ML080350348

Issuance of Amendments No. 154 and 154, Revise Technical Specification 5.5.16, Containment Leakage Rate Testing Program (TAC Nos. MD5151 and MD5152)

ML080350348
Person / Time
Site:	Byron
Issue date:	02/12/2008
From:	Thorpe M NRC/NRR/ADRO/DORL/LPLIII-2
To:	Pardee C G Exelon Generation Co
Thorpe-Kavanaugh, Meghan, LPL3-1
Shared Package
ML080350289	List: ML080350348
References
TAC MD5151, TAC MD5152
Download: ML080350348 (22)

Text

February 12, 2008

Mr. Charles G. Pardee Chief Nuclear Officer and Senior Vice President Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

BYRON STATION, UNIT NOS. 1 AND 2 - ISSUANCE OF AMENDMENTS RE: REQUEST FOR AMENDMENT TO TECHNICAL SPECIFICATION 5.5.16, "CONTAINMENT LEAKAGE RATE TESTING PROGRAM" (TAC NOS. MD5151 AND MD5152)

Dear Mr. Pardee:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 154 to Facility Operating Li cense No. NPF-37 and Amendment No. 154 to Facility Operating License No. NPF-66 for the By ron Station, Unit Nos. 1 and 2, respectively. The amendments are in response to your application dated April 4, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070950418), as supplemented by letters dated October 10, 2007, and January 31, 2008 (ADAMS Accession Nos. ML072840458 and ML080320555, respectively).

The amendments revise TS 5.5.16, "Containment Leakage Rate Testing Program," to reflect a one-time, 5-year extension of the current containment Type A test (containment integrated leakage rate test (IRLT)) interval requirement, under Title 10 of the Code of Federal Regulations, Part 50, Appendix J, Option B, from 10 years to 15 years. The amendments allow the next Type A ILRT to be performed within 15 years of the most recent Type A test at Byron Station, but no later than February 19, 2013, for Unit No. 1 and no later than November 2, 2014, for Unit No. 2.

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,

/RA/

Meghan M. Thorpe-Kavanaugh, Project Manager Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket Nos. STN 50-454 and STN 50-455

Enclosures:

1. Amendment No. 154 to NPF-37

2. Amendment No. 154 to NPF-66

3. Safety Evaluation

cc w/encls: See next page

Pkg ML080350289 (Amendment ML080350348, TS Pgs ML080350396) *By SE dated 12/3/07 **By SE dated 2/4/08 NRR-058 OFFICE LPL3-2/PM LPL3-2/LA DRA/APLA DSS/SCVB DE/EMCB OGC LPL3-2/BC NAME MThorpe-Kavanaugh EWhitt MRubin* RDennig* KManoly** JRund NLO w/comments RGibbs DATE 2/11/08 2/11/08 12/03/07 12/03/07 02/04/08 2/ 8 /08 2/12/08 Byron Station, Unit Nos. 1 and 2

cc:

Corporate Distribution Exelon Generation Company, LLC via e-mail

Byron Distribution Exelon Generation Company, LLC via e-mail

Illinois Emergency Management Agency Division of Disaster Assistance &

Preparedness via e-mail

Mr. Dwain W. Alexander, Project Manager Westinghouse Electric Corporation via e-mail

Howard A. Learner Environmental Law and Policy Center of the Midwest via e-mail

Byron Senior Resident Inspector U.S. Nuclear Regulatory Commission via e-mail

Byron Resident Inspectors U. S. Nuclear Regulatory Commission via e-mail

Ms. Lorraine Creek RR 1, Box 182 Manteno, IL 60950

Chairman, Ogle County Board P.O. Box 357 Oregon, IL 61061

Mrs. Phillip B. Johnson 1907 Stratford Lane Rockford, IL 61107

Attorney General 500 S. Second Street Springfield, IL 62701

Chairman Will County Board of Supervisors Will County Boar d Courthouse Joliet, IL 60434

Mr. Barry Quigley 3512 Louisiana Rockford, IL 61108

EXELON GENERATION COMPANY, LLC DOCKET NO. STN 50-454 BYRON STATION, UNIT NO. 1 AMENDMENT TO FACILITY OPERATING LICENSE

Amendment No. 154 License No. NPF-37

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

A. The application for amendment by Exelon Generation Company, LLC (the licensee) dated April 4, 2007, as supplemented by letters dated October 10, 2007, and January 31, 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 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. Accordingly, the license is amended by 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-37 is hereby amended to read as follows: (2) Technical Specifications The Technical Specifications contained in Appendix A as revised through Amendment No. 154 and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

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

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Russell Gibbs, Chief Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operat ing License

Date of Issuance: February 12, 2008

EXELON GENERATION COMPANY, LLC DOCKET NO. STN 50-455 BYRON STATION, UNIT NO. 2 AMENDMENT TO FACILITY OPERATING LICENSE

Amendment No. 154 License No. NPF-66

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

A. The application for amendment by Exelon Generation Company, LLC (the licensee) dated April 4, 2007, as supplemented by letters dated October 10, 2007, and January 31, 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 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. Accordingly, the license is amended by 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-66 is hereby amended to read as follows: (2) Technical Specifications The Technical Specifications contained in Appendix A (NUREG-1113), as revised through Amendment No. 154 and the Environmental Protection Plan contained in Appendix B, both of which were attached to License No. NPF-37, dated February 14, 1985, are hereby incorporated into this license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

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

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Russell Gibbs, Chief Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operat ing License

Date of Issuance: February 12, 2008 ATTACHMENT TO LICENSE AMENDMENT NOS. 154 AND 154 FACILITY OPERATING LICENSE NOS. NPF-37 AND NPF-66 DOCKET NOS. STN 50-454 AND STN 50-455

Replace the following pages of the Facility Operating License and Appendix A A@ Technical Specifications with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert

License NPF-37 License NPF-37 License Page 3 License Page 3

License NPF-66 License NPF-66 License Page 3 License Page 3

TSs TSs 5.5-20 5.5-20 (4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulation set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at reactor core power levels not in excess of 3586.6 megawatts thermal (100 percent power) in accordance with the conditions specified herein.

(2) Technical Specifications The Technical Specifications contained in Appendix A as revised through Amendment No. 154 and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated

into this license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Deleted.

(4) Deleted.

(5) Deleted.

(6) The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the licensee's Fire Protection Report, and as approved in the SER dated February 1987 through Supplement No. 8, subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

Amendment No. 154 (3) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required;

(4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulation set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at reactor core power levels not in excess of 3586.6 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A (NUREG 1113), as revised through Amendment No.

154, and the Environmental Protection Plan contained in Appendix B, both of which were attached to License No. NPF 37, dated February 14, 1985, are hereby incorporated into this license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Deleted.

(4) Deleted.

(5) Deleted.

Amendment No. 154

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 154 TO FACILITY OPERATING LICENSE NO. NPF-37 AND AMENDMENT NO. 154 TO FACILITY OPERATING LICENSE NO. NPF-66 EXELON GENERATION COMPANY, LLC BYRON STATION, UNIT NOS. 1 AND 2 DOCKET NOS. STN 50-454 AND STN 50-455

1.0 INTRODUCTION

By application dated April 4, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070950418), as supplemented by letters dated October 10, 2007, and January 31, 2008 (ADAMS Accession Nos. ML072840458 and ML080320555, respectively),

Exelon Generation Company, LLC (Exelon, the licensee), requested an amendment to Appendix A, Technical Specifications (TS) of Facility Oper ating License Nos. NPF-37 and NPF-66 for Byron Station, Units 1 and 2 (Byron Station). The proposed amendment would revise TS 5.5.16, "Containment Leakage Rate Testing Program," to reflect a one-time, 5-year extension of the current containment Type A test (containment integrated leakage rate test (ILRT)) interval requirement from 10 years to 15 years. The proposed change would allow the next Type A ILRT to be performed within 15 years of the most recent Type A test at Byron Station but no later than February 19, 2013, for Unit No. 1, and no later than November 2, 2014, for Unit No. 2.

The supplemental letters provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's original proposed no significant hazards consideration determination as published in the Federal Register on June 5, 2007 (72 FR 31100).

2.0 REGULATORY EVALUATION

Paragraph 50.54(o) of Title 10 of the Code of Federal Regulations (10 CFR), and 10 CFR Part 50, Appendix J, Option B requires that a Type A test be conducted at a periodic interval based on historical performance of the overall containment system. The Type A test must be conducted (1) after a containment system has been completed and is ready for operation, and (2) at a periodic interval based on historical performance of the overall containment system.

Section V.B.3 of 10 CFR 50 Appendix J, Option B, requires that the regulatory guide or other implementation document used by a licensee to develop a performance-based leakage-testing program must be included, by general reference, in the plant technical specifications. Further, the submittal for TS revisions must contain justification, including supporting analyses, if the licensee chooses to deviate from methods approved by the Commission and endorsed in a regulatory guide.

Byron Station TS 5.5.16, "Containment Leakage Rate Testing Program," requires that leakage rate testing be performed as required by 10 CFR 50.54(o) and 10 CFR Part 50, Appendix J, Option B, as modified by approved exemptions, and in accordance with the guidelines contained in Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995. This RG endorses, with certain exceptions, Nuclear Energy Institute (NEI) report NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 26, 1995.

A Type A test is an overall ILRT of the containment structure. NEI 94-01 specifies an initial test interval of 48 months, but allows an extended interval of 10 years, based upon two consecutive successful tests. There is also a provision for extending the test interval an additional 15 months in certain circumstances. The most recent two Type A tests at the Byron Station have been successful, so the current interval requirement would normally be 10 years.

However, by the current application dated April 4, 2007, the licensee is seeking deviation from the NEI 94-01 guidelines by requesting a one-time extension of the Type A test interval from 10 years to 15 years based on historical performance of its containment supported by a risk-informed analysis. Specifically, the licensee is requesting a change to TS 5.5.16 which would add exceptions from the guidelines of RG 1.163 and NEI 94-01, Revision 0, regarding the Type A test interval. The exceptions state that for Byron Station:

The first Unit 1 Type A test performed after the February 19, 1998 Type A test shall be performed no later than February 19, 2013.

The first Unit 2 Type A test performed after the November 2, 1999 Type A test shall be performed no later than November 2, 2014.

The local leakage rate tests (Type B and Type C tests), including their schedules, are not affected by this request. The proposed TS change does not involve any other changes to licensing commitments or acceptance criteria.

3.0 TECHNICAL EVALUATION

The Byron Station containments are post-tensioned reinforced concrete structures with a carbon steel liner on the inside surface. Each containment consists of a cylindrical wall, a flat foundation mat, a shallow dome roof, and penetrations through the structure. The post-tensioning system consists of vertical and horizontal tendons in the cylinder wall and three-way tendons in the dome. The steel liner and its penetrations establish the leakage-limiting boundary of the containment. The post-tensioned reinforced concrete structures provide containment structural integrity. The leak-tight integrity of the containment penetrations (equipment hatch, airlocks, flanges, and sealing mechanisms) and isolation valves are verified through Type B and Type C local leak rate tests (LLRTs). The overall leak-tight integrity and structural integrity of the containment is verified through a Type A ILRT as required by 10 CFR 50, Appendix J. These tests are performed at the calculated peak containment internal pressure related to the design-basis loss-of-coolant accident. Under Option B, the two units at Byron Station currently have an ILRT interval of 10 years. By letter dated April 4, 2007, the licensee requested a one-time 5-year extension of the Type A test interval from 10 years to 15 years. The licensee justifies the proposed change based on historical plant-specific containment leakage testing program results and containment in-service inspection program (CISI) results, supported by a risk-informed analysis.

The leakage rate testing requirements of 10 CFR 50, Appendix J, Option B (Type A ILRT and Type B and Type C LLRTs), and the CISI requirements mandated by 10 CFR 50.55a together help ensure the continued leak-tight and structural integrity of the containment during its service life. Therefore, the staff requested information regarding the licensee's program for LLRTs, containment ISI and potential areas of weaknesses in the containment that may not be apparent in the risk assessment. The review of the Section 4.1 of Attachment 1 of the licensee's April 4, 2007, submittal warranted certain additional information. The information presented in the licensee's submittal, staff's requests for additional information (RAI) dated September 7, 2007 (ADAMS Accession No. ML072490143), and the licensee's supplemental responses in letters dated October 10, 2007, and January 31, 2008, are discussed and evaluated below.

3.1 Containment

ISI Program and Structural/Leak-Tight Integrity Considerations

The licensee stated that the results of previous Type A ILRTs performed at Byron Station, Units 1 and 2, demonstrate that the containment structure of each unit remains essentially a leak-tight barrier. The licensee presented the plant-specific results from the recent two previous Type A ILRTs for Unit No. 1 (August 1991 and February 1998) and Unit No. 2 (August 1993 and November 1999), which were successful. The most recent of these tests indicated a leakage rate of 0.065 and 0.071 percent weight per day for Unit Nos. 1 and 2, respectively, in comparison to the allowable containment leakage rate (0.75 La) of 0.075 percent weight per day. The licensee stated that License Amendment 147 for Byron Station, Unit Nos. 1 and 2, granted by the NRC on September 8, 2006, which fully implemented an alternative accident source term pursuant to 10 CFR 50.67, increased the acceptance criteria for allowable leakage rate (0.75 La) for all future ILRT results from less than 0.075 percent to less than 0.15 percent of containment air weight per day. This increase in the acceptance criteria for future ILRTs provides additional margin of assurance that the Byron Stat ion containment structures will continue to perform their design function following the design-basis accident.

The licensee also stated that adoption of Option B performance-based leakage testing program did not alter the basic test methods nor the acceptance criteria, but it did alter the test frequency of containment leakage testing in Type A, B, and C tests based on an evaluation which utilizes the as-found leakage history. The licensee stated that continued satisfactory results from the Type B and Type C LLRTs and containment inspections support the proposed extension of the Type A test interval. The initial test interval for Type B and Type C tests is 30 months but may be extended to 120 months for Type B tests and 60 months for Type C tests based on acceptable performance, established by passing two as-found LLRTs. Type B components whose test intervals are extended to more than 60 months are tested on a staggered basis for early detection of common mode failures. In question 1 to its September 10, 2007, RAI (RAI 1),

the staff requested the licensee to provide the current test intervals under Option B for the Type B and Type C LLRTs. The staff also requested a schedule for the Type B and Type C

tests on containm ent pressure-retaining boundaries that are or will be scheduled to be performed prior to and during the requested 5-year extension period.

In its response by letter dated October 10, 2007, the licensee provided, for each unit, a comprehensive table that identified all the penetrations subjected to Types B and C testing and their current test frequencies established under Option B based on performance. The licensee identified only one penetration (fuel transfer tube) in each unit with bellows. The licensee indicated that the test frequencies are re-evaluated after each refueling outage for potential changes. The licensee also provided the date of the last test and the date for the next scheduled test between now and the next ILRT. The tabular information provided by the licensee in its response indicates that each unit has approximately 59 penetrations that are subject to local leak rate tests. These penetrations are scheduled for testing as follows: 20 to 25 percent every refueling outage; 15 to 20 percent every alternate outage; 36 percent every third outage; 10 percent every fourth or sixth outage; 3 percent every 3 months, and 3 percent every 6 months.

Based on the information in the tables, it can be deduced that, for each unit, approximately 40 percent of the penetrations will be tested two or more times between now and the next proposed ILRT and the remaining w ill be tested at least one time. Thus, the response indicates that the performance of each of the c ontainment pressure boundary penetrations will be monitored by a Type B or Type C test at least once and about half of them two to three times during the requested extension period for the ILRT interval. The staff finds that the licensee is effectively implementing its Type B and Type C LLRT program under Option B in a rational and systematic manner that is consistent with industry standards and regulatory guidance, and will continue to do so during the requested ILRT interval extension period. Therefore, the response to RAI 1 is acceptable to the staff.

The licensee stated that the containments at Byron Station are examined by the Appendix J Visual Inspections program, CISI program, and Coatings Inspections program and discussed these programs in Section 4.1.3 of the submittal dated April 4, 2007.

The licensee stated that, as part of the 10 CFR 50 Appendix J Program, Byron Station performs visual inspections of accessible interior and exterior containment surfaces to uncover any evidence of structural deterioration that may affect containment structural and leak-tight integrity.

These examinations are conducted consistent with the requirements of 10 CFR 50 Appendix J Option B, RG 1.163, and NEI 94-01, prior to any Type A test, and during two refueling outages prior to the next Type A test, based on a 10-year frequency. The licensee stated that additional visual inspections are conducted in accordance with the requirements of American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code)Section XI, "Inservice

Inspection," Subsection IWE, "Requirements for Class NMC and Metallic Liners of Class CC Components of Light-Water Cooled Power Plants," and Subsection IWL, "Requirements of Class CC Concrete Components of Light-Water Cooled Power Plants." The licensee stated that the most recent visual inspections of accessible interior and exterior containment surfaces at Byron Station, completed in 2006 for Unit No. 1 and in 2004 for Unit No. 2, indicated that there were no structural problems that could affect containment structural leakage integrity.

In RAI 2 and RAI 3 of its September 10, 2007, letter, the staff requested the licensee to provide information with regard to how the licensee was implementing the general visual inspection requirements of 10 CFR 50, Appendix J, Option B. The staff requested the licensee to discuss its program, for Byron Station Unit Nos. 1 and 2, for visual inspections (with schedule and methods) that meet the guidelines contained in RG 1.163. The staff also requested the licensee to indicate, with reference to schedule, how it would supplement this 10-year interval-based visual inspections requirement for the requested 15-year ILRT interval to ensure a continuing means of early uncovering of evidence of containment structural deterioration.

In its response to RAI 2 and RAI 3, by letter dated October 10, 2007, the licensee stated that it is using the rigorous CISI program visual examinations pursuant to ASME Code,Section XI, Subsections IWL and IWE to satisfy the visual examination requirement in Regulatory Position C.3 of RG 1.163 for the performance-based Option B Containment Leakage Testing Program. Subsection IWE requires the licensee to perform general visual examinations of the liner and penetrations three times in a 10-year CISI interval. Subsection IWL requires the licensee to perform general visual examinations of the accessible concrete surfaces two times in a 10-year CISI interval. During the 15-year ILRT interval, this will result in three IWL visual examinations of the concrete surfaces and more than three IWE visual examinations of

accessible metallic containment surfaces for Byr on Station, Unit Nos. 1 and 2. Prior to performing an ILRT, the licensee will schedule its IWE and IWL examinations in a way that it is considered as a pre-ILRT examination. This process satisfies the intent and frequency of visual examinations required by Regulatory Position C.3 of RG 1.163 even for a 15-year ILRT interval.

The staff finds that the licensee's implementation of the visual examination program provides an acceptable level of quality and safety even for the 15-year ILRT interval. Therefore, the response to RAI 2 and RAI 3 are acceptable.

The licensee has stated that Byron Station has implemented a comprehensive CISI program in accordance with the frequency and requirements of the ASME Code,Section XI, Subsections IWE and IWL. The first CISI interval examinations at Byron Station were performed in accordance with the 1992 Edition and 1992 Addenda of the ASME Code,Section XI, Subsections IWE and IWL, as modified by 10 CFR 50.55a. In its response to RAI 4 to the staff's September 10, 2007, letter, the licensee clarified that the current (second) CISI intervals for both Byron Station units end on January 15, 2016. For the current (second) CISI interval, which includes the requested 5-year extension period, Byron Station is committed to the 2001 Edition and 2003 Addenda of the ASME Code,Section XI. The licensee stated that during these IWE/IWL inspections, various indications were identified that were either repaired, or documented and evaluated as acceptable by the Responsible Individual/Responsible Engineer, without compromising the structural integrity. In RAI 5 to the staff's September 10, 2007, letter, the staff requested the licensee to substantiate the statement made in the previous sentence by providing the historic highlights of plant-specific results of inspections/examinations performed on structures and components of the containment pressure boundary at Byron Station with significant findings and actions taken that demonstrate effective implementation of the CISI program in managing containment degradation and ensuring its structural and leak-tight integrity. The staff also requested the schedule of IWE/IWL exam inations that will be performed during the requested extension period.

In its response to RAI 5, by letters dated October 10, 2007, and January 31, 2008, the licensee

stated that the CISI examinations will continue to proceed in accordance with the schedule and requirements in Subsections IWE and IWL of the ASME Code,Section XI, 2001 Edition through 2003 Addenda during the requested extension period. The licensee provided a spreadsheet table summarizing the results of the CISI program inspections performed, in accordance with Subsections IWE and IWL, since 1998 to date (2006, 2007) for the first and the second CISI intervals, for Byron Station Unit Nos. 1 and 2. The table summarized the examination scope, method of examination, significant indications and actions taken during each period of the CISI interval for IWE examinations and each 5-year interval for the IWL examinations, and a corresponding date of the ISI summary report. Based on review of the table, the staff finds that the indications found were small and the corrective actions taken by the licensee were appropriate for managing the degradation. Therefore, the staff finds the response to RAI 5 acceptable.

Since bellows are another component for potential leakage, in RAI 6 to the staff's September 10, 2007, letter, the staff requested the licensee discuss if bellows were used on penetrations through containment pressure-retaining boundaries at Byron Station. If used, the licensee was requested to provide information on their location, inspection, testing, and operating experience with regard to detection of leakage through the penetration bellow.

In its response by letter dated October 10, 2007, the licensee stated that there is only one pressure-retaining boundary penetration in each unit at Byron Station that has bellows. This penetration is around the fuel transfer tube, and is in the fuel transfer canal between containment and the fuel handling building, which houses the spent fuel pool. These bellows are not regularly inspected. However, they are local leak-rate tested in accordance with 10 CFR 50, Appendix J. The licensee provided dates of the last completed test, next planned test, as well as the current test frequency in its response to RAI 1. The licensee stated that no leakage issues with these bellows have been identified at Byron Station

The licensee's response to RAI 6 identified that there was only one fuel transfer tube penetration that had bellows in each unit. These bellows are local leak-rate tested every sixth outage and no leakage issues have been identified so far with these bellows. Therefore, the response to RAI 6 addressed the staff's concern with regard to leakage through bellows and is acceptable.

Since management of degradation in inaccessible and uninspectable areas of the containment is an area of concern, in RAI 7 of the staff's September 10, 2007, letter, the staff requested the licensee to provide information regarding instances, if any, during implementation of the IWE/IWL CISI program at Byron Station where existence of or potential for degradation

conditions in inaccessible areas of the c ontainment stru cture and metallic liner were identified and evaluated based on conditions found in accessible areas as required by 10 CFR 50.55a(b)(2)(viii)(E) and 10 CFR 50.55a(b)(2)(ix)(A). If there were any instances of such conditions, the licensee was requested to discuss the findings and actions taken.

In its response by letter dated October 10, 2007, the licensee stated that there have been no conditions at Byron Station where existence of or potential for degradation conditions in

inaccessible areas of the containm ent structure and metallic liner were identified and evaluated based on conditions found in acce ssible areas as required by 10 CFR 50.55a(b)(2)(viii)(E) and 10 CFR 50.55a(b)(2)(ix)(A). The licensee added that the moisture barrier (MB) area has been recognized as an area susceptible to accelerated degradation and aging, as discussed in NRC Information Notice 97-10, "Liner Plate Corrosion in Concrete Containments." The licensee stated that several instances of containment MB degradation were identified in both Byron Station units, prior to the implementation of the IWE/IWL CISI program. As a result, the Unit No. 2 containment MB was completely replaced during the spring 2001 refueling outage. The Unit No. 1 containment MB was partially replaced during the fall 2000 refueling outage to address only the degraded areas, since the scope of degradation was small. Since the examination of the exposed liner plates directly behind the MB during the replacement activities revealed no liner plate degradation, no augmented examinations were required for Byron Station Unit Nos. 1 and 2. In addition, since no degradation was found in the exposed areas, no evaluation of inaccessible areas of the liner plate directly behind the MB was necessary.

The licensee's response to RAI 7 identified MB degradations in both units. As an appropriate corrective action, the moisture barrier was completely replaced for Unit No. 2 and the partial affected area was replaced for Unit No. 1. No liner plate degradation was found in these affected areas. The response established that no suspect areas of potential degradation in inaccessible and uninspectable areas of the containment have been revealed thus far based on the IWE/IWL examinations of accessible containment surfaces. Further, the licensee's risk analysis used the Calvert Cliffs Nuclear Power Plant's methodology to estimate the likelihood and risk implications of corrosion-induced leakage of the steel liners going undetected in inaccessible areas during the extended test interval. The increase in large early release frequency (LERF) associated with corrosion events was estimated to be insignificant, and is discussed in the Risk Assessment section of this safety evaluation. Therefore, the staff finds that this issue is adequately addressed and the response to RAI 7 to be acceptable.

The licensee stated that as part of the IWL-2520 examination of the post-tensioning systems, Exelon verified that the prestressing forces for the tendons selected for examination met the acceptance criteria for predicted forces. The licensee stated that a regression analysis using individual tendon lift-off forces measured during tendon surveillances, performed as recommended in NRC Information Notice 99-10, indicated acceptable margin for all tendons for the design life of Byron Station. The licensee concluded that the IWL and IWE program examinations have demonstrated that the structural integrity and leak-tightness of the Byron

Station containment have not been compromised. There will be no c hange to the CI SI program schedule as a result of the proposed changes.

With regard to the regression analyses of the tendon prestressing forces, in RAI 8 to the staff's September 10, 2007, letter, the staff requested the licensee to confirm if the analyses were based on individual tendon lift-off forces measured during tendon surveillanc es and indicate the number of surveillances from which data was used. The licensee was also requested to explain the reason why annual grease can inspections in areas susceptible to moisture intrusion is not being performed at Byron Station. The staff further requested the licensee to confirm if accessible grease caps are visually examined as part of the CISI programs at Byron Station as required by 10 CFR 50.55a(b)(2)(viii)(A).

In its response to RAI 8, by letter dated October 10, 2007, the licensee stated that the regression analysis was performed primarily from data obtained from the control tendon for each group (i.e.,

vertical, horizontal, and dome groups). Since the non-control tendons have not undergone more than two lift-off inspections, sufficient data is not available for non-control tendons to perform a regression analysis to predict future lift-off forces (i.e., more than two data points are required to identify a trend). Non-control tendon data was, however, considered in the analysis. A set of regression analyses was performed for the control tendons. The results of the regression analyses were then extended to the non-control tendons. Data from surveillance activities extending back to 1987 (i.e., the first surveillance) were used in t he regression analysis.

The licensee stated that annual examination of grease cans is not performed at Byron Station because there is not a history of identification of the existence of free water at specific tendon anchorage locations at Byron Station. However, Byron Station conducts visual examination of grease cans in the tendon tunnels on a 20-month frequency due to evidence of minor grease leakage at several locations. This examination frequency is used to identify leaking cans and allow corrective actions to be implemented in a timely manner to prevent significant loss of grease. Grease cans are examined for evidence of water leakage, grease leakage, and conditions that could indicate degradation of the anchorage components. The licensee further

stated that, as required by 10 CFR 50.55a(b)(2)(v iii)(A), grease caps inst alled at By ron Station are visually inspected during every surveillance with a 5-year frequency. Each of the grease caps in each unit is inspected for evidence of grease leakage, grease cap deformation, evidence of free water, and evidence of corrosion that challenges the capability of the grease cap to contain the grease.

Based on the response to RAI 8, the staff finds that the licensee performed the regression analysis of the tendon lift-off forces in a rational manner within the limitations of available data.

The response also indicates that licensee has an adequate program for examination of grease cans for evidence of water leakage, grease leakage and degradation of tendon anchorage components. The licensee is also performing visual inspections of the grease caps as required by the modification in 10 CFR 50.55a(b)(2)(viii)(A). Therefore, the staff finds the response to RAI 8 acceptable.

The licensee stated that it conducts periodic ins pections that meet RG 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants," quality assurance requirements of Service Level 1 coatings inside containment during each refueling outage at Byron Station, as required by the plant licensing basis and station procedures. Any localized areas of degraded coatings identified by these inspections are evaluated and repaired or replaced as necessary.

The licensee stated that recent inspections of containment coatings at Byron Station indicate that coatings were generally in a good condition. In some areas on the liner plate and other surfaces where indications of degraded coatings were observed, the licensee implemented measures to evaluate and repair the coating deterioration to an acceptable condition. The

inspection requirements of the containm ent coatings program will not be changed as a result of the requested ILRT interval extension.

In summary, the licensee has effectively implemented adequate LLRT, CISI and safety-related coatings inspection programs to periodically examine, monitor and manage age-related and environmental degradations of the Byron Station, Unit Nos. 1 and 2, containment structures.

The results of the past ILRTs and the CISI programs demonstrate that the structural and leak-tight integrity of the containment structures is sound and adequately managed. The

containment structures will continue to be periodically monitored by these pr ograms dur ing the requested 5-year extension period for the ILRT interval. Thus, the staff finds that there is

reasonable assurance t hat the contai nment structural and leak-tight integrity will continue to be maintained without undue risk to safety during the requested 5-year extension period for the ILRT interval. Therefore, the staff finds it acceptable to grant the requested one-time extension of the ILRT interval to 15 years for Byron Station, Unit Nos. 1 and 2. However, the staff notes that the dates for the next ILRT being approved by this TS amendment are not likely to coincide with a future refueling outage date. Therefore, the staff recommends that the licensee plan well ahead to conduct the next ILRT for Byron Stations, Unit Nos. 1 and 2, within the 15-year interval being approved without seeking further extensions.

3.2 Risk Impact Assessment

The licensee has performed a risk impact assessment of extending the Type A test interval to 15 years. The risk assessment was provided in the April 4, 2007, application for license amendment. In performing the risk assessment, the licensee considered the guidelines of NEI 94-01, the methodology used in Electric Power Research Institute (EPRI) Topical Report (TR)-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing," the NEI Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Surveillance Intervals, and RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis."

The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during the development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493, "Performance-Based Containment Leak-Test Program," provided the technical basis to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. To supplement this basis, industry undertook a similar study. The results of that study are documented in EPRI Research Project Report TR-104285.

The EPRI study used an analytical approach similar to that presented in NUREG-1493 for evaluating the incremental risk associated with increasing the interval for Type A tests. The Appendix J, Option A, requirements that were in effect for Byron Station early in the plants' life required a Type A test frequency of three tests in 10 years. The EPRI study estimated that relaxing the test frequency from three tests in 10 years to one test in 10 years would increase the average time that a leak, that was detectable only by a Type A test, goes undetected from 18 to 60 months. Since Type A tests only detect about 3 percent of leaks (the rest are identified during local leak-rate tests based on industry leakage rate data gathered from 1987 to 1993),

this results in a 10 percent increase in the overall probability of leakage. The risk contribution of pre-existing leakage for the pressurized-water reactor and boiling-water reactor representative plants in the EPRI study confirmed the NUREG-1493 conclusion that a reduction in the frequency of Type A tests from three tests in 10 years to one test in 20 years leads to an "imperceptible" increase in risk that is on the order of 0.2 percent and a fraction of one-person-rem (roentgen equivalent man) per year in increased public doses.

Building upon the methodology of the EPRI study and the NEI Interim Guidance, the licensee assessed the change in the predicted person-rem per year frequency. The licensee quantified the risk from sequences that have the potential to result in large releases if a pre-existing leak were present. Since the Option B rulemaking was completed in 1995, the staff has issued RG 1.174 on the use of probabilis tic risk assessment (PRA) in evaluating risk-informed changes to a plant's licensing basis. The licensee has proposed using RG 1.174 to assess the acceptability of extending the Type A test interval beyond t hat established dur ing the Option B rulemaking.

RG 1.174 provides risk-acceptance guidelines for assessing the increases in core damage frequency (CDF) and LERF for risk-informed license amendment requests. Since the Type A test does not impact CDF, the relevant criterion is the change in LERF. The licensee has estimated the change in LERF for the proposed change based on the cumulative change from the original frequency of three tests in a 10-year interval. RG 1.174 also discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. The licensee estimated

the change in the conditional containment failure probability for the proposed change to demonstrate that the defense-in-depth philosophy is met.

The licensee provided analyses, as discussed below. The following comparisons of risk are based on a change in test frequency from three tests in 10 years (the test frequency under Appendix J, Option A) to one test in 15 years. This bounds the impact of extending the test frequency from one test in 10 years to one test in 15 years. The following conclusions can be drawn from the analysis associated with extending the Type A test frequency:

1. Given the change from a three in 10-year test frequency to a one in 15-year test frequency, the increase in the total integrated plant risk is estimated to be about 0.1 person-rem per year or less for both units. This increase is comparable to that estimated in NUREG-1493, where it was concluded that a reduction in the frequency of tests from three in 10 years to one in 20 years leads to an "imperceptible" increase in risk. Therefore, the increase in the total integrated plant risk for the proposed change is considered small and supportive of the proposed change.

2. The increase in LERF resulting from a change in the Type A test frequency from the original three in 10 years to one in 15 years is estimated to be about 5.8 x 10-7 per year for the Byron Station units based on the unit-specific internal events PRA. This estimate assumes all non-LERF end states are assigned to EPRI Class 1 (intact containment), and as such are included as potential LERF contributors in the event of a large undetected leak pursuant to the NEI methodology. In fact, many of these Class 1 sequences would involve successful operation of containment sprays, in which case the potential for a pre-existing leak to result in a large release would be greatly reduced. Based on a separate assessment, the licensee estimates that 50 percent or more of the Class 1 frequency would involve operation of containment sprays, even after accounting for dependent operator action failures and hardware dependencies. Thus, the estimated increase in LERF reported above is conservative. There is also some likelihood that the flaws in the containment estimated as part of the Class 3b frequency would be detected as part of the IWE/IWL visual examination of the containment surfaces (as identified in ASME Code,Section XI, Subsections IWE/IWL). Visual inspections are expected to be effective in detecting large flaws in the visible regions of containment, and this would reduce the impact of the extended test interval on LERF. The licensee's risk analysis considered the potential impact of age-related corrosion/degradation in inaccessible areas of the containment shell on the proposed change. The increase in LERF associated with corrosion events is estimated to be less than 1 x 10

-8 per year for both units.

When the calculated increase in LERF is in the range of 10

-7 per year to 10

-6 per year, applications are considered if the total LERF is less than 10

-5 per year. The licensee estimates that the total LERF for internal and external events, including the requested change, was about 7.7 x 10

-6 and 9.5 x 10

-6 per year for Byron Station Units 1 and 2, respectively. Thus, the total LERF including the requested change would remain below 10

-5 per year. The LERF contribution from external events was determined based on a simplifying assumption that the LERF (i.e., the CDF and the fraction of core damage events contributing to LERF) for external events is comparable to that for internal events less the LERF contribution from interfacing-system loss-of-coolant-accidents and steam generator tube rupture events (since these types of events would not typically occur from an external event initiator). This assumption is reasonable and somewhat conservative since the results of the Individual Plant Examination of External Events (IPEEE) for Byron Station indicate that fire events are the dominant external-event risk contributor, and that the fire CDF as reported in the IPEEE is approximately one decade lower than the internal events CDF for all units. The LERF impact of the ILRT extension for external events was also assumed to be the same as that for internal events. This is also conservative given that the estimated LERF increase for internal events conservatively neglects the impact of containment spray operation on LERF, as discussed above. The staff concludes that increasing the Type A interval to 15 years results in only a small change in LERF and is consistent with the acceptance guidelines of RG 1.174.

3. RG 1.174 also encourages the use of risk analysis techniques to help ensure and show that the proposed change is consistent with the defense-in-depth philosophy. Consistency with the defense-in-depth philosophy is maintained if a reasonable balance is preserved between prevention of core damage, prevention of containment failure, and consequence mitigation. The licensee estimates the

change in the conditional containment failure probability to be an increase of approximately one percentage point for all units for the cumulative change of going from a test frequency of three in 10 years to one in 15 years. The staff finds that the defense-in-depth philosophy is maintained based on the small magnitude of the change in t he conditional containment failure probability for the proposed amendment.

Based on these conclusions, the staff finds that the increase in predicted risk due to the proposed change is within the acceptance guidelines, while maintaining the defense-in-depth philosophy, of RG 1.174 and, therefore, is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission

=s regulations, t he Illinois State official was notified of the proposed issuance of the amendment. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to installation or use of a facility's component located within the restricted area as defined in 10 CFR Part 20. 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

(72 FR 31100, June 5, 2007). 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.

6.0 CONCLUSION

The NRC staff concludes that the structural and leak-tight integrity of the Byron Station, Unit Nos. 1 and 2, containment structures is sound and adequately managed. Further, since the licensee has adequate LLRT and CISI programs in place that will continue to examine, monitor and manage potential degradations of the pressure-retaining components of the containments, there is reasonabl e assurance that t he containment stru ctural and leak-tight integrity will continue to be maintained if the ILRT interval is extended, as proposed, to 15 years.

Additionally, the NRC staff concludes that the increase in predicted risk due to the proposed change is within the acceptance guidelines, while maintaining the defense-in-depth philosophy, of RG 1.174. Therefore, the one-time extension of the ILRT interval to 15 years until the next Type A test and that the proposed change to Technical Specification 5.5.16 is acceptable at Byron Station, Unit Nos. 1 and 2.

However, the NRC staff notes that the dates for the next ILRT being approved by this TS amendment are not likely to coincide with a future refueling outage date. Therefore, the staff recommends that the licensee plan well ahead to conduct the next ILRT for Byron Station, Units 1 and 2, within the 15-year interval being approved without seeking further extensions.

Thus, 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 pr oposed manner, (2) such activities will be conducted in compliance with the Commission's r egulations, 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 Contributors: B. Lee R. Palla G. Thomas

Date: February 12, 2008