ML16229A113

Issuance of Amendments Regarding Extension of the Containment Integrated Leak Rate Test Intervals

ML16229A113
Person / Time
Site:	Catawba
Issue date:	09/12/2016
From:	Michael Orenak Plant Licensing Branch II
To:	Henderson K Duke Energy Carolinas
Orenak, M, NRR/DORL/LPLII-1, 415-3229
References
CAC MF7265, CAC MF7266
Download: ML16229A113 (33)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 Mr. Kelvin Henderson Site Vice President Catawba Nuclear Station Duke Energy Carolinas, LLC 4800 Concord Road York, SC 297 45 September 12, 2016

SUBJECT:

CATAWBA NUCLEAR STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS REGARDING EXTENSION OF THE CONTAINMENT INTEGRATED LEAK RATE TEST INTERVALS (CAC NOS. MF7265 AND MF7266)

Dear Mr. Henderson:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 286 to Renewed Facility Operating License No. NPF-35 and Amendment No. 282 to Renewed Facility Operating License No. NPF-52 for the Catawba Nuclear Station (CNS), Units 1 and 2, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated January 18, 2016, as supplemented by letter dated June 20, 2016.

The amendments revise TS 5.5.2, "Containment Leakage Rate Testing Program," to allow (1) an increase in the existing Type A Integrated Leakage Rate Testing Program test interval from 10 years to 15 years, in accordance with Nuclear Energy Institute (NEI) Topical Report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," and the conditions and limitations specified in NEI 94-01, Revision 2-A; (2) adoption of an extension of the containment isolation valve leakage testing (Type C) frequency from 60 months to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A; (3) adoption of the use of American National Standards Institute/American Nuclear Society (ANSl/ANS)-56.8-2002, "Containment System Leakage Testing Requirements"; and (4) adoption of a more conservative grace interval of 9 months for Type A, Type B, and Type C leakage tests, in accordance with NEI 94-01, Revision 3-A.

The amendments also make the following administrative changes: (1) deletion of the information regarding the performance of containment visual inspections as required by Regulatory Position C.3, as the containment inspections are addressed in TS Surveillance Requirement 3.6.1.1, and (2) deletion of the information regarding the performance of the next CNS, Unit 1, Type A test no later than November 13, 2015, and the next CNS, Unit 2, Type A test no later than February 6, 2008, as both Type A tests have already occurred.

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

If you have any questions, please contact me at 301-415-3229 or by e-mail at Michael. Orenak@n re. gov.

Docket Nos. 50-413 and 50-414

Enclosures:

1. Amendment No. 286 to NPF-35

2. Amendment No. 282 to NPF-52

3. Safety Evaluation cc w/enclosures: Distribution via Listserv Sincerely, MLvl~oJ_,

Michael D. Orenak, Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 DUKE ENERGY CAROLINAS. LLC NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION DOCKET NO. 50-413 CATAWBA NUCLEAR STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 286 Renewed License No. NPF-35

1.

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

A.

The application for amendment to the Catawba Nuclear Station, Unit 1 (the facility) Renewed Facility Operating License No. NPF-35, filed by Duke Energy Carolinas, LLC, acting for itself, and North Carolina Electric Membership Corporation (the licensees), dated January 18, 2016, as supplemented by letter dated June 20, 2016, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B.

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

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D.

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

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

2.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-35 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 286, which are attached hereto, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC, shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 120 days of issuance.

Attachment:

Changes to the License No. NPF-35 and the Technical Specifications FOR THE NUCLEAR REGULA TORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: September 12, 2016

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 DUKE ENERGY CAROLINAS. LLC NORTH CAROLINA MUNICIPAL POWER AGENCY NO. 1 PIEDMONT MUNICIPAL POWER AGENCY DOCKET NO. 50-414 CATAWBA NUCLEAR STATION. UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 282 Renewed License No. NPF-52

1.

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

A.

The application for amendment to the Catawba Nuclear Station, Unit 2 (the facility) Renewed Facility Operating License No. NPF-52, filed by Duke Energy Carolinas, LLC, acting for itself; North Carolina Municipal Power Agency No. 1; and Piedmont Municipal Power Agency (the licensees), dated January 18, 2016, as supplemented by letter dated June 20, 2016, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations as set forth in 10 CFR Chapter I; B.

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

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I; D.

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

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

2.

Accordingly, the license is hereby amended by page changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-52 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 282, which are attached hereto, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC, shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 120 days of issuance.

Attachment:

Changes to License No. NPF-52 and the Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: September 12, 2016

ATTACHMENT TO CATAWBA NUCLEAR STATION. UNITS 1AND2 LICENSE AMENDMENT NO. 286 RENEWED FACILITY OPERATING LICENSE NO. NPF-35 DOCKET NO. 50-413 AND LICENSE AMENDMENT NO. 282 RENEWED FACILITY OPERATING LICENSE NO. NPF-52 DOCKET NO. 50-414 Replace the following pages of the Renewed Facility Operating Licenses and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Licenses NPF-35, page 4 NPF-52, page 4 TSs 5.5-1 5.5-2 Licenses NPF-35, page 4 NPF-52, page 4 TSs 5.5-1 5.5-2 (2)

TECHNICAL SPECIFICATIONS The Technical Specifications contained in Appendix A, as revised through Amendment No. 286 which are attached hereto, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Technical Specifications.

(3)

Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation. Duke shall complete these activities no later than December 6, 2024, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71 (e)(4),

following issuance of this renewed operating license. Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

(4)

Antitrust Conditions Duke Energy Carolinas, LLC shall comply with the antitrust conditions delineated in Appendix C to this renewed operating license.

(5)

Fire Protection Program (Section 9.5.1, SER, SSER #2, SSER #3, SSER #4, SSER #5)*

Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report, as amended, for the facility and as approved in the SER through Supplement 5, subject to the following provisions:

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.

• The parenthetical notation following the title of this renewed operating license condition denotes the section of the Safety Evaluation Report and/or its supplement wherein this renewed license condition is discussed.

Renewed License No. NPF-35 Amendment No. 286 (2)

TECHNICAL SPECIFICATIONS The Technical Specifications contained in Appendix A, as revised through Amendment No. 282, which are attached hereto, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Technical Specifications.

(3)

Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation. Duke shall complete these activities no later than December 6, 2024, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50. 71 (e)(4),

following issuance of this renewed operating license. Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section (4)

Antitrust Conditions Duke Energy Carolinas, LLC shall comply with the antitrust conditions delineated in Appendix C to this renewed operating license.

(5)

Fire Protection Program (Section 9.5.1, SER, SSER #2, SSER #3, SSER #4, SSER #5)*

Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report, as amended, for the facility and as approved in the SER through Supplement 5, subject to the following provisions:

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.

• The parenthetical notation following the title of this renewed operating license condition denotes the section of the Safety Evaluation Report and/or its supplement wherein this renewed license condition is discussed.

Renewed License No. NPF-52 Amendment No. 282

5.0 ADMINISTRATIVE CONTROLS 5.5 Programs and Manuals Programs and Manuals 5.5 The following programs shall be established, implemented, and maintained.

5.5.1 Offsite Dose Calculation Manual (ODCM)

The ODCM shall contain the methodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm and trip setpoints, and in the conduct of the radiological environmental monitoring program.

Licensee initiated changes to the ODCM:

a.

Shall be documented and records of reviews performed shall be retained.

This documentation shall contain:

1.

sufficient information to support the change(s) together with the appropriate analyses or evaluations justifying the change(s), and

2.

a determination that the change(s) do not adversely impact the accuracy or reliability of effluent, dose, or setpoint calculations;

b.

Shall become effective after the approval of the Plant Manager or Radiation Protection Manager; and

c.

Shall be submitted to the NRC in the form of a complete, legible copy of the entire ODCM as a part of or concurrent with the Radioactive Effluent Release Report for the period of the report in which any change in the ODCM was made. Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (i.e., month and year) the change was implemented.

5.5.2 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01 Revision 2-A, dated October 2008.

(continued)

Catawba Units 1 and 2 5.5-1 Amendment Nos. 286/282

5.5 Programs and Manuals Programs and Manuals 5.5 5.5.2 Containment Leakage Rate Testing Program (continued)

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 14.68 psig. The containment design pressure is 15 psig.

The maximum allowable containment leakage rate, La. at Pa, shall be 0.3% of containment air weight per day.

Leakage Rate acceptance criteria are:

a.

Containment leakage rate acceptance criterion is~ 1.0 La. During the first plant startup following testing in accordance with this program, the leakage rate acceptance criteria are:::; 0.75 La for Type A tests and< 0.6 La for Type B and Type C tests.

b.

Air lock testing acceptance criteria for the overall air lock leakage rate is

~ 0.05 La when tested at:,, Pa For each door, the leakage rate is ~ 0.01 La when tested at:,, 14.68 psig.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

Nothing in these Technical Specifications shall be construed to modify the testing Frequencies required by 10 CFR 50, Appendix J.

5.5.3 Primary Coolant Sources Outside Containment This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The systems include Containment Spray, Safety Injection. Chemical and Volume Control, and Nuclear Sampling. The program shall include the following:

a.

Preventive maintenance and periodic visual inspection requirements; and

b.

Integrated leak test requirements for each system at refueling cycle intervals or less.

5.5.4 DELETED (continued)

Catawba Units 1 and 2 5.5-2 Amendment Nos. 286/282

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 286 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-35 AND AMENDMENT NO. 282 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-52 DUKE ENERGY CAROLINAS, LLC CATAWBA NUCLEAR STATION, UNITS 1 AND 2 DOCKET NOS. 50-413 AND 50-414

1.0 INTRODUCTION

By application dated January 18, 2016 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML16026A048), as supplemented by letter dated June 20, 2016 (ADAMS Accession No. ML16174A370), Duke Energy Carolinas, LLC (Duke Energy, the licensee) requested changes to the Technical Specifications (TSs) for the Catawba Nuclear Station (CNS), Units 1 and 2. The supplement dated June 20, 2016, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the staff's original proposed no significant hazards consideration determination as published the Federal Register on March 15, 2016 (81 FR 13839).

The proposed changes revise TS 5.5.2, "Containment Leakage Rate Testing Program," to allow (1) an increase in the existing Type A Integrated Leakage Rate Testing (ILRT) Program test interval from 10 years to 15 years, in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NE1 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" (ADAMS Accession No. ML12221A202), and the conditions and limitations specified in NEI 94-01, Revision 2-A (ADAMS Accession No. ML100620847); (2) adoption of an extension of the containment isolation valve leakage testing (Type C) frequency from 60 months to a 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A; (3) adoption of the use of American National Standards Institute/American Nuclear Society (ANSl/ANS)-56.8-2002, "Containment System Leakage Testing Requirements"; and (4) adoption of a more conservative grace interval of 9 months for Type A, Type B, and Type C leakage tests in accordance with NEI 94-01, Revision 3-A.

The proposed amendments also make the following administrative changes: deletion of the information regarding the performance of containment visual inspections as required by Regulatory Position C.3 as the containment inspections are addressed in TS Surveillance Requirement (SR) 3.6.1.1, and deletion of the information regarding the performance of the next CNS, Unit 1, Type A test no later than November 13, 2015, and the next CNS, Unit 2, Type A test no later than February 6, 2008, as both Type A tests have already occurred.

2.0 REGULATORY EVALUATION

2.1

System Description

The containment at CNS, Units 1 and 2, consists of a containment vessel and an enclosing reactor building with a 1.8-meter (m) (6 feet (ft)) annular space in-between. The reactor building provides environmental, as well as missile protection, for the containment vessel. The ice condenser is an annular compartment enclosing approximately 300 degrees of the upper containment. The ice condenser is designed to provide a large heat sink during a design-basis accident in the containment. A minimum of 967,060 kilograms (2, 132,000 pounds) of ice is stored in each condenser in ice baskets.

The containment vessels are freestanding, welded, cylindrical steel structures with hemispherical domes and flat circular bases. These vessels have a diameter of 35 m (115 ft) and an overall height of 52.2 m (171 ft 3 in). The reactor buildings are reinforced concrete structures with a diameter of 38.7 m (127 ft) and a wall thickness of 0.9 m (3 ft). The foundation is 41.8 m (137 ft) in diameter, with a thickness of 1.8 m [6 ft]. The containment shell in each unit is anchored to the reactor building foundation. The flat base of the containment vessel is a liner plate with thickness of 6.35 millimeter (mm) (0.25 in) and is anchored to the foundation of the reactor building. The base liner is used for leak-tight integrity only; no structural function is assumed. The containment at both units is designed for a leakage rate not to exceed 0.3 percent by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculated peak accident pressure.

2.2 Proposed Changes The requested change would revise TS 5.5.2 to require compliance with NEI 94-01, Revision 3-A, in lieu of Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," September 1995 (ADAMS Accession No. ML003740058), including listed exceptions. Additionally, the change would require compliance with the limitations and conditions specified in Section 4.0 of the safety evaluation for NEI 94-01, Revision 2-A.

CNS, Units 1 and 2, TS 5.5.2 currently states, in part:

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exceptions:

a. The containment visual examinations required by Regulatory Position C.3 shall be conducted 3 times every 10 years, including during each shutdown for SR 3.6.1.1 Type A test, prior to initiating the Type A test; and

b. NEI 94-01-1995, Section 9.2.3: The first Type A test performed after the November 14, 2000 (Unit 1) and February 7, 1993 (Unit 2) Type A test shall be performed no later than November 13, 2015 (Unit 1) and February 6, 2008 (Unit 2).

With the proposed change, CNS TS 5.5.2 would state, in part:

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J,"

Revision 3-A dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.

The license amendment request (LAR) follows NEI 94-01, Revision 3-A, and the limitations and conditions of Section 4.0 of the NEI 94-01, Revision 2-A, safety evaluation, and Section 4.0 of the NEI 94-01, Revision 3-A, safety evaluation. The licensee proposes an extension of the Type A test interval from 10-year intervals to 15 years from the last Type A test (June 2014 and November 2007 for CNS, Units 1 and 2, respectively). The approval of the amendment would allow the next Unit 1 and Unit 2 Type A tests to be performed no later than June 2029 and November 2022, instead of no later than June 2024 and November 2017, respectively, based on the current TS requirements. To extend the Type A test interval, NEI 94-01, Revision 3-A, provides a guideline that the extension shall be based on two consecutive successful Type A tests (i.e., performance history) and other requirements stated in Section 9.2.3, "Extended Test Intervals," of NEI 94-01, Revisions 2-A and 3-A. The U.S. Nuclear Regulatory Commission (NRC or the Commission) staff's review of the CNS Type A test performance history, with respect to meeting the Section 9.2.3 requirements and safety evaluation limitations and conditions, is presented in safety evaluation Section 3.2.1 of this safety evaluation.

The licensee also proposes an extension of the Type C test interval. For CNS, Units 1 and 2, Type C tests are currently required to be performed at no longer than a 60-month interval. The proposed amendment would extend the Type C test interval to no longer than 75-months from the last Type C test, with a permissible extension period of 9 months (total of 84 months) for non-routine emergent conditions, based on acceptable performance. The NEI 94-01, Revision 3-A, guidelines explain that extensions of Type C test intervals are allowed, based upon completion of two consecutive periodic as-found tests, where the results of each test are within a licensee's allowable administrative limits and other requirements stated in Section 10.2.3, "Type C Test Interval," in NEI 94-01, Revision 3-A. The NRC staff's review of the CNS Type C test performance history, with respect to meeting the Section 10.2.3 requirements and safety evaluation limitations and conditions, is presented in Section 3.2.2 of this safety evaluation.

2.3 Regulations and Guidance The regulations at Title 1 O of the Code of Federal Regulations (1 O CFR) 50.36(c)(5), "Technical Specifications," require, in part, the inclusion of administrative controls in TSs that are necessary to ensure operation of the facility in a safe manner. This license amendment requests a change to the "Administrative Controls" section of the CNS TSs.

The regulations in 1 O CFR 50.54(0) require that the primary reactor containments for water cooled power reactors shall be subject to the requirements set forth in Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," to 1 O CFR Part 50.

Appendix J to 1 O CFR Part 50 includes two options: Option A-Prescriptive Requirements, and Option B-Performance-Based Requirements, either of which can be chosen for meeting the requirements of Appendix J.

The testing requirements in Appendix J ensure that leakage through the primary containment and related systems and components penetrating primary containment does not exceed allowable leakage rate value specified in the TSs or associated bases, and that integrity of the containment structure is maintained during its service life.

The licensee has adopted and has been implementing Option B for meeting the requirements of Appendix J. Option B of Appendix J specifies the performance-based requirements and criteria for preoperational and subsequent leakage-rate testing. These requirements are met by (1) performance of Type A tests to measure the containment system's overall integrated leakage rate, (2) Type B pneumatic tests to detect and measure local leakage rates across pressure retaining leakage-limiting boundaries such as penetrations, and (3) Type C pneumatic tests to measure containment isolation valve leakage rates. After the preoperational tests, these tests are required to be conducted at periodic intervals based on the historical performance of the overall containment system (for Type A tests), and based on the safety significance and historical performance of each boundary and isolation valve (for Type B and Type C tests), to ensure the integrity of the overall containment system as a barrier to fission product release. The leakage rate test results must not exceed the allowable leakage rate with margin as specified in the TSs. Option B also requires that a general visual inspection for structural deterioration of the accessible interior and exterior surfaces of the containment, which may affect the containment leak-tight integrity, be conducted prior to each Type A test and at a periodic interval between tests, based on the performance of the containment system.

Section V.B.3 of 1 O CFR 50 Appendix J, Option B, requires that the RG or other implementation document used by a licensee to develop a performance-based leakage-testing program be included, by general reference, in the plant TSs. Furthermore, 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 an RG.

The implementation document that is currently referenced in TS 5.5.12 is RG 1.163. RG 1.163 endorsed Nuclear Energy Institute (NEI) TR 94-01, Revision O," dated July 21, 1995 (ADAMS Accession No. ML11327A025), as a document that provides methods acceptable to the NRC staff for complying with the provisions of Option B of 10 CFR 50, Appendix J, subject to four regulatory positions delineated in Section C of the RG. NEI 94-01, Revision 0, includes provisions that allow the performance-based Type A test interval to be extended for up to 1 O years, based upon two consecutive successful tests.

NEI 94-01, Revisions 2 and 3, were reviewed by the NRC and approved for use. The final safety evaluation for Revision 2, issued by letter dated June 25, 2008 (ADAMS Accession No. ML081140105), documents the NRC's evaluation and acceptance of Revision 2, subject to six specific limitations and conditions listed in Section 4.1 of the safety evaluation for Type A tests. The safety evaluation also states that the NRC staff agrees with methodology used in ANSl/ANS-56.8-2002 and accepts it as a reference for how licensees should perform the Type A, Type 8, and Type C tests. The final safety evaluation for Revision 3, issued by letter dated June 8, 2012 (ADAMS Accession No. ML121030286), includes two specific limitations and conditions listed in Section 4.0 of the safety evaluation for Type C tests. The approved versions of NEI 94-01, Revisions 2 and 3, incorporating the NRC staff's safety evaluations, were issued as NEI 94-01, Revision 2-A, and NEI 94-01, Revision 3-A, respectively. Consistent with the requested change, the licensee's submittal was reviewed against the limitations and conditions presented in the safety evaluations included in NEI 94-01, Revisions 2-A and 3-A.

3.0 TECHNICAL EVALUATION

3.1 Deterministic Considerations: Structural and Leak Integrity of the Containment 3.1.1 Historical Type A Test Results The maximum allowable containment leakage rate is 0.75 La, which is 0.3 percent of containment air weight per day at the peak calculated containment internal pressure for a design-basis loss-of-coolant accident.

In LAR Table 3.2.3-1, the licensee presented the historical results of the CNS, Unit 1, Type A tests as summarized below.

CNS Unit 1 ILRT Test Results As-Found Leakage As-Left Leakage Test Date

(% weioht per day)

(% weioht per day)

June 2014 0.057135 0.060505 November 2000 0.0965 0.0965 March 1991 0.06745 0.06745 November 1987 0.06141 0.05216 January 1984 N.A.

0.1115 In LAR Table 3.2.3-2, the licensee presented the historical results of the CNS, Unit 2, Type A tests as summarized below.

CNS Unit 2 ILRT Test Results As-Found Leakage As-Left Leakage Test Date

(% weight per day)

(% weight per day)

November 2007 0.127999 0.127999 February 1993 0.1461 0.1461 March 1989 0.0243 0.0243 July 1985 N.A.

0.1259 The results of the last two Type A ILRTs for CNS, Units 1 and 2, are less than the previous maximum allowable containment leakage rate of 0.3 percent of containment air weight per day.

The results show substantial margin has been maintained relative to the performance criterion, so the extended interval would be allowed by program guidance for CNS, Units 1 and 2. In addition, there is no trend toward increasing leakage rates that would suggest the performance criterion might be exceeded with the requested interval extension to 15 years.

Based on the above, the NRC staff concludes that since the last two Type A ILRTs for CNS, Units 1 and 2, were less than the design-basis leak rate and the guidelines in NEI 94-01, Revisions 2-A and 3-A, regarding acceptable performance history, has been met. The NRC staff concludes that the results of the Type A ILRTs provide reasonable assurance that containment overall leakage will be maintained below the design-basis leak rate, consistent with the requirements in TS 5.5.22, and will fulfill the requirements of 1 O CFR 50, Appendix J, Option B.

3.1.2 Historical Type B and Type C Test Results In LAR Table 3.3-1, the licensee presented the results of the CNS, Unit 1, Type Band Type C test combined as-found minimum pathway leakage totals as summarized below:

Refuel Outage and As-Found Minimum Pathway

% of TS 5.5.2 Combined Type B Year of Tests Leakage Rate (standard cubic and C Total Criterion (0.6La which centimeters per minute, seem) equates to 82,979 seem) 1EOC15, 2005 11709 14.1 1EOC16, 2006 11699 14.1 1 EOC17, 2008 10604 12.8 1EOC18, 2009 12867 15.5 1EOC19, 2011 9728 11.7 1 EOC20, 2012 9068 10.9 1 EOC21, 2014 5360 6.5 In LAR Table 3.3-1, the licensee presented the results of the CNS, Unit 1, Type Band Type C test combined as-found minimum pathway leakage totals as summarized below:

Refuel Outage and As-Found Minimum Pathway

% of TS 5.5.2 Combined Type B Year of Tests Leakage Rate (standard cubic and C Total Criterion (0.6La which centimeters per minute, seem) equates to 82,979 seem) 2EOC14, 2006 10346 12.5 2EOC15, 2007 13715 16.5 2EOC16, 2009 12626 15.2 2EOC17, 2010 13088 15.8 2EOC18, 2012 16350 19.7 2EOC19, 2013 6290 7.6 2EOC20, 2015 9103 11.0 The CNS TS 5.5.2 acceptance criterion for combined Type B and Type C test total is 0.6 La, which the LAR indicated as being 82,979 standard cubic centimeters per minute (seem). These totals were calculated using the as-found minimum pathway values. The NRC staff reviewed the Type B and Type C results and determined that these as-found minimum pathway totals for both CNS, Units 1 and 2, in the last two tests show substantial margin to the acceptance criterion, and there is no trend towards increasing leakage rates. This suggests that that performance criteria are unlikely to be exceeded by allowable extensions of Type C test intervals to 75 months.

Based on the above, the NRC staff concludes that since the Type Band Type C tests for CNS, Units 1 and 2, were less than the design-basis leak rate and the guidelines in NEI 94-01, Revisions 2-A and 3-A, regarding acceptable performance history, has been met. The NRC staff concludes that the results of the Type B and Type C tests provide reasonable assurance that as-found minimum pathway totals will be maintained below the design-basis leak rate consistent with the requirements in TS 5.5.2 and fulfill the requirements of 1 O CFR 50, Appendix J, Option B.

3.1.3 Containment Inspections The licensee stated that the third 10-year containment inservice interval for CNS, Units 1 and 2, began on November 15, 2005, and will errd November 4, 2025. The effective edition and addenda of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI, is the 2007 Edition through the 2008 Addenda.

Subsections IWE and IWL of the ASME Code,Section XI, contain inservice inspection (ISi) and repair and replacement rules for metal containment vessels (Class MC) and concrete containment vessels (Class CC), respectively. The reactor containments at CNS are freestanding structural steel containments, to which only the requirements of Subsection IWE apply. The IWE examination is used to identify and remedy degradation of the accessible surfaces of the containment liner to prevent loss of leak tightness of the barrier.

The licensee stated that examinations have been scheduled for the third inspection interval in accordance with ASME Code,Section XI, IWE-2411. In the LAR, the licensee specified the components exempted from this examination because they are outside containment. Vessels, parts, and appurtenances outside the containment boundary are exempted from the inspection plan. Embedded or inaccessible portions or those portions of the containment vessels, parts, and appurtenances that became inaccessible due to repair or replacement are also exempted.

In addition to the inspection specified by the ASME Code, the LAR lists additional owner-specified examinations to be performed at CNS, Units 1 and 2. These examinations include those resulting from licensee commitments, required by regulations, and deemed appropriate by the licensee. The licensee stated that it may remove, add, or modify only those items included by it in this list.

The licensee also conducts additional inspections that include general visual inspections of the steel containment vessel and the reactor shield building in accordance with the containment structural integrity inspection. These inspections are performed to satisfy:

(i) 10 CFR 50, Appendix J, Option A, which states, in part, in paragraph V.A:

Containment inspection: A general inspection of the accessible interior and exterior surfaces of the containment structures and components shall be performed prior to any Type A test to uncover any evidence of structural deterioration which may affect either the structural integrity or leak-tightness; (ii) 1 O CFR 50, Appendix J, Option B, which states, in part, in paragraph Ill.A:

Type A Test. A general visual inspection of the accessible interior and exterior surfaces of the containment system for structural deterioration which may affect the containment leak-tight integrity must be conducted prior to each test; and (iii)

ASME Code,Section XI, Subsection IWE, which states, in part: A general visual examination on Class MC components prior to each Type A test.

Conditions identified during previous inspections requiring ongoing monitoring are reexamined at successive general visual examinations during each inspection period by a qualified inspector to satisfy the requirements of the ASME Code,Section XI, Subsection IWE, Category E-A, Items E1.11 and E1.30. For example, several locations in the CNS, Unit 2, containment vessel interior surface accumulator A Room/34 degrees through 54 degrees, are monitored by ongoing containment inspections after the containment vessel was judged acceptable following partial removal of the moisture barrier.

The NRG staff reviewed the containment ISi program. In LAR Table 3.2.2-7, the licensee identified that general visual examinations of accessible surfaces of the containment vessel and moisture barriers for identification of structural problems are conducted in accordance with the CNS, Units 1 and 2, containment ISi program and schedule, which implement the requirements of ASME Code,Section XI, Subsection IWE, as required by 10 CFR 50.55a(g). LAR Table 3.2.2-8 lists the areas of the containment surfaces requiring augmented examinations following ASME Code,Section XI, Subsection IWE, Category E-C. The examinations include VT-1 visual and ultrasonic thickness measurements. Bolted connections receive a VT-1 visual examination following ASME Code,Section XI, Subsection IWE, Category E-G. The IWE inspections, in addition to owner-specified inspections and supplemental inspections, are used to satisfy the general visual examination requirements of 10 CFR 50, Appendix J, Option B, and monitor and manage the age-related degradation of the primary containment. The IWE inspections also monitor and manage the pressure retaining boundary of the containment vessel to ensure that containment structural integrity and leak-tight integrity are maintained through its service life.

Additionally, the NRC staff reviewed the ASME Code,Section XI, Subsection IWE, information and noted that the examinations have been completed successfully. No identified degradation or corrosion of the containment vessel in CNS, Units 1 and 2, has occurred. Problems identified in the past are included in the corrective action plan for licensee action and the ASME Code,Section XI, repairs were properly conducted and inspected by qualified inspectors. Areas requiring ongoing monitoring are reexamined at successive general visual examinations following ASME Code,Section XI, Subsection IWE, during each inspection period to ensure continued satisfactory performance.

Based on the review of containment ISi program and the IWE inspection results discussed above, the NRC staff concludes that there has been no evidence to date of significant degradation of CNS, Units 1 and 2, primary containments, and that any degradations have been entered into the CNS corrective action program and appropriately managed and/or corrected.

Based on the above evaluation, the NRC staff concludes that there is reasonable assurance that the licensee is adequately monitoring and managing age-related degradation of the CNS primary containment and the removal of TS 5.5.2.a is acceptable.

3.2 NRC Staff Evaluation of the Conditions and Limitations As discussed in Section 2.0 of this safety evaluation, and in accordance with the guidance in NEI 94-01, Revision 2-A, the licensee proposes to extend the containment Type A test interval from the current approved 1 O years to 15 years, based on acceptable performance. The NRC staff's evaluation of the proposed LAR against the limitations and conditions in NEI 94-01, Revision 2-A, is discussed in Section 3.3.1 of this safety evaluation.

As discussed in Section 2.0 of this safety evaluation, and in accordance with the guidance in NEI 94-01, Revision 3-A, the licensee proposes to extend the containment Type C test interval from the current approved 60 months to 75 months, with a permissible extension period of 9 months (total of 84 months) for non-routine emergent conditions, based on acceptable performance. The NRC staff's evaluation of the LAR against the limitations and conditions in NEI 94-01, Revision 3-A, is discussed below in Section 3.3.2 of this safety evaluation.

3.2.1 NRC Conditions in NEI 94-01, Revision 2-A In Section 4.1 of the NRC staff's safety evaluation for NEl-94-01, Revision 2, which is incorporated into TR NEI 94-01, Revision 2-A, the NRC staff concluded that the guidance in the TR is acceptable for reference by licensees proposing to amend their TSs to permanently extend the I LRT surveillance interval to 15 years, provided that six conditions are satisfied. The NRC staff evaluated whether the licensee addressed and satisfied these conditions for CNS, as applicable, as discussed below.

a. NRC Condition 1 NRC Condition 1 states: "For calculating the Type A leakage rate, the licensee should use the definition in the NEI TR 94-01, Revision 2, in lieu of that in ANSl/ANS-56.8-2002.

(Refer to SE [safety evaluation] Section 3.1.1.1 )."

The licensee states in Section 3.6.1 of the LAR that it will utilize the definition in NEI 94-01, Revision 2-A, Section 5.0. This approach is acceptable because the definition remains unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

Therefore, the NRC staff concludes that the licensee has addressed and satisfied NRC Condition 1.

b. NRC Condition 2 NRC Condition 2 states: "The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3)."

NEI 94-01, Section 9.2.3.2, "Supplemental Inspection Requirements," states that in order to provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test, if the interval of the Type A test is extended to 15 years.

The licensee provided the current schedule of containment inspections in the LAR Tables 3.2.2-1, 3.2.2-2, 3.2.2-3, 3.2.2-4, 3.2.2-5, and 3.2.2-6 for the second, third, and fourth containment ISi intervals. In the LAR Tables 3.2.2-7 through 3.2.2-10, the licensee provided the categories for the supplemental inspection of the containment vessel pressure retaining boundary, accessible surface areas, and moisture barriers that are required during each inspection period per ASME Code,Section XI, IWE Table IWE-2500-1.

The licensee's schedule of general visual examinations of accessible containment vessel surfaces results in at least three examinations between Type A tests and one examination immediately prior to the Type A test. This meets the requirements of the proposed revision to TS 5.5.2; the inspection requirements of ASME Code,Section XI, Subsection IWE; and NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2. The approach to use NEI 94-01, Revision 3-A, is acceptable because Sections 9.2.1 and 9.2.3.2 are identical in both revisions, and the licensee has submitted a schedule of inspections to be performed prior to and between Type A Tests. Therefore, the NRC staff concludes that the licensee has addressed and satisfied NRC Condition 2.

c.

NRC Condition 3 NRC Condition 3 states: "The licensee addresses the areas of the containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3)."

The licensee states that it will continue to perform general visual observations of the accessible interior and exterior surfaces of the containment structure in accordance with containment structural integrity test procedures to meet the requirements of the proposed revision to TS 5.5.2; the inspection requirements of ASME Code,Section XI, Subsection IWE; and NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2. The NRC staff concludes that the use of NEI 94-01, Revision 3-A, is acceptable because Sections 9.2.1 and 9.2.3.2 are identical in both revisions and address containment structure areas that are potentially subject to degradation. Therefore, the NRC staff concludes that the licensee has addressed and satisfied NRC Condition 3.

d. NRC Condition 4 NRC Condition 4 states: "The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4)."

The licensee indicated in the LAR that CNS, Unit 1, steam generators were replaced in 1996 using the equipment hatch and that the CNS, Unit 2, steam generators are original and that there are no planned modifications that would require a Type A test. Therefore, the licensee addressed and satisfied NRC Condition 4.

e. NRC Condition 5 NRC Condition 5 states: "The normal Type A test interval should be less than 15 years. 1 If a licensee has to utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to SE Section 3.1.1.2)."

The previous Type A ILRTs were performed in June 2014 (Unit 1) and in November 2007 (Unit 2). The licensee stated in its LAR that the next Type A ILRT would be performed in 2022 (Unit 2).

Extending the ILRT interval beyond 15 years does not apply to this LAR as the licensee only submitted a request for an extension up to 15 years. However, in the event that an extension beyond 15 years is desired, the licensee would need prior NRC approval by an LAR consistent with the staff position in Regulatory Issue Summary (RIS) 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 1 O CFR Part 50" (ADAMS Accession No. ML080020394).

1 Although NRG Condition 5 states that the normal Type A test interval should be less than 15 years, the NRG approved the use of Revision 2 to extend Type A test intervals up to 15 years, provided that the conditions are satisfied as described in Reference 9, Sections 4.1 and 5.0.

Based on the above, the NRC staff concludes that the licensee has addressed and satisfied the intent of the applicable portion of NRC Condition 5 because it proposes a test interval of up to 15 years.

f.

NRC Condition 6 NRC Condition 6 states:

For plants licensed under 10 CFR Part 52, applications requesting a permanent extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI TR 94-01, Revision 2, and EPRI [Electric Power Research Institute] Report No. 1009325, Revision 2, including the use of past containment ILRT data.

This condition is not applicable to CNS, Units 1 and 2, since they were not licensed under 10 CFR Part 52.

3.2.2 NRC Conditions in NEI 94-01, Revision 3-A In Section 4.0 of the NRC staff's safety evaluation, incorporated in TR NEI 94-01, Revision 3-A, the NRC staff concluded that the guidance in the TR is acceptable for reference by licensees in the implementation for the optional performance-based requirements of Option B to 1 O CFR 50, Appendix J, provided that two conditions were satisfied. The NRC staff has evaluated whether the licensee addressed and satisfied these conditions for CNS, as applicable, in the LAR as discussed below.

NRC Condition 1 NRC Condition 1 states, in part, that:

The [NRC] staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The [NRC] staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g. BWR MSIVs [boiling-water reactor main steam isolation valves]), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

NRC Condition 2 NRC Condition 2 states, in part, that:

When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B & C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

The licensee indicated in the LAR that the CNS, Units 1 and 2, post-outage reports will include the margin between the Type B and Type C minimum pathway leak rate summation value adjusted for understatement and the acceptance criterion. Should the Type Band Type C combined totals exceed an administrative limit of 0.5 La but be less than the TS acceptance value (performance criterion) of 0.6 La, then an analysis will be performed and a corrective action plan prepared to restore and maintain the leakage summation margin to less than the administrative limit. The LAR also stated that CNS, Units 1 and 2, will apply the 9-month grace period only to eligible Type C tested components and only for non-routine emergent conditions.

The licensee acknowledges these two conditions and the likelihood that longer test intervals would increase the understatement of actual leakage potential, given the method by which the totals are calculated, and will assign additional margin for monitoring acceptability of results by administrative limits and understatement contribution adjustments.

Therefore, the licensee addressed and satisfied NRC Conditions 1 and 2 of NEI 94-01, Revision 3-A.

3.3 Probabilistic Risk Assessment 3.3.1

Background

Section 9.2.3.1, "General Requirements for ILRT Interval Extensions Beyond Ten Years," of NEI 94-01, Revision 3-A, states that plant-specific confirmatory analyses are required when extending the Type A ILRT interval beyond 1 O years. Section 9.2.3.4, "Plant-Specific Confirmatory Analyses," of NEI 94-01 states that the assessment should be performed using the approach and methodology described in Electric Power Research Institute (EPRI) Report No. 1018243,2 "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals."

The analysis is to be performed by the licensee and retained in the plant documentation and records as part of the basis for extending the ILRT interval.

In the safety evaluation report, dated June 25, 2008 (ADAMS Accession No. ML081140105),

the NRC staff found the methodology in NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT interval to 15 years, provided certain conditions are satisfied.

2 EPRI Report No.-1018243 is also identified as EPRI Report No. 1009325, Revision 2-A. This report is publicly available and can be found at www.tm_ri.com by typing "1018243" in the search field box.

These conditions, set forth in Section 4.2 of the safety evaluation report for EPRI Report No. 1009325, Revision 2, stipulate that:

1. The licensee submit documentation indicating that the technical adequacy of their Probabilistic Risk Assessment (PRA) is consistent with the requirements of RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," relevant to the ILRT extension application.

Additional application specific guidance on the technical adequacy of a PRA used to extend ILRT intervals is provided in the safety evaluation report for EPRI Report No. 1009325, Revision 2.

2. The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small and consistent with the clarification provided in Section 3.2.4.63 of the safety evaluation report for EPRI Report No. 1009325, Revision 2.

3. The methodology in EPRI Report No. 1009325, Revision 2, is acceptable, provided the average leak rate for the pre-existing containment large leak accident case (i.e., accident case 3b) used by licensees is assigned a value of 100 times the maximum allowable leakage rate (La) instead of 35 La.

4. An LAR is required in instances where containment over-pressure is relied upon for emergency core cooling system (ECCS) performance.

3.3.2 Plant-Specific Risk Evaluation The licensee performed a risk impact assessment for extending the Type A containment ILRT interval to once in 15 years. The risk assessment was provided in Attachment 5 to the LAR and in the supplement dated June 20, 2016.

In Section 1.0 of Attachment 5 to the LAR, the licensee stated, in part, that the plant-specific:

... risk assessment follows the guidelines from NEI 94-01, Revision 3-A, the methodology described in EPRI TR-104285, the NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" from November 2001, the NRC regulatory guidance on the Use of Probable Risk Assessment (PRA) as stated in Regulatory Guide 1.200 as applied to ILRT interval extensions, risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174, the methodology used for Catawba to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval, and the methodology used in EPRI 1018243, Revision 2-A of EPRI 1009325.

3 Section 4.2 of the safety evaluation report for EPRI Report No. 1009325, Revision 2, indicates that the clarification regarding small increases in risk is provided in Section 3.2.4.5; however, the clarification is actually provided in Section 3.2.4.6.

The licensee addressed each of the four conditions for the use of EPRI Report No. 1009325, Revision 2, which are listed in Section 4.2 of the associated NRC safety evaluation. A summary of how each condition has been met is provided in the sections below.

3.3.2.1 Technical Adequacy of the PRA The first condition stipulates that the licensee submits documentation indicating that the technical adequacy of its PRA is consistent with the requirements of RG 1.200 relevant to the ILRT extension application.

Consistent with the information provided in NRC Regulatory Issue Summary (RIS) 2007-06, "Regulatory Guide 1.200 Implementation" (ADAMS Accession No. ML070650428), the NRC staff uses Revision 2 of RG 1.200 (ADAMS Accession No. ML090410014) to assess technical adequacy of the PRA used to support risk-informed applications received after March 2010. In Section 3.2.4.1 of the safety evaluation for NEI 94-01, Revision 2, and in EPRI Report No. 1009325, Revision 2, the NRC staff states that Capability Category I of the ASME PRA standard shall be applied as the standard for assessing PRA quality for ILRT extension applications, since approximate values of core damage frequency and large early release frequency (LERF), and their distribution among release categories, are sufficient to support the evaluation of changes to ILRT frequencies.

In Section A.1 of Attachment 5 to the LAR, the licensee discussed the technical adequacy of the internal events PRA, LERF PRA, internal flood PRA, fire PRA, and high wind PRA.

Internal Events PRA In March 2002, the most recent full scope CNS internal events PRA peer review was performed using the process described in NEI 00-02. In 2008, Duke Energy performed a self-assessment that evaluated the differences between the original peer review against NEI 00-02 and RA-S-2008 of the ASME/ANS PRA Standard, as endorsed by RG 1.200, Revision 1.

Additionally, the licensee performed a self-assessment in 2013 against the ASME/ANS PRA Standard RA-Sa-2009 supporting requirements, as endorsed by RG 1.200, Revision 2.

The licensee provided Table A-1 in Attachment 5 of the LAR that presents an assessment of all ASME/ANS PRA Standard RA-Sa-2009 supporting requirements that (1) were assessed to be "Not Met" at the equivalent of Capability Category II in the 2002 peer review, (2) were not assessed in the 2002 peer review (no equivalent NEI 00-02 sub-elements), or (3) were assessed to be "Met" but had related Findings.

The NRC staff reviewed the internal events quality statement and the associated Table A-1 that contained the dispositioned facts and observations (F&Os) and the responses in the June 20, 2016, supplement against the ASME/ANS PRA Standard RA-Sa-2009 supporting requirements for internal events. The NRC staff found that each of the F&O responses was assessed and dispositioned properly in regard to the ILRT extension.

LERF and Internal Flood PRA The licensee stated that in December 2012, a focused scope peer review was performed of the CNS LERF PRA against selected requirements of the ASME/ANS PRA Standard RA-Sa-2009 and any clarifications and qualifications provided in the NRC endorsement of the standard contained in Revision 2 to RG 1.200. The peer review was performed using the process defined in NEI 05-04, Revision 2, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard" (ADAMS Accession No. ML083430462). The scope of the review was limited to the high level requirements and supporting requirements in Part 2, requirements for internal events at-power PRA. Additionally, in September 2012, a focused scope peer review was performed of the CNS internal flood PRA using the NEI 05-04 process and the ASME PRA Standard ASME/ANS RA-Sa-2009, along with the NRC clarifications provided in RG 1.200, Revision 2.

In the June 20, 2016, supplement, the licensee stated that internal flooding was a significant contributor to the risk in the ILRT extension request. Each of the F&Os was re-examined and dispositioned with reasons now specific to each, rather than the previous global disposition.

The NRC staff reviewed the LERF and internal flood quality statements and the associated Tables A-2 and A3 that contained the dispositioned F&Os and the responses in the June 20, 2016, supplement against the ASME/ANS PRA Standard RA-Sa-2009, as endorsed by RG 1.200, Revision 2. The NRC staff found that each of the F&O responses was assessed and dispositioned properly in regard to the ILRT extension.

Fire PRA Section A.2 of Attachment 5 addresses the technical quality of the fire PRA. Citing Position 4.3 of RG 1.205, "Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants,"4 the licensee stated that the CNS internal events model was also updated to support the CNS fire PRA. The CNS fire PRA peer review was performed on July 12-16, 2010, using RG 1.200, Revision 2; the combined PRA standard, ASME/ANS RA-Sa-2009 as endorsed by RG 1.200, Revision 2; and the NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines," process. The licensee also stated that the peer review findings were addressed, and the dispositions reviewed, to validate that no changes were made that meet the definition of a PRA model upgrade per RG 1.200, Revision 2. The licensee concluded that no additional peer reviews (partial scope or focused scope), were required to be conducted for the CNS fire PRA.

The NRC staff reviewed the fire PRA statement and the associated Tables A-4 and A-5 that contained the dispositioned F&Os and the responses in the June 20, 2016, supplement against the ASME/ANS PRA Standard RA-Sa-2009, as endorsed by RG 1.200, Revision 2. The NRC staff found that each of the F&O responses was assessed and dispositioned properly in regard to the ILRT extension.

4 "The licensee should submit the documentation described in Section 4.2 of Regulatory Guide 1.200 to address the baseline PRA and application-specific analyses. For PRA Standard 'supporting requirements' important to the NFPA [National Fire Protection Association] 805 risk assessments, the NRC position is that Capability Category II is generally acceptable."

High Wind PRA The licensee states that the high wind (HW) PRA was assessed in August 2013 by a peer team against the ASME/ANS PRA standard with RG 1.200, Revision 2, clarifications. The peer team documented the F&Os that pertain to the CNS HW PRA, and each are resolved or dispositioned in order to ensure the capability category of each individual standard requirement is met so that the CNS HW PRA can be used to support risk-informed applications.

The NRC staff reviewed the HW PRA statement and the associated Table A-6 that contained the dispositioned F&Os and the responses in the June 20, 2016, supplement against the ASME/ANS PRA Standard RA-Sa-2009, as endorsed by RG 1.200, Revision 2. The NRC staff found that each of the F&O responses was properly assessed and dispositioned in regard to the ILRT extension.

Given that the licensee has (1) evaluated its PRA against RG 1.200, including addressing of clarifications and qualifications to the ASME PRA standard cited in Revision 2, (2) evaluated all of the PRA peer review findings for applicability to the ILRT interval extension, and (3) determined that any unresolved issues would not impact the conclusions of the ILRT risk assessment, the NRC staff concludes that the CNS PRA model used for this application is of sufficient technical adequacy to support the evaluation of changes to ILRT frequencies.

Accordingly, the first limitation and condition is met.

3.3.2.2 Estimated Risk Increase The second condition stipulates that the licensee submit documentation indicating that the estimated risk increase associated with permanently extending the ILRT interval to 15 years is small and consistent with the guidance in RG 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," and the clarification provided in Section 3.2.4.5 of the NRC safety evaluation report for NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. Specifically, a small increase in population dose should be defined as an increase of no more than 1.0 person-Roentgen equivalent man (rem) per year or 1 percent of the total population dose, whichever is less restrictive. In addition, a small increase in conditional containment failure probability (CCFP) should be defined as a value marginally greater than that accepted in previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage points. Additionally, for plants that rely on containment over-pressure for net positive suction for ECCS injection, both core damage frequency (CDF) and LERF will be considered in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174. As discussed in Section 3.3.2.4 of this safety evaluation, CNS, Units 1 and 2, do not rely on containment over-pressure for ECCS performance. Thus, the associated risk metrics include LERF, population dose, and CCFP.

The licensee reported the results of the plant-specific risk assessment, and the reported risk impacts are based on a change in test frequency from three tests in 10 years (the test frequency under 1 O CFR 50, Appendix J, Option A) to one test in 15 years. In the June 20, 2016, supplement, the licensee clarified a discrepancy between the reported increases in population dose, conditional containment failure probability, increase in LERF, and baseline LERF reported in Table 3.7.1-1 of the main report and Table 6-1 and Section 7.0 in, "Evaluation of Risk Significance of Permanent ILRT Extension." The licensee indicated that the values reported in Attachment 5 are correct and that Table 3.7.1-1 should be updated.

The NRC staff reviewed the plant-specific risk assessment (and the updated results in Table 3.7.1-1) and found:

1.

The reported increase in LERF is 4.7E-7/year for each unit, which includes internal events and the potential effects of liner corrosion. When the risk contribution from external events, including the effects of internal fires, seismic events, and high winds, are added, the total reported LERF increase per unit rises to 1.2E-6/year, including the adjustment to the seismic contribution as detailed below in light of the June 20, 2016, supplement. The internal events LERF is 1.7E-6/year for each unit.

When the risk contribution from external events, including the effects of internal fires, seismic events, and high winds, are added, the total reported LERF per unit rises to 7.0E-6/year. Therefore, this change in risk is considered to challenge the threshold for "small" changes (i.e., below 1 E-6/year given a total LERF below 1 E-5/year) per the acceptance guidelines in RG 1.174. As stated in RG 1.174, "In the context of the integrated decisionmaking, the boundaries between regions are not definitive; the numerical values associated with defining the regions in the figure are to be interpreted as indicative values only." This provides the NRC staff with discretion when determining acceptability for risk increases that challenge the threshold, as is the case here. Given that the thresholds are resolved to only one significant figure, the reported total LERF increase (1 E-6/year to one significant figure) is at the threshold for acceptability. In Attachment 5, the licensee cites several sources of conservatism for its analysis. Among these are: (1) categorizing class 3b accidents as 100 percent LERF; (2) generic conservatisms in the, "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment ILRT Intervals," Revision 4, when applied to Class 3b; and (3) not crediting alternative means of detecting failures such as continuing Type B local leak rate tests. As stated, in part, by the licensee:

Although the total change in LERF is somewhat close to [now slightly above] the Regulatory Guide 1.17 4 limit when external event risk is included, several conservative assumptions were made in the ILRT analysis... ; therefore the total change in LERF is considered conservative for this application.

An additional example of conservatism is regarding the seismic CDF, as discussed in Section 3.3.2.2.1 of this safety evaluation. Based on the guidance regarding interpreting thresholds in RG 1.174 and the conservatisms cited, the NRC staff concludes that the LERF increase per unit can be considered a "small" change and is, therefore, acceptable for the ILRT extension.

2. The reported change in Type A ILRT frequency from three in 10 years to once in 15 years results in a reported increase in the total population dose of 0.11 person-rem/year for each unit. The reported increase in total population dose is below the values provided in EPRI Report No. 1009325, Revision 2-A, and defined in Section 3.2.4.6 of the NRC safety evaluation for NEI 94-01, Revision 2. Thus, this increase in the total population dose for the proposed change is considered small and supportive of the proposed change.

3. The increase in CCFP due to change in test frequency from three in 10 years to once in 15 years is 0.89 percent for each unit. This value is below the acceptance guidelines in Section 3.2.4.6 of the NRC safety evaluation for NEI 94-01, Revision 2.

3.3.2.2.1 Seismic CDF Adjustment The licensee used the seismic CDF from the CNS individual plant examination of external events {IPEEE) instead of more recent updates per the NRC Information Notice 2010-18:

Generic Issue (GI) 199, "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants," dated September 2, 201 O (ADAMS Accession No. ML101970221 ), which based seismic CDF on the 2008 U.S. Geological Survey revised seismic hazard curves for CNS. The use of the seismic CDF from the IPEEE, instead of the most conservative results from GI 199, resulted in the LEAF increases in the "weakest link model" for each unit rising from the cited 9.3E-7/year to 1.2E-6/year, with the total LEAF per unit also increasing from 7.1 E-6/year to 8.1 E-6/year.

While the licensee declined to use the GI 199 seismic CDF estimates instead of its original values, it provided the following explanation and citation of conservatisms in the analysis. The most recent safe-shutdown earthquake-ground motion response spectrum comparison data for CNS indicated earthquakes should have lower spectral frequencies than the current design basis. Exceeding the design basis will not occur until higher frequencies are reached, and these are expected to be less damaging. Since the lower frequencies are more likely and more damaging, the reported seismic CDF is the more appropriate. The licensee reviewed the Gl-199 analysis, noting that the "weakest link model" could introduce a conservative bias in the plant fragility assessment.

In addition, the following conservatisms in the calculation for the increase in LEAF were cited by the licensee: (1) conservative classification of data for the initial probability of ILRT failure, including containment leakage events that would not significantly affect population dose and/or LEAF calculations; (2) assumption that every containment leak event results in a LEAF; (3) assumption that all Class 1 sequences coincident with Class 3b leak failures would constitute a LEAF, discounting that some Class 1 sequences have successful operation of containment sprays, thereby eliminating some as LEAF sequences; and (4) use of a factor of five for the change in leak detection probability, ignoring the potential for detection by other means.

The NRC staff reviewed the licensee's justification and the revised LEAF estimates. The revised LERFs increased 1.15E-6/year for CNS, Unit 1, and 1.16E-6/year for CNS, Unit 2, which slightly exceeds the allowed total change in LEAF of 1 E-6/year for 'small' changes.

However, considering the conservativisms employed by the licensee and that the change in LERF is very close to 1 E-6/year even when the "weakest link model" is used, the NRG staff concludes that the LERF increase can still be considered "small" with respect to RG 1.17 4.

3.3.2.2.2 Conclusion for the Estimated Risk Increase Based on the risk assessment results, the NRG staff concludes that the increase in LERF is small and consistent with the acceptance guidelines of RG 1.17 4. The increase in the total population dose and the magnitude of the change in the CCFP for the proposed change are small and supportive of the LAR. The defense-in-depth philosophy is maintained, as the independence of barriers will not be degraded as a result of the requested change, and the use of the three quantitative risk metrics collectively ensures that the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved.

Accordingly, the second condition is met.

3.3.2.3 Leak Rate for the Large Pre-Existing Containment Leak Rate Case The third condition stipulates that in order to make the methodology in EPRI Report No. 1009325, Revision 2, acceptable, the average leak rate for the pre-existing containment large leak rate accident case (i.e., accident case 3b) used by the licensees shall be 100 La instead of 35 La. As noted by the licensee in the Table 5-1 O of Attachment 5 to the LAR, the methodology in EPRI Report No. 1009325, Revision 2-A, incorporated the use of 100 La as the average leak rate for the pre-existing containment large leakage rate accident case (accident case 3b), and this value has been used in the plant-specific risk assessment. Accordingly, the NRG staff concludes that the third condition is met.

3.3.2.4 Applicability if Containment Overpressure is Credited for ECCS Performance The fourth condition stipulates that in instances where containment over-pressure is relied upon for ECCS performance, an LAR is required to be submitted. In Section 5.2.4 of Attachment 5 to the LAR, the licensee stated that containment over-pressure is not required in support of ECCS performance to mitigate design-basis accidents at CNS. Accordingly, the fourth condition is met.

3.3.3 PRA Conclusion The licensee performed a plant-specific risk impact assessment for extending the Type A containment ILRT interval to 15 years in accordance with EPRI Report No. 1009325, Revision 2. As part of this assessment, the licensee addressed each of the four conditions for the use of EPRI Report No. 1009325, Revision 2, listed in Section 4.2 of the NRG safety evaluation report for NEI 94-01, Revision 2, and in EPRI Report No. 1009325, Revision 2. The NRG staff concludes that the PRA technical adequacy and estimated risk increases are acceptable for this application, given that the licensee assumed the appropriate leak rate for accident case 3b, and that CNS, Units 1 and 2, do not rely on containment over-pressure.

Based on the above, the NRG staff concludes that the plant-specific confirmatory analyses for the proposed permanent extension of the Type A containment ILRT frequency to once in 15 years for CNS, Units 1 and 2, is acceptable.

3.4 Summary The NRC staff reviewed the proposed changes to TS 5.5.2 and verified that the revised program description that incorporates NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, contains the appropriate administrative controls for the Containment Leakage Rate Testing Program. The NRC staff concludes that the licensee continues to provide the appropriate administrative controls to ensure that the requirements of 10 CFR 50.36(c)(5) and Appendix J to 1 O CFR Part 50 are satisfied.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the South Carolina State official was notified on August 16, 2016, of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR 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 (81 FR 13839; March 15, 2016). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 1 O 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 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) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor(s): Amitava Ghosh Ray Gallucci Jerome Bettle Date: September 12, 2016

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

If you have any questions, please contact me at 301-415-3229 or by e-mail at Michael.Orenak@nrc.gov.

Docket Nos. 50-413 and 50-414

Enclosures:

1. Amendment No. 286 to NPF-35

2. Amendment No. 282 to NPF-52

3. Safety Evaluation cc w/enclosures: Distribution via Listserv DISTRIBUTION:

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