ML082530044

Issuance of Amendment Nos. 152 and 133 Steam Generator Tube Inspection Program (Tac Nos. MD9148 and MD9149)

ML082530044
Person / Time
Site:	Vogtle
Issue date:	09/16/2008
From:	Martin R Plant Licensing Branch II
To:	Tynan T Southern Nuclear Operating Co
Jervey, Richard 301-415-2728
Shared Package
ML082530013	List: ML082530044 ML082530055
References
TAC MD9148, TAC MD9149
Download: ML082530044 (23)

Text

September 16, 2008 Mr. Tom E. Tynan Vice President - Vogtle Vogtle Electric Generating Plant 7821 River Road Waynesboro, GA 30830

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT, UNITS 1 AND 2, ISSUANCE OF AMENDMENTS REGARDING STEAM GENERATOR TUBE INSPECTON PROGRAM (TAC NOS. MD9148 AND MD9149)

Dear Mr.Tynan:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 152 to Facility Operating License NPF-68 and Amendment No. 133 to Facility Operating License NPF-81 for the Vogtle Electric Generating Plant, Units 1 and 2 (VEGP). The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated June 27, 2008.

The amendments revise the combined VEGP Units 1 and 2 TS 5.5.9, Steam Generator (SG)

Program and TS 5.6.10, Steam Generator Tube Inspection Report, to incorporate a one-cycle interim alternate repair criterion in the provisions for SG tube repair criteria for VEGP Unit 2 during refueling outage 2R13 and the subsequent operating cycle.

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

Sincerely,

/RA/

Robert E. Martin, Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-424 and 50-425

Enclosures:

1. Amendment No. 152 to NPF-68

2. Amendment No. 133 to NPF-81

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

September 16, 2008 Mr. Tom E. Tynan Vice President - Vogtle Vogtle Electric Generating Plant 7821 River Road Waynesboro, GA 30830

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT, UNITS 1 AND 2, ISSUANCE OF AMENDMENTS REGARDING STEAM GENERATOR TUBE INSPECTON PROGRAM (TAC NOS. MD9148 AND MD9149)

Dear Mr.Tynan:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 152 to Facility Operating License NPF-68 and Amendment No. 133 to Facility Operating License NPF-81 for the Vogtle Electric Generating Plant, Units 1 and 2 (VEGP). The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated June 27, 2008.

The amendments revise the combined VEGP Units 1 and 2 TS 5.5.9, Steam Generator (SG)

Program and TS 5.6.10, Steam Generator Tube Inspection Report, to incorporate a one-cycle interim alternate repair criterion in the provisions for SG tube repair criteria for VEGP Unit 2 during refueling outage 2R13 and the subsequent operating cycle.

A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commissions next biweekly Federal Register notice.

Sincerely,

/RA/

Robert E. Martin, Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-424 and 50-425

Enclosures:

1. Amendment No. 152 to NPF-68

2. Amendment No. 133 to NPF-81

3. Safety Evaluation cc w/encls: See next page DISTRIBUTION: Public RidsAcrsAcnwMailCenter LPL2-1 R/F GHill (4 hard copies)

RidsNrrDorlLpl2-1 (MWong)

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RidsNrrDorlDpr RidsOgcRp AJohnson, DCI/CSGB Package No.: ML082530013 Amendment No.: ML082530044 Tech Spec No.: ML082530055 OFFICE NRR/LPL2-1/PM NRR/LPL2-1/LA OGC NRR/LPL2-1/BC NAME RJervey, REM for GLappert JBielecki Mwong DATE 8/21/08 9/9/08 8/28/08 9/16/08 OFFICIAL RECORD COPY

SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA VOGTLE ELECTRIC GENERATING PLANT, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 152 License No. NPF-68

1.

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

A.

The application for amendment to the Vogtle Electric Generating Plant, Unit 1 (the facility) Facility Operating License No. NPF-68 filed by the Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated June 27, 2008, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as 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 set forth in 10 CFR Chapter I; 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.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. NPF-68 is hereby amended to read as follows:

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 152, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 30 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

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

Attachment:

Changes to License No. NPF-68 and the Technical Specifications Date of Issuance: September 16, 2008

SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA CITY OF DALTON, GEORGIA VOGTLE ELECTRIC GENERATING PLANT, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 133 License No. NPF-81

1.

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

A.

The application for amendment to the Vogtle Electric Generating Plant, Unit 2 (the facility) Facility Operating License No. NPF-81 filed by the Southern Nuclear Operating Company, Inc. (the licensee), acting for itself, Georgia Power Company Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and City of Dalton, Georgia (the owners), dated June 27, 2008, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as 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 set forth in 10 CFR Chapter I; 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.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. NPF-81 is hereby amended to read as follows:

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 133, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 30 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

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

Attachment:

Changes to License No. NPF-81 and the Technical Specifications Date of Issuance: September 16, 2008

ATTACHMENT TO LICENSE AMENDMENT NO. 152 FACILITY OPERATING LICENSE NO. NPF-68 DOCKET NO. 50-424 AND TO LICENSE AMENDMENT NO. 133 FACILITY OPERATING LICENSE NO. NPF-81 DOCKET NO. 50-425 Replace the following pages of the Licenses 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. NPF-68, page 4 License No. NPF-68, page 4 License No. NPF-81, page 4 License No. NPF-81, page 4 TSs TSs 5.5-8 5.5-8 5.5-9 5.5-9 5.5-10 5.5-10 5.5-11 5.5-11 5.6-6 5.6-6 5.6-7

ENCLOSURE SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 152 TO FACILITY OPERATING LICENSE NPF-68 AND AMENDMENT NO. 133 TO FACILITY OPERATING LICENSE NPF-81 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

VOGTLE ELECTRIC GENERATING PLANT, UNITS 1 AND 2 DOCKET NOS. 50-424 AND 50-425

1.0 INTRODUCTION

By application dated June 27, 2008 to the U.S. Nuclear Regulatory Commission (NRC),

(Agencywide Documents Access and Management System (ADAMS) Accession No. ML081820196), Southern Nuclear Operating Company, Inc. (Southern Nuclear, the licensee),

requested changes to the Technical Specifications (TSs) for the Vogtle Electric Generating Plant, (VEGP) Units 1 and 2.

The request proposed changes to the requirements of TS section 5.5.9, ASteam Generator (SG)

Program,@ and to the reporting requirements of TS section 5.6.10, Steam Generator Tube Inspection Report. The proposed changes would establish alternate repair criteria for portions of the SG tubes within the tubesheet, and would be applicable to Unit 2 during Refueling Outage 13 (2R13) and the subsequent operating cycle.

In its letter dated June 27, 2008, the licensee submitted Westinghouse Electric Company (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, and 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. The topical reports contained information considered to be proprietary by Westinghouse Electric Company LLC and an application was included requesting that the NRC withhold the proprietary information from the public in accordance with Title 10 of the Code of Federal Regulations (10 CFR), paragraph 2.390.

The NRC staff letter of August 6, 2008 (ADAMS Accession No. ML081900681) determined that the submitted information sought to be withheld contains proprietary commercial information and should be withheld from public disclosure. There is no proprietary information in this safety evaluation (SE).

2.0 BACKGROUND

Vogtle Electric Generating Plant, Unit 2, has four Model F SGs designed and fabricated by Westinghouse. There are 5626 tubes in each SG, each with an outside diameter of 0.688 inches and a nominal wall thickness of 0.040 inches. The tubes are thermally treated alloy 600 and are hydraulically expanded for the full depth of the tubesheet (21.03 inches) 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 VEGP or other nuclear power plants in the United States. As a result, most plants, including VEGP, 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 VEGP, 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, which is less than the service experience that the SGs at VEGP have currently accumulated, with a comparable hot-leg operating temperature. The crack-like indications at Catawba were found in bulges (also called over-expansions) in the tubesheet region, in the tack expansion region, and near the tube-to-tubesheet weld. 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 in overexpansions (OXPs) during the spring 2005 Unit 1 refueling outage and reported three circumferential indications located at OXPs in two SG tubes in SG 4. In fall 2005, eddy current inspections were performed in two of the four Unit 2 SGs and no degradation was detected in the tubesheet region. The inspections focused on the upper 17 inches of the tube within the tubesheet, since the licensee concluded that flaws located below 17 inches from the TTS (i.e., in the bottom 4 inches of the tube within the tubesheet) had no potential to impair tube integrity. The NRC approved restricting the inspection and repair of tubes that were found to have flaws, to the upper 17 inches of the tube within the hot-leg tubesheet, in Amendment Nos. 138 and 117 (Units 1 and 2, respectively), on September 21, 2005. Amendment Nos. 138 and 117 applied to 1R12 (Spring 2005) and 2R11 (Fall 2005) and the subsequent operating cycle of each unit.

During the Fall 2006 Unit 1 refueling outage, VEGP again performed rotating coil inspections of OXPs within the tubesheet. The inspections focused on the upper 17 inches of the tube within the tubesheet, since the licensee concluded that flaws located below 17 inches from the TTS (i.e., in the bottom 4 inches of the tube within the tubesheet) had no potential to impair tube integrity. The NRC approved restricting the inspection and repair of tubes that were found to have flaws, to the upper 17 inches of the tube within the hot-leg tubesheet, in Amendment Nos. 146 and 126

(Units 1 and 2, respectively), on September 12, 2006. Amendment Nos. 146 and 126 applied to 1R13 (Fall 2006) and 2R12 (Spring 2007) and the subsequent operating cycle of each unit.

By letter dated November 30, 2007 (ADAMS Accession No. ML073380100), the licensee requested an amendment for VEGP that would make the inspection and repair modifications of Amendments 146 and 126 permanent and would add some additional reporting requirements under TS section 5.6.10, Steam Generator Tube Inspection Report. The permanent amendment request was based on a technical analysis approach, identified as H*/B*, that was also used as a basis for a permanent amendment request submitted by Wolf Creek Nuclear Operating Corporation (WCNOC) for the Wolf Creek Generating Station on February 21, 2006.

After three requests for additional information (RAIs) and several meetings with WCNOC, the NRC staff informed WCNOC during a phone call on January 3, 2008, that it had not provided sufficient information to allow the NRC staff to review and approve the permanent LAR.

Since the lack of information in the technical analysis mentioned above also affected VEGP, the licensee submitted a revised application on February 13, 2008. The revised application proposed to modify TS sections 5.5.9 and 5.6.10 with a more conservative interim alternate repair criteria (IARC) approach that was only applicable to 1R14 (Spring 2008) and 2R13 (Fall 2008), and the subsequent operating cycle for each unit. On March 10, 2008 (ADAMS Accession No. ML080710160), and March 18, 2008 (ADAMS Accession No. ML080710160), the NRC provided the licensee with seventeen questions, by electronic mail, regarding the February 13, 2008, LAR for VEGP. By letter dated March 21, 2008 (ADAMS Accession No. ML080850256), the licensee submitted a revision to the LAR dated February 13, 2008. The revision proposed having the more conservative IARC apply only to 1R14 and the subsequent operating cycle. The revised LAR was approved by the NRC on April 9, 2008 (ADAMS Accession No. ML080950247).

By letter dated June 27, 2008 (ADAMS Accession No. ML081820196), the licensee submitted the proposed LAR to have the more conservative IARC apply to 2R13 and the subsequent operating cycle.

3.0 REGULATORY EVALUATION

In 10 CFR 50.36, the Commission established its 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 rule does not specify the particular requirements to be included in a plants TSs. In 10 CFR 50.36(d)(5), administrative controls are stated to be "the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure 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.

The requirements for (1) SG tube inspections and repair, and (2) reporting on these inspections and repair for VEGP are in TS 3.4.17, Steam Generator (SG) Tube Integrity, and TS 5.5.9, and TS 5.6.10, respectively.

The technical specifications for all pressurized water reactor (PWR) plants require that an SG program be established and implemented to ensure that SG tube integrity is maintained. As stated by the licensee:

SG tube integrity is maintained by meeting specified performance criteria (in TS 5.5.9.b) for structural and leakage integrity, consistent with the plant design and licensing basis.

TS 5.5.9 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 5.5.9 also includes provisions regarding the scope, frequency, and methods of SG tube inspections. Of relevance to the amendment application, these provisions require that the number and portions of tubes inspected and methods of inspection shall 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 above regarding the one-cycle application of a limited scope of inspection in the tubesheet region]. The applicable tube repair criteria, specified in TS 5.5.9.c, are that tubes found by an inservice inspection (ISI) to contain flaws with a depth equal to or exceeding 40 percent of the nominal tube wall thickness shall be plugged.

The SG tubes function as an integral part of the reactor coolant pressure boundary (RCPB) and, in addition, serve to isolate radiological fission products in the primary reactor 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 (GDC) in Appendix A to 10 CFR Part 50 provide regulatory requirements in the GDC which state that the RCPB shall have an extremely low probability of abnormal leakage... and of 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 leaktight integrity" (GDC 32). To this end, 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 PWR facility like VEGP, 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.Section XI requirements pertaining to ISI 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 (DBAs) such as an SG tube rupture and main steam line break (MSLB). These analyses consider primary-to-secondary leakage which may occur 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, GDC 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

VEGP is being changed because of the proposed amendment and, thus, no radiological consequences of any accident analysis are being changed.

The licensee's proposed changes to TS 5.5.9 are to stay within the GDC requirements for the SG tubes and to maintain the accident analysis and consequences that NRC has reviewed and approved for the postulated DBAs for SG tubes. VEGP Amendment Nos. 117 and 126 modified the TS wording at VEGP to restrict the required inspection and plugging in the hot-leg tubesheet region to the uppermost 17 inches of the tubesheet region for 2R12 and the subsequent operating cycle. This excluded the lowermost 4 inches of the tubesheet on the hot-leg side from the TS inspection and plugging requirements. Amendment Nos. 117 and 126 also added a requirement that all tubes found with flaws in the upper 17 inches of the tubesheet region on the hot-leg side be plugged to provide added assurance that tube-to-tubesheet joint integrity would be maintained.

The proposed amendment is applicable to 2R13 and the subsequent operating cycle. This license amendment differs from Amendment Nos. 117 and 126 in a number of ways. First, the lowermost 4 inches of the tubesheet would no longer be excluded from the TS inspection requirements in TS 5.5.9.d. The lowermost 4 inches would be subject to the same inspection requirements as the rest of the tubing. Second, any flaws in the lowermost 4 inches of the tubesheet would not be excluded from requirements to plug. Under the proposed amendment, flaws found in the lowermost 4 inches of tubing would be subject to a specified alternate repair criterion (ARC) in lieu of the aforementioned 40 percent depth-based criterion; the latter criterion would continue to be applicable outside of the tubesheet region. Third, the proposed amendment applies to both the hot-and cold-leg sides of the tubesheet. Fourth, the proposed amendment would include new reporting requirements to allow the NRC staff to monitor the implementation of the amendment. As with Amendment Nos. 117 and 126 for the hot-leg side, 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-and cold-leg sides.

4.0 TECHNICAL EVALUATION

4.1 Proposed Changes to the TSs TS 5.5.9.c currently states:

1.

Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

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

depth-based criteria:

1.

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged

upon detection.

2.

For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the hot leg tubesheet shall be plugged upon detection.

3.

For Unit 1 during Refueling Outage 14 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 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 found in the tube exceeds 94 degrees, then the tube shall be removed from service.

When the circumferential components of each of the flaws are added, it is

acceptable to count the overlapped portions only once in the total of circumferential components.

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

c.

Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

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

1.

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged upon detection.

2.

For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

For Unit 1 during Refueling Outage 13 and the subsequent operating cycle, and for Unit 2 during Refueling Outage 12 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the hot leg tubesheet shall be plugged upon detection.

3.

For Unit 1 during Refueling Outage 14 and the subsequent operating cycle and for Unit 2 during Refueling Outage 13 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 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 found in the tube exceeds 94 degrees, then the tube shall be removed from service.

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

TS 5.6.10 currently states:

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, "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. Following completion of a Unit 1 inspection performed in Refueling Outage 14 (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 5.5.9.c.3;

i.

Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle), the primary to secondary LEAKAGE rate observed in each SG (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 SG) during the cycle preceding the inspection which is the subject of the report; and

j.

Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle), the calculated accident leakage rate from the portion of the tube below 17 inches from the top of the tubesheet for the most limiting accident in the most limiting SG.

TS 5.6.10 would be revised as follows, as noted in bold type:

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, "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. Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (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 5.5.9.c.3;

i.

Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (and any inspections performed in the subsequent operating cycle), the primary to secondary LEAKAGE rate observed in each SG (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 SG) during the cycle preceding the inspection which is the subject of the report; and

j.

Following completion of a Unit 1 inspection performed in Refueling Outage 14 (and any inspections performed in the subsequent operating cycle) and following completion of a Unit 2 inspection performed in Refueling Outage 13 (and any inspections performed in the subsequent operating cycle), the calculated accident leakage rate from the portion of the tube below 17 inches from the top of the tubesheet for the most limiting accident in the most limiting SG.

4.2 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.

The TS changes under Amendment Nos. 117 and 126 exempted the lower 4-inch portion of the tube within the 21-inch-deep tubesheet from an inspection and exempted tubes with flaw indications in this region from being removed from service (i.e., plugged). This amendment, 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. The amendment 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 amendment that is the subject of this SE differs fundamentally from Amendment Nos. 117 and 126 and is a more conservative approach. The proposed amendment 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 amendment 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 5.5.9.c, Provisions for SG tube repair criteria The 40 percent depth-based tube repair criterion in TS 5.5.9.c is intended to ensure, in conjunction with other elements of TS 5.5.9, that tubes accepted for continued service (i.e., not plugged) satisfy the performance criteria for structural integrity in TS 5.5.9.b.1 and the performance criteria for accident leakage integrity in TS 5.5.9.b.2. The criterion includes an allowance for eddy current measurement error and incremental flaw growth prior to the next inspection of the tube. The alternate tube repair criteria in the existing TSs and the proposed IARC in the proposed amendment are alternatives 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 up to 100 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 on the basis of the remaining cross-sectional area of the tube needed to resist the limiting axial end-cap load on the tube and the pressure load on the flaw cross-section, using limit-load analysis, with safety factors consistent with those required by the performance criteria for structural integrity in TS. 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 up to 100 percent through-wall flaws to remain in service provided the circumferential component of these flaws does not exceed 94 degrees. This criterion is based on the minimum tube-to-tubesheet weld cross-sectional area needed to resist the limiting axial end-cap load on the tube and the pressure load on the flaw cross-section, using limit load analysis, with safety factors consistent with those required by the performance criteria for structural integrity in the TS. A 203-degree crack in the tube wall immediately above the weld could potentially concentrate the entire end cap load to a 157-degree segment of the weld, whereas a minimum 266 degree segment (i.e., 360 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 intended to ensure that the weld is not overstressed. Although the NRC staff did not complete its review of the specific limit-load methodology used to calculate the 94-degree criterion, it reviewed 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 performance criteria for tube structural integrity are intended to ensure safety margins 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 stress limits and is, therefore, acceptable.

The 203-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 licensees 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 licensees growth rate estimate. However, the NRC staff notes that the effect of any lack of conservatism in the licensees estimate is mitigated somewhat by the fact that all of the SGs at VEGP will be inspected at 2R14, should any crack indications be found during 2R13. In addition, the 203-and 94-degree criteria conservatively take no credit for the effects of friction between the tube and tubesheet in any portion of the tube-to-tubesheet joint, in reacting out a portion of the axial end-cap load before it reaches the cracked cross-section. Thus, the NRC staff concludes that the 203-and 94-degree criteria are conservative, irrespective of growth rate uncertainties.

The 203-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-and 94-degree repair criteria is that all detected circumferential flaws in the lowermost 4 inches of the tube are fully 100% through wall, irrespective of the actual depth of the flaw. 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 (i.e., 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-and 94-degree repair criteria.

The proposed IARC also includes criteria to account for interaction effects for multiple circumferential flaws that are in close proximity. The proposed criteria treat the 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 flaw is the sum of the individual flaw arc lengths with overlapping arc lengths counted only once. The licensee stated that the summation of cracks with both located more than 17 inches from the TTS and more than 1 inch from the bottom of the tube will be compared to the 203-degree criterion. The summation of cracks with one flaw located less than 1 inch from the bottom of the tubesheet and the other within 1 inch of the first (or both flaws within 1 inch of the bottom of the tubesheet) would be compared to the 94-degree criterion.

Cracks 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. Because 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 lower most 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 would continue to include the current requirement, added by Amendment Nos. 117 and 126, 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-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 100 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 TX 3.4.13, RCS Operational Leakage. However, it must also be demonstrated that the proposed TS changes do not create the potential for leakage during DBAs to exceed the accident leakage performance criteria in TS 5.5.9.b.2, including the leakage values assumed in the plant licensing basis accident analyses. The licensee states that this is ensured for VEGP by limiting primary-to-secondary leakage to 0.35 gallon per minute in the faulted SG during an MSLB accident.

The leakage path between the tube and tubesheet has been modeled by the licensees contractor, Westinghouse, as a crevice consisting of a porous media. Using Darcys 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.

Westinghouse performed leak tests of tube-to-tubesheet joint mockups to establish loss coefficient as a function of contact pressure. Westinghouse 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.

Using the above model, a modified B* approach for calculating accident leakage was initially proposed in the amendment 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 (lNOP) 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 (lNOP/ lSLB) 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*/B* 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.

The licensee included a regulatory commitment in its June 27, 2008, LAR 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 lower 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 the 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.

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 has agreed that NEI 99-04, 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 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 the plant for commitment management in accordance with NEI 99-04, which include notification of 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 5.6.10, Steam Generator Tube Inspection Report The NRC staff has reviewed the proposed new reporting requirements and finds that they are sufficient to allow the NRC staff to monitor the implementation of the proposed amendment.

Based on this conclusion, the NRC staff finds that the proposed new reporting requirements are acceptable.

4.2.3 Licensee Issues Relating to Tube-to-Tubesheet Welds The STS and the VEGP TSs state specifically that the tube to tubesheet welds are not part of the

tube. Therefore, the requirements of TS 5.5.9 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 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 VEGP. An industry peer review was recently conducted for the Catawba Unit 2, 2007 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. An NRC staff member and an expert consultant from Argonne National Laboratory also reviewed these indications and concluded that the industrys position was reasonable. The peer review group and the NRC 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, which is applicable only to 2R13 and the subsequent operating cycle, ensures that SG tube structural and leakage integrity will be maintained during this period with structural safety margins consistent with the design basis and with leakage integrity within assumptions employed in the licensing basis accident analyses, and will have no adverse impact on the ability of the tube-to-tubesheet welds to perform their safety-related function. Based on this finding, the NRC staff further concludes that the proposed amendment meets 10 CFR 50.36 and, thus, the proposed amendment is acceptable.

The current TSs and the proposed amendment 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 Section 2 of this safety evaluation, that the axial end-cap loads in the tube is reacted by frictional forces developed between the tube and tubesheet before any portion of the end-cap load is transmitted to the weld.

Although the licensees request for a permanent H*/B* amendment has been withdrawn (see Section 2), the licensee and the industry are pursuing development of the information needed by the NRC 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 staffs 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 the NRC 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 Georgia State official was notified of the proposed issuance of the amendments. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 [and change surveillance requirements]. The NRC staff has determined that the amendments involve 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 amendments involve no significant hazards consideration, and there has been no public comment on such finding (73 FR 40394, July 14, 2008). Accordingly, the amendments meet 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 amendments.

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 amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor: A. Johnson Date: September 16, 2008