ML14183B318

North Anna Units 1 & 2, Proposed License Amendment Request Permanent Fifteen-Year Type a Test Interval

ML14183B318
Person / Time
Site:	North Anna
Issue date:	06/30/2014
From:	Sartain M D Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
14-272
Download: ML14183B318 (93)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 June 30, 2014 U. S. Nuclear Regulatory Commission Serial No.: 14-272 Attention:

Document Control Desk NLOS/ETS:

RO Washington, DC 20555-0001 Docket Nos.: 50-338/339 License Nos.: NPF-4/7 VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION UNITS 1 AND 2 PROPOSED LICENSE AMENDMENT REQUEST PERMANENT FIFTEEN-YEAR TYPE A TEST INTERVAL Pursuant to 10CFR50.90, Virginia Electric and Power Company (Dominion) requests license amendments in the form of changes to the Technical Specifications, for facility Operating License Numbers NPF-4 and NPF-7 for North Anna Power Station Units 1 and 2, respectively.

The proposed amendments revise North Anna Power Station Units 1 and 2 Technical Specification (TS) 5.5.15, "Containment Leakage Rate Testing Program," by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used to develop the North Anna performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A of NEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending the Type A primary containment integrated leak rate test (ILRT) intervals to fifteen years and the Type C local leak rate test intervals to 75 months, and incorporates the regulatory positions stated in RG 1.163.Attachment 1 provides a discussion of the change and a summary of the supporting probabilistic risk assessment (PRA). Discussion of the supporting risk assessment and documentation of the technical adequacy of the PRA model are provided in Attachments 4 and 5, respectively.

In addition, the marked-up and proposed TS pages are provided in Attachments 2 and 3, respectively.

We have evaluated the proposed amendments and have determined that they do not involve a significant hazards consideration as defined in 10CFR50.92.

The basis for that determination is included in Attachment

1. We have also determined that operation with the proposed change will not result in any significant increase in the amount of effluents that may be released offsite or any significant increase in individual or cumulative occupational radiation exposure.

Therefore, the proposed amendments are eligible for categorical exclusion from an environmental assessment as set forth in 10CFR51.22(c)(9).

Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change. The proposed TS change has been reviewed and approved by the Facility Safety Review Committee.

Serial No.14-272 Docket Nos. 50-338/339 Page 2 of 3 The next Unit 1 ILRT is currently due no later than October 2017. Based on the current outage schedule for Unit 1, the current ten-year frequency would require the next Unit 1 ILRT to be performed during the fall 2016 refueling outage. Due to lead time required to procure the services and equipment to perform a Type A test, Dominion requests approval of the proposed change by December 31, 2015.Should you have any questions or require additional information, please contact Mr. Thomas Shaub at (804) 273-2763.Respectfully, Mark Sartain Vice President

-Nuclear Engineering Commitment contained in this letter: See Attachment 6.Attachments:

1.2.3.4.5.6.Discussion of Change Marked-up Technical Specifications Page Proposed Technical Specifications Page Risk Assessment PRA Technical Adequacy List of Regulatory Commitments M O "r T Pta Commonwet of Vllin'hm I Reg.# 140542 MyCommission sx~rit~ 320112 COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO)))The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mr. Mark D. Sartain, who is Vice President

-Nuclear Engineering, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are tru to the best of his knowledge and belief.Acknowledged before me this .__7.day of .4, .,2014.My Commission Expires: 5 U.Notary Public' Serial No.14-272 Docket Nos. 50-338/339 Page 3 of 3 cc: U.S. Nuclear Regulatory Commission

-Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, GA 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building -7 th floor 109 Governor Street Suite 730 Richmond, VA 23219 Dr. V. Sreenivas NRC Project Manager North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector North Anna Power Station Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 1 Discussion of Change Virginia Electric and Power Company (Dominion)

North Anna Station Units I and 2 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 DISCUSSION OF CHANGE 1.0 D E S C R IP T IO N ...............................................................................................

..2 2.0 PROPOSED CHANGE ......................................................................................

2 3.0 BACKGROUND

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3 3.1 10 CFR 50, Appendix J, Option B Requirements

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3 3.2 Reason for Proposed Amendment

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4 4.0 TECHNICAL ANALYSIS ....................................................................................

5 4.1 Description of Containment

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6 4.2 Integrated Leak Rate Test History .........................................................................

8 4.3 Type B and C Testing Programs ...........................................................................

9 4.4 Supplemental Inspection Requirements

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10 4.4.1 IW E Examination

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11 4.4.2 IW L Examinations

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12 4.5 Deficiencies Identified

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14 4.6 Plant-Specific Confirmatory Analysis .................................................................

14 4 .6 .1 M ethodology

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..14 4 .6 .2 P R A Q ua lity ........................................................................................

.... 16 4.6.3 Summary of Plant-Specific Risk Assessment Results ..................................

16 4 .7 C o nclu sio n .................................................................................................

.... 17 5.0 REGULATORY ASSESSMENT

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17 5.1 Applicable Regulatory Requirements/Criteria

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17 5.2 No Significant Hazards Consideration

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18 5.3 Environmental Considerations

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20 6.0 PRECEDENCE

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20 Page 1 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 DISCUSSION OF CHANGE 1.0 DESCRIPTION The proposed amendment revises North Anna Power Station (NAPS) Units 1 and 2 Technical Specification (TS) 5.5.15, "Containment Leakage Rate Testing Program," by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used by Virginia Electric and Power Company (Dominion) to develop the North Anna performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A of NEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending primary containment integrated leak rate test (ILRT) intervals to 15 years and Type C test intervals to 75 months, and incorporates the regulatory positions stated in RG 1.163. In the safety evaluation (SE) issued by NRC letter dated June 25, 2008 and June 8, 2012, the NRC concluded that NEI 94-01, Revision 3-A, describes an acceptable approach for implementing the optional performance-based requirements of Option B of 10 CFR 50, Appendix J, and found that NEI 94-01, Revision 3-A, is acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.0 of the two SEs.In accordance with the guidance in NEI 94-01, Revision 3-A, Dominion proposes to extend the interval for the primary containment ILRTs, which are currently required to be performed at ten year intervals, to no longer than 15 years from the last ILRT for both Units 1 and 2. The next ILRT is currently due no later than October 11, 2017 for Unit 1 and October 9, 2014 for Unit 2 (with an NRC approved 5-year extension).

This is approximately 10 years since the last ILRT for Unit 1 and 15 years for Unit 2. The Unit 2 schedule is acceptable based on a one-time extension of the frequency that was requested in Dominion letter dated December 5, 2007 (Serial No. 07-0769), and approved in NRC letter dated July 7, 2008. The current Unit 1 10-year frequency would require the next ILRT to be performed during the fall 2016 refueling outage. The proposed amendment would allow the next ILRT for North Anna Unit 1 to be performed within 15 years from the last ILRT (i.e., October 11, 2007), as opposed to the current 10-year interval.

This would allow the Unit 1 and 2 ILRTs to be performed at a 15-year interval consistent with the NRC approved guidance documents (NEI 94-01, Rev. 3A) and establish a 15 year ILRT frequency for both Units 1 and 2. The performance of fewer ILRTs will result in significant savings in radiation exposure to personnel, cost, and critical path time during future refueling outages.2.0 PROPOSED CHANGE TS 5.5.15, "Containment Leakage Rate Testing Program," currently states: "A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) 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, modified by the following exception:

NEI-94-01-1995, Section 9.2.3: The first Unit 2 Type A test performed after the October 9, 1999 Type A test shall be performed no later than October 9, 2014." The proposed change would revise this portion of TS 5.5.15 by replacing the reference to RG 1.163 with a reference to NEI 94-01, Revision 3-A as follows: TS 5.5.15, "Containment Leakage Rate Testing Program," currently states: "A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o)Page 2 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 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, Revision 3-A,"Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012." Attachment 2 of the letter contains the existing TS page 5.5.15 marked-up to show the proposed changes to TS 5.5.15.3.0 BACKGROUND 3.1 10 CFR 50, Appendix J, Option B Requirements The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS, and that periodic surveillance of containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of the containment and the systems and components penetrating containment.

The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant design basis accident.

Appendix J identifies three types of required tests: (1) Type A tests, intended to measure the containment overall integrated leakage rate; (2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for containment penetrations; and (3) Type C tests, intended to measure containment isolation valve leakage. Type B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," was amended to provide a performance-based Option B for the containment leakage testing requirements.

Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B. Also in 1995, RG 1.163 was issued. The RG endorsed NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," with certain modifications and additions.

Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency from the containment Type A (ILRT) test from three tests in ten years to one test in ten years. This relaxation was based on an NRC risk program, and Electric Power Research Institute (EPRI) TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals", both of which illustrated that the risk increase associated with extending the ILRT surveillance interval was very small.NEI 94-01, Revision 2, describes an approach for implementing the optional performance-based requirements of Option B described in 10 CFR 50, Appendix J, which includes provisions for extending Type A intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies.

This method uses industry performance data, plant-specific performance data, and risk insights in determining the appropriate Page 3 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 testing frequency.

NEI 94-01, Revision 2, also discusses the performance factors that licensees must consider in determining test intervals.

However, it does not address how to perform the tests because these .details are included in existing documents (e.g., American National Standards Institute

/ American Nuclear Society [ANSI/ANS]-56.8-2002).

The NRC final SE issued by letter dated June 25, 2008, documents the NRC's evaluation and acceptance of NEI 94-01, Revision 2, subject to the specific limitations and conditions listed in Section 4.1 of the SE. The accepted version of NEI 94-01 has subsequently been issued as Revision 2-A dated October 2008.TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals", Revision 2, provides a risk impact assessment for optimized ILRT intervals of up to 15 years, utilizing current industry performance data and risk-informed guidance, primarily Revision 1 of RG 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Bases." The NRC's final SE issued by letter dated June 25, 2008, documents the NRC's evaluation and acceptance of EPRI TR-1 04285, Revision 2, subject to the specific limitations and conditions listed in Section 4.2 of the SE. An accepted version of EPRI TR-1009325 has subsequently been issued as Revision 2-A (also identified as TR-1018243) dated October 2008.NEI 94-01, Revision 3, describes an approach for implementing the optional performance-based requirements of Option B described in 10 CFR 50, Appendix J, which includes provisions for extending Type A and Type C intervals to up to 15 years and 75 months, respectively, and incorporates the regulatory positions stated in RG 1.163. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies.

This method uses industry performance data, plant-specific performance data, and risk insights in determining the appropriate testing frequency.

NEI 94-01, Revision 3, also discusses the performance factors that licensees must consider in determining test intervals.

However, it does not address how to perform the tests because these details are included in existing documents (e.g., American National Standards Institute/American Nuclear Society (ANSI/ANS]-56.8-2002).

The NRC final SE issued by letter dated June 8, 2012, documents the NRC's evaluation and acceptance of NEI 94-01, Revision 3, subject to the specific limitations and conditions listed in Section 4.1 of the SE. The accepted version of NEI 94-01 has subsequently been issued as Revision 3-A dated July 2012.EPRI TR-1009325, Revision 2, provides a validation of the risk impact assessment of EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," dated August 1994. The assessment validates increasing allowable extended LLRT intervals to the 120 months as specified in NEI 94-01, Revision 0. However, the industry requested that the allowable extended interval for Type C LLRTs be increased only to 75 months, to be conservative, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The NRC final SE issued by letter dated June 8, 2012, documents the NRC's evaluation and acceptance of EPRI TR-1009325 as a validation of EPRI TR-104285, Revision 2 bases to extend Type C LLRT to 120 months, subject to the specific limitations and conditions listed in Section 4.1 of the SE.3.2 Reason for Proposed Amendments With the approval of the TS change request, North Anna Units 1 and 2 will have transitioned to a performance-based test frequency for the Type A tests and Local Leak Rate Testing (Type B and C) consistent with NEI 94-01, Revision 3-A.Page 4 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 4.0 TECHNICAL ANALYSIS As required by 10 CFR 50.54(o), the North Anna containments are subject to the requirements set forth in 10 CFR 50, Appendix J. Option B of Appendix J requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Currently, the North Anna 10 CFR 50 Appendix J Testing Plan is based on RG 1.163, which endorses NEI 94-01, Revision 0. This license amendment request proposes to revise the North Anna 10 CFR 50, Appendix J Testing Plan by implementing the guidance in NEI 94-01, Revision 3-A.In the SE issued by the NRC dated June 8 2012, the NRC concluded that NEI 94-01, Revision 3, as modified to include two limitations and conditions, is acceptable for referencing by licensees proposing to amend their TS in regard to containment leakage rate testing for the optional performance-based requirements of Option B of 10 CFR 50, Appendix J.The following addresses each of the limitations and conditions of the 2008 and 2012 SEs.Limitation

/ Condition North Anna Response (from Section 4.1 of SE dated June 25, 2008)1. For calculating the Type A leakage rate, the licensee Following the NRC approval of this license amendment request, should use the definition in the NEI TR 94-01, North Anna will use the definition in Section 5.0 of NEI 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002).

Revision 3-A, for calculating the Type A leakage rate when future North Anna Type A tests are performed (see Attachment 6, "List of Regulatory Commitments").

2. The licensee submits a schedule of containment A schedule of containment inspections is provided in Section inspections to be performed prior to and between 4.2 below.Type A tests.3. The licensee addresses the areas of the containment General visual examination of accessible interior and exterior structure potentially subjected to degradation.

surfaces of the containment system for structural problems is typically conducted in accordance with the North Anna IWE/IWL Containment Inservice Inspection Plans which implement the requirements of the ASME, Section Xl, Subsections IWE and IWL, as required by 10 CFR 50.55a(g).

Although not a specific line item in the North Anna IWE program, accessible leak chase channel plugs and caps are inspected during the general visual examination completed in accordance with our IWE program. There are no primary containment surface areas that require augmented examinations in accordance with ASME Section XI, IWE-1240.4. The licensee addresses any test and inspections North Anna has already replaced the Steam Generators which performed following major modifications to the did not required modifications to the containment structure.

containment structure, as applicable.

When North Anna Units 1 and 2 replaced the reactor vessel closure head, the containment structure was modified.

The design change process addressed the testing requirements of the containment structure modifications.

5. The normal Type A test interval should be less than Dominion acknowledges and accepts this NRC staff position, as 15 years. If a licensee has to utilize the provisions of. communicated to the nuclear industry in Regulatory Issue Section 9.1 of NEI TR 94-01, Revision 2, related to Summary (RIS) 2008-27 dated December 8, 2008.extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition.

S. For plants licensed under 10 CFR Part 52, Not applicable.

North Anna Unit 1 and 2 are not licensed applications requesting a permanent extension of the pursuant to 10 CFR Part 52.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, Rev. 2, and EPRI Report No. 1009325, Rev. 2, including the use of past containment ILRT data.Page 5 of 20 Serial No 14-272 Docket Nos. 50-3331339 Type A Test Interval Extension

-LAR Attachment 1 Limitation

/ Condition North Anna Response (from Section 4.1 of SE dated July 2012)1. The staff is allowing the extended interval for Type C Following the approval of the amendment, North Anna will LLRTs be increased to 75 months with the follow the guidance of NEI 94-01, Rev. 3-A to assess and requirement that, a licensee's post-outage report monitor margin between the Type B and C leakage rate include the margin between the Type B and Type C summation and the regulatory limit. This will include corrective leakage rate summation and its regulatory limit. In actions to restore margin to an acceptable level.addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The 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), 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.2. When routinely scheduling any LLRT valve interval Following the approval of the amendment, consistent with the beyond 60-months and up to 75-months, the primary guidance of Section 11.3.2 of NEI 94-01, Rev. 3-A North Anna containment leakage rate testing program trending will estimate the amount of understatement in the Type B & C or monitoring must include an estimate of the total and include determination of the acceptability in a post-amount of understatement in the Type B & C total, outage report.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.

To comply with the requirement of 10 CFR 50, Appendix J, Option B,Section V.B, North Anna Units 1 and 2 TS 5.5.15.a currently references RG 1.163. RG 1.163 states that NEI 94-01, Revision 0, provides methods acceptable to the NRC for complying with Option B of 10 CFR 50, Appendix J, with the following exception:

The 5-year extension for North Anna Unit 2 Type A test to be performed no later than October 9, 2014 is the only exception to the guidelines.

4.1 Description of Containment The reactor containment structure is a steel-lined, heavily reinforced concrete structure with vertical cylindrical wall and hemispherical dome, supported on a flat base mat. Below grade the containment structure is constructed inside an open cut excavation in rock. The structure is rock-supported.

The base of the foundation mat is located approximately 67 feet below finished ground grade. The containment structure has an inside diameter of 126 ft. 0 in. The bend line of the dome is 127 ft. 7 in. above the top of the foundation mat. The inside radius of the dome is 63 ft.0 in.The interior vertical height is 190 ft. 7 in. measured from the top of the foundation mat to the center of the dome. The cylindrical wall is 4 ft. 6 in. thick, the dome is 2 ft. 6 in. thick, and the base mat is 10 ft. 0 in. thick. The steel liner for the wall is 3/8 inch thick. The steel liner for the mat consists of a 0.25-inch plate except: in the incore instrumentation area, where an exposed 0.75-inch plate is used; and the inside recirculation spray pump sumps, where an exposed 0.5-inch plate is used.The steel liner for the dome is 0.5 inch thick. A waterproof membrane was placed below the containment structural mat and carried up the containment wall to above ground-water level.Attached to and entirely enveloping the structure below grade, the membrane protects concrete Page 6 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 reinforcing from ground-water corrosion, and the steel liner from external hydrostatic pressure.Access to the containment structure is provided by a 7 ft. 0 in. inside diameter (ID) personnel hatch and a 14 ft. 6 in. ID equipment hatch. Other smaller containment structure penetrations include hot and cold pipes, main steam and feedwater pipes, the fuel transfer tube, and electrical conductors.

The reinforced-concrete structure is designed to withstand all loadings and stresses anticipated during the operation and life of the plant. The steel liner is attached to and supported by the concrete.

The liner functions primarily as a gas tight membrane, and transmits loads to the concrete.

During construction, the steel liner served as the inside form for the concrete wall and dome. The containment structure does not require the participation of the liner as a structural component.

No credit is taken for the presence of the steel liner in the design of the containment structure to resist seismic forces or other design loads.The steel wall and dome liner are protected from potential interior missiles by interior concrete shield walls. The base mat liner is protected by a 21-inch to 30-inch thick concrete cover, except in the incore instrumentation area, the inside recirculation spray pump sumps, the containment drainage sumps, the low end of the containment sump trench, where the slope results in a minimum of approximately 12 inches of concrete cover, and the bottom of the containment sump.The safety design basis for the containment is that the containment must withstand the pressure and temperatures of the limiting design basis accident (DBA) without exceeding the design leakage rate.Containment air partial pressure is an initial condition used in the containment DBA analyses to establish the maximum peak containment internal pressure.

The limiting DBAs considered relative to containment pressure are the loss of coolant accident (LOCA) and steam line break (SLB). The LOCA and SLB are assumed not to occur simultaneously or consecutively.

The containment analysis for the DBA shows that the maximum peak containment pressure results from the limiting design basis SLB. However, peak accident pressure in the TS is based on the LOCA peak. The maximum design internal pressure for the containment is 45.0 psig, which bounds the design basis accidents.

The LOCA and SLB analyses establish the limits for the containment air partial pressure operating range. This maximum peak containment internal pressure of 42.7 psig for a LOCA, which is less than the maximum design internal pressure for the containment.

The SLB analysis resulted in a maximum peak containment internal pressure of 43.0 psig.The containment was also designed for an external pressure load of 9.2 psid (i.e., a design minimum pressure of 5.5 psia). The inadvertent actuation of the Quench Spray (QS) System was analyzed to confirm the reduction in containment pressure remains within the containment minimum design pressure.During power operation, North Anna Units 1 and 2 are maintained at a subatmospheric condition (see TS 3.6.4). Containment air partial pressure is maintained with an operating range (10.3 psia to 12.3 psia) based on service water temperature to ensure the containment design pressure is not exceeded during a design basis accident.

Instrumentation constantly monitors containment pressure.

If pressure rises, an alarm annunciates conditions approaching the limits allowed by the Technical Specifications.

Although not as significant as the differential pressure resulting from a design basis accident, the fact that the containment can be maintained subatmospheric provides a degree of assurance of containment structural integrity (i.e., no large leak paths in the containment structure).

This feature is a complement to visual inspection of the interior and exterior of the containment structure for those areas that may be inaccessible for visual examination.

Page 7 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 4.2 Integrated Leak Rate Test History Unit I Test Date As-Found Leakage Acceptance Limit*June 23, 1989 Measured Leakage With Upper 0.26 of La Confidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.34 of La Non-vented Penalty 0.03 of La TOTAL 0.63 of La 1.0 La (0.1%/day)

April 3,1993 Measured Leakage With Upper 0.31 of La Confidence Limit (UCL)Margin 0.31_ofLa Total Type C Penalty (leakage savings) 0.01 of La Non-vented Penalty 0.02 of La TOTAL 0.34 of La 1.0 La October 11, 2007 Measured Leakage With Upper 0.534 of La Confidence Limit (UCL)Margin 0_534_ofLa Total Type C Penalty (leakage savings) 0.023 of La Non-vented Penalty 0.0 of La TOTAL 0.557 of La 1.0 La* The total allowable "as-left" leakage is 0.75 La, (La, 0.1% of primary containment air by weight per day, is the leakage assumed in dose consequences) with 0.6 La, the maximum leakage from Type B and C components.

The ILRT test pressure is maintained between 44.1 psig and 45.Unit 2 Test Date As-Found Leakage Acceptance Limit*April 1989 Measured Leakage With Upper 0.27 of La Confidence Limit (UCL)Margin 0.27_ofLa Total Type C Penalty (leakage savings) 0.19 of La Non-vented Penalty 0.03 of La TOTAL 0.49 of La 1.0 La October 1990 Measured Leakage With Upper 0.22 of La Confidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.12 of La Non-vented Penalty 0.03 of La TOTAL 0.37 of La 1.0 La October 1999 Measured Leakage With Upper 0.4898 of La Confidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.089 of La Non-vented Penalty 0.035 of La TOTAL 0.6138 of La 1.0 La* The total allowable "as-left" leakage is 0.75 La, (La, 0.1% of primary containment air by weight per day, is the leakage assumed in dose consequences) with 0.6 La, the maximum leakage from Type B and C components.

The ILRT test pressure is maintained between 44.1 psig and 45.Containment penetration (Type B and C) testing is being performed in accordance with Option B of 10 CFR 50, Appendix J. The current total penetration leakage on a minimum path basis is less than 10% of the leakage allowed for containment integrity.

No modifications that require a Type A test are planned prior to Unit 1 fall of 2022 and Unit 2 fall 2014 refueling outages, when the next Type A tests will be performed under this proposed change.Any unplanned modifications to the containment prior to the next scheduled Type A test would be subject to the special testing requirements of Section IV.A of 10 CFR 50, Appendix J. There have Page 8 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 been no pressure or temperature excursions in the containment which could have adversely affected containment integrity.

There is no anticipated addition or removal of plant hardware within containment which could affect leak-tightness.

4.3 Type B and Type C Testing Program The North Anna Unit 1 and 2 Appendix J, Type B and Type C leakage rate testing requires testing of electrical penetrations, airlocks, hatches, flanges, and valves within the scope of the program as required by 10 CFR 50, Appendix J, Option B and TS 5.5.15. The Type B and Type C testing program consists of local leak rate testing of penetrations with a resilient seal, expansion bellows, double gasketed manways, hatches and flanges, and containment isolation valves that serve as a barrier to the release of the post-accident containment atmosphere.

A review of the most recent Type B and Type C test results and their comparison with the allowable leakage rate was performed.

The combined Type B and Type C leakage acceptance criterion is 182.6 standard cubic feet per hour (scfh) for North Anna Units 1 and 2. The maximum and minimum pathway leak rate summary totals for the last three refueling outages are shown below.Unit 1 October 2010 -As-Found Min Pathway Leakage 7.248 scfh October 2010 -As-Left Max Pathway Leakage 20.9 scfh October 2010 -As-Left Minimum Pathway Leakage 9.618 scfh April 2012 -As-Found Min Pathway Leakage 11.607 scfh April 2012 -As-Left Max Pathway Leakage 44.134 scfh April 2012- As-Left Minimum Pathway Leakage 10.292 scfh October 2013 -As-Found Min Pathway Leakage 6.205 scfh October 2013 -As-Left Max Pathway Leakage 23.808 scfh October 2013 -As-Left Minimum Pathway Leakage 6.554 scfh There were no Type B or C penetration test failures during the Unit 1 2013 refueling outage. The results of the Type C testing during the Unit 1 2013 refueling outage indicates that:* 1-CC-119, which had acceptable leakage in 2013, remains on accelerated schedule based on leakage greater than administrative limit identified in 2012 refueling outage (RFO).* Four valves (1-IA-55, 1-IA-TV-102B and 1-S1-106, 1-SI-TV-100) completed their accelerated testing and can return to an extend test frequency.

Leakage results during 2013 RFO were acceptable.

• Four valves (1-DA-TV-1OOA and B, containment sump discharge and 1-CV-TV-100 and 1-CV-4, containment vacuum ejector) continue to be tested every outage for operational convenience.

Leakage results during 2013 RFO were acceptable.

• Six valves (1-HV-MOV-100A, B, C, and D, 1-HV-MOV-101 and 102, containment purge exhaust and supply) are tested in accordance with TS Surveillance Requirement (SR)3.6.3.4, which is at least every RFO. Leakage results during 2013 RFO were acceptable.

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-LAR Attachment 1 Unit 2 April 2010 -As-Found Min Pathway Leakage 11.86 scfh April 2010 -As-Left Max Pathway Leakage 23.71 scfh April 2010 -As-Left Minimum Pathway Leakage 3.54 scfh November 2011 -As-Found Min Pathway Leakage 6.66 scfh November 2011 -As-Left Max Pathway Leakage 10.68 scfh November 2011 -As-Left Minimum Pathway Leakage 4.34 scfh May 2013 -As-Found Min Pathway Leakage 7.18 scfh May 2013 -As-Left Max Pathway Leakage 17.66 scfh May 2013 -As-Left Minimum Pathway Leakage 4.15 scfh There were no Type B or C penetration test failures during the Unit 2 2013 refueling outage. The results of the Type C testing during the Unit 2 2013 refueling outage indicates that:* 2-IA-250 valve replaced in 2011 remains on an accelerated test frequency.

Leakage results during 2013 RFO were acceptable.

Requires one more successful test to return to extended test frequency.

• 2-BD-TV-200B was replaced in 2010 (body to bonnet leak which did not affect penetration leakage results) and placed on accelerated testing. Leakage results during 2011 and 2013 RFO were acceptable.

This valve will be tested during the 2014 outage and if acceptable results will be returned to an extended test frequency.

• Four valves (2-DA-TV-200A and B, containment sump discharge and 2-CV-TV-200 and 2-CV-4, containment vacuum ejector) continue to be tested every outage for operational convenience.

Leakage results during 2013 RFO were acceptable.

• Six valves (1-HV-MOV-200A, B, C, and D, and 2-HV-MOV-201 and 202, containment purge exhaust and supply) are tested in accordance with TS SR 3.6.3.4, which is at least every RFO. Leakage results during 2013 RFO were acceptable.

As discussed in NUREG-1493, Type B and Type C tests can identify the vast majority (greater than 95%) of all potential containment leakage paths. This amendment request adopts the guidance in NEI 94-01, Revision 3-A, in place of NEI 94-01, Revision 0 for the Type C test interval, but otherwise does not affect the scope or performance of Type B or Type C tests. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

4.4 Supplemental Inspection Requirements Prior to initiating a Type A test, a general visual examination of accessible interior and exterior surfaces of the containment system for structural problems that may affect either the containment structure leakage integrity or the performance of the Type A test is performed.

This inspection is typically conducted in accordance with the North Anna Containment Inservice Inspection (ISI) Plan, which implements the requirements of ASME, Section Xl, Subsection IWE/IWL. The applicable code edition and addenda for the second ten-year interval IWE/IWL program is the 2001 Edition with the 2003 Addenda.The examination performed in accordance with the IWE/IWL program satisfies the general visual examination requirements specified in 10 CFR 50, Appendix J, Option B. Identification and evaluation of inaccessible areas are addressed in accordance with the requirements of 10 CFR Page 10 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 50.55a(b)(2)(ix)(A) and (E). Examination of pressure-retaining bolted connections and evaluation of containment bolting flaws or degradation are performed in accordance with the requirements of 10 CFR 50.55a(b)(ix)(G) and 10 CFR 50.55a(b)(ix)(H).

Each ten-year ISI interval is divided into three inspection periods of 3, 4 and 3 year durations for IWE. A minimum of one inspection during each inspection period of the ISI interval is required by the IWE program. Each ten-year ISI interval is divided into two five-year inspection periods for IWL. A minimum of one inspection during each inspection period of the ISI interval is required by the IWL program.As noted on the tables below, the required IWL and IWE and Technical Requirements Manual (TRM) inspections satisfies the requirement of NEI 94-01, Revision 3-A, Section 9.2.3.2, to perform the general visual examinations at least three other times before the next Type A test, if the Type A test interval is to be extended to 15 years. The North Anna TRM surveillance requirements, TSR 3.6.2.7, specifically requires a general visual examination of the accessible interior and exterior surfaces of the containment prior to initiating a Type A test.The examinations performed in accordance with the North Anna Unit 1 and 2, American Society of Mechanical Engineers (ASME) Code,Section XI, Subsection IWE/IWL program satisfy the general visual examinations requirements specified in 10 CFR 50, Appendix J, Option B. ASME Code,Section XI, Subsection IWE assures that at least three general visual examinations of metallic components will be conducted before the next Type A test if the Type A test interval is extended to 15 years. This meets the requirements of Section 9.2.3.2 of NEI 94-01, Revision 3-A and Condition 2 in Section 4.1 of the NRC safety evaluation for NEI 94-01, Revision 2.Visual examinations of accessible concrete containment components in accordance with ASME Code, Section Xl, Subsection IWL are performed every five years, resulting in at least three IWL examinations being performed during a 15-year Type A test interval.Together, these examinations assure that at least three general visual examinations of the accessible containment surfaces (exterior and interior) and one visual examination immediately prior to a Type A test will be conducted before the next Type A test if the Type A test interval is extended to 15 years, thereby meeting the requirements of Section 9.2.3.2 of NEI 94-01, Revision 3-A and Condition 2 in Section 4.1 of the NRC safety evaluation for NEI 94-01, Revision 2.4.4.1 IWE Examinations A review was conducted for North Anna Units 1 and 2 per IWE-1241, Examination Surface Areas (1992 Edition with 1992 Addenda of ASME Xl) for the initial ten-year Category E-C examination requirements.

No areas were deemed susceptible on Unit 1 to accelerated degradation and aging;therefore, augmented examinations per Category E-C were not required.

Three areas in Unit 2 were deemed susceptible to accelerated degradation and aging due to wood entrapment inside the concrete and required augmented examinations per Category E-C. Corrective action to remove the wood was performed and the areas were re-examined in accordance with IWE-2420(b) and after three (3) augmented examinations were performed and remained essentially unchanged in accordance with IWE-2420(c) the inspection frequency was returned to normal. The volumetric examinations were performed in accordance with Relief Request RR-IWE6. During the second ten-year interval (2001 Edition through 2003 Addenda of ASME Section Xl), two (2) test plugs in each unit in the containment recirculation spray sump were determined to be part of the IWE boundary and subject to accelerated degradation per (IWE-1240).

Augmented detailed (VT-1)examinations were performed in accordance with IWE-2310(c) until the plugs were removed and the area was overlaid with stainless steel to preclude further degradation.

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-LAR Attachment 1 North Anna Unit 1 has completed the examination requirements of the Interval 2, Period 2 of Containment IWE Inservice Inspection Program. North Anna Unit 2 is scheduled to complete the Interval 2, Period 2 of the Containment IWE Inservice Inspection Program examination requirements by October 2014. Examinations are performed to the requirements of the 2001 Edition through 2003 Addenda of ASME XI as modified by the 10 CFR 50.55a(b) limitations for both units. At this time, no augmented Category E-C examinations are planned for NAPS Unit 1.For North Anna Unit 2, Interval 2, Period 1 during Containment IWE Inservice Interval examinations, one area of the liner (CR376005) was observed to have exhibited some blistering.

Although no liner degradation was observed during the inspection prior to recoating, this area was conservatively added as to the IDDEAL program as category E-C (Item E4.11), requiring re-examination during the next Unit 2 refueling outage. The remaining examinations are based on Category E-A, which are visual (General, VT-3 and VT-I) examinations based on Code or 10 CFR requirements.

In accordance with the Containment Inservice Testing Program, qualified station personnel perform an IWE -General Visual examination on the accessible surface area associated with the Containment Liner. Coating degradation found to date has been primarily the result of mechanical damage. However, occasionally minor blistering has been found in the coatings, in each of these instances, the liner beneath the blisters has not shown signs of degradation or accelerated corrosion.

There are no other primary containment surface areas that require augmented examination in accordance with ASME Section Xl, IWE-1240 for either unit.4.4.2 IWL Examinations The second interval concrete containment examinations (IWL) have specified dates of August 31, 2011 and August 31, 2016 for Units 1 and 2. General and detailed visual examinations were completed by the required August 31, 2011 date for the first five year period in the summer of 2011 in accordance with Category L-A of the 2001 Edition with 2003 Addenda of ASME Xl. The second 5-year concrete containment examination in accordance with Category L-A of the code is scheduled to be completed in the summer of 2016 for Units 1 and 2. The 2011 examinations on the concrete exterior were conducted by the Responsible Engineer using the approved Code visual methods. During the examinations, 25 indications were observed on each unit. The Unit 1 and Unit 2 indications noted were minor spalls, efflorescence pop-outs, cracks, stains, and abandoned anchors/anchor holes. Almost all conditions identified were minor in nature and did not require additional excavation for repair. In general, the indications requiring additional inspection or excavation involved embedded materials and loose or hollow-sounding areas. The designation of a code versus a cosmetic repair is detailed in ACI-349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures." The repairs were designated as cosmetic based on these criteria with the exception of one code repair area for Unit 1.The Code repair indications was a spall/rock pocket located on the Unit 1 dome approximately 4'long 5" wide and 3" deep that exposed primary reinforcement.

The area was repaired using safety-related repair concrete in accordance with station procedures.

A VT-1 exam was performed for this code repair.In summary, no significant defects or concerns were observed on the exterior concrete and for the most part, all observed defects were due to original construction flaws. Based on these inspections, the conclusion was that the Unit 1 and 2 containment structures were in good material condition.

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-LAR Attachment 1 The following provides an approximate schedule for the containment surface examinations, assuming the Type A test frequency is extended to 15 years. In addition to the required IWE/IWL inspection, additional visual inspections of the normally accessible portions of the interior and external surface of the containment are completed in accordance with the Technical Requirements Manual (TRM), which includes a requirement to perform this inspection prior to the Type A test.Unit I General Visual General Visual Examination of Examination of Visual Inspection Normally Accessible Calendar Year Type A Test Accessible Exterior Accessible Interior and External Containment Wall, (ILRT) Surfaces Interior Liner 1-PT-61.1A Sufae Surfaces (TRM 3.6.2.7)(IWL) (IWE)1993 4/3/1993 (with Type A) 3/25/1993 1994 1995 1996 2/27/1996 1997 1998 9/27/1998 1999 First required IWE 2000 exam 3/1/2000 X Spring (N1R14)2001 First required IWL exam 9/12/2001 X Summer 2002 2003 X Spring (N1R16) 3/3/2003 2004 X Fall (N1R17) 9/5/2004 2005 2006 2007 10/6/2007 X Winter/Spring X Fall (N1 R19) 9/28/2007 (with Type A)2008 2009 2010 X Fall (N1R21) 10/19/2010 2011 X Summer 9/29/2011 (post earthquake) 2012 2013 2014 2015 X Spring X (with IWE)2016 X (10-year) x X (if Type A)2017 2018 x X (with IWE)2019 2020 2021 X 2022 X (15-year)

X Fall X(with Type A)2023 2024 2025 X Fall X (with IWE)2026 x 2027 2028 X Fall X (with IWE)2029 2030 2031 X X Fall X (with IWE/IWL)2032 2033 2034 X Fall X (with IWE)2035 X 2036 2037 X (15-Year)Page 13 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 Unit 2 General Visual General Visual Examination of Examination of Visual Inspection Normally Accessible Type A Test amination amination Interior and External Containment Wall, Calendar Year (ILRT) Accessible Exterior Accessible 2-PT-61.IA Surfaces Interior Surfaces 2T-6.1A (IWL) (IWE) (TRM 3.6.2.7)1999 X (10-Year)

X Fall (N2R13) (with Type A) 9/10/1999 2000 2001 First required IWL exam-X Summer 2/21/2001 2002 8/18/2002 2003 First required IWE 2004 exam X Spring (N2R16)2005 2006 2007 X Winter/Spring X Spring (N2R18) 3/22/2007 2008 2009 2010 X Spring (N2R20) 3129/2010 2011 X Summer 9/29/2011 (post earthquake) 2012 2013 4/24/2013 2014 X (15-Year)

X Fall (N2R23) X (with Type A)2015 2016 X 2017 X Fall X (with IWE)2018 2019 2020 X Fall X (with IWE)2021 X 2022 2023 X Fall X (with IWE)2024 2025 2026 X X Fall X (with IWE/IWL)2027 _2028 2029 X (15-Year)

X Fall X (with Type A)2030 2031 X 2032 X Fall X (with IWE)If IWE/IWL examinations are performed at the same time those examinations/inspections will be used to satisfy the TRM inspection requirement.

4.5 Deficiencies Identified Consistent with the guidance provided in NEI 94-01, Revision 3, Section 9.2.3.3, abnormal degradation of the primary containment structure identified during the conduct of IWE / IWL program examinations or at other times is entered into the corrective action program for evaluation to determine the cause of the degradation and to initiate appropriate corrective actions.4.6 Plant-Specific Confirmatory Analysis 4.6.1 Methodology An evaluation has been performed to assess the risk impact of extending the North Anna Power Station (NAPS) Units 1 and 2 ILRT intervals from the current 10 years to 15 years. This plant-specific risk assessment followed the guidance in NEI 94-01, Revision 2-A, the methodology Page 14 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 described in EPRI TR-1009325, Revision 2-A and the NRC regulatory guidance outlined in RG 1.174 on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request to change the licensing basis of the plant. In addition, the methodology used for Calvert Cliffs Nuclear Power Plant to estimate the likelihood and risk implication of corrosion-induced leakage of steel containment liners going undetected during the extended ILRT interval was also used for sensitivity analysis.

The current NAPS-2 Level 1 and Large Early Release Frequency (LERF) internal events PRA model was used to perform the plant-specific risk assessment.

This PRA model has been updated to meet Capability Category II of ASME PRA Standard RA-Sb-2005 and RG 1.200, Revision 1. The analyses include evaluation for the dominant external events (seismic and fire) using conservative expert judgment with the information from the NAPS Individual Plant Examination of External Events (IPEEE). Though the IPEEE seismic and fire event models have not been updated since the original IPEEE, the insights and information of IPEEE have been used to estimate the effect on total LERF of including these external events in the ILRT interval extension risk assessment.

In the SE issued by NRC letter dated June 25, 2008, the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE. The following table addresses each of the four limitations and conditions for the use of EPRI TR-1009325, Revision 2.From Section 4.2 of SER North Anna Response 1. The licensee submits documentation indicating that North Anna PRA quality is addressed in the technical adequacy of their PRA is consistent with Section 4.6.2 below the requirements of RG 1.200 relevant to the ILRT Extension.

2. The licensee submits documentation indicating that EPRI Report No. 1009325, Revision 2-A, incorporates the estimated risk increase associated with permanently these population dose and Conditional Containment extending the ILRT surveillance intervalto 15 years is Failure Probability (CCFP) acceptance guidelines, and small, and consistent with the clarification provided in these guidelines have been used for the North Anna Section 3.2.4.5 of the SE. Specifically, a small increase plant specific assessment.

in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is restrictive.

In addition, a small increase in CCFP should be defined as a value marginally greater than that accepted in a previous one-time ILRT extension requests.

This would require that the increase in CCFP be less than or equal to 1.5 percentage point.3. The methodology in EPRI Report No. 1009325, EPRI Report No. 1009325, Revision 2-A, incorporated Revision 2, is acceptable except for the calculation of the the use of 100 La as the average leak rate for the pre-increase in expected population dose (per year of reactor existing containment large leakage rate accident case operation).

In order to make the methodology (accident case 3b), and this value has been used in the acceptable, the average leak rate accident case North Anna plant specific risk assessment.(accident case 3b) used by the licensees shall be 100 La instead of 35 La.4. A licensee amendment request (LAR) is required in North Anna Units 1 and 2 rely on containment instances where containment over-pressure is relied overpressure to assure adequate net positive suction upon for emergency core cooling system (ECCS) head for ECCS pump following design basis accidents.

performance.

Additional risk analysis has been performed to address any change in risk associated with reliance on containment overpressure for ECCS performance.

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-LAR Attachment 1 4.6.2 PRA Quality Level 1 and LERF PRA model that is used for North Anna is characteristic of the as-built plant.The current internal events model (NAPS-R07) is a linked fault tree model. Severe accident sequences have been developed from internally initiated events. The sequences have been mapped to the radiological release end state (i.e. source term release to environment).

The North Anna PRA is based on a detailed model of the plant developed from the Individual Plant Examination which underwent NRC review. Review comments, current plant design, current procedures, plant operating data, current industry PRA techniques, and general improvements identified by the NRC have been incorporated into the current PRA model. The model is maintained in accordance with Dominion PRA procedures.

Two industry peer reviews of the PRA model have been performed.

The first peer review was performed in 2001 using the Westinghouse Owners Group Peer Review Process Guidance, and the Facts and Observations (F&Os) were closed. A full-scope peer review was performed in 2013 using the ASME/ANS PRA Standard RA-Sa-2009, and 92% of the Supporting Requirements (SR)were considered Met with Capability Category 1/11 or greater. The 2013 peer review also determined that no additional work was necessary for the 2001 peer review F&Os. The open gaps identified by the peer review were evaluated for impact on the application.

As such, the updated North Anna PRA model is considered acceptable for use in assessing the risk impact of extending the North Anna Units 1 and 2 containment ILRT surveillance interval to 15 years.4.6.3 Summary of Plant-Specific Risk Assessment Results Based on the risk assessment results and the sensitivity calculations detailed in Attachment 4 of the letter, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to 15 years. These results apply to both Unit 1 and Unit 2.* Reg. Guide 1.174 [3] provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Reg. Guide 1.174 defines very small changes in risk as resulting in increases of CDF below I.OE-06/yr and increases in LERF below 1.OE-07/yr.

Since the ILRT extension was demonstrated to have no impact on CDF for NAPS, the relevant criterion is LERF. The increase in internal events LERF, which includes corrosion, resulting from a change in the Type A ILRT test frequency from three-per-ten years to one-per-fifteen years is conservatively estimated as 1.60E-08/yr (see Table 5.6-1) using the EPRI guidance as written. As such, the estimated change in internal events LERF is determined to be "very small" using the acceptance guidelines of Reg. Guide 1.174. The increase in LERF including both internal and external events is estimated as 1.29E-07/yr (see Table 5.7-2), which is considered a "small" change in LERF using the acceptance guidelines of Reg. Guide 1.174.* Reg. Guide 1.174 [3] also states that when the calculated increase in LERF is in the range of 1.OE-06 per reactor year to 1.OE-07 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.OE-05 per reactor year.Although the total increase in LERF for internal and external events is greater than 1.OE-7 per reactor year, the total LERF can be demonstrated to be well below 1.OE-5 per reactor year. The total base LERF for internal and external events is approximately 1.10E-06/yr based on Table 5.7-2. Given that the increase in LERF for the fifteen-year ILRT interval is 1..29E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-year interval can be estimated as 1.23E-06/yr.

This is well below the RG 1.174 acceptance criteria for total LERF of 1.OE-05/yr.

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-LAR Attachment 1" The change in dose risk for changing the Type A test frequency from three-per-ten years to one-per-fifteen years, measured as an increase to the total integrated dose risk for all accident sequences, is 9.11 E-04 person-rem/yr or 0.18% of the total population dose using the EPRI guidance with the base case corrosion case from Table 5.6-1. EPRI TR-1018243

[18] states that a very small population dose is defined as an increase of < 1.0 person-rem per year or < 1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals.

Moreover, the risk impact when compared to other severe accident risks is negligible.

• The increase in the conditional containment failure frequency from the three-per-ten year frequency to one-per-fifteen year frequency is 0.93% using the base case corrosion case in Table 5.6-1. EPRI TR-1018243

[18] states that increases in CCFP of < 1.5 percentage points are very small. Therefore this increase is judged to be very small.Therefore, increasing the ILRT interval to 15 years is considered to be insignificant since it represents a small change to the NAPS risk profile. Details of the North Anna risk assessment are contained in Attachment 4 to this enclosure.

4.7 Conclusion

NEI 94-01, Revision 3-A, describes an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A and Type C intervals to 15 years and 75 months, respectively.

NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies.

Dominion is adopting the guidance of NEI 94-01, Revision 3-A for the North Anna Units 1 and 2 10 CFR 50, Appendix J testing program plan.Based on the previous ILRT tests conducted at North Anna Units 1 and 2, it may be concluded that extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J and inspection activities performed as part of the North Anna Power Station IWE/IWL ISI program.This experience is supplemented by risk analysis studies, including the North Anna risk analysis provided in Attachment

4. The findings of the North Anna risk assessment confirm the general findings of previous studies, on a plant-specific basis, that extending the ILRT interval from 10 to 15 years results in a small change to the North Anna risk profile.5.0 REGULATORY ASSESSMENT 5.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met.10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment.

In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and Page 17 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 reporting requirements for each type of test. RG 1.163 was developed to endorse NEI 94-01, Revision 0 with certain modifications and additions.

The adoption of the Option. B performance-based containment leakage rate testing for Type A testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed.

Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that review "as-found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained.

The change to the Type A test frequency did not directly result in an increase in containment leakage.Similarly, the proposed change to the Type A test frequency will not directly result in an increase in containment leakage.NEI 94-01, Revision 3-A, describes an approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. The document incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A and Type C intervals to 15 years and 75 months, respectively.

NEI 94-01, Revision 3-A, delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate test frequencies.

In the SEs issued by NRC letters dated June 25, 2008 and June 8, 2012, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of 10 CFR 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions, noted in Section 4.0 of the SEs.EPRI TR-1009325, Revision 2, provides a risk impact assessment for optimized Integrated Leak Rate Test (ILRT) intervals up to 15 years, utilizing current industry performance data and risk informed guidance.

NEI 94-01, Revision 3, states that a plant-specific risk impact assessment should be performed using the approach and methodology described in TR-1009325, Revision 2, for a proposed extension of the ILRT interval to 15 years. In the safety evaluation (SE) issued by NRC letter June 25, 2008, the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of that SE.Based on the considerations above, (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 continue to be conducted in accordance with the site licensing basis, and (3) the approval of the proposed change will not be inimical to the common defense and security or to the health and safety of the public.In conclusion, Dominion has determined that the proposed change does not require any exemptions or relief from regulatory requirements, other than the TS, and does not affect conformance with any regulatory requirements/criteria.

5.2 No Significant Hazards Consideration A change is proposed to the North Anna Nuclear Power Station (NAPS) Units 1 and 2, Technical Specifications 5.5.15, "Containment Leakage Rate Testing Program." The proposed amendment would replace the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, dated July 2012, as the implementation document used by Virginia Electric and Power Company (Dominion) to develop the NAPS performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix Page 18 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 J. The proposed amendment would also extend the interval for the primary containment integrated leak rate test (ILRT), which is required to be performed by 10 CFR 50, Appendix J, from 10 years to no longer than 15 years from the last ILRT and permit Type C testing to be performed at an interval not to exceed 75 months.Dominion has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No.The proposed amendment involves changes to the NAPS Containment Leakage Rate Testing Program. The proposed amendment does not involve a physical change to the plant or a change in the manner in which the plant is operated or controlled.

The primary containment function is to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents.

As such, the containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve any accident precursors or initiators.

Therefore, the probability of occurrence of an accident previously evaluated is not significantly increased by the proposed amendment.

The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A, for development of the NAPS performance-based testing program. Implementation of these guidelines continues to provide adequate assurance that during design basis accidents, the primary containment and its components will limit leakage rates to less than the values assumed in the plant safety analyses.

The potential consequences of extending the ILRT interval to 15 years have been evaluated by analyzing the resulting changes in risk. The increase in risk in terms of person-rem per year within 50 miles resulting from design basis accidents was estimated to be acceptably small and determined to be within the guidelines published in RG 1.174. Additionally, the proposed change maintains defense-in-depth by preserving a reasonable balance among prevention of core damage, prevention of containment failure, and consequence mitigation.

NAPS has determined that the increase in Conditional Containment Failure Probability due to the proposed change is very small.Therefore, it is concluded that the proposed amendment does not significantly increase the consequences of an accident previously evaluated.

Based on the above discussion, it is concluded that the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response:

No.The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A, for the development of the NAPS performance-based leakage testing program, and establishes a 15-year interval for the performance of the containment ILRT. The containment and the testing Page 19 of 20 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 1 requirements to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, do not involve any accident precursors or initiators.

The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) or a change to the manner in which the plant is operated or controlled.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?Response:

No.The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A, for the development of the NAPS performance-based leakage testing program, and establishes a 15-year interval for the performance of the containment ILRT. This amendment does not alter the manner in which safety limits, limiting safety system setpoints, or limiting conditions for operation are determined.

The specific requirements and conditions of the Containment Leakage Rate Testing Program, as defined in the TS, ensure that the degree of primary containment structural integrity and leak-tightness that is considered in the plant's safety analysis is maintained.

The overall containment leakage rate limit specified by the TS is maintained, and the Type A, Type B, and Type C containment leakage tests will be performed at the frequencies established in accordance with the NRC-accepted guidelines of NEI 94-01, Revision 3-A.Containment inspections performed in accordance with other plant programs serve to provide a high degree of assurance that the containment will not degrade in a manner that is not detectable by an ILRT. A risk assessment using the current NAPS PRA model concluded that extending the ILRT test interval from 10 years to 15 years results in a small change to the NAPS risk profile.Therefore, the proposed change does not involve a significant reduction in a margin of safety.Based on the above, Dominion concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

5.3 Environmental Considerations The proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 PRECEDENCE

This request is similar in nature to the license amendments authorized by the NRC on March 30, 2010, for the Nine Mile Point Nuclear Station, Unit 2 (TAC No. ME1650, ADAMS Accession Number ML100730032) and April 7, 2011, for Arkansas Nuclear One, Unit No.2 -Issuance Of Amendment Re: Technical Specification Change To Extend The Type A Test Frequency To 15 Years (TAC No. ME4090, ADAMS Accession Number ML1 10800034).

Page 20 of 20 Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 2 Marked-up Technical Specification Page Virginia Electric and Power Company (Dominion)

North Anna Station Units I and 2 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed.

For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.5.5.15 Containment Leakage Rate Testing Program a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

This program shall be in accordance with the guidelines contained in Regulantm u, Gu 1.163, 2 Pernipplui.e-gabed Ce 1 l l,,iii, t Leak-Tes Program," dated gaptewbr .... a.. d..ifd by the fa!8.....NE. 94-C. 1995, Sectio 9.2.3. The first UWit 2 Type A test peirferncd after the Oetebe 9, 1999 Typ A test shaii b perfcrncd melater than .t ..r 9, 2614.b. The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 42.7 psig. The containment design pressure is 45 psig.c. The maximum allowable containment leakage rate, La, at Pas shall be 0.1ý of containment air weight per day.centli nued NEI 94-01, Revision 3-A,"Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012.North Anna Units 1 and 2 5.5-15 Amendments FHJ-21-59 Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 3 Proposed Technical Specification Page Virginia Electric and Power Company (Dominion)

North Anna Station Units 1 and 2 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed.

For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.5.5.15 Containment Leakage Rate Testing Program a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) 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, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012.b. The calculated peak containment internal pressure for the design basis loss of coolant accident, P,, is 42.7 psig. The containment design pressure is 45 psig.c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.1% of containment air weight per day.(continued)

North Anna Units 1 and 2 5.5-15 Amendments Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Risk Assessment Virginia Electric and Power Company (Dominion)

North Anna Station Units 1 and 2 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table of Contents 1.0 PURPO SE O F ANALYSIS .............................................................................................................................

2 1 .1 P u rp o s e ...............................................................................................................................................

2 1 .2 B a c k g ro u n d .........................................................................................................................................

2 1 .3 C rite ria .................................................................................................................................................

3 2.0 M ETHO DO LO GY ...........................................................................................................................................

3 3.0 G RO UND RULES ..................................................................................................................................

4 ....... 4 4 .0 IN P U T S ..........................................................................................................................................................

5 4.1 General Resources Available

......................................................................................................

5 4.2 Plant-Specific Inputs ............................................................................................................................

8 4.3 Impact of Extension on Detection of Component Failures That Lead to Leakage ............................

10 4.4 Impact of Extension on Detection of Steel Liner Corrosion That Leads to Leakage ........................

12 5 .0 R E S U L T S ....................................................................................................................................................

1 5 5.1 Step 1 -Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year ..............................

16 5.2 Step 2 -Develop Plant-Specific Person-Rem Dose (Population Dose)/Reactor Year .....................

18 5.3 Step 3 -Evaluate Risk Impact of Extending Type A Test Interval From 10 to 15 Years ..................

21 5.4 Step 4 -Determine the Change in Risk in Terms of Large Early Release Frequency (LERF) ....... 23 5.5 Step 5 -Determine the Impact on the Conditional Containment Failure Probability (CCFP) ....... 24 5.6 Sum m ary of Results ..........................................................................................................................

24 5.7 External Events Contribution

.......................................................................................................

26 5.8 Containm ent Overpressure Im pact on CDF .................................................................................

27 6 .0 S E N S IT IV IT IE S ...........................................................................................................................................

2 8 6.1 Sensitivity to Corrosion Im pact Assum ptions ..............................................................................

28 7.0 CO NCLUSIO NS ..........................................................................................................................................

29

8.0 REFERENCES

............................................................................................................................................

30 ATTACHM ENT A, M AAP ANALYSES ..............................................................................................................

32 Page 1 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 1.0 PURPOSE OF ANALYSIS 1.1 Purpose The purpose of this analysis is to provide an assessment of the risk associated with permanently extending the Type A integrated leak rate test (ILRT) interval from 10 years to 15 years for North Anna Power Station (NAPS). The risk assessment follows the guidelines from NEI 94-01, Revision 2-A [1], the methodology used in EPRI TR-104285

[2], the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals

[18], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG)1.174 (3], and the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [4]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the October 2008 EPRI final report [18].1.2 Background Revisions to 10CFR50, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirement from three-per-ten years to at least one-per-ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage rate was less than limiting containment leakage rate of 1La.The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493

[5], "Performance-Based Containment Leak Test Program," provides the technical basis to support rulemaking 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 the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285

[2], "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals." The NRC report on performance-based leak testing, NUREG-1493

[5], analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.

Consequently, it is desirable to confirm that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for NAPS.Earlier ILRT frequency extension submittals have used the EPRI TR-1 04285 [2] methodology to perform the risk assessment.

In October 2008, EPRI TR-1018243

[18] was issued to develop a generic methodology for the risk impact assessment for ILRT interval extensions to 15 years using current performance data and risk informed guidance, primarily NRC Regulatory Guide 1.174 [3]. This more recent EPRI document considers the change in population dose, large early release frequency (LERF), and containment conditional failure probability (CCFP), whereas TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for NAPS employs the EPRI TR-1018243 Page 2 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary.1.3 Criteria The acceptance guidelines in RG 1.174 [3] are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 1.OE-06 per reactor year and increases in large early release frequency (LERF) less than 1.OE-07 per reactor year. An evaluation of the CDF impact in Section 5 confirms that the change in risk is bounded by the LERF impact, so the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 1.OE-06 per reactor year. RG 1.174 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. Therefore, the increase in the conditional containment failure probability (CCFP) is also calculated to help ensure that the defense-in-depth philosophy is maintained.

Regardi ng CCFP, changes of up to 1.1% have been accepted by the NRC for the one-time requests for extension of ILRT intervals.

Given this perspective and based on the guidance in EPRI TR-1018243

[18], a change in the CCFP of up to 1.5% (percentage point) is assumed to be small.In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate the relative change in this parameter.

While no acceptance guidelines for these additional figures of merit are published, examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extension (summarized in Appendix G of EPRI TR-1018243

[18]) indicate a range of incremental increases in population dose that have been accepted by the NRC. The range of incremental population dose increases is from -.0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493 [5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <1.0 person-rem per year, or 1% of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.

It is noted that the methodology used in the one-time ILRT interval extension requests assumed a EPRI TR-1018243 uses 100La. The dose rates are impacted by this change and will be larger than those in previous submittals.

2.0 METHODOLOGY

A simplified bounding analysis approach consistent with the EPRI approach is used for evaluating the change in risk associated with increasing the test interval to 15 years [18]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current NAPS PRA analysis of record and subsequent containment responses resulting in various fission product release categories.

The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report.2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses.Page 3 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 3. Evaluate the risk impact (i.e., the change in containment release scenario type frequency and population dose) of extending the ILRT interval to 15 years.4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [3] and compare with the acceptance guidelines of RG 1.174.5. Determine the impact on the Conditional Containment Failure Probability (CCFP)6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis, external events, and to the fractional contribution of increased large isolation failures (due to liner breach) to LERF.Furthermore,* Consistent with the other industry containment leak risk assessments, the NAPS assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved." Containment overpressure is credited in the ECCS and Recirculation Spray pump NPSH calculations for NAPS [31, 33], so a first-order estimate of the CDF impact is evaluated as a part of the risk impact assessment.

The results of this assessment are compared to the guidelines in RG 1.174 to demonstrate that the change in CDF is acceptable.

• This evaluation for NAPS uses ground rules and methods to calculate changes in risk metrics that are similar to those used in EPRI TR-1018243

[18], Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals.

3.0 GROUND RULES The following ground rules are used in the analysis: " The NAPS Level 1 and Level 2 internal events PRA models provide representative results.* It is appropriate to use the NAPS internal events PRA model as a gauge to effectively describe the risk change attributable to the ILRT extension.

It is reasonable to assume that the impact from the ILRT extension (with respect to percent increases in population dose) will not substantially differ if fire and seismic events were to be included in the calculations.

However, external events have been accounted for in the analysis based on the available information from the NAPS IPEEE as described in Section 5.7.* Dose results for the containment failures modeled in the PRA are contained in NAPS calculation SM-1242 (referred to as the dose results from the NAPS SAMA analysis)[22]." Accident classes describing radionuclide release end states are defined consistent with EPRI methodology

[18] and are summarized in Section 4.2." The representative containment leakage for EPRI Accident Class 1 sequences is 11La.EPRI Accident Class 3 sequences account for increased leakage due to Type A inspection failures." The representative containment leakage for EPRI Accident Class 3a sequences is 10La based on the previously approved methodology performed for Indian Point Unit 3 [6, 7]." The representative containment leakage for EPRI Accident Class 3b sequences is 10OLa based on the guidance provided in EPRI TR-1018243

[18].Page 4 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4* The EPRI Accident Class 3b sequences can be conservatively categorized as LERF based on the previously approved methodology

[6, 7]." The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension, but is accounted for in the EPRI methodology as a separate entry for comparison purposes.

Since the containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from this separate categorization.

• The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal.* All of the calculations for this analysis were performed electronically using Microsoft Excel, which eliminates rounding error. As a result, hand calculations using the values in each table may yield slightly different results.4.0 INPUTS This section summarizes the general resources available as input (Section 4.1) and the plant-specific resources required (Section 4.2).4.1 General Resources Available Various industry studies on containment leakage risk assessment are briefly summarized here 1. NUREG/CR-3539

[8]2. NUREG/CR-4220

[9]3. NUREG-1273

[10]4. NUREG/CR-4330

[11]5. EPRI TR-105189

[12]6. NUREG-1493

[5]7. EPRI TR-104285

[2]8. Calvert Cliffs liner corrosion analysis [4]9. EPRI TR-1018243

[18]The first study is applicable because it provides one basis for the threshold that could be used in the Level 2 PRA for the size of containment leakage that is considered significant and is to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident.

The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database.

The fourth study provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension.

The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and local leak rate test (LLRT) intervals on at-power public risk. The eighth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations.

Finally, the ninth study builds on the previous work and includes a recommended methodology and template for evaluating the risk associated with a permanent 15-year extension of the ILRT interval.Page 5 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 NUREG/CR-3539

[81 Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.

This study uses information from WASH-1400

[14] as the basis for its risk sensitivity calculations.

ORNL concluded that the impact of leakage rates on light water reactor (LWR) accident risks is relatively small.NUREG/CR-4220

[91 NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.The study reviewed over two thousand licensee event reports (LER), ILRT reports and other related records to calculate the unavailability of containment due to leakage.NUREG-1273

[101 A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database.

This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected.

In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system.NUREG/CR-4330

[111 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals.

However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: "...the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189

[121 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because it provides insight regarding the impact of containment testing on shutdown risk. This study contains a quantitative evaluation (using the EPRI ORAM software) for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The conclusion from the study is that a small but measurable safety benefit is realized from extending the test intervals.

NUREG-1493

[51 NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies: Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk. Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk.EPRI TR-104285

[21 Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG- 1150 Level 3 population dose models to perform the analysis.

The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due Page 6 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 to extending the ILRT and LLRT test intervals.

EPRI TR-104285 uses a simplified Containment Event Tree to subdivide representative core damage frequencies into eight classes of containment response to a core damage accident: 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failures due to core damage accident phenomena 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded:

"... the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.04 person-rem per year..." Release Category Definitions Table 4.1-1 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology

[18]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report.Table 4.1-1 EPRI/NEI Containment Failure Classifications EPRI Class EPRI Class Description Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant.Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment.

Independent (or random) isolation failures include those accidents in which the 3 pre-existing isolation failure to seal (i.e., provide a leak-tight containment) is not dependent on the sequence in progress.Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress.4 This class is similar to Class 3 isolation failures, but is applicable to sequences involving Type B tests and their potential failures.

These are the Type B-tested components that have isolated but exhibit excessive leakage.Independent (or random) isolation failures include those accidents in which the 5 pre-existing isolation failure to seal is not dependent on the sequence in progress.This class is similar to Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.Page 7 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 EPRI Class EPRI Class Description Containment isolation failures include those leak paths covered in the plant test 6 and maintenance requirements or verified per in service inspection and testing (ISI/IST) program.Accidents involving containment failure induced by severe accident phenomena.

Changes in Appendix J testing requirements do not impact these accidents.

Accidents in which the containment is bypassed (either as an initial condition or 8 induced by phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.

Calvert Cliffs Response to Request for Additional Information Concerning the License Amendment for a One-Time Integrated Leakage Rate Test Extension

[41 This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension.

The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner.NAPS has a similar type of containment, and the same methodology will be used in this risk impact assessment.

EPRI Report No. 1009325, Revision 2-A, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals

[181 This report provides a risk impact assessment for the permanent extension of ILRT test intervals to 15 years. This document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology

[2]and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER)and Crystal River.The approach included in this guidance document is used in the NAPS risk impact assessment to determine the estimated increase in risk associated with the ILRT extension.

This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5.4.2 Plant-Specific Inputs The plant-specific information used to perform the NAPS ILRT Extension Risk Assessment includes the following: " Internal events PRA model results [19]* Source term category definitions and frequencies used in the Level 2 Model [19, 21]* Source term category population dose within a 50-mile radius [22, 23, 24]* External events PRA model results [25, 26]NAPS Internal Events PRA Model The Level 1 and Level 2 PRA model that is used for NAPS is characteristic of the as-built plant.The current internal events model (NAPS-R07) is a linked fault tree model. Using the average Page 8 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 maintenance model, the Unit 1 model was quantified with the total Core Damage Frequency (CDF) = 1.61E-06/yr and Large Early Release Frequency (LERF) = 1.37E-07/yr, and the Unit 2 model was quantified with the CDF = 1.58E-06/yr and LERF = 1.36E-07/yr

[19].NAPS Source Term Categqory Frequencies The current Level 2 release category definitions were developed in notebook NAPS-LE.1 R2 (referred to as the NAPS Level 2 model using revised LERF fractions)

[21]. The current source term category frequencies were developed from the plant damage state frequencies calculated from the Level 1 and Level 2 PRA model [19] and the relative contributions to CDF for the analyzed containment failure modes documented in NAPS-LE.1

[21]. The total CDF associated with the sum of Unit 1 release category frequencies is 1.72E-06/yr as shown in Table 4.2-1.Since this CDF value is higher than the CDF for both Unit 1 and Unit 2, it is taken as a conservative estimation of the risk for both units. This risk impact assessment will be based on this CDF, and it will be assumed that the results of the assessment are conservative for both Units. Each of the source term categories is associated with a corresponding EPRI class, and the EPRI class frequencies are calculated by summing the associated source term category frequencies.

NAPS Source Term Category Population Dose A plant-specific population dose was developed using MAAP for twelve source term categories (STC) in calculation SM-1 242 [22] for the SAMA analysis.

The source term category diagram in the IPE [23] contained twenty-four source term categories.

Ten of the STCs used the population dose calculated by their respective MAAP runs. The remaining fourteen STCs used recommended alternate population doses from the ten STCs that were evaluated using MAAP as specified in the IPE. The STC diagram has been revised since the IPE. The latest STC Diagram is documented in NAPS-LE.1

[21], and the number of STCs was reduced from twenty-four to seventeen.

The dose results from SM-1242 were correlated to the current STCs by associating sequences in the current STC diagram with sequences in IPE STC diagram. Using calculation SM-1242 [22] in conjunction with NAPS-LE.1

[21] and the IPE [23] allows the population doses to be determined for the current STCs. The STCs which do not result in a release do not have a recommended population dose, which would result in no dose information for EPRI Class 1 binning. The methodology used in calculation SM-1325 (referred to the NAPS one-time ILRT extension)

[24] will be employed in which population dose for STC 2 from the IPE, which would be an EPRI Class 7, will be used as the EPRI Class 1 population dose. This approach is conservative because the STC 2 MAAP run has characteristics that are representative of the EPRI Class 1 containment leakage, but the EPRI Class 1 assumes a much smaller containment leak rate.Release Category Definitions Table 4.2-1 below defines the NAPS release categories and associates them with the EPRI accident classes used in the ILRT extension evaluation.

These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report.Page 9 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 4.2-1 NAPS Release Cateaorv Definitions.

Freauencv.

and Population Dose NAPS Rees 2tar eiiin raec n ouainDs NAPS Frequency Person-Rem' EPRI Category per year (50 miles) Class Description 1 6.11E-07 4.24E+02 3 1 No Containment Failure 2 O.OOE+00 2.35E+06 4 7 Early Containment Failure 3 6.43E-08 1.99E+04 5 7 Late Containment Failure 4 4.17E-09 6.69E+05 5 7 Late Containment Failure 5 3.55E-09 1.99E+04 4 7 Late Containment Failure 6 0.OOE+00 6.69E+05 5 7 Late Containment Failure 7 0.OOE+00 2.68E+05 4 7 Late Containment Failure 8 1.28E-07 5.60E+04 5 7 Late Containment Failure 9 8.01 E-08 5.60E+04 4 7 Late Containment Failure 10 2.86E-08 1.99E+04 5 7 Meltthru 11 6.47E-07 4.24E+02 5 2 No Containment Isolation 12 1.53E-09 3.86E+05 5 2 No Containment Isolation 13 1.15E-08 2.41 E+06 5 8 Event V (ISLOCA) -attenuation 14 1.15E-08 6.15E+06 4 8 Event V (ISLOCA) -no attenuation 15 7.90E-08 4.74E+06 4 8 Steam Generator Tube Rupture 16 2.56E-09 2.37E+066 8 Steam Generator Tube Rupture (non-LERF) 17 4.35E-08 3.86E+05' 8 Containment Failure before Vessel Failure CDF 1.72E-06 LERF I 1.36E-07 1. STC frequencies were calculated using the NAPS Level 1 and Level 2 PRA and the NAPS-LE.1 Revision 2 notebook.2. The population dose for each STC is based on the correlation of the current STCs to the IPE STCs and the population dose results from calculation SM-1 242 for the SAMA analysis.3. The STC 2 population dose from calculation SM-1 242 was used for the current STC 2 based on calculation SM-1 325.4. The population dose was taken from the MAAP run for the associated IPE STC.5. The population dose was taken from the MAAP run for the recommended alternate STC in the IPE.6. The dose for STC 16 is assumed to be half of STC 15 since it is a non-LERF SGTR.Using the data in Table 4.2-1, the frequency and dose for the EPRI accident classes as they apply to North Anna can be calculated.

The frequency of each EPRI class is the sum of the associated STC frequencies, and the doses for classes 2, 7, and 8 are frequency weighted.Table 4.2-2 Summary of Release Frequency and Population Dose Organized by EPRI Release Category EPRI Class Frequency

(/yr) Dose (person-rem) 1 6.11 E-07 4.24E+02 2 6.48E-07 1.33E+03 7 3.09E-07 5.30E+04 8 1.48E-07 3.35E+06 4.3 Impact of Extension on Detection of Component Failures That Lead to Leakage The ILRT can detect a number of component failures such as liner breach, failure of certain bellows arrangements and failure of some sealing surfaces, which can lead to leakage. The proposed ILRT test interval extension may influence the conditional probability of detecting these types of failures.

To ensure that this effect is properly accounted for, the EPRI Class 3 Page 10 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 containment failure classification, as defined in Table 4.1-1, is divided into two sub-classes, Class 3a and Class 3b, representing small and large leakage failures, respectively.

The probability of the EPRI Class 3a and 3b failures is determined consistent with the EPRI guidance [18]. For Class 3a, the probability is based on the maximum likelihood estimate of failure (arithmetic average) from the available data (i.e., 2 "small" failures in 217 tests leads to 2/217=0.0092).

For Class 3b, Jeffrey's non-informative prior distribution is assumed for no"large" failures in 217 tests (i.e., 0.5/(217+1)

= 0.0023).The EPRI methodology

[18] contains information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC regulatory guide 1.174 [3]. This information includes a discussion of conservatisms in the quantitative guidance for delta LERF. The EPRI report [18] describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method.The supplemental information states: The methodology employed for determining LERF (Class 3b frequency) involves conservatively multiplying the CDF by the failure probability for this class (3b) of accident.

This was done for simplicity and to maintain conservatism.

However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage.The application of this additional guidance to the analysis for NAPS would result in a reduction of the CDF applied to the Class 3a and Class 3b CDFs. However, the NAPS risk assessment will conservatively forgo the application of this guidance and will apply the total CDF in the calculation of the Class 3a and 3b frequencies.

Consistent with the EPRI methodology

[18], the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection.

For example, the average time that a leak could go undetected with a three-year test interval is 1.5 years (3 yr / 2), and the average time that a leak could exist without detection for a ten-year interval is 5 years (10 yr / 2). This change would lead to a non-detection probability that is a factor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing.Correspondingly, an extension of the ILRT interval to 15 years can be estimated to lead to about a factor of 5.0 (7.5/1.5) increase in the non-detection probability of a leak.It should be noted that using the methodology discussed above is very conservative compared to previous submittals (e.g., the Indian Point Unit 3 request for a one-time ILRT extension that was approved by the NRC [7]) because it does not factor in the possibility that the failures could be detected by other tests (e.g., the Type B local leak rate tests that will still occur). Eliminating this possibility conservatively over-estimates the factor increases attributable to the ILRT extension.

Page 11 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 4.4 Impact of Extension on Detection of Steel Liner Corrosion That Leads to Leakage An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is evaluated using the methodology from the Calvert Cliffs liner corrosion analysis [4]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner.NAPS has a similar type of containment.

The following approach is used to determine the change in likelihood, due to extending the ILRT, of detecting corrosion of the containment steel liner. This likelihood is then used to determine the resulting change in risk. Consistent with the Calvert Cliffs analysis, the following issues are addressed: " Differences between the containment basemat and the containment cylinder and dome" The historical steel liner flaw likelihood due to concealed corrosion* The impact of aging* The corrosion leakage dependency on containment pressure* The likelihood that visual inspections will be effective at detecting a flaw Assumptions

• Consistent with the Calvert Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures.* The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the NAPS containment analysis.

These events, one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference

[28]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Valley 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9-year period are judged to be adequately represented by the two events in the 5.5-year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. (See Table 4.4-1, Step 1.)" Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is also limited to 70 steel-lined containments and 5.5 years to reflect the years since September 1996 when 10 CFR 50.55a started requiring visual inspection to the time the Calvert Cliffs liner corrosion analysis was performed.

Additional success data was not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date (and have been performed since the time frame of the Calvert Cliffs analysis), and there is no evidence that additional corrosion issues were identified. (See Table 4.4-1, Step 1.)" Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed to double every five years. This is based solely on judgment and is included in this analysis to address the increased likelihood of corrosion as the steel liner ages. (See Page 12 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 4.4-1, Steps 2 and 3) Sensitivity studies are included that address doubling this rate every ten years and every two years.In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated as 1.1% for the cylinder and dome and 0.11% (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure, and the selected values are consistent with a pressure that corresponds to the ILRT target pressure of 37 psig. For NAPS, the containment failure probabilities are less than these values at 42.7 psig [29]. Conservative probabilities of 1% for the cylinder and dome and 0.1% for the basemat are used in this analysis, and sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4)* Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crack formation) in the basemat region is considered to be less likely than the containment cylinder and dome region. (See Table 4.4-1, Step 4)* Consistent with the Calvert Cliffs analysis, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used.To date, all liner corrosion events have been detected through visual inspection. (See Table 4.4-1, Step 5) Sensitivity studies are included that evaluate total detection failure likelihood of 5% and 15%, respectively." Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases.

This approach avoids a detailed analysis of containment failure timing and operator recovery actions.Page 13 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 4.4-1 Steel Liner Corrosion Base Case Step Description Containment Walls Containment Basemat 1 Historical Steel Liner Events: 2 Events: 0 (assume 0.5 failures)Flaw Likelihood 2/(70 -5.5) 5.2E-3 0.5/(70 -5.5) 1.3E-3 2 Age-Adjusted Steel Year Failure Rate Year Failure Rate Liner Flaw Likelihood 1 2.05E-03 1 5.13E-04 2 2.36E-03 2 5.89E-04 3 2.71E-03 3 6.77E-04 4 3.111E-03 4 7.77E-04 5 3.57E-03 5 8.93E-04 6 4.10E-03 6 1.03E-03 7 4.71E-03 7 1.18E-03 8 5.41E-03 8 1.35E-03 9 6.22E-03 9 1.55E-03 10 7.14E-03 10 1.79E-03 11 8.21E-03 11 2.05E-03 12 9.43E-03 12 2.36E-03 13 1.08E-02 13 2.71E-03 14 1.24E-02 14 3.111E-03 15 1.43E-02 15 3.57E-03 3 Flaw Likelihood at 3, 1 to 3 years 0.71% 1 to 3 years 0.18%10,and15years 1to 10 4.14% 1 to 10 years 1.03%years ito 15 9.66% 1 to 15 years 2.41%years 4 Likelihood of Breach Pressure Pressure in Containment (psia) (psia)Given Steel Liner 2.OOE+01 0.1% 2.OOE+01 0.01%Flaw 6.47E+01 1.1% 6.47E+01 0.11%1.OOE+02 7.0% 1.OOE+02 0.70%1.20E+02 20.3% 1.20E+02 2.03%1.50E+02 100.0% 1.50E+02 10.00%5 Visual Inspection Detection Failure 10% 100%Likelihood 6 Likelihood of Non- 3 years 0.00077% 3 years 0.00019%Detected 0.71%* 1.1%* 10% 0.18%* 0.11%* 100%Containment 10 years 0.00445% 10 years 0.00111%Leakage 4.14%* 1.1%* 10% 1.03%* 0.11%* 100%15 years 0.01039% 15 years 0.00260%9.66%* 1.1%* 10% 2.41%* 0.11%* 100%The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 for the containment cylinder and dome and the containment basemat as summarized below for NAPS.Page 14 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Total Likelihood of Non-Detected Containment Leakage Due To Corrosion for NAPS: At 3 years : 0.00077% + 0.00019% = 0.00096%At 10 years : 0.00445% + 0.00111% = 0.00556%At 15 years : 0.01039% + 0.00260% = 0.01298%The above factors are applied to the non-LERF containment overpressure CDF scenarios, and the result is added to the Class 3b frequency in the corrosion sensitivity studies. The non-LERF containment overpressure CDF is calculated by subtracting the Class 1, Class 3b, and Class 8 CDFs from the total CDF so that only Classes 2, 3a, and 7 are included in the CDF calculation.

5.0 RESULTS The application of the approach based on the EPRI guidance [18] has led to the following results. As described in Section 4.2, the results of this assessment are taken as a conservative representation of the risk associated with extending the ILRT frequency for both NAPS Unit 1 and NAPS Unit 2. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes.The analysis performed examined NAPS-specific accident sequences in which the containment remains intact or the containment is impaired.

Specifically, the categorization of the severe accidents contributing to risk was considered in the following manner:* Core damage sequences in which the containment remains intact initially and in the long term (EPRI TR-104285 Class 1 sequences)." Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components.

For example, liner breach or bellows leakage. (EPRI Class 3 sequences)." Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left "opened" following a plant post-maintenance test (e.g., a valve failing to close following a valve stroke test). (EPRI Class 6 sequences).

Consistent with the EPRI guidance, this class is not specifically examined since it will not significantly influence the results of this analysis." Accident sequences involving containment bypassed (EPRI Class 8 sequences), large containment isolation failures (EPRI Class 2 sequences), and small containment isolation "failure-to-seal" events (EPRI Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change." Class 4 and 5 sequences are impacted by changes in Type B and C test intervals; therefore, changes in the Type A test interval do not impact these sequences.

Page 15 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.0-1 EPRI Accident Classes EPRI Accident Description Class 1 No Containment Failure 2 Large Isolation Failures (Failure to Close)3a Small Isolation Failures (liner breach)3b Large Isolation Failures (liner breach)4 Small Isolation Failures (Failure to seal -Type B)5 Small Isolation Failures (Failure to seal-Type C)6 Other Isolation Failures (e.g., dependent failures)7 Failures Induced by Phenomena (Early and Late)8 Bypass (Interfacing System LOCA and Steam Generator Tube Rupture)CDF Sum of all accident class frequencies (including very low and no release)The steps taken to perform this risk assessment evaluation are as follows: Step 1 Quantify the base-line risk in terms of frequency per reactor year for each of the eight accident classes presented in Table 5.0-1.Step 2 Develop plant-specific person-rem dose (population dose) per reactor year for each of the eight accident classes.Step 3 Evaluate the risk impact of extending Type A test interval from three to fifteen and ten to fifteen years.Step 4 Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174.Step 5 Determine the impact on the Conditional Containment Failure Probability (CCFP).5.1 Step I -Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena.

For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks is included in the model. These events are represented by the Class 3 sequences in EPRI TR-104285. Two failure modes were considered for the Class 3 sequences.

These are Class 3a (small breach) and Class 3b (large breach).The frequencies for the severe accident classes defined in Table 5.0-1 were developed for NAPS by first determining the frequencies for Classes 1, 2, 7 and 8 using the categorized sequences and the identified correlations shown in Table 4.2-2, determining the frequencies for Classes 3a and 3b, and then determining the remaining frequency for Class 1. Furthermore, adjustments were made to the Class 3b and hence Class 1 frequencies to account for the impact of undetected corrosion of the steel liner per the methodology described in Section 4.4.Class 1 Sequences This group consists of all core damage accident progression bins for which the containment remains intact (modeled as Technical Specification Leakage).

The frequency per year is initially determined from the Level 2 Release Category 1 listed in Table 4.2-1, which was 6.11 E-07/yr.Page 16 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 With the inclusion of the EPRI 3a and 3b classes, the EPRI Class 1 frequency will be reduced by the EPRI Class 3a and 3b frequencies.

Class 2 Sequences This group consists of all core damage accident progression bins for which a failure to isolate the containment occurs. The frequency per year for these sequences is obtained from the Release Categories 11 and 12 listed in Table 4.2-1, which was 6.48E-07/yr.

Class 3 Sequences This group consists of all core damage accident progression bins for which a pre-existing leakage in the containment structure (e.g., containment liner) exists. The containment leakage for these sequences can be either small (in excess of design allowable but <1OLa) or large (>10OLa).The respective frequencies per year are determined as follows: PROBclass_3a

= probability of small pre-existing containment liner leakage= 0.0092 [see Section 4.3]PROBclass_3b

= probability of large pre-existing containment liner leakage= 0.0023 [see Section 4.3]As described in Section 4.3, the total CDF will be conservatively applied to these failure probabilities in the calculation of the Class 3 frequencies.

Class 3a = 0.0092

• CDF= 0.0092

• 1.72E-06/yr

= 1.58E-08/yr Class 3b = 0.0023

• CDF= 0.0023

• 1.72E-06/yr

= 3.96E-09/yr For this analysis, the associated containment leakage for Class 3A is 1OLa and for Class 3B is 1OOLa. These assignments are consistent with the guidance provided in EPRI TR-1 018243.Class 4 Sequences This group consists of all core damage accident progression bins for which containment isolation failure-to-seal of Type B test components occurs. Because these failures are detected by Type B tests which are unaffected by the Type A ILRT, this group is not evaluated any further in the analysis.Class 5 Sequences This group consists of all core damage accident progression bins for which a containment isolation failure-to-seal of Type C test components.

Because the failures are detected by Type C tests which are unaffected by the Type A ILRT, this group is not evaluated any further in this analysis.Class 6 Sequences This group is similar to Class 2. These are sequences that involve core damage accident progression bins for which a failure-to-seal containment leakage due to failure to isolate the containment occurs. These sequences are dominated by misalignment of containment isolation valves following a test/maintenance evolution.

Consistent with guidance provided in EPRI TR-Page 17 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 1018243, this accident class is not explicitly considered since it has a negligible impact on the results.Class 7 Sequences This group consists of all core damage accident progression bins in which containment failure induced by severe accident phenomena occurs (e.g., overpressure).

For this analysis, the frequency is determined from Release Categories 2 through 10 from the NAPS Level 2 results in Table 4.2-1, and the result is 3.09E-07/yr.

Class 8 Sequences This group consists of all core damage accident progression bins in which containment bypass occurs. For this analysis, the frequency is determined from Release Categories 13 through 17 from the NAPS Level 2 results in Table 4.2-1, and the result is 1.48E-07/yr.

Summary of Accident Class Frequencies In summary, the accident sequence frequencies that can lead to radionuclide release to the public have been derived consistent with the definitions of accident classes defined in EPRI TR-1018243. Table 5.1-1 summarizes these accident frequencies by accident class for NAPS.Table 5.1-1 Accident Class Frequencies Accident Class Description Frequency (1/YR)1 No Containment Failure 5.91 E-07 2 Large Containment Isolation Failures (Failure to close) 6.48E-07 3a Small Isolation Failures (Type A test) 1.58E-08 3b Large Isolation Failures (Type A test) 3.96E-09 4 Small Isolation Failure (Type B test) N/A 5 Small Isolation Failure (Type C test) N/A 6 Containment Isolation Failures (personnel errors) N/A 7 Severe Accident Phenomena Induced Failure 3.09E-07 8 Containment Bypassed 1.48E-07 CDF All CET End States (including intact case) 1.72E-06 5.2 Step 2 -Develop Plant-Specific Person-Rem Dose (Population Dose) Per Reactor Year Plant-specific release analyses were performed to estimate the person-rem doses to the population within a 50-mile radius from the plant. The releases are based on information contained in calculation SM-1242 [22] for the NAPS SAMA analysis, the NAPS-LE.1 R2 notebook [21], the NAPS IPE [23], and calculation SM-1325 [24]. Calculation SM-1242 contains the dose results in Sieverts for the release categories that were evaluated in the SAMA analysis.

The LE.1 notebook [21] and the IPE [22] are used to associate the STCs from the current STC diagram with the STCs from the previous STC diagram which was used during the SAMA analysis.

The IPE [22] is also used to identify the recommended alternate STC with representative results for STCs for which a MAAP run does not exist. Since the Class 1 STCs do not result in containment failure and no population dose has been calculated for these STCs, the Class 1 STC dose can be conservatively represented by the STC 2 dose from the SAMA analysis based on SM-1 325 [24]. The STC 2 dose is documented in SM-1 242 [22], and it would be classified as a Class 7 EPRI release category.

The use of this Class 7 result for the Class 1 Page 18 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 dose is conservative since the STC 2 MAAP run has characteristics that are representative of an EPRI Class 1 containment leakage, but the Class 7 containment leak rate is much greater than the Class 1 containment leak rate. The results of applying these releases to the EPRI containment failure classification are as follows: Class 1 = 4.24E+02 person-rem (at 1.OLa) (1)Class 2 = 1.33E+03 person-rem (2)Class 3a= 4.24E+02 person-rem x 1OLa = 4.24E+03 person-rem (3)Class 3b= 4.24E+02 person-rem x 1OOLa = 4.24E+04 person-rem (3)Class 4 = Not analyzed Class 5 = Not analyzed Class 6 = Not analyzed Class 7 = 5.30E+04 person-rem (4)Class 8 = 3.35E+06 person-rem (5)(1) The dose for the EPRI Class 1 is taken from NAPS calculation SM-1 325 [24] Table 2.(2) The Class 2 dose is assigned from the frequency weighted dose for release categories resulting in containment isolation failure.(3) The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with the guidance provided in EPRI TR-1018243.

(4) The Class 7 dose is assigned from frequency weighted dose for release categories resulting in containment failure.(5) Class 8 sequences involve containment bypass failures; as a result, the person-rem dose is not based on normal containment leakage. The dose for this class is assigned from the frequency weighted dose for release categories resulting in containment bypass.In summary, the population dose estimates derived for use in the risk evaluation per the EPRI methodology

[18] containment failure classifications are provided in Table 5.2-1.Table 5.2-1 Accident Class Population Dose Accident Class Description Person-Rem 1 No Containment Failure 4.24E+02 2 Large Containment Isolation Failures (Failure to close) 1.33E+03 3a Small Isolation Failures (Type A test) 4.24E+03 3b Large Isolation Failures (Type A test) 4.24E+04 4 Small Isolation Failure (Type B test) N/A 5 Small Isolation Failure (Type C test) N/A 6 Containment Isolation Failures (personnel errors) N/A 7 Severe Accident Phenomena Induced Failure 5.30E+04 8 Containment Bypassed 3.35E+06 The above dose estimates, when combined with the results presented in Table 5.1-1, yield the NAPS baseline mean consequence measures for each accident class. These results are presented in Table 5.2-2.Page 19 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.2-2 Accident Class Frequency and Dose Risk for 3-per-10 Year ILRT Frequency Base Case (3 per 10 years)Without Corrosion With Corrosion EPRI Description Person-Rem Frequency Person- Frequency Person- Changerin (1/YR) Rem/YR (1/YR) Rem/YR RemsoR Rem/YR 1 No Containment 4.24E+02 5.91 E-07 2.51 E-04 5.91 E-07 2.51 E-04 -3.95E-09 Failure Large Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04 Close)Small Isolation 3a Failures (liner 4.24E+03 1.58E-08 6.71 E-05 1.58E-08 6.71 E-05 breach)Large Isolation 3b Failures (liner 4.24E+04 3.96E-09 1.68E-04 3.96E-09 1.68E-04 3.95E-07 breach)Small Isolation 4 Failures (Failure to N/A N/A N/A N/A N/A seal -Type B)Small Isolation 5 Failures (Failure to N/A N/A N/A N/A N/A seal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/A dependent failures)Failures Induced 7 by Phenomena 5.30E+04 3.09E-07 1.64E-02 3.09E-07 1.64E-02 --(Early and Late)8 Containment 3.35E+06 1.48E-07 4.96E-01 1.48E-07 4.96E-01 --Bypass Sum of All Total Accident Class 1.72E-06 5.14E-01 1.72E-06 5.14E-01 3.91 E-07 Results Table 5.2-3 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the 3 per 10 years ILRT frequency.

Table 5.2-3 Corrosion Impact on Class 3b Frequency for 3-per-10 year ILRT Frequency Metric Result ILRT Frequency 3 per 10 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.00096%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 9.73E-07/yr Increase in LERF (0.00096%

• 9.73E-07/yr) 9.31 E-1 2/yr Class 3B Frequency (Without Corrosion) 3.96E-09/yr Class 3B Frequency (With Corrosion)

(3.96E-09/yr

+ 9.31 E-1 2/yr) 3.96E-09/yr Page 20 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 5.3 Step 3 -Evaluate Risk Impact of Extending Type A Test Interval From 10 to 15 Years The next step is to evaluate the risk impact of extending the test interval from its current ten-year value to fifteen years. To do this, an evaluation must first be made of the risk associated with the ten-year interval since the base case applies to a three-year interval (i.e., a simplified representation of a three-per-ten interval).

Risk Impact Due to 10-year Test Interval As previously stated, Type A tests impact only Class 3 sequences.

For Class 3 sequences, the release magnitude is not impacted by the change in test interval (a small or large breach remains the same, even though the probability of not detecting the breach increases).

Thus, only the frequency of Class 3a and 3b sequences is impacted.

The risk contribution is changed based on the NEI guidance as described in Section 4.3 by a factor of 3.33 compared to the base case values. The results of the calculation for a 10-year interval are presented in Table 5.3-1.Table 5.3-1 Accident Class Frequency and Dose Risk for I-per-10 Year ILRT Frequency S10-Year Interval (1 per 10 years)Without Corrosion With Corrosion EPRI Description Person-Rem Frequency Person- Frequency Person- Change in (I/YR) Rem/YR (I/YR) Rem/YR Person-Rem/YR 1 No Containment 4.24E+02 5.45E-07 2.31E-04 5.45E-07 2.31E-04 -2.38E-08 Failure Large Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04 Close)3a Small Isolation 3a Failurs(lin 4.24E+03 5.27E-08 2.23E-04 5.27E-08 2.23E-04 --Failures (liner breach)3b Large Isolation 4.24E+04 1.32E-08 5.58E-04 1.32E-08 5.61E-04 2.38E-06 Failures (liner breach)Small Isolation 4 Failures (Failure to N/A N/A N/A N/A N/A --seal -Type B)Small Isolation 5 Failures (Failure to N/A N/A N/A N/A N/A --seal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/A --dependent failures)Failures Induced by 7 Phenomena (Early and 5.30E+04 3.09E-07 1.64E-02 3.09E-07 1.64E-02 --Late)8 Containment Bypass 3.35E+06 1.48E-07 4.96E-01 1.48E-07 4.96E-01 --Sum of All Accident11 Total Ss ResAl A1.72E-06 5.14E-01 1.72E-06 5.14E-01 2.36E-06 Class ResultsI Table 5.3-2 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the one-per-ten years ILRT frequency.

Page 21 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.3-2 Corrosion Impact on Class 3b Frequency for 1-per-10 year ILRT Frequency Metric Result ILRT Frequency 3 per 10 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.00556%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 1.01 E-06/yr Increase in LERF (0.00556%

• 1.01E-06/yr) 5.62E-1 1/yr Class 3B Frequency (Without Corrosion) 1.32E-08/yr Class 3B Frequency (With Corrosion)

(1.32E-08/yr

+ 5.62E-1 1/yr) 1.32E-08/yr Risk Impact Due to 15-Year Test Interval The risk contribution for a 15-year interval is calculated in a manner similar to the 10-year interval.

The difference is in the increase in probability of leakage in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the 3-year interval value, as described in Section 4.3. The results for this calculation are presented in Table 5.3-3.Table 5.3-3 Accident Class Frequency and Dose Risk for 1-per-15 Year ILRT Frequency 15-Year Interval (1 per 15 years)Without Corrosion With Corrosion EPRI Description Person-Rem Frequency Person- Frequency Person- Change in (IYR) Rem/YR (1/YR) Rem/YR Person Rem/YR 1 No Containment 4.24E+02 5.12E-07 2.17E-04 5.12E-07 2.17E-04 -5.71E-08 Failure Large Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04 Close)Small Isolation 3a Failures (liner 4.24E+03 7.91E-08 3.35E-04 7.91E-08 3.35E-04 breach)Large Isolation 3b Failures (liner 4.24E+04 1.98E-08 8.39E-04 1.99E-08 8.44E-04 5.71 E-06 breach)Small Isolation 4 Failures (Failure to N/A N/A N/A N/A N/A seal -Type B)Small Isolation 5 Failures (Failure to N/A N/A N/A N/A N/A seal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/A dependent failures)Failures Induced by 7 Phenomena (Early 5.30E+04 3.09E-07 1.64E-02 3.09E-07 1.64E-02 and Late)8 Containment Bypass 3.35E+06 1.48E-07 4.96E-01 1.48E-07 4.96E-01 Sum of All Total Accident Class 1.72E-06 5.15E-01 1.72E-06 5.15E-01 5.65E-06 Results Page 22 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.3-4 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the 1-per-15 years ILRT frequency.

Table 5.3-4 Corrosion Impact on Class 3b Frequency for 1-per-15 year ILRT Frequency Metric Factor ILRT Frequency 1 per 15 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.01298%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 1.04E-06/yr Increase in LERF (0.01298%*

1.04E-06/yr) 1.35E-10/yr Class 3B Frequency (Without Corrosion) 1.98E-08/yr Class 3B Frequency (With Corrosion)

(1.98E-08/yr

+ 1.35E-10/yr) 1.99E-08/yr 5.4 Step 4 -Determine the Change in Risk in Terms of Large Early Release Frequency (LERF)The risk increase associated with extending the ILRT interval involves the potential that a core damage event that normally would result in only a small radioactive release from an intact containment could in fact result in a larger release due to the increase in probability of failure to detect a pre-existing leak. With strict adherence to the EPRI guidance, 100% of the Class 3b contribution would be considered LERF.Regulatory Guide 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of core damage frequency (CDF) below 1.0E-06/yr and increases in LERF below 1.OE-07/yr, and small changes in LERF as below 1.OE-06/yr.

Because the ILRT does not impact CDF, the relevant metric is LERF.For NAPS, 100% of the frequency of Class 3b sequences can be used as a very conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI guidance methodology).

Based on the original three-per-ten year test interval from Table 5.2-2, the Class 3b frequency is 3.96E-09/yr.

Based on a 10-year test interval from Table 5.3-1, the Class 3b frequency is 1.32E-08/yr, and based on a 15-year test interval from Table 5.3-3, it is 1.98E-08/yr.

Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from three to 15 years is 1.58E-08/yr.

Similarly, the increase due to increasing the interval from 10 to 15 years is 6.61E-09/yr.

As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology), the estimated change in LERF is below the threshold criteria for a very small change when comparing the fifteen-year results to both the current ten-year requirement and the original three-year requirement.

If the effects due to liner corrosion are included in the 15-year interval results, the Class 3b frequency becomes 1.99E-08/yr as shown in Table 5.3-3. Conservatively neglecting the impact of steel liner corrosion On the Class 3b frequency for the three-year and 10-year intervals, the change in LERF associated with the 15-year interval including the effects of steel liner corrosion is 1.60E-08/yr compared to the 3-year interval and 6.74E-09/yr compared to the 10-year interval.

This is an increase in LERF of 1.35E-10/yr from the fifteen-year interval results without corrosion.

These results indicate that the impact due to steel liner corrosion is very small, and the estimated change in LERF is below the threshold criteria for a very small change when Page 23 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 comparing the fifteen-year results with corrosion effects to both the current ten-year requirement and the original three-year requirement.

5.5 Step 5 -Determine the Impact on the Conditional Containment Failure Probability (CCFP)Another parameter that the NRC guidance in RG 1.174 states can provide input into the decision-making process is the change in the conditional containment failure probability (CCFP).The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can be calculated from the results of this analysis.

One of the difficult aspects of this calculation is providing a definition of the "failed containment." In this assessment, the CCFP is defined such that containment failure includes all radionuclide release end states other than the intact state. The conditional part of the definition is conditional given a severe accident (i.e., core damage).The change in CCFP can be calculated by using the method specified in the EPRI TR-1018243.

The NRC has previously accepted similar calculations

[7] as the basis for showing that the proposed change is consistent with the defense-in-depth philosophy.

CCFP = [1 -(Class 1 frequency

+ Class 3a frequency)

/ CDF]

• 100%CCFP 3 = 64.64%CCFP 1 o = 65.18%CCFP 1 5 = 65.56%ACCFP 3-To-l 5 = CCFP 1 5 -CCFP 3 = 0.92%ACCFP 1 0.To.1 5 = CCFP 1 5 -CCFP 1 o = 0.38%The CCFP is also calculated for the 15-year interval to evaluate the impact of the steel liner corrosion impact on the ILRT extension.

The steel liner corrosion effects will be conservatively neglected for the 3-year and 10-year intervals, which will result in a greater change in CCFP.CCFP, 5+corrosion

= 65.57%ACCFP3-To-15+Corrosion

= CCFP15+Corrosion

-CCFP 3 = 0.93%ACCFP1o-To-15+Corrosion

= CCFP15+corrosion

-CCFP 1 o = 0.39%The change in CCFP of approximately 0.93% by extending the test interval to 15 years from the original three-per-ten year requirement is judged to be insignificant.

5.6 Summary of Results The results from this ILRT extension risk assessment for NAPS are summarized in the following Table 5.6-1.Page 24 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.6-1 Summa of Results for ILRT Frequency Extensions Base Case (3 per 10 years) 1 per 10 years 1 per 15 years Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion Person- Person- Delta Person- Person- Delta EPRI Frequency Rem r Frequency Rem per person-rem Frequency Person- Frequency per Delta Frequency Rem per Frequency Rem per person-Class (per year) (per year) (per year) (per year) -rem (per year) (per yr) rem per year year peryear year year per year year year yearyear year 1 5.91E-07 2.51E-04 5.91E-07 2.51E-04 -3.95E-09 5.45E-07 2.31E-04 5.45E-07 2.31E-04 -2.38E-08 5.12E-07 2.17E-04 5.12E-07 2.17E-04 -5.71E-08 2 6.48E-07 8.65E-04 6.48E-07 8.65E-04 0.OOE+00 6.48E-07 8.65E-04 6.48E-07 8.65E-04 0.OOE+00 6.48E-07 8.65E-04 6.48E-07 8.65E-04 0.OOE+00 3a 1.58E-08 6.71E-05 1.58E-08 6.71E-05 0.OOE+00 5.27E-08 2.23E-04 5.27E-08 2.23E-04 0.OOE+00 7.91E-08 3.35E-04 7.91E-08 3.35E-04 0.OOE+00 3b 3.96E-09 1.68E-04 3.96E-09 1.68E-04 3.95E-07 1.32E-08 5.58E-04 1.32E-08 5.61 E-04 2.38E-06 1.98E-08 8.39E-04 1.99E-08 8.44E-04 5.71 E-06 7 3.09E-07 1.64E-02 3.09E-07 1.64E-02 0.00E+00 3.09E-07 1.64E-02 3.09E-07 1.64E-02 0.OOE+00 3.09E-07 1.64E-02 3.09E-07 1.64E-02 0.OOE+00 8 1.48E-07 4.96E-01 1.48E-07 4.96E-01 0.00E+00 1.48E-07 4.96E-01 1.48E-07 4.96E-01 0.OOE+00 1.48E-07 4.96E-01 1.48E-07 4.96E-01 0.OOE+00 Total 1.72E-06 5.14E-01 1.72E-06 5.14E-01 3.91E-07 1.72E-06 5.14E-01 1.72E-06 5.14E-01 2.36E-06 1.72E-06 5.15E-01 1.72E-06 5.15E-01 5.65E-06 Delta 5.28E-04 5.30E-04 9.06E-04 9.11 E-04 Dose 1 N/A N/A 0.10% 0.10% 0.18% 0.18%CCFP 64.64% 64.64% 65.18% 65.18% 65.56% 65.57%Delta CCFP 2 N/A N/A 0.54% 0.54% 0.92% 0.93%Class 3.96E-09 1.32E-08 1.99E-08 3b 3.96E-09 (9.31E-12) 1.32E-08 (5.62E-11) 1.98E-08 (1.35E-10)

LERF 3 D 9.27E-09 1.60E-08 Delta LERF From Base Case (3 per 10 years)3 9.22E-09 (562E1 1) 1.58E-08(1.5E-10) 6.74E-09 Delta LERF From 1 per 10 years 3 N/A 6.61E-09 6.74E-09 (1.35E-10)

1. The delta dose is expressed as both change in dose rate (person-rem/year) from base dose rate and as % of base total dose rate.2. The delta CCFP is calculated with respect to the base case CCFP.3. The delta between the results with and without corrosion for each interval is shown in parentheses below the results with corrosion.

Page 25 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 5.7 External Events Contribution Since the risk acceptance guidelines in RG 1.174 are intended for comparison with a full-scope assessment of risk including internal and external events, an analysis of the potential impact from external events is presented here.The IPEEE only evaluated the external events risk associated with NAPS Unit 1 although unique scenarios were included for Unit 2. The Unit 2 internal fire CDF was slightly higher than the Unit 1 CDF, so the Unit 2 CDF (4.08E-6/yr) was used for the external events calculation as a result. It was determined that the differences between Unit 1 and Unit 2 would have negligible impact on the PRA results, so the IPEEE CDF and LERF were taken as representative of both Unit 1 and Unit 2.Similarly, this risk impact assessment assumes that the results shown in Table 5.7-2 are representative of both Unit 1 and Unit 2.No seismic PRA quantification is available for North Anna since the seismic margins method was used in the IPEEE [25]. A comparison of the Surry internal fire CDF and seismic CDF from the Surry IPEEE, which were estimated to be 6.3E-6/yr

[20] and 8.OE-6/yr

[27], respectively, shows that the seismic CDF was estimated to be 27% higher than the internal fire CDF. Since there is uncertainty related to differences between Surry and North Anna's designs and seismic hazard curves, the North Anna seismic CDF will be assumed to be 100% higher than, or double, the internal fire CDF. As a result, the seismic CDF is assumed to be 8.16E-6/yr for this evaluation.

This estimation is judged to be acceptable for an order-of-magnitude estimate of the seismic external events contribution to the LERF increase resulting from extending the ILRT interval from 10 years to 15 years.The method chosen to account for external events contributions is similar to the approach used to calculate the change in LERF for the internal events using the guidance in EPRI TR-1 018243 [18].The Class 3b frequency for the internal events analysis was calculated by multiplying the total CDF by the probability of a Class 3b release. The same approach will be used for external events using the CDF for internal fires and seismic. Other external events such as high winds, external floods, transportation, and nearby facility accidents were considered and screened in the IPEEE [25], so their impact will be assumed to be negligible compared to the impact associated with internal fires and seismic events. The North Anna IPEEE [25] did not evaluate LERF. However, the internal fire and seismic LERF will be estimated using the ratio of LERF to CDF from the internal events model.Table 5.7-1 External Events Base CDF and LERF External Event Initiator Group CDF LERF Internal Events (CDF

• Internal Events Ratio) LERF/CDF Ratio Seismic 8.16E-06 6.45E-07 7.90E-02 Internal Fire 4.08E-06 3.22E-07 7.90E-02 Total 1.22E-05 9.67E-07 Table 5.7-2 shows the calculation of the base Class 3b frequency for internal and external events, the increased Class 3b frequency as a result of the ILRT interval extension, and the total change in LERF.Page 26 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Table 5.7-2 Total LERF Increase for 15-year ILRT Interval Including Internal and External Events Initiating Class 3b Frequency

(/yr) LERF Event CDF LERF Class 3b 3 per 10 1 per 10 1 per 15 Increase Group (/yr) (/yr) Probability year year ILRT ILRT year ILRT (Iyr)Internal 1.72E- 1.36E- 0.0023 3.96E-09 1.32E-08 1.98E-08 1.58E-08 Events 06 07 External 1.22E- 9.67E- 0.0023 2.82E-08 9.40E-08 1.41E-07 1.13E-07 Events 05 07 Total 1.40E l11E- -3.22E-08 1.07E-07 1.61E-07 1.29E-07 05 06 As with the internal events analysis, 100% of the frequency of Class 3b sequences can be used as a very conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI guidance methodology).

Based on the total three-per-ten year test interval from Table 5.7-2, the Class 3b frequency is 3.22E-08/yr.

Based on a 10-year test interval, it is 1.07E-07/yr, and based on a 15-year test interval, it is 1.61E-07/yr.

Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years is 1.29E-07/yr and from 10 to 15 years is 5.36E-08/yr.

As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology), the estimated change in LERF is small according to RG 1.174 since it falls below 1.OE-07/yr when comparing the 15-year result to the current 10-year requirement and between 1.OE-07/yr and 1.OE-06/yr when comparing the 15-year result to the original 3-year requirement.

5.8 Containment Overpressure Impact on CDF The NAPS design basis calculations credit containment overpressure to satisfy the net positive suction head (NPSH) requirements for recirculation spray (RS) and low-head safety injection (LHSI) in recirculation mode during loss of coolant accidents (LOCA). However, these calculations do not evaluate the effect of an increased containment leak rate on the NPSH of the pumps. In addition, only large LOCAs are considered in the design basis calculations since this is the most limiting case for the analysis.

Several cases were evaluated using MAAP in order to determine if NPSH would be lost for the RS pumps and LHSI pumps during small, medium, and large LOCAs with a 100La containment leak rate. The MAAP analysis, documented in Attachment D, demonstrated that NPSH would not be lost for any RS or LHSI pumps for any LOCA size evaluated.

Based on these results, a more detailed CDF evaluation does not need to be performed, and the impact of the ILRT interval extension is bounded by the LERF analysis.Page 27 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 6.0 SENSITIVITIES 6.1 Sensitivity to Corrosion Impact Assumptions The results in Tables 5.2-2, 5.3-1 and 5.3-3 show that including corrosion effects calculated using the assumptions described in Section 4.4 does not significantly affect the results of the ILRT extension risk assessment.

Sensitivity cases were developed to gain an understanding of the sensitivity of the results to the key parameters in the corrosion risk analysis.

The time for the flaw likelihood to double was adjusted from every five years to every two and every ten years. The failure probabilities for the cylinder and dome and the basemat were increased and decreased by an order of magnitude.

The total detection failure likelihood was adjusted from 10% to 15% and 5%. The results are presented in Table 6.1-1. In every case the impact from including the corrosion effects is minimal. Even the upper bound estimates with conservative assumptions for all of the key parameters yield increases in LERF due to corrosion of only 2.37E-08 /yr. The results indicate that even with conservative assumptions, the conclusions from the base analysis would not change.Table 6.1-1 Liner Corrosion Sensitivity Cases Steel Increase in Class 3b Containment Visual Inspection Frequency (LERF) for ILRT Age Breach & Non-Visual Likelihood Extension from 3-per-10 to (Step 2) (Step 4) Flaws Flaw is LERF 1-per-15 Years (/yr)(Step 5) Increase Due Total to Corrosion Increase Base Case Base Case Base Case Base Case Double/5 Years 1.1/0.11 10% 100% 1.35E-10 1.60E-08 Double/2 Years Base Base Base 1.24E-09 1.71 E-08 Double/1 0 Years Base Base Base 7.28E-1 1 1.59E-08 Base Base Point 1Ox Lower Base Base 2.97E-11 1.59E-08 Base Base Point 10x Higher Base Base 6.10E-10 1.64E-08 Base Base 5% Base 8.07E-11 1.59E-08 Base Base 15% Base 1.88E-10 1.60E-08 Lower Bound Double/10 Years Base Point 1Ox Lower 5% 10% 9.65E-13 1.58E-08 Upper Bound Double/2 Years Base Point 10x Higher 15% 100% 7.88E-09 2.37E-08 Page 28 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4

7.0 CONCLUSION

S Based on the results from Section 5 and the sensitivity calculations presented in Section 6, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test interval from the current 10 years to 15 years. These results apply to both Unit 1 and Unit 2." Reg. Guide 1.174 [3] provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Reg. Guide 1.174 defines very small changes in risk as resulting in increases of CDF below 1.0E-06/yr and increases in LERF below 1.OE-07/yr.

Since the ILRT extension was demonstrated to have no impact on CDF for NAPS, the relevant criterion is LERF. The increase in internal events LERF, which includes corrosion, resulting from a change in the Type A ILRT test frequency from three-per-ten years to one-per-fifteen years is conservatively estimated as 1.60E-08/yr (see Table 5.6-1) using the EPRI guidance as written. As such, the estimated change in internal events LERF is determined to be "very small" using the acceptance guidelines of Reg. Guide 1.174. The increase in LERF including both internal and external events is estimated as 1.29E-07/yr (see Table 5.7-2), which is considered a "small" change in LERF using the acceptance guidelines of Reg. Guide 1.174." Reg. Guide 1.174 [3] also states that when the calculated increase in LERF is in the range of 1.OE-06 per reactor year to 1.OE-07 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.OE-05 per reactor year.Although the total increase in LERF for internal and external events is greater than 1.OE-7 per reactor year, the total LERF can be demonstrated to be well below 1.OE-5 per reactor year. The total base LERF for internal and external events is approximately 1.1E-06/yr based on Table 5.7-2. Given that the increase in LERF for the 15-year ILRT interval is 1.29E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-year interval can be estimated as 1.23E-06/yr.

This is well below the RG 1.174 acceptance criteria for total LERF of 1.OE-05/yr.

• The change in dose risk for changing the Type A test frequency from three-per-ten years to one-per-fifteen years, measured as an increase to the total integrated dose risk for all accident sequences, is 9.11 E-04 person-rem/yr or 0.18% of the total population dose using the EPRI guidance with the base case corrosion case from Table 5.6-1. EPRI TR-1018243

[18] states that a very small population dose is defined as an increase of - 1.0 person-rem per year or - 1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals.

Moreover, the risk impact when compared to other severe accident risks is negligible.

• The increase in the conditional containment failure frequency from the three-per-ten year frequency to one-per-fifteen year frequency is 0.93% using the base case corrosion case in Table 5.6-1. EPRI TR-1018243

[18] states that increases in CCFP of < 1.5 percentage points are very small. Therefore this increase judged to be very small.Therefore, increasing the ILRT interval from 10 to 15 years is considered to be insignificant since it represents a small change to the NAPS risk profile.Page 29 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 Previous Assessments The NRC in NUREG-1493

[5] has previously concluded that:* Reducing the frequency of Type A tests (ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

• Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated.

Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.

The findings for NAPS confirm these general findings on a plant specific basis considering the severe accidents evaluated for NAPS, the NAPS containment failure modes, and the local population surrounding NAPS within 50 miles.

8.0 REFERENCES

[1] Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, NEI 94-01 Revision 2-A, October 2008.[2] Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI, Palo Alto, CA EPRI TR-104285, August 1994.[3] An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174 Revision 1, November 2002.[4] Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Letter from Mr. C. H.Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No.50-317, March 27, 2002.[5] Performance-Based Containment Leak-Test Program, NUREG-1493, September 1995.[6] Letter from R. J. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-007, January 18, 2001.[7] United States Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No. 3-Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing (TAC No. MB0178), April 17, 2001.[8] Impact of Containment Building Leakage on LWR Accident Risk, Oak Ridge National Laboratory, NUREG/CR-3539, ORNL/TM-8964, April 1984.[9] Reliability Analysis of Containment Isolation Systems, Pacific Northwest Laboratory, NUREG/CR-4220, PNL-5432, June 1985.[10] Technical Findings and Regulatory Analysis for Generic Safety Issue II.E. 4.3 'Containment Integrity Check', NUREG-1 273, April 1988.[11] Review of Light Water Reactor Regulatory Requirements, Pacific Northwest Laboratory, NUREG/CR-4330, PNL-5809, Vol. 2, June 1986.[12] Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMTM, EPRI, Palo Alto, CA TR-1 05189, Final Report, May 1995.[13] Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG- 1150, December 1990.[14] United States Nuclear Regulatory Commission, Reactor Safety Study, WASH-1400, October 1975.Page 30 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4[15] Letter from J.A. Hutton (Exelon, Peach Bottom) to U.S. Nuclear Regulatory Commission, Docket No. 50-278, License No. DPR-56, LAR-01-00430, dated May 30, 2001.[16] Risk Assessment for Joseph M. Farley Nuclear Plant Regarding ILRT (Type A) Extension Request, prepared for Southern Nuclear Operating Co. by ERIN Engineering and Research, P0293010002-1929-030602, March 2002.[17] Letter from D.E. Young (Florida Power, Crystal River) to U.S. Nuclear Regulatory Commission, 3F0401-11, dated April 25, 2001.[18] Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, TR-1018242, Revision 2-A of 1009325, EPRI, Palo Alto, CA: 2008.[19] PRA Model Notebook NAPS-QU.2 Revision 6, Model Quantification Results, Dominion Resources Services, Inc., North Anna Power Station NAPS-R07 PRA Model, October 2013.[20] Individual Plant Examination of Non-Seismic External Events and Fires, Surry Power Station Units 1 and 2, Virginia Electric and Power Company, December 1994.[21] PRA Model Notebook NAPS-LE.1 Revision 2, Level 2 Analysis, Dominion Resources Services, Inc., North Anna Power Station, October 2013.[22] Calculation Number SM-1242, MACCS2 Model for North Anna Level 3 Application, Dominion Resources Services, Inc., Surry Power Station, February 2000.[23] Probabilistic Risk Assessment For the Individual Plant Examination Final Report, North Anna Power Station Units 1 and 2, Virginia Electric and Power Company, December 1992.[24] Calculation Number SM-1 325, Risk Impact Assessment of Extending Containment Type A Test Interval at North Anna Power Station, Virginia Electric and Power Company, North Anna Power Station, October 2001.[25] Individual Plant Examination of Non-Seismic External Events and Fires, North Anna Power Station Units 1 and 2, Virginia Electric and Power Company, April 1994.[26] Individual Plant Examination of External Events -Seismic, North Anna Power Station Units 1 and 2, Virginia Electric and Power Company, May 1997.[27] EQE Report 250226-R-001 Revision 0, Sequence Quantification, Seismic IPEEE, Surry Power Station Units 1 and 2, Virginia Electric and Power Company, November 1997.[28] Letter from P. B. Cowan (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information

-License Amendment Request for Type Test Extension", NRC Docket No. 50-277, May 2010.[29] Administrative Controls 5.5.15, "Containment Leakage Rate Testing Program", Technical Specifications and Bases, North Anna Power Station Units 1 and 2, Dominion Resources Services, Inc., North Anna Power Station, January 2014.[30] NOT USED[31] DOM-NAF-3-0.0-NP-A, "GOTHIC Methodology for Analyzing the Response to Postulated Pipe Ruptures Inside Containment", Dominion, September 2006.[32] NOT USED[33] SM-1 513, "North Anna GOTHIC Analysis of NPSH Available for the LHSI and RS Pumps", Dominion, August 2007.[34] PRA Model Notebook NAPS-Appendix A Revision 1, PRA Model Reviews, Dominion Resources Services, Inc., North Anna Power Station, July 2010.[35] PRA Model Notebook SPS-Appendix A.1 Revision 1, Internal Events Model Independent Assessment, Dominion Resources Services, Inc., North Anna Power Station, June 2010.[36] LTR-RAM-II-14-001, North Anna Nuclear Plant RG 1.200 Internal Events and Internal Flooding PRA Peer Review Report, Westinghouse Electric Company LLC, 2013 PWROG PRA Peer Review, April 2014.Page 31 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 ATTACHMENT A, MAAP ANALYSES The purpose of this attachment is to document MAAP cases analyzed in support of the North Anna Power Station ILRT extension application.

MAAP analyses were performed for different break size LOCAs to demonstrate that assuming an increased leakage from containment exceeding design leakage by a factor of 100, enough NPSH would still be available to the Recirculation Spray pumps to successfully perform containment heat removal function.The MAAP cases analyzed were l in-SLOCA, 2in-SLOCA, 4in-MLOCA, 6in-MLOCA, and 31in-LLOCA, respectively for 1", 2", 4", 6" and 31" break LOCAs. It was assumed that both CS pumps and all four RS pumps were available to start and run on demand. The IRS pumps were assumed to start on high containment pressure signal concurrent with RWST level below 60%, and ORS pumps would start two minutes later. It was assumed that all RS pumps would fail immediately after loss of NPSH (no pump cavitation was allowed).

It was assumed that sump recirculation was established automatically when RWST level dropped below 23%.The design leakage from containment is assumed to be 0.1% of the free containment air weight at design containment pressure within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This is increased by a factor of 100 to 10% for the purposes of ILRT analyses.

According to NAPS MAAP input parameter VOLRB(1) through VOLRB(11) that represent containment volumes in different compartments, the total modeled containment volume is 1,842,070 ft 3 which converts to 88,693 lbs of air (see table below).Total Containment Volume and Air Weight 1 Compartment Weight (Ib) Volume (ft 3)1 607 12570 2 14759 306000 3 8053 167000 4 2155 44700 5 2213 45900 6 2517 52200 7 2120 44000 8 1615 33500 9 28733 596900 10 24918 518500 11 1003 20800 Total 88693 1842070 So, 10% of that within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is calculated to about 370 lbs/hr of leakage from containment.

Because the containment volume used is slightly less than the maximum free containment volume of 1,916,000 ft 3 per UFSAR Table 6.2-2, the target leakage from containment was increased to 500 lbs/hr. The equivalent containment break area to result in 500 lbs/hr leakage is about 2.636E-3 ft 2 (obtained by iterative MAAP runs using parameter WRB(2)). It should be noted that since this break area results in 500 lbs/hr leakage at 20-25 psia of containment pressure, it will result in a higher leakage at containment design pressure of 60 psia, thus making the selection of this break area conservative for the purposes of ILRT analysis.1 Air weight is obtained from MAAP output parameter MGRB(1) through MGRB(11) taken at time = 0 Page 32 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 The output results of cases 1 in-SLOCA, 2in-SLOCA, 4in-MLOCA, 6in-MLOCA and 31 in-LLOCA did not include any loss of NPSH. This is well demonstrated by Figures D-1 through D-5. All MAAP input and output files are provided below.I-- 1" Break LOCA 0.E E M 0 U-9 8 7 6 5 4 3 2 1 0 0 5 10 15 20 25 Time (hr)Figure D-1: 1" Break LOCA, Water Level in Containment Sump Page 33 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 2" Break LOCA 0.E E 0 9 8 7 6 5 4 3 2 1 0 0 5 10 15 20 Time (hr)Figure D-2: 2" Break LOCA, Water Level in Containment Sump 25 4" Break LOCA 9 1 8 cL 7.E 0U 5 E 4'( 4 0 3 0 5 10 1 02 Time (hr)15 20 25 Figure D-3: 4" Break LOCA, Water Level in Containment Sump Page 34 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 6" Break LOCA 0.E E 0 U 4-'9 8 7 6 5 4 3 2 1 0 0 5 10 15 20 Time (hr)Figure D-4: 6" Break LOCA, Water Level in Containment Sump 25 Page 35 of 36 Serial No 14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 4 31" Break LOCA 10 CL E 3.E 4.r 0 U 1 0 0 5 10 15 20 25 Time (hr)Figure D-5: 31" Break LOCA, Water Level in Containment Sump MAAP Input and Output Files Page 36 of 36 Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 5 PRA Technical Adequacy Virginia Electric and Power Company (Dominion)

North Anna Station Units I and 2 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 PRA TECHNICAL ADEQUACY The PRA model used to analyze the risk of this application is the CAFTA accident sequence model referred to as NAPS-R07 [19]. The effective date of this model is October 16, 2013. North Anna PRA Model Notebook QU.2, Rev. 6 [19] documents the quantification of the PRA model. This is the most recent evaluation of the NAPS internal events at-power risk profile. The PRA model is maintained and updated under a PRA configuration control program in accordance with Dominion procedures.

Plant changes, including physical and procedural modifications and changes in performance data, are reviewed and the PRA model is updated to reflect such changes periodically by qualified personnel, with independent reviews and approvals.

Summary of the NAPS PRA History: The Level 1 and Level 2 NAPS PRA analyses were originally developed and submitted to the NRC in 1992 as the Individual Plant Examination (IPE) Submittal.

The NAPS PRA has been updated many times, since the original IPE. A summary of the NAPS PRA history is as follows:* 1992 Original IPE* 1994 Submitted IPEEE Seismic only* 1997 Submitted IPEEE Fire and other External Events* 1997 Data update; update to address issues needed to support the Maintenance Rule program* 2000 Model Update to Support WOG PRA Peer Review* 2000 Addressed several F&Os identified during PRA Peer Review* 2005 Data update; update to address requirements for MSPI* 2007 Data update; addressed ASME PRA Standard SRs that were not met;extensive changes throughout the model as the model was converted to Cafta* 2013 Data update; addressed ASME PRA Standard SRs that were not met;implemented enhancements to system fault trees, event trees and modeling of various elements such as ISLOCA, ATWS, flooding.The NAPS PRA model has benefited from the following comprehensive technical PRA peer reviews. In addition, the self-identified model issues tracked in the PRA configuration control program were evaluated and do not have any impact on the results of the application.

NEI PRA Peer Review The NAPS internal events PRA received a formal industry PRA Peer Review in 2001[34]. The purpose of the PRA Peer Review process is to provide a method for establishing the technical quality of a PRA for the spectrum of potential risk-informed plant licensing applications for which the PRA may be used. The PRA Peer Review process uses a team composed of industry PRA and system analysts, each with Page 1 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 significant expertise in both PRA development and PRA applications.

This team provides both an objective review of the PRA technical elements and a subjective assessment, based on their PRA experience, regarding the acceptability of the PRA elements.

The team uses a set of checklists as a framework within which to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA products available.

The NAPS review team used the "Westinghouse Owners Group (WOG) Peer Review Process Guidance" as the basis for the review.The general scope of the implementation of the PRA Peer Review includes review of eleven main technical elements, using checklist tables (to cover the elements and sub-elements), for an at-power PRA including internal events, internal flooding, and containment performance, with focus on LERF.The facts and observations (F&Os) from the 2001 PRA Peer Review were prioritized into four categories (A through D) based upon importance to the completeness of the model. The 2013 Full Scope Peer Review team reviewed the F&Os and their associated dispositions from the 2001 peer review and concluded that no additional work is needed [36].NAPS PRA Self-Assessment A self-assessment/independent review of the NAPS PRA [35] against the ASME PRA Standard was performed by Dominion with the support of a contracting company, MARACOR, in late 2007 using guidance provided in NRC Regulatory Guide RG 1.200, revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results from Risk-Informed Activities".

This self-assessment was documented and used as a planning guide for the NAPS 2009 model update.2013 NAPS PRA Full Scope Peer Review A full scope peer review of the NAPS PRA model against the requirements of the ASME/ ANS PRA standard [36] and any Clarifications and Qualifications provided in the NRC endorsement of the Standard contained in Revision 2 to RG 1.200 was conducted in November 2013 by the Pressurized Water Reactor Owners Group (PWROG). This peer review was performed using the process defined in NEI 05-04.In the course of this review, seventy-two (72) new F&Os were prepared, including thirty-five (35) suggestions, thirty-five (35) findings, and two (2) best practices.

Many of these F&Os involve documentation issues. The 35 suggestions do not affect the technical adequacy of the PRA model and have no impact on the results of this evaluation.

The 35 findings have been evaluated as described in Table B.1 below.As part of this review, the review team also reviewed previous F&Os and associated dispositions.

The review concluded that these "old F&Os" and associated dispositions do not impact the current review and no additional work was identified as being needed from these "old F&Os" and their associated dispositions.

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-LAR Attachment 5 Table B.1 Thirtv-Four Findinas from 2013 NAPS PRA Full Scone Peer Review ["36'Other No. F&O # Level Affected Issue Impact on Application SRs 2 IE-A6-01 Finding Discussion:

Common cause and routine system alignments are Common cause initiating generally appropriately considered for complicated safety system events are expected to have initiating event fault trees. However, for other systems (notably, electrical relatively low frequencies, systems) there is no discussion or evidence of a review for initiators due and their impact on the CDF to common cause of electrical systems nor due to routine system and LERF are bounded by alignments.

GARD NF-AA-PRA-101-204C identifies that transformers, an order of magnitude battery chargers, and inverters are candidates for common cause. These increase.

The sensitivity common cause failures are modeled in the core damage mitigation fault study in Attachment C trees. However, these common cause failures are not considered as demonstrates that an order initiating events, particularly for RSST 4KV transformers, vital inverters, of magnitude increase in and 125VDC battery chargers.

Also, for example, unavailability of a CDF or LERF does not backup battery charger may drive a plant shutdown given loss of the impact acceptability of the normally operating charger. results for this application.

In addition, could not find a discussion of why common cause blockage of service water travelling screens was not considered.

Basis for Significance:

IE-A6 CAT II requires a systematic evaluation of initiating events, including events resulting from multiple failures resulting from common cause or from routine system alignments.

Notebook IE. 1 says that due to the independency of busses, the loss of more than one bus at a time is assessed as negligible frequency, however this statement does not consider common cause. No evidence of a systematic evaluation is evident.Possible Resolution:

Perform this systematic review and document it.In particular, provide a basis for not including the potential common cause initiating events described above, as these initiators may be significant.

Incorporate any new initiating events into the model.Page 3 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 4 IE-Cl-01 Finding Discussion:

Plant specific-only data are used for some initiating events. The plant specific frequency Initiating event SPUR-SIS has only one failure, but there is no justification for SPUR-SIS is only 15%for not incorporating generic data. lower than the generic frequency.

The expected Basis for Significance:

Initiating event SPUR-SIS uses plant-specific impact on CDF and LERF data, but not justification made that there is adequate plant-specific data due to this difference is to characterize the parameters.

minimal. As a result, this gap has no impact on the Possible Resolution:

Justify use of only plant-specific data for the application.

SPUR-SIS initiating event.6 IE-C3-01 Finding Discussion:

Many recovery actions are credited in SSIE fault trees. No There is little to no impact on discussion or analysis was found to justify these credits. CDF or LERF as this is primarily a documentation Basis for Significance:

SR IE-C3 requires justification for credited enhancement.

As a result, recoveries in initiating events. These recoveries are also used in the this gap has no impact on post-initiating event mitigation tree. the application.

Possible Resolution:

Evaluate these initiating event human error probability items to assure that the assumptions, cues, and procedures I are appropriate for use as initiating event recoveries.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 10 AS-Al 0- Finding IE-B3 Discussion:

Differences in transient initiating event group are not clearly Loss of condenser vacuum is 01 described impact of the loss of condenser vacuum which affects steam not an issue since makeup to dump capability and operability of main feed water and the spurious SI the condenser is available at which challenges PORV open. Loss of condenser vacuum is not explicitly NAPS, so MFW can still be modeled and is treated as a transient with MFW, which affect steam used to supply water to the dump capability and main feedwater.

Spurious SI event increases RCS SGs.pressure and subsequently open a PORV when operator fails to terminate the SI. A sensitivity study in which the spurious SI initiating Basis for Significance:

General transient event tree logic should capture event was modeled as a the differences.

small LOCA was performed by adding the %U1-SPUR-Possible Resolution:

The difference should be properly captured in the SIS event under the same accident sequence analysis.

gates as the %U1-SLOCA events. The same was done for the Unit 2 initiating events. The resulting changes in CDF and LERF are bounded by the sensitivity in Attachment C.The sensitivity study in Attachment C demonstrates that an order of magnitude increase in CDF or LERF does not impact acceptability of the results for this application.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 14 AS-B6-01 Finding Discussion:

No discussion could be identified in the AS calculation and There is little to no impact on supporting information with respect to plant configurations and CDF or LERF as this is maintenance practices creating dependencies among various system primarily a documentation alignments, enhancement.

As a result, this gap has no impact on Basis for Significance:

System alignments could have an impact on the the application.

risk profile if unique plant configurations or maintenance practices are used.Possible Resolution:

Review plant configurations or maintenance practices to see if any outliers are present that could impact the risk profile. Document the review and conclusions.

15 AS-Cl-01 Finding AS-Cl- Discussion:

Accident sequence analysis is a key element of PRA to There is little to no impact on 02, AS- integrate many other elements of PRA, but accident sequence notebook CDF or LERF as this is C2-01, needs to improve for further application and update. For instance primarily a documentation AS-C2- operator actions are generally described without specific governing enhancement.

As a result, 02 procedures and basic event name modeled in HRA. Observations in AS- this gap has no impact on C2 provide more specific examples.

Observations in AS-C1-02 and AS- the application.

C2-01 and 02 provide more specific examples.Basis for Significance:

This would facilitate emergent risk informed applications using documents with better traceability.

Possible Resolution:

See resolutions in Observations AS-C1-02 and AS-C2-01 and 02.Page 6 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 17 AS-C2-01 Finding Discussion:

1. Inconsistent documentation for mitigation tops with There is little to no impact on designators (e.g., -LATE, -EARLY, etc). Additionally, some of the CDF or LERF as this is mitigation top discussions are inappropriate for the initiator being primarily a documentation discussed OR the cross reference to the applicable mitigation top enhancement.

As a result, discussion is invalid. For example, for the LOOP initiator, the BAF this gap has no impact on mitigation top discusses the failure of MFW, even though MFW is not the application.

used in the LOOP event tree.2. Accident sequence notebook does not include a description of the accident progression for each sequence or group of similar sequences.

3. Operator action is described in the accident sequence notebook, but there is limited timing information and no link with HRA information.

Basis for Significance:

This would improve traceability of accident sequence model and facilitate further risk informed applications.

Possible Resolution:

1. The mitigation top name used in the event tree should be included in the documentation and the differences between the mitigation tops with different designators should be clearly discussed.

2. Accident sequence notebook need to update to describe major accident sequences for each modeled initiating event.3. Time information should be provided and/or HFE name should be specified in the description.

20 DA-B2-01 Finding Discussion:

This SR instructs that outliers not be included in the Any change in CDF or LERF definition of a data group. Looking at the NAPS Data calculation outliers resulting from addressing with zero demands were included in groups with frequently tested this F&O is expected to be components.

small and bounded by an order of magnitude increase.The sensitivity study in Basis for Significance:

These data events could impact risk results Attachment C demonstrates that an order of magnitude Possible Resolution:

Close gap in this SR identified above, increase in CDF or LERF does not impact acceptability of the results for this application.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 21 DA-C14- Finding Discussion:

Coincident maintenance events for intersystem events have Coincident maintenance may 01 not been looked at. Need to evaluate historical maintenance schedules to result in an increase in CDF detect patterns of typical maintenance combinations and then add these and LERF, but the impact is identified coincident maintenance events to the model. expected to be bounded by an order of magnitude.

The Basis for Significance:

These events could have an impact on the sensitivity study in annual risk results. Some plants have experienced a significant impact to Attachment C demonstrates their results form including such events in the model. that an order of magnitude increase in CDF or LERF Possible Resolution:

Close gap in this SR identified above, does not impact acceptability of the results for this application.

22 DA-D8-01 Finding Discussion:

No discussion of evaluation of the impact of plant There is little to no impact on modifications on the data could be found in any of the below: CDF or LERF as this is primarily a documentation-GARD on Data (2061, 2063) enhancement.

As a result,-Data Calculation and Supporting Analyses this gap has no impact on-SY.3 System Notebooks the application.

Therefore this SR is considered to be Not Met Basis for Significance:

This item could change the results from the PRA.Possible Resolution:

Revise the GARD on data so that impact of plant modifications on the data analysis will be routinely evaluated and documented and model changes will be made as appropriate.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 24 DA-D8-02 Finding Discussion:

No discussion of evaluation of the impact of plant There is little to no impact on modifications could be found in any of the below: CDF or LERF as this is-GARD on Data (2061, 2063) primarily a documentation-Data Calculation and Supporting Analyses enhancement.

As a result,-System Notebooks this gap has no impact on the application.

Basis for Significance:

Data could be impacted by a plant mod and effect risk results Possible Resolution:

Revise GARD and ensure that data impacts are considered when evaluating a plant mod.Suggest also have a new section in SY notebooks so that this will be proactively considered in future PRA updates.Page 9 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 26 SC-B1-01 Finding SC-B3 Discussion:

The large break LOCA success criterion used in the PRA A sensitivity was performed appears to be inconsistent with the Chapter 14 UFSAR analysis.

to address this modeling concern, and the impact of Basis for Significance:

For large LOCA, NAPS SC. 1 R 3, Section 5.2.2, this change was less than Table 5.2-2 shows for the injection phase that 2/2 accumulators on intact 1% increase in CDF. As a loops and 1 of 2 LHSI pumps are needed. The basis is stated to be the result, this gap has no UFSAR. However, the large break LOCA analysis in Chapter 14/15 of impact on the application.

the UFSAR is based on the most limiting single failure, typically, an emergency diesel generator.

The UFSAR thus may credit charging flow (of the order of 650 gpm). Therefore, the success criterion that is assumed in the PRA may be a smaller set of equipment than the analysis on which it is supposedly based, without justification for excluding the charging pump.Possible Resolution:

Perform an analysis demonstrating that injection from 1 charging pump relative to 1 LHSI pump and 2/2 intact accumulators has no impact on peak cladding temperature and does not impact success, or use a T-H code such as RELAP5 to justify the minimum set of equipment, or reference a WCAP analysis, or similar plant large LOCA success criterion based on non-MAAP analysis.Alternatively, change the success criterion for large LOCA to include a charging pump, and/or perform a review of large LOCA cut sets to bound the potential contribution of the charging pump exclusion to CDF/LERF.Make a note of model limitations.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 29 SY-A14- Finding Discussion:

There was no evidence that plugging of manual valves was Manual valve plugging 01 considered for instances where an exposure time is valid. For example, if failures are not expected to a manual valve is normally open in a standby train, it is susceptible to dominate the failure plugging over an exposure time between system alignment rotations probability of trains or (could be every 2 weeks). Applying an exposure to the manual valve functions.

As a result, the plugging failure data may result in a failure probability higher than check increase in CDF and LERF is valve fails closed failure probability (which is currently modeled).

This expected to be small.could be a significant contributor for RHR HX and pump manual valves, Although the actual risk that could have a very long exposure rate between tests or alignments impact is difficult to estimate since there is uncertainty Basis for Significance:

The generic assumption about plugging of associated with which valves manual valves does not provide evidence that plugging was considered are in scope and which over the exposure time for the standby trains. The system notebooks did functions affected, it is not seem to provide any sort of modeling notes on this topic either. If expected that the increase in using the SY-A15 screening, it should be documented that this case CDF or LERF would be meets SY-Al5. This could be a significant contributor for RHR HX and bounded by an order of pump manual valves that could have a very long exposure rate between magnitude increase.

The tests or alignments, sensitivity study in Attachment C demonstrates Possible Resolution:

Model manual valve plugging over the appropriate that an order of magnitude exposure time for standby trains or provide documentation that manual increase in CDF or LERF valve plugging over the standby train exposure time can be screened per does not impact acceptability SY-Al 5. of the results for this application.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 31 SY-Cl-01 Finding SY-Al Discussion:

The dependency matrix appears to address dependency for There is little to no impact on front-line systems and mechanical support systems, but appears CDF or LERF as this is incomplete for electrical support systems. For example, no dependency primarily a documentation is listed for 125VDC panel 2-BY-B-2-11 or MCC 2-EP-MCC-2A1-2.

In enhancement.

As a result, some instances the support system gate is provided, in other instances this gap has no impact on only the system name is provided, the application.

Basis for Significance:

This issue made it difficult to assess the completeness of the dependency analysis and made it difficult to assess the completeness of the identification of the systems needed to provide or support the safety functions contained in the accident sequence analysis.Possible Resolution:

Review and update dependency analysis for completeness.

34 HR-D3-01 Finding Discussion:

The additional NRC notes adds a requirement for Due to the uncertainty adherence to NUREG-0700, Human-System Interface Design Review associated with the scope of Guidelines.

The basis for stating that no cases were identified where the affected HEPs and the quality is lacking needs to reference NUREG-0700 as the process for amount by which they would validating the quality of the man-machine interface, change, a bounding sensitivity was performed in Basis for Significance:

Additional NRC requirement to go from Cat. I to which all of the individual Cat. II. HEPs were increased by a factor of 10. The resulting Possible Resolution:

Review quality of the man-machine interface for changes in CDF and LERF adherence to NUREG-700 and document in NAPS HR.2. are bounded by the sensitivity in Attachment C.The sensitivity study in Attachment C demonstrates that an order of magnitude increase in CDF or LERF does not impact acceptability of the results for this application.

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-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 38 HR-G2-01 Finding Discussion:

Dependency not assessed for recoveries credited in post- Due to the uncertainty initiators using the CBDTM method. associated with the scope of affected HEPs and the Basis for Significance:

Potential to underestimate human error amount by which they would probabilities.

change, a bounding sensitivity was performed in Possible Resolution:

Update the post-initiator HFEs to include the which all of the individual appropriate dependency level for the CBDTM method. HEPs were increased by a factor of 10. The resulting changes in CDF and LERF are bounded by the sensitivity in Attachment C.The sensitivity study in Attachment C demonstrates that an order of magnitude increase in CDF or LERF does not impact acceptability of the results for this application.

40 HR-G3-01 Finding Discussion:

Cat. II requires an evaluation of the quality of operator There is little to no impact on training on the HFE of interest, including whether the training is CDF or LERF as this is classroom training or simulator training and the frequency of such primarily a documentation training.

The frequency field in the HRA Calculator was not filled out for enhancement.

As a result, the NAPS post initiator HFEs. this gap has no impact on the application.

Basis for Significance:

Provides documentation for the quality of operator training for the HFE of interest.Possible Resolution:

Fill out the training frequency field in the HRA Calculator.

Page 13 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 41 HR-G6-01 Finding Discussion:

HR-G6 requires a check of the consistency of the post- A comparison between HFEs initiator HEP quantifications.

The instructions are to review the HFEs and and their final HEPs for a their final HEPs relative to each other to check their reasonableness reasonableness check was given the scenario context, plant history, procedures, operational performed prior to release of practices, and experience.

HR.2 states that an operator survey, which the NAPS-R07 model.collects operator response times, was performed to meet this However, the documentation requirement.

However, the surveys do not really check the consistency of of the review requires the HEP quantifications.

enhancement.

There is little to no impact on CDF or Basis for Significance:

Confirm that quantifications are reasonable.

LERF as this is primarily a documentation Possible Resolution:

Review the HFEs and their final HEPs relative to enhancement.

As a result, each other to check their reasonableness given the scenario context, this gap has no impact on plant history, procedures, operational practices, and experience, the application.

42 HR-G7-01 Finding Discussion:

There were some cases of unanalyzed dependency HEP combinations that may combinations found in the cutsets of cutset file U1-CDF-Avg have fallen below the Maintenance-R07.cut.

Examples include cutsets 3119, 22480, 22642, thresholds used in the 22643, 22868, 23050. The applicable truncation limits used in the dependency analysis are not dependency analysis needs to be adjusted to eliminate unanalyzed considered to have any combos in the cutsets. significant impact on the model results. As a result, Basis for Significance:

Some cutsets may have higher failure this gap has no impact on probabilities than presently quantified.

the application.

Possible Resolution:

Lower applicable truncation limits used in the dependency analysis to eliminate unanalyzed combos in the cutsets.43 HR-13-01 Finding Discussion:

NAPS HR.1, HR.2, HR.3 section 2.3 and HR.4 section 5 There is little to no impact on addresses assumptions and uncertainties.

Only source of model CDF or LERF as this is uncertainty listed is lack of ERO credit which in reality can be accounted primarily a documentation for using the recoveries available in the HRA calculator.

NUREG/CR-enhancement.

As a result, 1278 lists sources of uncertainty which could be referenced.

this gap has no impact on the application.

Basis for Significance:

Need better documentation of sources of uncertainty.

Possible Resolution:

List sources of uncertainty from NUREG/CR-1278 or other sources.Page 14 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 46 IFPP-B1- Finding IFPP-A1, Discussion:

It is suggested to add an overall site layout drawing into the There is little to no impact on 01 IFPP-B2 IF. 1A notebook with the other individual building level layout drawings to CDF or LERF as this is aid in reader understanding of the buildings' relationships to each other primarily a documentation and a table of such buildings and their disposition in the flooding study enhancement.

As a result, (i.e. include/retain, screened, etc.) prior to or in conjunction with the this gap has no impact on Appendix R information being used as a flooding study input, the application.

Basis for Significance:

Deemed a finding for document enhancement due to the inability to perform as detailed a review as could be possible given documentation updates. The flooding notebooks seem to present the results more so than the starting point through the endpoint with some discussion given in Section 2.1 of the IF.A notebook related to using Appendix R information and the overall process.Possible Resolution:

Include a site layout drawing showing the various buildings involved in the flooding study and a table of such buildings and their disposition (i.e. include/retain, qualitatively screened, etc.) as requiring inclusion in the flooding analysis or not to enhance the brief methodology given in Section 2.1 of the IF.1A notebook.

This may also serve to aid the discussion in Section 2.2 of NOTEBK-PRA-NAPS-IF.

1A as to why for some areas, "while investigated, had no information I deemed worthy of completing a walkdown sheet".Page 15 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 47 IFPP-B3- Finding Discussion:

No discussion is given in the various internal flooding There is little to no impact on 01 notebooks with regard to the plant partitioning process or conclusions as CDF or LERF as this is what sources of uncertainty may be present or may have been introduced primarily a documentation as part of the partitioning task. Assumptions are given in Section 2.3 of enhancement.

As a result, the IF. lB notebook related to flood area definitions, though no discussion this gap has no impact on of their potential impacts to the analysis are given. Sources of the application.

uncertainty related to the flooding initiating events pipe mode are included in Section 6.0 of the IF.2 notebook and repeated in Section 2.0 of the QU.4 notebook (with no other internal flooding related uncertainties added in this QU.4 notebook) while Section 5.0 of the IF.3 notebook indicates that sensitivities related to internal flooding are contained in the QU notebooks, though only sensitivity cases related to HEP and CCF values were noted which contained the overall internal flooding events in the sensitivity case model quantifications.

Basis for Significance:

The SR was deemed 'not met' thus a finding level is appropriate.

Possible Resolution:

Include such discussion as relevant to sources of uncertainty related to plant partitioning, though it is not expected that the partitioning task would have significant sources of uncertainty.

Also, discussion of the flooding area assumptions and their potential impacts to the analysis should be added to the internal flooding notebooks with I sensitivity cases defined and analyzed if appropriate.

Page 16 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 48 I FQU-A6-01 Finding Discussion:

While the flooding-specific HFEs are developed with detailed assessments, several of the noted items in the SR were not accounted for.Items noted from review of SR IFQU-A6: (b) The impact of the flooding on cues that the control room uses for a non-flooding HFEs is not discussed in the supporting spreadsheet of the internal flooding HRA notebook for internal events HFEs used in the flooding analysis.(a) The impact of the flooding on additional workload and stress in the control room uses for a non-flooding HFEs is not discussed in the supporting spreadsheet of the internal flooding HRA notebook for internal events HFEs used in the flooding analysis.

In addition, the stress levels for the flooding-specific events were evaluated at low stress levels, which is inconsistent with the intent of the SR.In addition, there appears to be inconsistent timings for the HEPs defined between the HRA calculator inputs and the NOTEBK-PRA-NAPS-IF.2 for time to perform the action (which is usually 1 minute less than the time to damage) being noted in the NOTEBK-PRA-NAPS-IF.2 notebook and the time to damage being used in the HRA calculator.

This slight difference is not expected to cause significant changes, but should be reviewed for consistency and updated as needed.Basis for Significance:

The SR was deemed 'not met' thus the level of finding is appropriate.

Possible Resolution:

Include consideration for and documentation of the impact on HFE cues and increased stress levels. Ensure that appropriate HRA calculator parameters for items such as cues and stress level are used for the flooding HFEs and update as appropriate.

Review HRA calculator time inputs for consistency and update as needed to be consistent with the NOTEBK-PRA-NAPS-IF.2 notebook.

Also ensure that the timings for event HEP-ISO-TBSWLL are correct as currently the time to submergence is shorter than the time available for action.There is little to no impact on CDF or LERF as this is primarily a documentation enhancement.

As a result, this gap has no impact on the application.

Page 17 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 49 IFQU-A9- Finding Discussion:

One internal flooding source system, firewater, was noted A sensitivity was performed 01 as not always failed when its piping is the flooding source. Credit of the by assuming all of the alternate pump cooling from firewater is still possible under flooding functions that rely on initiating events from firewater piping. firewater are failed during a fire protection piping flood.Basis for Significance:

Revision of the PRA model is required, thus a The resulting changes in level of finding is deemed appropriate.

CDF and LERF are bounded by the sensitivity in Possible Resolution:

Either include the firewater pipe failure lEs at the Attachment C. The modeled firewater backup function gates for HHSI pump cooling and sensitivity study in AFW pump OR determine if the postulated firewater line breaks would fail Attachment C demonstrates the backup functions of the firewater system and include sufficient that an order of magnitude documentation as such. increase in CDF or LERF does not impact acceptability of the results for this application.

Page 18 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 50 IFQU-B1- Finding IFQU-A5, Discussion:

Several internal flooding HRA documentation There is little to no impact on 01 IFQU-B2 inconsistencies were noted during review. CDF or LERF as this is primarily a documentation Examples include: enhancement.

As a result, this gap has no impact on-the HRA notebook NOTEBK-PRA-NAPS-HR.10 and the internal flooding the application.

notebook NOTEBK-PRA-NAPS-IF.2 do not list the same set of flooding-specific HFEs-all of the HFEs listed in the HRA notebook NOTEBK-PRA-NAPS-HR.10 do not appear in the PRA model, event REC-FLD-ABSWLL appears as a flag event-the internal flooding notebook NOTEBK-PRA-NAPS-IF.2 presents HFE HEP-ISO-TBSWLL which is not contained in the HRA calculator which does contain event REC-FLD-TBSWLL, however, neither event appears in the PRA model.Basis for Significance:

Information is needed in the flooding/HRA notebooks, thus a finding rather than a small item that would warrant a suggestion.

Possible Resolution:

Update documentation listings between the NOTEBK-PRA-NAPS-HR.10 and NOTEBK-PRA-NAPS-I F.2 notebooks, ensuring that any non-credited HFEs that are desired to remain in the documentation are noted as being non-credited, and that all flooding HFEs included in the HRA calculator are covered by the noted notebooks.

Also ensure that Table 6-1 of the NOTEBK-PRA-NAPS-QU.

1 is treated consistently.

Page 19 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 52 IFSN-A5- Finding Discussion:

The critical height of all PRA-related SSCs is not given in an There is little to no impact on 01 easy to identify single location such as the table listing of PRA-related CDF or LERF as this is SSCs within the various internal flood areas. In addition, the critical primarily a documentation height is not always defined in the other sections of the internal flooding enhancement.

As a result, notebooks such as walkdowns or area scenario discussions, only for the this gap has no impact on end-state important SSCs. the application.

Basis for Significance:

SR requires spatial location of SSCs which was not consistently done.Possible Resolution:

Update Table 1 of the NOTEBK-PRA-NAPS-IF.1 B notebook to indicate the critical heights of the SSCs listed in that table.53 IFSN-A8- Finding Discussion:

Assumptions of doors failing without allowing water An evaluation has shown 01 accumulation may be a beneficial failure for the flood room/area where that the current modeling the accumulation would not occur due to the assumption of the door assumptions associated with failing open immediately.

doors failing without water accumulation is conservative Basis for Significance:

Potential non-conservatism without significant for North Anna. As a result, analysis to ensure treatment is okay. this gap has no impact on the application.

Possible Resolution:

Include accumulation in rooms/areas with doors to the recommended heights with consideration for door opening direction using the same EPRI methodology used in the North Anna internal flooding analysis or perform more detailed investigations of the door failure water accumulation heights and SSC critical heights to ensure that beneficial failures are not being credited.Page 20 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 55 IFSN-B2- Finding IFEV-A2 Discussion:

The included pipe break flowrates do not always include a There is little to no impact on 02 calculation for the full diameter break size, and in addition, there is no CDF or LERF as this is consideration of pump runout flowrate comparison to the calculated break primarily a documentation flowrate in the various internal flooding notebooks.

Also, the flooding enhancement.

As a result, flowrate used to determine the consequential impacts for each flooding this gap has no impact on area should be listed in the area scenario discussions.

the application.

Basis for Significance:

Information is needed in the flooding notebooks, thus a finding rather than a small item that would warrant a suggestion.

Possible Resolution:

For the break flowrates presented, include a case at full diameter size. For the included flooding source systems, provide the full runout flowrate of the system pump(s) for comparison to the calculated flowrates to ensure the appropriate flooding flowrate is being used and include the flowrate used to determine the consequential impacts for each flooding area should be listed in the area scenario discussions.

57 IFSO-A4- Finding IFSO-B1 Discussion:

Inadvertent actuation of fire protection system outside of An evaluation of inadvertent 01 Aux Building not modeled or screened.

Inadvertent actuation of fire actuation of the fire protection system inside of Aux Building not discussed.

protection system has shown that the frequency of this Basis for Significance:

SR specifically calls for inadvertent actuation to event is low compared to the be considered.

failure rate of affected equipment, and the Possible Resolution:

Assess the risk for inadvertent fire protection equipment affected by the system actuation outside of the Aux Building.

Document the inclusion of actuation is limited in scope.inadvertent actuation in the Aux Building.

As a result, a small impact on CDF and LERF is expected.

The sensitivity study in Attachment C demonstrates that an order of magnitude increase in CDF or LERF does not impact acceptability of the results for this application.

Page 21 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 58 IFSO-AS- Finding Discussion:

The capacities of various sources are limited by an A sensitivity was performed 01 assumption that all flood isolations could be performed within 60 minutes. to assess the impact of flood No basis is given for this assumption, and the potential of all scenarios scenarios that screened out using a purely assumptive basis for such inherent screening of potential based on the 60 minute impacts should also model non-isolated scenarios for the same pipe timeframe, and the CDF break source. Also, the treatment is inconsistent with an IF HFE that is impact of those scenarios evaluated past 60 minutes. was insignificant.

As a result, this gap has no This F&O applies to the following SRs: IFSO-B1, IFQU-A6, IFQU-A5, impact on the application.

IFSN-A9, IFSN-A15, IFSN-A16, IFSN-A10, IFSN-A14, and IFSN-B2.Basis for Significance:

This assumption could have significant impact to internal floods risk. REC-FLD-IRR has available time of 84 minutes, yet still analyzed for failure probability.

Possible Resolution:

If assessing the capacity of the source by crediting a recovery action to isolate the source, then credit the capacity given both a successful recovery and a failed recovery.61 IFSO-B3- Finding Discussion:

There is no uncertainty analysis related to flood sources. There is little to no impact on 01 CDF or LERF as this is Basis for Significance:

Missing uncertainty analysis.

SR unmet. primarily a documentation enhancement.

As a result, Possible Resolution:

Perform uncertainty analysis for flood sources. this gap has no impact on the application.

Page 22 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 64 LE-G1-01 Finding LE-G5 Discussion:

There is no adequate roadmap that facilitates peer review of There is little to no impact on the Level 2/LERF documentation.

This is exacerbated by the significant CDF or LERF as this is reliance on historical documents going back to the original IPE report. primarily a documentation enhancement.

As a result, Basis for Significance:

There are several dated self-assessment this gap has no impact on documents.

For LE, about one-third of the SRs do not have any the application.

discussion of how the SR is met and where the documentation can be found. Moreover, because of the conversion of the Volume numbers (e.g. LE.2 to LE.1), there is additional confusion added for LE. Many of the referenced sections in the self-assessment (e.g., Section 5.4.1 of LE.1 (old LE.2)) appear to no longer exist. Finally, unlike the other technical elements that have completely revised the analysis, the Level 2 relies significantly on historical documents including the 20 year old IPE, SM-1243 and SM-1464.Possible Resolution:

In the LE.1 notebook, provide an SR-by-SR table of how each SR is addressed and where the documentation can be found.67 QU-B5-01 Finding SY-C2 Discussion:

Section 3.2 of fleet wide PRA procedure NF-AA-PRA-28 There is uncertainty describes a method to break the circular logic appropriately and Table 3 associated with the scope in SY.2 attachment lists circular logic break gates, but further review of and impact associated with the logic indicates the circular logic is not handled properly.

this modeling issue.However, it is expected than A Gate 2-EP-CB-12A-LC "NO ELECTRIC POWER 125 V DC BUS 2-1 the CDF and LERF impact (U2 ESGR) (CIRC LOGIC BREAK)" is modeled under EDG 2H. The resulting from correcting the 125V DC power supply with circular logic break is supplied power only circular logic break modeling from battery under LOOP condition which is required the EDG. However would be bounded by an the battery power is ANDed with battery charger failures as below: order of magnitude increase.2-EP-CB-12A-PS-LC AND 2-BY-BC-2-1-FAIL 2-BY-BC-2C-I-FAIL 2-BY-B- The sensitivity study in 2-1 Attachment C demonstrates that an order of magnitude Basis for Significance:

Improper breaking of circular logics would result increase in CDF or LERF in improper accident sequence evaluation, does not impact acceptability of the results for this Possible Resolution:

Identify and correct errors in circular logic application.

development.

Page 23 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Other No. F&O # Level Affected Issue Impact on Application SRs 68 QU-B8-01 Finding Discussion:

NASP PRA developed logic to eliminate mutually exclusive A sensitivity study was situations to correct cutsets containing mutually exclusive events, performed to address this However a mutually exclusive logic "U1-EVENTS-NO-AUTO-PRZ-PRES-modeling issue, and the CDF NX" may delete LOSC sequence because the logic produces U12-LOSS-and LERF each increased by SW-EVENTS*LOSCS combination.

This logic seems to delete LOSCS less than 1%. As a result, logic associated with total loss of SW event which results in loss of RCP this gap has no impact on seal cooling and injection, the application.

Basis for Significance:

Incorrect mutually exclusive logic deletion may result in improper accident sequence evaluation.

Possible Resolution:

Review the logic and correct the combination, if it is error.70 QU-F5-01 Finding Discussion:

Quantification code limitations are stated as being contained There is little to no impact on in the user manuals to the various software codes and there is no CDF or LERF as this is discussion provided in the .NOTEBK-PRA-NAPS-QU.

1 or QU.2 primarily a documentation notebooks.

enhancement.

As a result, this gap has no impact on Basis for Significance:

Finding based on need for actual information in the application.

the notebook(s).

Possible Resolution:

Include a summary listing of the quantification code software limitations as found in the indicated reference user manuals and a description of how these limitations could impact the application of the PRA model.Page 24 of 25 Serial No 14-272 Docket Nos. 50-333/339 Type A Test Interval Extension

-LAR Attachment 5 Enclosure 1 PRA TECHNICAL ADEQUACY SENSITIVITY STUDY This sensitivity study demonstrates the impact of an order of magnitude increase in the internal events CDF on the ILRT interval extension results.The CDF is increased by an order of magnitude from 1.72E-06/yr to 1.72E-05/yr.

The base Class 3a and Class 3b frequencies are calculated by multiplying the CDF by 9.22E-3 and 2.30E-3, respectively.

The 15-year Class 3a and Class 3b frequencies are calculated by multiplying the base Class 3a and 3b frequencies by 5. The Class 3a and 3b dose risk are multiplied by 4.24E+3 person-rem and 4.24E+4 person-rem, respectively, for both the base and 15-year cases. The ALERF is calculated by taking the difference between the Class 3b frequencies for the 15-year and base cases. The increase in dose risk is calculated by taking the difference between the total 15-year Class 3 dose and the total base Class 3 dose. The percent dose is calculated by comparing the increase in dose risk to the total base dose risk, which is 5.14E-01 person-rem per year.Base 15-year Delta Delta %CDF 3a 3b 3a 3b 3a 3b 3a 3b LERF Dose Dose Freq Freq Dose Dose Freq Freq Dose Dose 1.72E-05 1.59E-07 3.96E-08 6.72E-04 1.68E-03 7.93E-07 1.98E-07 3.36E-03 8.40E-03 1.59E-07 9.41E-03 1.83%In order to calculate the ACCFP, the increase in CDF is assumed to be associated with the Class 1 frequency.

The base Class 1 frequency is adjusted by subtracting out the base Class 3a and 3b frequencies above, and the same is done to adjust the Class 1 frequency for the 15-year case.The adjusted Class 1 frequencies, the Class 3a frequencies, and the CDF are used to calculate the CCFP for the base case and 15-year ILRT case. The ACCFP is calculated by taking the difference between the CCFPs for the base and 15-year cases.Base 15 Year Adjusted Class 1 Freq CCFP Adjusted Class 1 Freq CCFP 1.61E-05 1.59E-05 6.66% 1.51 E-05 7.58% 0.92%The results of this sensitivity are still well below the acceptance criteria for the application based on the guidance in EPRI TR-1018243.

The ALERF is below 1.OE-06/yr, the increase in population dose risk is less than 1.0 person-rem per year, and the ACCFP is below 1.5%. Therefore, it has been shown that this increase in CDF will not have any impact on the results of the application.

An increase in internal events LERF will have little impact on the application.

The increase in LERF would result in an increase in the total population dose, but this would actually result in a decrease in the percent change in population dose due to the ILRT extension.

The change in population dose, the ACCFP, and the ALERF would be unaffected since these results are dependent on the CDF and the Class 3a and 3b results. According to RG 1.174, no changes are allowed if the total LERF exceeds 1.OE-05, and the NAPS LERF is low enough that exceeding this limit is not a concern. As a result, an order of magnitude increase in internal events LERF will not impact the results of the application.

Page 25 of 25 Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 6 List of Regulatory Commitments Virginia Electric and Power Company (Dominion)

North Anna Station Units 1 and 2 i Serial No.14-272 Docket Nos. 50-338/339 Type A Test Interval Extension

-LAR Attachment 6 Page 1 of 1 List of Regulatory Commitments This table identifies actions discussed in this letter for which Dominion commits to perform. Any other actions discussed in this submittal are described for the NRC's information and are not commitments.

Type Scheduled Commitment One-time Continuing Completion Date Compliance Dominion will use the definition in Section 5 of NEI 94-01 Revision 3-A for Upon NRC approval of calculating the Type A leakage rate. X this License Amendment Request