ML080310769

License Amendment, Allowed a One Time Type a Test Extension

ML080310769
Person / Time
Site:	Limerick
Issue date:	02/20/2008
From:	Peter Bamford NRC/NRR/ADRO/DORL/LPLI-2
To:	Pardee C Exelon Generation Co
Bamford, Peter J., NRR/DORL 415-2833
Shared Package
ml080310759	List: ML080310769 ML080310786 ML080310826
References
TAC MD5198, TAC MD5199
Download: ML080310769 (23)

Text

February 20, 2008 Mr. Charles G. Pardee Chief Nuclear Officer and Senior Vice President Exelon Generating Company, LLC 200 Exelon Way, KSA 3-E Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT RE: ONE TIME TYPE A TEST EXTENSION (TAC NOS. MD5198 AND MD5199)

Dear Mr. Pardee:

The Commission has issued the enclosed Amendment No. 190 to Facility Operating License No. NPF-39 and Amendment No. 151 to Facility Operating License No. NPF-85, for Limerick Generating Station, Units 1 and 2. These amendments consist of changes to the Technical Specifications (TSs) in response to your application dated February 20, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070530296), as supplemented by letters dated September 14, 2007, October 18, 2007 and December 20, 2007 (ADAMS Accession Nos. ML072600355, ML072920008 and ML073540557, respectively).

The amendments consist of changes to the TSs of each unit to allow a deferral of the next required Type A, containment integrated leak rate test to May 15, 2013, (Unit 1) and to May 21, 2014, (Unit 2). The changes reflect an extension of the test interval for each unit from 10 to 15 years.

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/

Peter Bamford, Project Manager Plant Licensing Branch 1-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-352 and 50-353

Enclosures:

1. Amendment No. 190 to License No. NPF-39

2. Amendment No. 151 to License No. NPF-85

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

February 20, 2008 Mr. Charles G. Pardee Chief Nuclear Officer and Senior Vice President Exelon Generating Company, LLC 200 Exelon Way, KSA 3-E Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT RE: ONE TIME TYPE A TEST EXTENSION (TAC NOS. MD5198 AND MD5199)

Dear Mr. Pardee:

The Commission has issued the enclosed Amendment No. 190 to Facility Operating License No. NPF-39 and Amendment No. 151 to Facility Operating License No. NPF-85, for Limerick Generating Station, Units 1 and 2. These amendments consist of changes to the Technical Specifications (TSs) in response to your application dated February 20, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070530296), as supplemented by letters dated September 14, 2007, October 18, 2007 and December 20, 2007 (ADAMS Accession Nos. ML072600355, ML072920008 and ML073540557, respectively).

The amendments consist of changes to the TSs of each unit to allow a deferral of the next required Type A, containment integrated leak rate test to May 15, 2013, (Unit 1) and to May 21, 2014, (Unit 2). The changes reflect an extension of the test interval for each unit from 10 to 15 years.

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/

Peter Bamford, Project Manager Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-352 and 50-353

Enclosures:

1. Amendment No. 190 to License No. NPF-39

2. Amendment No. 151 to License No. NPF-85

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

PUBLIC LPL1-2 R/F RidsNrrDorlLpl1-2 RidsNrrPMPBamford Rids NrrLAABaxter GHill,OIS (2) RidsNrrDorlDpr RidsNrrDeEmcb RidsNrrDssScvb RidsNrrDraAplb RidsNrrDirsItsb RidsOgcRp RidsRgn1MailCenter RidsAcrsAcnwMailCenter GThomas, NRR JBettle, NRR RPalla, NRR Package Accession Number: ML; ML080310759 Amendment Accession Number: ML080310769 ; Tech Specs for Amd 190: MLML080310769; Tec Specs for Amd 151: ML080310826

• by memo LPLI-2/PM LPLI-2/LA EMCB/BC SCVB/BC APLA/BC ITSB/BC OGC LPLI-2/BC Name PBamford ABaxter KManoly* RDennig* MRubin* GWaig CChandler HChernoff Date 1/30/08 2/6/08 01/25/2008 11/07/2007 11/07/2007 2/6/08 2/14/08 2/20/08 Official Record Copy

Christopher Mudrick Manager Licensing Site Vice President Exelon Generation Company, LLC Limerick Generating Station Correspondence Control Exelon Generation Company, LLC P.O. Box 160 3146 Sanatoga Road Kennett Square, PA 19348 Sanatoga, PA 19464 Correspondence Control Desk Ed Callan, Plant Manager Exelon Generation Company, LLC Limerick Generating Station 200 Exelon Way, KSA 1-N-1 Exelon Generation Company, LLC Kennett Square, PA 19348 3146 Santoga Road Sanatoga, PA 19464 Regional Administrator, Region I U.S. Nuclear Regulatory Commission Manager Regulatory Assurance - Limerick 475 Allendale Road Generating Station King of Prussia, PA 19406 Exelon Generation Company, LLC 3146 Sanatoga Road Senior Resident Inspector Sanatoga, PA 19464 U.S. Nuclear Regulatory Commission Limerick Generating Station Senior Vice President - Mid-Atlantic P.O. Box 596 Operations Pottstown, PA 19464 Exelon Generation Company, LLC 200 Exelon Way, KSA 3-N Library Kennett Square, PA 19348 U.S. Nuclear Regulatory Commission Region I Chief Operating Officer- Exelon Nuclear 475 Allendale Road Exelon Generation Company, LLC King of Prussia, PA 19406 4300 Winfield Road Warrenville, IL 60555 Director, Bureau of Radiation Protection Pennsylvania Dept. of Environmental Senior Vice President -Operations Support Protection Exelon Generation Company, LLC Rachel Carson State Office Building 4300 Winfield Road P.O. Box 8469 Warrenville, IL 60555 Harrisburg, PA 17105-8469 Vice President Chairman Licensing and Regulatory Affairs Board of Supervisors of Limerick Township Exelon Generation Company, LLC 646 West Ridge Pike 4300 Winfield Road Linfield, PA 19468 Warrenville, IL 60555 Dr. Judith Johnsrud Director, Licensing and Regulatory Affairs National Energy Committee Exelon Generation Company, LLC Sierra Club Correspondence Control 433 Orlando Avenue P.O. Box 160 State College, PA 16803 Kennett Square, PA 19348

Limerick Generating Station, Unit Nos. 1 and 2 cc:

J. Bradley Fewell, Esquire Associate General Counsel Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555 Mr. Charles G. Pardee Chief Nuclear Officer and Senior Vice President Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348

EXELON GENERATION COMPANY, LLC DOCKET NO. 50-352 LIMERICK GENERATING STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 190 License No. NPF-39

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

A. The application for amendment by Exelon Generation Company, LLC (the licensee), dated February 20, 2007 supplemented by letters dated September 14, 2007, October 18, 2007, and December 20, 2007, 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-39 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 190 , are hereby incorporated into this license. Exelon Generation Company 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 60 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/ra/

Harold K. Chernoff, Chief Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operating License Date of Issuance: February 20, 2008

ATTACHMENT TO LICENSE AMENDMENT NO. 190 FACILITY OPERATING LICENSE NO. NPF-39 DOCKET NO. 50-352 Replace the following page of the Facility Operating License with the revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert Page 3 Page 3 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert 6-14c 6-14c

EXELON GENERATION COMPANY, LLC DOCKET NO. 50-353 LIMERICK GENERATING STATION, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 151 License No. NPF-85

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

A. The application for amendment by Exelon Generation Company, LLC (the licensee), dated February 20, 2007 supplemented by letters dated September 14, 2007, October 18, 2007, and December 20, 2007, 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-85 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 151 , are hereby incorporated into this license. Exelon Generation Company 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 60 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/ra/

Harold K. Chernoff, Chief Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications and Facility Operating License Date of Issuance: February 20, 2008

ATTACHMENT TO LICENSE AMENDMENT NO. 151 FACILITY OPERATING LICENSE NO. NPF-85 DOCKET NO. 50-353 Replace the following page of the Facility Operating License with the revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert Page 3 Page 3 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert 6-14c 6-14c

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 190 TO FACILITY OPERATING LICENSE NO. NPF-39 AND AMENDMENT NO. 151 TO FACILITY OPERATING LICENSE NO. NPF-85 EXELON GENERATION COMPANY, LLC LIMERICK GENERATING STATION, UNITS 1 AND 2 DOCKET NOS. 50-352 AND 50-353

1.0 INTRODUCTION

By application dated February 20, 2007 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML070530296), as supplemented by letters dated September 14, 2007, October 18, 2007 and December 20, 2007 (ADAMS Accession Nos.

ML072600355, ML072920008 and ML073540557, respectively), Exelon Generation Company, LLC (Exelon, the licensee) requested changes to the Technical Specifications (TSs) for the Limerick Generating Station (LGS), Units 1 and 2. The proposed amendment would revise TS 6.8.4.g, Primary Containment Leakage Rate Testing Program, for each unit, to reflect a one-time extension of the Type A Integrated Leakage Rate Test (ILRT) interval from 10 years to 15 years.

The proposed changes would also extend the interval for performance of the drywell-to-suppression chamber bypass leak tests (DWBT). The supplements 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 or Commission) staff=s original proposed no significant hazards consideration determination as published in the Federal Register on August 14, 2007 (72 FR 45456).

2.0 REGULATORY EVALUATION

Pursuant to Title 10 of the Code of Federal Regulations, (10 CFR), Section 50.54(o) and 10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, a 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. LGS, Units 1 and 2, implemented Appendix J, Option B pursuant to License Amendments 118 and 81 issued January 24, 1997 (ADAMS Accession No. ML011560583). These regulations specify that the regulatory guide or other implementing documents used to develop a performance-based leakage testing program be included, by general reference, in the plants TS. Additionally, submittals for associated TS revisions are to contain justification, including supporting analyses, for deviations from methods approved by the Commission and endorsed in a regulatory guide. The LGS Units 1 and 2, TSs reference Regulatory Guide (RG) 1.163 Performance Based Containment Leak-Test Program, September 1995, for this purpose. RG 1.163 directs licensees intending to comply with Option B of Appendix J to establish test intervals based upon Nuclear Energy Institute (NEI) 94-01 Industry Guideline for Implementing Performance Based Option of 10 CFR 50 Appendix J, Revision 0, dated July 26, 1995. NEI 94-01 specifies an initial test interval of 48 months, but Enclosure

allows an extended interval of 10 years, based upon two consecutive successful tests. The most recent two Type A tests at LGS Unit 1 (1990, 1998) and Unit 2 (1993, 1999) have been successful, so the current interval requirement would normally be 10 years. However, by the current application letter dated February 20, 2007, the licensee is seeking deviation from the NEI 94-01 allowance 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. The proposed change would revise the LGS, Units 1 and 2, TS 6.8.4.g to reflect a one-time extension of ILRT interval to 15 years from the previous successful test as an approved deviation from the guidelines contained in RG 1.163.

The ILRT extension would also result in an extension of the interval for performance of the drywell-to-suppression chamber bypass leak tests (DWBT). LGS, Units 1 and 2, TS Surveillance Requirement 4.6.2.1.e requires these tests to be conducted to coincide with the Type A test. The safety evaluation for LGS License Amendments 118 and 81 also established the acceptability of concurrently extending the interval of the bypass leak tests to 10 years.

The licensees February 20, 2007 application cited, as precedents for the one time ILRT interval extension from 10 years to 15 years, the license amendments approved for Peach Bottom Atomic Power Station, Unit 3 (ADAMS Accession No. ML012210108), Three Mile Island Nuclear Station, Unit 1 (ADAMS Accession No. ML032050212), Vermont Yankee Nuclear Power Station (ADAMS Accession No. ML052000003), and Cooper Nuclear Station (ADAMS Accession No. ML062540024). In addition, similar license amendments involving the concurrent extension of drywell-to-suppression chamber bypass leakage test intervals for Susquehanna Steam Electric Station (ADAMS Accession No. ML020280102) and Clinton Power Station (ADAMS Accession No. ML033360470) were also considered.

3.0 TECHNICAL EVALUATION

3.1 Background The LGS, Units 1 and 2, containment system limits the release of radioactive materials to the environs subsequent to the occurrence of a postulated Loss-of-Coolant Accident (LOCA) so that the offsite doses are below the "reference values" stated in 10 CFR 100 and in the LGS Updated Safety Analysis Report, Section 6.2.1.1. The LGS, Units 1 and 2, containments are Mark II BWR pressure-suppression with a primary and secondary containment. The primary containment of each unit is a reinforced concrete structure with a 1/4 inch (in) thick carbon steel welded liner on the inside surface. There are also penetrations that pass through the containment pressure boundary. Each penetration consists of a pipe sleeve with an annular ring welded to it, and embedded in the concrete to resist normal operating and accident loads. The pipe sleeve is also welded to the liner plate as a seal to prevent leakage. The liner consists of several sections: the cylinder, dome, and floor that together result in a leak-tight barrier.

The LGS primary containment has a design pressure of 55 pounds per square inch gauge (psig). LGS TS 6.8.4.g contains a maximum allowable primary containment leakage rate limit of 0.5 percent of primary containment air weight per day at the peak calculated containment accident pressure of 44 psig.

The LGS Mark II pressure suppression containment design incorporates a drywell located over the suppression chamber (wetwell) and separated from the suppression chamber by a diaphragm slab. The suppression chamber contains a pool of water having a depth of between 22 ft and 24.25 ft during normal operation. Eighty-seven downcomers and 14 main steam

safety/relief valve (SRV) discharge lines penetrate the diaphragm slab and terminate at a pre-designed submergence within the pool. During a LOCA inside containment, the containment design directs steam from the drywell to the suppression pool via the downcomers through the pool of water to limit the maximum containment pressure to less than the design pressure. The effectiveness of the LGS pressure suppression containment requires that the leak path from the drywell to the suppression chamber airspace be minimized. Steam that enters the suppression pool airspace through the leak paths will bypass the suppression pool and can result in a rapid post-LOCA increase in containment pressure depending on the size of the bypass flow area.

The design value for leakage area is determined by analyzing a spectrum of LOCA break sizes.

For each break size there is a limiting leakage area. In determining the limiting leakage area, credit is taken for the capability of operators to initiate drywell and suppression pool sprays after a period of time sufficient for them to realize that there is a significant bypass leakage flow. The effect of suppression pool bypass on containment pressure response is greatest with small breaks. The design value of 0.0500 square feet for LGS represents the maximum leakage area that can be tolerated for that break size that is most limiting with respect to suppression pool bypass. LGS TS conservatively specify a maximum allowable bypass area limit of 10 percent of the design value of 0.0500 square feet. This TS limit thus provides an additional safety factor of 10 above the conservatisms taken in the steam bypass analysis. The DWBT verifies that the actual bypass flow area is less than or equal to the TS limit.

3.2 Risk Analysis The licensee has performed a risk impact assessment of extending the test interval for the Type A ILRT and the DWBT to 15 years. The risk assessment was provided in the February 20, 2007, application for license amendment. Additional analysis and information was provided by the licensee in its letter dated September 14, 2007. In performing the risk assessment, the licensee considered the guidelines of NEI 94-01, the methodology used in Electric Power Research Institute (EPRI) 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 Test Surveillance Intervals, and One-Time Extension of Containment Integrated Leak Rate Testing Interval - Additional Information, as well as 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 Type A 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 LGS 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 three percent of leaks (the rest are identified during local leak rate tests (LLRTs) 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 per year in increased public dose.

Building upon the methodology of the EPRI study and the NEI Interim Guidance, the licensee assessed the risk increase associated with extending the Type A test interval from 10 years to 15 years. The licensee quantified the risk from sequences that have the potential to result in large releases if a pre-existing containment leak were present. Since the Option B rulemaking was completed in 1995, the NRC staff has issued RG 1.174 on the use of probabilistic risk assessment (PRA) in evaluating risk-informed changes to a plants licensing basis. The licensee has proposed using RG 1.174 guidance to assess the acceptability of extending the Type A test interval beyond that established during the Option B rulemaking. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 1 x 10-6 per year and increases in large early release frequency (LERF) less than 1 x 10-7 per year. 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 amendment and 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 amendment to demonstrate that the defense-in-depth philosophy is met.

The licensee provided a separate assessment of the risk impacts associated with the DWBT interval extension. The assessment included both deterministic thermal hydraulic analyses to identify the impact of increased bypass leakage on containment pressure response for various scenarios, and a probabilistic assessment of the impact of increased bypass leakage on risk metrics. The deterministic analyses indicate that small break LOCA events with failure of drywell spray and emergency depressurization present the most significant challenge to containment in the event of significant bypass leakage. Also, some accident scenarios that are currently classified as early failures in the wetwell region of containment (and that do not contribute to LERF because the fission products are scrubbed by the suppression pool) have the potential to be re-categorized as LERF contributors if the bypass area is large enough to defeat the fission product scrubbing capabilities of the suppression pool.

The probability of a large pre-existing drywell-to-suppression chamber bypass leak was assumed to be the same as the equivalent category for the Type A evaluations. For small break LOCAs with failure of drywell spray and emergency depressurization, a large bypass leak was assumed to lead to containment over-pressure failure and subsequent core damage. (Drywell-to-suppression chamber bypass leakage was assumed to have no impact on containment performance if containment sprays operate or the reactor coolant system is depressurized, since the sprays would condense any steam that bypasses the suppression pool, and depressurization would direct releases into the suppression pool.) For events that were previously classified as early failures in the wetwell region, that portion impacted by bypass leakage was reassigned to EPRI accident classes associated with large containment isolation and containment bypass, and was assumed to contribute to LERF.

The results of this assessment show the risk impacts for the DWBT interval extension to be negligible, e.g., an increase in LERF of about 3 x 10-9 per year, and an increase in population dose and conditional containment failure probability of less than 0.1 percent. Accordingly, the risk impacts of extending the Type A test interval are representative of the risk impacts for the combined Type A and DWBT interval extension.

The licensee provided analyses, as discussed below, to support the interval extension. 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 discussion summarizes the analysis associated with extending the 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. 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 NRC staff concludes that the increase in the total integrated plant risk for the proposed change is small and supportive of the proposed change.

2. The increase in LERF resulting from a change in the test frequency from the original three in 10 years to one in 15 years is estimated to be about 4.3 x 10-8 per year based on the internal events PRA, and 1.7 x 10-7 per year when external events are included. There is some likelihood that the flaws in the containment estimated as part of the Class 3b frequency would be detected as part of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code, (ASME Code),Section XI, subsections IWE/IWL, visual examinations of the containment surfaces. 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 licensees 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.

When the calculated increase in LERF is in the range of 1 x 10-7 per year to 1 x 10-6 per year, applications are considered if the total LERF is less than 1 x 10-5 per year. The licensee estimates that the total LERF for internal and external events, including the requested change, is about 4.8 x 10-7 per year, which meets the total LERF criteria. The NRC staff concludes that increasing the Type A and DWBT test 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 percent for the cumulative change of going from a test

frequency of three in 10 years to one in 15 years. The NRC staff finds that the defense-in-depth philosophy is maintained based on the small magnitude of the change in the conditional containment failure probability for the proposed amendment.

Based on these conclusions, the NRC 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.

3.3 Deterministic Analysis The licensee provided their historical ILRT and LLRT maximum pathway results in their February 20, 2007 application and the supplemental information letter dated September 14, 2007. For Unit 1 this included data from years 1984, 1987, 1990 and 1998 and for Unit 2 from years 1989, 1993 and 1999. Review of this data shows LGS containment leakage has remained well below the respective acceptance limits and that there is no indication of any adverse trends. The most recent of these tests indicated a leakage rate of 0.3070 and 0.3272 weight percent per day for Units 1 and 2, respectively. The maximum allowable primary containment leakage rate is 0.50 weight percent per day. Based on the historical leak rate test results, it appears likely that the LGS containment leakage will remain well below the leakage limits during the requested 5 year extension of the ILRT interval.

The licensee also provided their historical data for drywell-to-suppression chamber bypass leakage tests performed during the same refueling outages as the ILRTs. The bypass leakage test data show the total effective leakage areas to be less than six percent of their limit. Again there was no discernable adverse trend apparent in this data. This suggests that the bypass leakages would also remain well below the associated limits during the five year extension in the test interval. Several potential bypass leakage pathways exist:

• Diaphragm floor penetrations (downcomers and SRV discharge lines)

• Diaphragm floor/liner cracks

• Downcomer and SRV discharge line pipe cracks in the suppression pool airspace

• Leakage through the four sets of drywell-to-suppression chamber containment vacuum breakers

• Seat Leakage of isolation valves in piping connecting the drywell and the suppression chamber air space The most probable leakage paths between the drywell and the suppression chamber are through the four sets of vacuum breakers. Each set consists of two vacuum breakers in series, flange mounted to a tee off the downcomers in the suppression chamber airspace.

LGS TS 4.6.2.1.f will continue to require the leakage test of these vacuum breakers each refueling outage that a DWBT is not performed with a limit of 24 percent of the total limit for bypass leakage area. This provides further assurance that no appreciable increase in the bypass leakage would go undetected during the interval extension Based on the information provided by the licensee and the conclusions of this deterministic analysis, the NRC staff finds the requested ILRT and DWBT interval extensions acceptable.

3.4 Containment Inservice Inspection (CISI) Program and Structural/Leak-Tight Integrity Considerations The overall leak-tight integrity and structural integrity of the primary containment is verified through a Type A ILRT, as required by 10 CFR Part 50, Appendix J. The leak tight integrity of the penetrations and isolation valves are verified through Type B and Type C LLRTs. These tests are performed at the design basis accident (DBA) pressure. In addition to the risk informed analysis previously discussed, the licensee justifies the proposed, one time, five-year extension of the type A test interval based on historical plant specific containment leakage testing program results (previously discussed) and CISI program results.

The leakage rate testing requirements of 10 CFR Part 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 NRC staff requested information regarding the licensees program for LLRTs, CISI and potential areas of weaknesses in the containment that may not be apparent in the risk assessment. The information presented in the licensees submittal, the NRC staffs requests for additional information (RAIs), and the licensees responses are discussed and evaluated below.

The licensee stated that industry experience has demonstrated that the Type B and Type C tests detect a large percentage of containment leakage. 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. An RAI was issued to the licensee (ADAMS Accession No. ML072140510) to provide the current test intervals under Option B for the Type B and Type C LLRTs. This RAI also requested a schedule for the Type B and Type C tests on containment 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 September 14, 2007, and supplemented by letter dated October 18, 2007, the licensee provided a comprehensive table for each unit that identified all the penetrations subjected to Type B and Type C testing and their current test frequencies that were established under Option B based on their performance. The licensee also identified the penetrations with non-metallic seals. The licensee indicated that the test frequencies are re-evaluated after each refueling outage for potential changes. The licensee also provided dates (refueling outages) that these tests are currently planned for between now and the next ILRT.

The tabular information provided by the licensee in its response indicates that each Unit has approximately 130 penetrations that are subject to local leak rate tests. Over 50 percent of these penetrations are tested every refueling outage (i.e., every 24 months). The remaining are currently tested at a frequency of 60 months. One Unit 2 penetration is being tested at a frequency of 120 months. The date information in the tables indicates that the implementation of the tests for the penetrations with 60-month frequencies are being staggered approximately every alternate outage, which means that they are actually being performed every 48 months in a staggered fashion. Based on the information in the tables, it can be deduced that the penetrations with the 24-month frequency will be tested three times between now and the next proposed ILRT. Of the penetrations with the 60-month frequency, approximately 40 percent will be tested two times and the remaining 60 percent will be tested at least one time between now and the next proposed ILRT. The one penetration with the 120-month frequency will be tested once prior to the next ILRT. Thus, the response indicates that the performance of each of the containment pressure boundary penetrations will be monitored by a Type B or Type C test at

least once and a majority of them two to three times during the requested extension period for the ILRT interval. Based on the information provided in response to the RAI, the NRC 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.

In Section 4.4 of the February 20, 2007 submittal, the licensee discussed its CISI program and recent inspection results. The licensee stated that the next CISI interval for LGS, Units 1 and 2, began on February 1, 2007, and complies with the 2001 edition through 2003 addenda of the ASME Code Section XI, subsections IWE and IWL. The first CISI interval examinations were performed in accordance of the 1992 edition with the 1992 addenda of the ASME Code Section XI.

The NRC staff requested that the licensee provide the following information with regard to how the general visual inspection requirements of 10 CFR 50 Appendix J, Option B were being implemented. Specifically, the NRC staff pointed out that Regulatory Position C.3 of RG 1.163 specifies that visual examinations should be conducted prior to initiating a Type A test, and during two other refueling outages before the next Type A test based on a 10-year ILRT interval.

The NRC staff requested that the licensee discuss the program, for LGS Units 1 and 2, for visual inspections (with schedule and methods) that meets this requirement. The staff also requested the licensee to indicate, with 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 by letter dated September 14, 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 LGS, Units 1 and 2. Prior to performing an ILRT, the licensee will schedule its IWE and IWL examinations in a way that it be 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 interval. Therefore, the NRC staff finds that the licensees implementation of the visual examination program provides an acceptable level of quality and safety even for the 15-year ILRT interval.

The licensee stated that the results of the most recent IWL inspections of the accessible areas of concrete completed during the tenth Unit 1 refueling outage (1R10) in 2004 revealed no reportable indications. The next IWL concrete containment inspections are scheduled to be completed prior to March 2009, in accordance with the requirements of the 2001 edition, 2003 addenda, of ASME Section XI, as modified by 10 CFR 50.55a. The licensee stated that results of the most recent Unit 2 IWL inspections of the accessible areas of concrete completed in refueling outage 2R08 (2005) also revealed no reportable indications. The next Unit 2 IWL concrete containment inspections are scheduled to be completed prior to March 2010, in accordance with the requirements of the 2001 edition, 2003 addenda, of ASME Section XI, as modified by 10 CFR 50.55a.

The licensee stated that the most recent Unit 1 IWE examinations have been completed (during the 1R11 refueling outage in March 2006) and found one recordable indication of a pit in the suppression pool steel liner. This pit was isolated from further corrosion by performing a qualified coating application. The remaining wall thickness under this pit was greater than the required design minimum wall thickness. The licensee added that one, other less severe pit, was similarly isolated previously. The licensee stated that the most recent Unit 2 IWE examinations have not identified any recordable indications; however, the suppression pool has not yet been inspected as part of the first period IWE inspections. This inspection is scheduled to be completed in 2R10 (2009). The licensee stated that there are no IWE augmented inspections required for either Unit 1 or Unit 2. There are also no relief requests being developed for this interval that will impact containment inspections. In order to understand the nature of the pitting degradation stated above, the NRC staff requested further information regarding the pits and the management of the degradation via letter dated December 13, 2007 (ADAMS Accession No. ML073410462).

In its response by letter dated December 20, 2007, the licensee stated that two spot corrosion locations on the submerged portion of the Unit 1 suppression chamber liner have been recoated.

At the time of recoating, the pits were measured as 119 mils deep (located in a floor panel) and 71 mils deep (located in a wall panel). The licensee noted that the coating application effectively isolates the bare steel substrate from both water and oxygen by establishing a tight bond with the substrate and adjacent tightly adhered coating, which arrests further progression of corrosion. The licensee added that subsequent inspections would detect a failure of the coating to arrest corrosion based on resulting cracks, blisters or de-lamination.

The licensee stated that the 0.25 inch thick liner of the concrete containment pressure vessel was of mild carbon steel material. The suppression chamber portion of the liner is coated with a sacrificial inorganic zinc protective coating. The licensee identified the cause of the pitting to be generalized corrosion due to permeation of water through portions of the protective coating and depletion of the sacrificial zinc. The licensee stated in their letter dated December 20, 2007, that the area will be re-inspected during the next inspection of the submerged space in accordance with Limerick Specification NE-101, Specification For coating and Liner Repair of the Suppression chamber at Limerick Generating Station Units 1 and 2.

The licensee discussed its design analysis that established the minimum wall thickness and maximum allowable wall metal loss criteria. The licensee selected a less severe metal loss threshold for applying a localized coating application to arrest further metal loss. This analysis addressed two degradation conditions: general (uniform) corrosion and pitting (localized) corrosion.

The licensee stated that the principal design code standard for original design of the 0.25 inch liner plate for the suppression pool is the ASME Code,Section VIII, Division I, 1968 edition with winter 1969 addenda, with certain identified exceptions. The load combinations used for the evaluation of the liner were the same as those used for the concrete containment. However, the acceptance criteria were based on allowable strain levels rather than on stress levels, since the liner is not relied upon to resist loads but must be able to withstand the strains experienced by the concrete. The acceptance criteria for the original design of the liner were: (i) strain in the liner should be less than 0.005 inch per inch; (ii) liner should not buckle under negative pressure; and (iii) the load carrying capacity of the anchorage should be adequate. To determine the minimum wall thickness criteria for general corrosion, these same criteria were used and the original evaluation re-performed assuming various levels of uniform corrosion of

the pool liner, using the degraded thickness in lieu of the original thickness, to determine if the three success criteria were met. The analysis concluded that, from the general corrosion point of view, the liner thickness could be as low as 0.12 inch (i.e., metal loss of 0.13 inch or 130 mils from nominal 0.25 inch original thickness) and would meet the original design acceptance criteria.

The licensee stated that since pitting (localized) corrosion was not evaluated as part of the original design basis of the liner, an evaluation was performed to determine the depth and diameter combination of a local pitted area that will meet the reinforcement rules of NE-3334 in ASME Code Section Ill, Division 1, Subsection NE, 1974 edition. The reinforcement rules allow missing material from the pit to be compensated by the excess material in the surrounding area adjacent to the pit within the limits of reinforcement. This evaluation considered the size and spacing between corrosion sites and the surrounding wall thickness. This evaluation, which established the acceptance criteria for visual examination of the liner surfaces, determined the pit depth threshold for applying a protective coating as 125 mils deep and for a pit to require a repair as 187.5 mils deep. This criteria is for a pitted area up to 12.5 inches in diameter with a surrounding wall thickness greater than 175 mils. The licensee stated that neither of the identified pits that were recoated, or any other pits, exceeded the threshold for applying a protective coating. The licensee stated that since LGS, Units 1 and 2, do not have any pits that are deeper than the owner-established visual examination acceptance criteria (per IWE-3510.2) for containment surfaces of 125 mils, no pits are required to be re-examined as Table IWE-2500, Category E-C items.

In the above response, the licensee addressed general and pitting corrosion degradations and established the acceptance criteria for general visual examination of the liner surfaces in a manner consistent with the original design basis and industry standards. The licensee established that the two isolated pits discussed above did not exceed the depth threshold for a coating application, but a coating application was performed anyway to arrest further progression of corrosion. The NRC staff finds that the pitting identified is generally minor and isolated, and the actions taken by the licensee in managing the degradation to be adequate.

In its letter dated December 20, 2007, the licensee stated that the steel liner is experiencing some minor corrosion and provided a summary table of the pits that have been identified in the suppression pool for both Units 1 and 2. The sacrificial zinc coating depleted in these areas leaving the steel liner exposed and subject to corrosion at those locations. For Unit 1, the licensee identified 12 pits on the wall and 5 pits on the floor that were 50 to 80 mils in depth, and one pit on the floor that was 119 mils deep. One of these pits on the wall (71 mils deep) and one on the floor (119 mils deep) were recoated, as discussed previously. For Unit 2, the licensee identified 13 pits on the floor that were 40 to 70 mils in depth.

The licensee stated that the station schedules the inspection of the submerged areas of the liner to be completed prior to the time when a pit depth is expected to exceed the coating application threshold. The method used for scheduling the inspections is a Preventative Maintenance (PM) task that is scheduled every 4 years. The station performs a technical evaluation to establish a corrosion rate that is applied to the known pits to determine the expected pit growth. The PM task may be deferred if the expected pit depth remains below the coating application threshold in the outage following the outage in which the PM task is presently scheduled. The licensee stated that the inspection results are evaluated in accordance with the LGS Maintenance Rule Implementation Program required by 10 CFR 50.65. The program ensures the primary containment liners, including its coating system, are capable of fulfilling their intended safety functions. Inspections are performed at a frequency sufficient to monitor the condition of the

liner and coating against established goals so as to provide reasonable assurance that the associated safety functions will be fulfilled. The licensee stated that the inspection program described above assures that the small corrosion sites in the suppression pool liner are being effectively managed and provides reasonable assurance that the leak-tight integrity of the suppression pool liner is maintained.

Based on the information provided, the NRC staff finds that the pitting corrosion identified in the suppression pool liners at LGS is generally minor, within the established threshold for a coating application, and the licensee has an adequate program as required by 10 CFR 50.65 to monitor and manage the degradation.

The NRC staff requested that the licensee describe, with schedule and methods, the ASME Section XI, subsections IWE/IWL, CISI program examinations that are or will be scheduled to be performed on containment pressure-retaining structures, systems and components prior to and during the requested 5-year extension period for LGS, Units 1 and 2. The NRC staff requested that this should include the licensees schedule and methods for examination and testing of seals, gaskets, moisture barriers and bolted connections associated with containment pressure boundary for both units. The NRC staff also requested the licensee indicate the dates when the most recent IWE examinations were completed for Unit 1.

In its response to this request, by letter dated September 14, 2007, the licensee stated that the LGS CISI Program examinations are scheduled to be performed in accordance with the requirements of ASME Section XI IWE (Class MC components) and IWL (Class CC components). For example, Exam Category E-A, Item No. E1.11, for the MC components, require a general visual examination be performed on 100 percent of the accessible surface areas during each inspection period, and Exam Category L-A, Item No. L1.11, for the CC components, require that a general visual examination be performed on all accessible surface areas once per 5 years.

The licensee stated that the 2001 edition with the 2003 addenda of ASME Section XI no longer requires that seals and gaskets be inspected. However, the Appendix J program still requires that leak rate testing be conducted on the applicable containment penetrations. The tables included in the licensee RAI response dated September 14, 2007, identify those penetrations with non-metallic seals.

The licensee further stated that LGS containment design does not have a moisture barrier, and therefore no inspection is performed. Containment bolted connection examinations will be performed for the second CISI Interval in accordance with ASME Section XI, Article IWE, as modified by 10 CFR 50.55a(b)(2)(ix)(H). Also, the most recent IWE examinations for Unit 1 were completed during the 1R11 refueling outage in March 2006.

The licensees response indicates that the examinations for the second CISI interval that began on February 1, 2007, will continue to proceed in accordance with the schedule in subsections IWE and IWL of the ASME Code Section XI, 2001 edition through 2003 addenda during the requested extension period. The 2001 edition through 2003 addenda of the ASME Section XI Code, subsection IWE, excluded examination requirements for seals and gaskets since these are non-metallic components that do not fall under its scope. However, the licensee has correctly stated that the penetrations with non-metallic seals and gaskets are tested under the local leak rate testing program and the licensee has explicitly identified these penetrations in the tables provided in the response letter dated September 14, 2007. The NRC staff finds that

these aspects of the LGS CISI program are being properly implemented and will therefore provide an appropriate monitoring program during the 5 year interval extension.

Since management of degradation in inaccessible and uninspectable areas of the primary containment is an area of concern, the NRC staff requested the licensee provide information of instances, if any, during implementation of the IWE/IWL CISI program at LGS Units 1 & 2 where existence of, or potential for, degradation conditions in inaccessible areas of the primary containment structure and metallic liners were identified. In its response, by letter dated September 14, 2007, the licensee stated that no conditions have been found on either Unit 1 or Unit 2 that required an evaluation of the condition of the inaccessible areas in accordance with either of these regulations. This gives reasonable assurance to the NRC staff that the inaccessible and uninspectible areas of primary containment will continue to provide their design basis function during the five year extension period.

In both the February 20, 2007 application and the September 14, 2007 RAI response, the licensee indicated that no bellows are used in penetrations through the containment pressure retaining boundary. This eliminates this potential leakage path from applicability to LGS.

The licensee stated, in its submittal, that LGS implements a safety-related coatings program that ensures qualified coating systems are used inside primary containment and the coating systems condition is monitored. It is implemented in accordance with the licensee commitments made in response to Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System After a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment, and monitored with a maintenance rule 10 CFR 50.65 condition monitoring program. The safety-related coatings program, as well as the ASME Section XI containment inspections, are intended to provide a high degree of assurance that any degradation of the containment structure is identified and corrected before a leakage path is introduced.

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 LGS, Units 1 and 2, primary containments. The results of the past ILRTs and the CISI programs demonstrate that the structural and leak-tight integrity of the primary containment structures is sound and adequately managed. The primary containment structures will continue to be periodically monitored by these programs during the requested 5-year extension period for the ILRT interval. Thus, the NRC staff finds that there is reasonable assurance that the containment 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 NRC staff finds it acceptable to grant the requested one-time extension of the ILRT interval to 15 years for LGS, Units 1 and 2.

4.0 STATE CONSULTATION

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

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no

significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (72 FR 45456). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

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

Principal Contributors: George Thomas Jerome Bettle Robert Palla Date: February 20, 2008