tubesheet, to remain in service provided the circumferential component of these flaws does not exceed 203 degrees. The 203-degree criterion was determined by calculating the minimum tube cross-sectional area needed to resist both the limiting axial end-cap load and the pressure load on the flaw cross-section, using limit-load analysis, with the required TS structural integrity performance criteria safety factors. Because the 203-degree criterion was determined on this basis, the NRC staff finds this approach acceptable.

For the portion of the tube from the bottom of the tubesheet to 1 inch above the bottom of the tubesheet, the proposed IARC would permit tubes with 1OO-percent through-wall flaws to remain in service, provided the circumferential component of these flaws does not exceed 94 degrees.

This 94-degree criterion was determined by calculating the minimum tube-to-tubesheet weld

- 9 cross-sectional area needed to resist both the limiting axial end-cap load and the pressure load on the flaw cross-section, using limit-load analysis, with the required TS structural integrity performance criteria safety factors. A 203-degree crack in the tube wall immediately above the weld would concentrate the entire end-cap load on a 157-degree segment of the weld, and would result in an inadequate safety margin. A minimum 266-degree segment (Le., 360 degrees minus 94 degrees) of weld is needed to resist the end-cap load with adequate safety margin. Thus, the 94-degree criterion for the tube in the lowermost 1-inch region is required to ensure that the weld is not overstressed. Although the NRC staff did not complete its review on the specific limit-load methodology used to calculate the 94-degree criterion, the NRC staff did review the results of the stress analysis of the weld, which was performed to demonstrate that the weld complied with the stress limits of the ASME Code,Section III. The TS structural integrity performance criteria are intended to ensure the tube safety margins are consistent with the ASME Code,Section III stress limits. Based on a comparison of the calculated maximum design stress to the ASME Code-allowable stress, the NRC staff concludes that the proposed 94-degree criterion ensures that the weld can carry the end-cap loads with margins to failure consistent with the margins ensured by the ASME Code stress limits and is, therefore, acceptable.

The 203-degree and 94-degree criteria include an allowance for incremental flaw growth in the circumferential direction prior to the next inspection. The licensee states that no significant growth rate data exists for the specific case of circumferential cracking in the tUbesheet expansion region.

The licensee's growth rate estimate is based on a 95-percent upper bound value of available primary water stress corrosion crack (PWSCC) growth rate data for other tube locations. Given the lack of actual growth rate data for cracks that may potentially initiate in the lowermost 4 inches of the tube, the NRC staff attaches only a low level of confidence in the conservatism of the licensee's growth rate estimate. However, the NRC staff notes that the effect of any lack of conservatism in the licensee's estimate is mitigated to some extent by the fact that TS 6.4.QA.c requires inspections to be performed at Surry 1 during refueling outage 23 (fall 2010), should any crack indications be found during refueling outage 22 (spring 2009). In addition, the 203-degree and 94-degree criteria conservatively take no credit for the effects of friction in the tube-to-tubesheet joint. Any friction in the tube-to-tubesheet joint would reduce the amount of axial end-cap load that reaches the cracked tube cross-section. Thus, the NRC staff concludes that the 203-and 94-degree criteria are conservative, irrespective of growth rate uncertainties.

The 203-degree and 94-degree criteria do not include an explicit allowance for eddy current measurement error. The licensee will be utilizing an inspection technique that has been qualified for the detection of circumferential PWSCC in tube expansion transitions and in the tack expansion region just above the tube-to-tubesheet weld. The tack expansion is an approximately 1-inch long expansion of the tube in the tubesheet that is performed before the tube is hydraulically expanded for the entire depth of the tubesheet. A fundamental assumption behind the proposed 203-degree and 94-degree repair criteria is that all detected circumferential flaws in the lowermost 4 inches of the tube are 1OO-percent through-wall, irrespective of the actual flaw depth. With this assumption, the licensee referenced an Electric Power Research Institute (EPRI) sponsored study that indicated the eddy current measurement of the crack arc length was conservative (Le., larger than the actual crack size), and resulted in an estimate of the remaining cross sectional area that was always smaller than values obtained through direct measurement of cracks. Although the NRC staff has not reviewed the EPRI study in detail, it finds, based on the results of the study, that any uncertainties relating to measured arc length of the flaw are not expected to impair the conservatism of the 203-degree and 94-degree criteria.

- 10 The proposed IARC also accounts for the interaction effects of multiple circumferential flaws that are in close proximity. The proposed IARC treats multiple circumferential flaws located within 1 inch of one another as all occurring at the same axial location. The total arc length of the combined flaws is the sum of the individual flaw arc lengths, with overlapping arc lengths counted only once. The licensee stated that flaws located more than 17 inches below the TTS and more than 1 inch above the bottom of the tubesheet will be compared to the 203-degree criterion. If one flaw is located less than 1 inch from the bottom of the tubesheet and another flaw is within 1 inch of the first flaw (or if both flaws are within 1 inch of the bottom of the tubesheet) these flaws would be compared to the 94-degree criterion. Flaws located more than 1 inch apart are assumed to act independently of each other. This 1-inch criterion was determined using a fracture mechanics approach to determine the axial distance from an individual crack tip at which the stress distribution reverts to a nominal stress distribution for an uncracked section. The 1-inch criterion is twice the calculated distance since twice this distance is the necessary separation between two cracks for the cracks to act independently of each other. The NRC staff reviewed the basis for the 1-inch criterion and the fracture mechanics approach to determining the criterion. Since the criterion is based on a valid fracture mechanics approach, the NRC staff finds it acceptable.

The proposed IARC would permit tubes with axial cracks in the lowermost 4 inches of the tube to remain in service, irrespective of crack depth. The NRC staff finds this acceptable because axial cracks do not impair the ability of the tube or the weld to resist axial load and because the tube is fully constrained by the tubesheet against an axial failure mode.

Finally, the proposed IARC includes a requirement to plug all tubes in which flaws are detected in the upper 17-inch portion of the tube within the tubesheet. This adds to the conservatism of the 203-degree and 94-degree criteria since it mitigates any loss of tightness and, thus, any loss of friction between the tube and tubesheet due to flaws in the upper 17-inch region of the joint.

4.2.1.2 Accident Leakage Integrity Considerations If a tube is assumed to contain a 1OO-percent through-wall flaw some distance into the tubesheet, a potential leak path between the primary and secondary systems is introduced between the hydraulically expanded tubing and the tubesheet. Operational leakage integrity is assured by monitoring primary-to-secondary leakage relative to the applicable TS LCO limits in TS 3.1.C, "RCS Operational Leakage." However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBA to exceed the accident leakage performance criteria in TS 6.4.Q.2.b, including the leakage values assumed in the plant licensing basis accident analyses. The licensee states that this is ensured for Surry 1 by limiting primary-to-secondary leakage to 0.35 gallons per minute in the faulted SG during an MSLB accident.

The leakage path between the tube and tubesheet has been modeled by the licensee's contractor, WEC, as a crevice consisting of a porous media. Using Darcy's model for flow through a porous media, leak rate is proportional to differential pressure and inversely proportional to flow resistance. Flow resistance is a direct function of viscosity, loss coefficient, and crevice length.

WEC performed leak tests of tube-to-tubesheet joint mockups to establish loss coefficient as a function of contact pressure. WEC states that the flow resistance varies as a log normal linear function of joint contact pressure, but due to the large scatter of the flow resistance test data, has been assumed to be constant with joint contact pressure at a value which conservatively lower bounds the data.

- 11 Using the above model, a "modified B*" approach for calculating accident leakage was initially proposed in the licensee's request. The proposed modified B* approach relies to some extent on an assumed, constant value of loss coefficient, based on a lower bound of the data. This contrasts with the "nominal B*" approach which, in its latest form, is not directly impacted by the assumed value of loss coefficient since this value is assumed to be constant with increasing contact pressure between the tube and tubesheet. The NRC staff is not able to make a conclusion as to whether the assumed value of loss coefficient in the "modified B*" approach is conservative at this time. However, the NRC staff has performed some evaluations regarding the potential for the normal operating leak rate to increase under steam-line break conditions. Making the conservative assumption that loss coefficient and viscosity are constant under both normal operating and steam-line break conditions, the ratio of steam-line break leakage rate to normal operating leak rate is equal to the ratio of steam-line break differential pressure to normal operating differential pressure times the ratio of effective crevice length under normal operating conditions (INOP) to effective crevice length under steam-line break conditions (lsLB). Effective crevice length is the crevice length over which there is contact between the tube and tubesheet.

Using various values of (INOPt IsLB) determined from the "nominal B*" approach (which does not rely on an assumed value of loss coefficient) and recognizing the issues associated with some of these previous H*tB* analyses, the NRC staff concludes that a factor of 2.5 reasonably bounds the potential increase in leakage from the lowermost 4 inches of tubing that would be realized in going from normal operating to steam-line break conditions.

4.2.1.3 Regulatory Commitment The licensee stated in its October 14, 2008, license amendment request that it would apply the 2.5 factor in its condition monitoring (CM) and operational assessment (OA) upon implementation of the subject license amendment. Specifically, for the CM assessment, the licensee states that the component of leakage from the lowermost 4 inches for the most limiting SG during the prior cycle of operation will be multiplied by a factor of 2.5 and added to the total leakage from any other source and compared to allowable accident leakage limit. For the OA, the licensee stated that the difference in leakage from the allowable accident leakage limit and the accident leakage from other sources will be divided by 2.5 and compared to the observed (operational) leakage and that an administrative limit (for operational leakage) will be established to not exceed the calculated value. Since this properly addresses the factor of 2.5 that bounds the potential increase in leakage in the lowermost 4 inches of tubing, the NRC staff finds this acceptable.

In its letter dated February 20, 2009, the licensee submitted a regulatory commitment that stated the 2.5 factor would be used in the completion of its CM and OA upon implementation of the IARC in this amendment. This is an IARC because it applies only to Surry 1 refueling outage 22 and the subsequent operating cycle.

The NRC staff finds that reasonable controls for the licensee's implementation and subsequent evaluation of any changes to the regulatory commitment are provided by the licensee's administrative processes, including its commitment management program. The NRC staff has determined that the commitment does not warrant the creation of regulatory requirements, which would require prior NRC approval of subsequent changes. The NRC staff has agreed that NEI 99-04, "Guidelines for Managing NRC Commitment Changes" Revision 0, provides reasonable guidance for the control of regulatory commitments made to the NRC staff (Regulatory Issue Summary 2000-17, "Managing Regulatory Commitments Made by Power Reactor Licensees to the NRC Staff," dated September 21,2000). These commitments will be controlled

- 12 in accordance with the licensee's commitment management program in accordance with NEI 99-04. Any change to the regulatory commitments is subject to licensee management approval and subject to the procedural controls established at Surry 1 and 2 for commitment management in accordance with NEI 99-04, which include notification to the NRC. Also, the NRC staff may choose to verify the implementation and maintenance of these commitments in a future inspection or audit.

Based on this, the NRC staff concludes that the regulatory commitment addressed above for this amendment is acceptable.

4.2.2 Proposed Change to TS 6.6.A.3, "Steam Generator Tube Inspection Report" The NRC staff has reviewed the proposed new reporting reqUirements and found that they are sufficient to allow the NRC staff to monitor the implementation of the proposed amendment request. Therefore, the NRC staff finds that the proposed new reporting requirements are acceptable.

4.2.3 Considerations Relating to Tube-to-Tubesheet Welds NUREG-1431, "Standard Technical Specifications, Westinghouse Plants," Revision 3, and the Surry 1 TSs state specifically that the tube-to-tubesheet welds are not part of the tube. Therefore, the requirements of TS 6.4.0 do not apply to these welds. However, licensees typically visually inspect the tube ends (including the welds) for evidence of leakage while the SG primary manways are open to permit eddy current inspection of the tubes.

Eddy-current inspection of the SG tubes at Catawba Unit 2 in 2007, revealed indications interpreted as cracks at or near the tube-to-tubesheet weld, suggesting the potential for such cracks in similar SGs, such as those at Surry 1. An industry peer review was recently conducted for the Catawba Unit 22007, cold-leg tube-end indications to establish whether the reported indications are in the tube material or the welds. A consensus was reached that the indications most likely exist within the tube material. However, some of the indications extend close enough to the tube end that the possibility that the flaws extend into the weld could not be ruled out. The NRC staff and an expert consultant from Argonne National Laboratory also reviewed these indications and concluded that the industry's position was reasonable. The peer review group and the !\\IRC consultant also reviewed eddy-current signals from a tube-to-tubesheet mockup, which included a circumferential notch in one of the welds, and they concluded that this notch did not produce a detectable signal.

4.3 Summary Based on the above evaluation, the NRC staff finds that the proposed license amendment request, which is applicable only to refueling outage 22 and the subsequent operating cycle of Surry 1, ensures that SG tube structural and leakage integrity will be maintained during this period.

Structural safety margins consistent with the design basis and leakage integrity within assumptions employed in the licensing basis accident analyses will also be maintained.

Additionally, there will be no adverse impact on the ability of the tube-to-tubesheet welds to perform their safety-related function. Based on these findings, the NRC staff further concludes that the proposed amendment request meets 10 CFR 50.36 and, therefore, acceptable.

- 13 The current ToSs and the proposed amendment request do not address inspection requirements for the tube-to-tubesheet welds. There are no safety issues with respect to hypothetical cracks in the weld if it can be demonstrated, such as with the H*/B* strategies discussed in this SE, that the axial end-cap loads in the tube are reacted by frictional forces developed between the tJbe and tubesheet before any portion of the end-cap load is transmitted to the weld.

Currently, all industry requests for a permanent H*/B* amendment have been withdrawn; however, the industry is still pursuing development of the information needed by theNRC staff to support future amendment requests for H*/B*. The licensee has concluded that cracking exclusively in the weld is not a potential damage mechanism on the basis of the peer review findings. Should it not be possible for the NRC staff to approve an acceptable H*/B* amendment within a reasonable time period, it is the NRC staff's position that the industry will need to develop inspection techniques (e.g., visual, eddy-current) capable of detecting weld cracks to ensure that the welds are capable of performing their safety-related function. It should be noted that theNRC staff observed a demonstration of an available visual inspection technique for inspecting the welds, but raised questions on whether this technique was sufficiently reliable.

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Virginia State official was notified of the proposed issuance of the amendment The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes requirements with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff hcs determined that the amendment involves no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (73 FR 76414). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor: A. Johnson, NRR Date: April 8, 2009

April 8, 2009 Mr. David A. Christian President and Chief Nuclear Officer Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711 SU B..1 ECT:

SURRY POWER STATION, UNIT NO.1, ISSUANCE OF AMENDMENT REGARDII\\IG PROPOSED L1CEI\\ISE AMENDMENT REQUEST - INTERIM ALTERNATE REPAIR CRITERIA FOR STEAM GENERATOR TUBE REPAIR (TAC NO. MD9976)

Dear Mr. Christian:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 263 to Renewed Facility Operating License No. DPR-32 for the Surry Power Station, Unit NO.1 (Surry 1).

The amendment changes the Technical Specifications (TSs) in response to your application dated October 14, 2008, as supplemented February 20, 2009.

The amendment revises TS 6.4.Q, "Steam Generator (SG) Program," and TS 6.6.A.3, "Steam Generator Tube Inspection Report," to incorporate an interim alternate repair criterion into the provisions for SG tube repair for use during the Surry 1 2009 spring refueling outage (R-22) and the subsequent operating cycle.

A copy of the Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, IRA!

Donna N. Wright, Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-280

Enclosures:

1. Amendment No. 263 to DPR-32

2. Safety Evaluation cc w/encls: See next page DISTRIBUTION:

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