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 COMPANYRICHMOND, VIRGINIA 23261June 30, 2014U. S. Nuclear Regulatory Commission Serial No.: 14-272Attention:

Document Control Desk NLOS/ETS:

ROWashington, DC 20555-0001 Docket Nos.: 50-338/339 License Nos.: NPF-4/7VIRGINIA ELECTRIC AND POWER COMPANYNORTH ANNA POWER STATION UNITS 1 AND 2PROPOSED LICENSE AMENDMENT REQUESTPERMANENT FIFTEEN-YEAR TYPE A TEST INTERVALPursuant to 10CFR50.90, Virginia Electric and Power Company (Dominion) requestslicense amendments in the form of changes to the Technical Specifications, for facilityOperating License Numbers NPF-4 and NPF-7 for North Anna Power Station Units 1and 2, respectively.

The proposed amendments revise North Anna Power Station Units1 and 2 Technical Specification (TS) 5.5.15, "Containment Leakage Rate TestingProgram,"

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 theimplementation document used to develop the North Anna performance-based leakagetesting program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-Aof NEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending the Type A primarycontainment integrated leak rate test (ILRT) intervals to fifteen years and the Type Clocal 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 anddocumentation of the technical adequacy of the PRA model are provided inAttachments 4 and 5, respectively.

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

We have evaluated the proposed amendments and have determined that they do notinvolve a significant hazards consideration as defined in 10CFR50.92.

The basis forthat 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 ofeffluents that may be released offsite or any significant increase in individual orcumulative occupational radiation exposure.

Therefore, the proposed amendments areeligible for categorical exclusion from an environmental assessment as set forth in10CFR51.22(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 proposedchange. The proposed TS change has been reviewed and approved by the FacilitySafety Review Committee.

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

Respectfully, Mark SartainVice President

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

1.2.3.4.5.6.Discussion of ChangeMarked-up Technical Specifications PageProposed Technical Specifications PageRisk Assessment PRA Technical AdequacyList of Regulatory Commitments M O "r T PtaCommonwet of Vllin'hm IReg.# 140542MyCommission sx~rit~ 320112COMMONWEALTH OF VIRGINIACOUNTY OF HENRICO)))The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, todayby Mr. Mark D. Sartain, who is Vice President

-Nuclear Engineering, of Virginia Electric and Power Company.

Hehas affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of thatcompany, 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. 14-272Docket Nos. 50-338/339 Page 3 of 3cc: U.S. Nuclear Regulatory Commission

-Region IIMarquis One Tower245 Peachtree Center Avenue, NE Suite 1200Atlanta, GA 30303-1257 State Health Commissioner Virginia Department of HealthJames Madison Building

-7th floor109 Governor StreetSuite 730Richmond, VA 23219Dr. V. Sreenivas NRC Project Manager North AnnaU.S. Nuclear Regulatory Commission One White Flint NorthMail Stop 08 G-9A11555 Rockville PikeRockville, MD 20852-2738 NRC Senior Resident Inspector North Anna Power Station Serial No. 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 1Discussion of ChangeVirginia Electric and Power Company(Dominion)

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

-LARAttachment 1DISCUSSION OF CHANGE1.0 D E S C R IP T IO N ...............................................................................................

..22.0 PROPOSED CHANGE ......................................................................................

23.0 BACKGROUND

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33.1 10 CFR 50, Appendix J, Option B Requirements

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33.2 Reason for Proposed Amendment

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

44.0 TECHNICAL ANALYSIS

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54.1 Description of Containment

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64.2 Integrated Leak Rate Test History .........................................................................

84.3 Type B and C Testing Programs

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

94.4 Supplemental Inspection Requirements

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104.4.1 IW E Examination

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114.4.2 IW L Examinations

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124.5 Deficiencies Identified

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144.6 Plant-Specific Confirmatory Analysis

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

144 .6 .1 M ethodology

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..144 .6 .2 P R A Q ua lity ........................................................................................

.... 164.6.3 Summary of Plant-Specific Risk Assessment Results ..................................

164 .7 C o nclu sio n .................................................................................................

.... 175.0 REGULATORY ASSESSMENT

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175.1 Applicable Regulatory Requirements/Criteria

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175.2 No Significant Hazards Consideration

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185.3 Environmental Considerations

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206.0 PRECEDENCE

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

-LARAttachment 1DISCUSSION OF CHANGE1.0 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 thereference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topicalreport NEI 94-01, Revision 3-A, as the implementation document used by Virginia Electric andPower Company (Dominion) to develop the North Anna performance-based leakage testingprogram in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A of NEI 94-01describes an approach for implementing the optional performance-based requirements of OptionB, 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 andJune 8, 2012, the NRC concluded that NEI 94-01, Revision 3-A, describes an acceptable approachfor 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 thelimitations 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 theinterval for the primary containment ILRTs, which are currently required to be performed at ten yearintervals, to no longer than 15 years from the last ILRT for both Units 1 and 2. The next ILRT iscurrently due no later than October 11, 2017 for Unit 1 and October 9, 2014 for Unit 2 (with anNRC approved 5-year extension).

This is approximately 10 years since the last ILRT for Unit 1 and15 years for Unit 2. The Unit 2 schedule is acceptable based on a one-time extension of thefrequency 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 wouldrequire the next ILRT to be performed during the fall 2016 refueling outage. The proposedamendment would allow the next ILRT for North Anna Unit 1 to be performed within 15 years fromthe last ILRT (i.e., October 11, 2007), as opposed to the current 10-year interval.

This would allowthe Unit 1 and 2 ILRTs to be performed at a 15-year interval consistent with the NRC approvedguidance documents (NEI 94-01, Rev. 3A) and establish a 15 year ILRT frequency for both Units 1and 2. The performance of fewer ILRTs will result in significant savings in radiation exposure topersonnel, cost, and critical path time during future refueling outages.2.0 PROPOSED CHANGETS 5.5.15, "Containment Leakage Rate Testing Program,"

currently states: "A program shallestablish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR50, Appendix J, Option B, as modified by approved exemptions.

This program shall be inaccordance 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, 1999Type 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 RG1.163 with a reference to NEI 94-01, Revision 3-A as follows:TS 5.5.15, "Containment Leakage Rate Testing Program,"

currently states: "A programshall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o)Page 2 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

This programshall 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 proposedchanges 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 thecontainment, including systems and components that penetrate the containment, does not exceedthe 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 madeduring 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 basisaccident.

Appendix J identifies three types of required tests: (1) Type A tests, intended to measurethe containment overall integrated leakage rate; (2) Type B tests, intended to detect local leaksand to measure leakage across pressure-containing or leakage limiting boundaries (other thanvalves) 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 toensure continued leakage integrity of the containment structure by evaluating those structural partsof 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 Ctesting 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 itsfailure.

The use of the term "performance-based" in 10 CFR 50, Appendix J refers to both theperformance history necessary to extend test intervals as well as to the criteria necessary to meetthe 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 NEI94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., twoconsecutive, 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 anNRC risk program, and Electric Power Research Institute (EPRI) TR-104285, "Risk ImpactAssessment of Revised Containment Leak Rate Testing Intervals",

both of which illustrated that therisk 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 forextending Type A intervals to up to 15 years and incorporates the regulatory positions stated inRG 1.163. It delineates a performance-based approach for determining Type A, Type B, andType C containment leakage rate surveillance testing frequencies.

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

-LARAttachment 1testing 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 testsbecause 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 letterdated 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 acceptedversion 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 RG1.174, "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 tothe specific limitations and conditions listed in Section 4.2 of the SE. An accepted version of EPRITR-1009325 has subsequently been issued as Revision 2-A (also identified as TR-1018243) datedOctober 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 forextending Type A and Type C intervals to up to 15 years and 75 months, respectively, andincorporates 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, alsodiscusses 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 inexisting 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 theNRC's evaluation and acceptance of NEI 94-01, Revision 3, subject to the specific limitations andconditions 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 EPRITR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals,"

datedAugust 1994. The assessment validates increasing allowable extended LLRT intervals to the 120months 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 apermissible extension (for non-routine emergent conditions) of nine months (84 months total). TheNRC final SE issued by letter dated June 8, 2012, documents the NRC's evaluation andacceptance of EPRI TR-1009325 as a validation of EPRI TR-104285, Revision 2 bases to extendType C LLRT to 120 months, subject to the specific limitations and conditions listed in Section 4.1of 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 aperformance-based test frequency for the Type A tests and Local Leak Rate Testing (Type Band C) consistent with NEI 94-01, Revision 3-A.Page 4 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 14.0 TECHNICAL ANALYSISAs required by 10 CFR 50.54(o),

the North Anna containments are subject to the requirements setforth 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 NEI94-01, Revision

0. This license amendment request proposes to revise the North Anna 10 CFR50, 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 optionalperformance-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 whenfuture 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 Sectioninspections 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 exteriorstructure potentially subjected to degradation.

surfaces of the containment system for structural problems istypically conducted in accordance with the North Anna IWE/IWLContainment Inservice Inspection Plans which implement therequirements of the ASME, Section Xl, Subsections IWE andIWL, as required by 10 CFR 50.55a(g).

Although not a specific line item in the North Anna IWEprogram, accessible leak chase channel plugs and caps areinspected during the general visual examination completed inaccordance with our IWE program.

There are no primarycontainment 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 whichperformed 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 vesselclosure head, the containment structure was modified.

Thedesign change process addressed the testing requirements ofthe containment structure modifications.

5. The normal Type A test interval should be less than Dominion acknowledges and accepts this NRC staff position, as15 years. If a licensee has to utilize the provisions of. communicated to the nuclear industry in Regulatory IssueSection 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, thelicensee must demonstrate to the NRC staff that it isan unforeseen emergent condition.

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

North Anna Unit 1 and 2 are not licensedapplications requesting a permanent extension of the pursuant to 10 CFR Part 52.ILRT surveillance interval to 15 years should bedeferred until after the construction and testing ofcontainments for that design have been completed and applicants have confirmed the applicability of NEITR 94-01, Rev. 2, and EPRI Report No. 1009325,Rev. 2, including the use of past containment ILRTdata.Page 5 of 20 Serial No 14-272Docket Nos. 50-3331339 Type A Test Interval Extension

-LARAttachment 1Limitation

/ 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 willLLRTs be increased to 75 months with the follow the guidance of NEI 94-01, Rev. 3-A to assess andrequirement that, a licensee's post-outage report monitor margin between the Type B and C leakage rateinclude 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. Thestaff is also allowing the non-routine emergentextension out to 84-months as applied to Type Cvalves at a site, with some exceptions that must bedetailed in NEI 94-01, Revision

3. At no time shallan extension be allowed for Type C valves that arerestricted categorically (e.g. BWR MSIVs), andthose valves with a history of leakage, or any valvesheld to either a less than maximum interval or to thebase refueling cycle interval.

Only non-routine emergent conditions allow an extension to 84months.2. When routinely scheduling any LLRT valve interval Following the approval of the amendment, consistent with thebeyond 60-months and up to 75-months, the primary guidance of Section 11.3.2 of NEI 94-01, Rev. 3-A North Annacontainment leakage rate testing program trending will estimate the amount of understatement in the Type B & Cor 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 anddetermination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of thepenetrations.

To comply with the requirement of 10 CFR 50, Appendix J, Option B,Section V.B, North AnnaUnits 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 testto 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 verticalcylindrical wall and hemispherical dome, supported on a flat base mat. Below grade thecontainment 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 groundgrade. The containment structure has an inside diameter of 126 ft. 0 in. The bend line of thedome 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 centerof the dome. The cylindrical wall is 4 ft. 6 in. thick, the dome is 2 ft. 6 in. thick, and the base mat is10 ft. 0 in. thick. The steel liner for the wall is 3/8 inch thick. The steel liner for the mat consists ofa 0.25-inch plate except: in the incore instrumentation area, where an exposed 0.75-inch plate isused; 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 thecontainment 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 concretePage 6 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1reinforcing 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 hatchand a 14 ft. 6 in. ID equipment hatch. Other smaller containment structure penetrations includehot 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 stressesanticipated 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 theconcrete.

During construction, the steel liner served as the inside form for the concrete wall anddome. 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 concreteshield walls. The base mat liner is protected by a 21-inch to 30-inch thick concrete cover, except inthe 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 aminimum 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 pressureand temperatures of the limiting design basis accident (DBA) without exceeding the design leakagerate.Containment air partial pressure is an initial condition used in the containment DBA analyses toestablish the maximum peak containment internal pressure.

The limiting DBAs considered relativeto containment pressure are the loss of coolant accident (LOCA) and steam line break (SLB). TheLOCA 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 limitingdesign basis SLB. However, peak accident pressure in the TS is based on the LOCA peak. Themaximum design internal pressure for the containment is 45.0 psig, which bounds the design basisaccidents.

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

The SLBanalysis 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 designminimum pressure of 5.5 psia). The inadvertent actuation of the Quench Spray (QS) System wasanalyzed 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 psiato 12.3 psia) based on service water temperature to ensure the containment design pressure is notexceeded during a design basis accident.

Instrumentation constantly monitors containment pressure.

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

Although not as significant as the differential pressure resulting from adesign basis accident, the fact that the containment can be maintained subatmospheric provides adegree 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 thecontainment structure for those areas that may be inaccessible for visual examination.

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

-LARAttachment 14.2 Integrated Leak Rate Test HistoryUnit ITest Date As-Found Leakage Acceptance Limit*June 23, 1989 Measured Leakage With Upper 0.26 of LaConfidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.34 of LaNon-vented Penalty 0.03 of LaTOTAL 0.63 of La 1.0 La (0.1%/day)

April 3,1993 Measured Leakage With Upper 0.31 of LaConfidence Limit (UCL)Margin 0.31_ofLa Total Type C Penalty (leakage savings) 0.01 of LaNon-vented Penalty 0.02 of LaTOTAL 0.34 of La 1.0 LaOctober 11, 2007 Measured Leakage With Upper 0.534 of LaConfidence Limit (UCL)Margin 0_534_ofLa Total Type C Penalty (leakage savings) 0.023 of LaNon-vented Penalty 0.0 of LaTOTAL 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 leakageassumed in dose consequences) with 0.6 La, the maximum leakage from Type B and C components.

The ILRT testpressure is maintained between 44.1 psig and 45.Unit 2Test Date As-Found Leakage Acceptance Limit*April 1989 Measured Leakage With Upper 0.27 of LaConfidence Limit (UCL)Margin 0.27_ofLa Total Type C Penalty (leakage savings) 0.19 of LaNon-vented Penalty 0.03 of LaTOTAL 0.49 of La 1.0 LaOctober 1990 Measured Leakage With Upper 0.22 of LaConfidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.12 of LaNon-vented Penalty 0.03 of LaTOTAL 0.37 of La 1.0 LaOctober 1999 Measured Leakage With Upper 0.4898 of LaConfidence Limit (UCL)Margin Total Type C Penalty (leakage savings) 0.089 of LaNon-vented Penalty 0.035 of LaTOTAL 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 leakageassumed in dose consequences) with 0.6 La, the maximum leakage from Type B and C components.

The ILRT testpressure is maintained between 44.1 psig and 45.Containment penetration (Type B and C) testing is being performed in accordance with Option B of10 CFR 50, Appendix J. The current total penetration leakage on a minimum path basis is lessthan 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 fall2014 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 besubject to the special testing requirements of Section IV.A of 10 CFR 50, Appendix J. There havePage 8 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1been 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 withincontainment which could affect leak-tightness.

4.3 Type B and Type C Testing ProgramThe North Anna Unit 1 and 2 Appendix J, Type B and Type C leakage rate testing requires testingof electrical penetrations,

airlocks, hatches,

flanges, and valves within the scope of the program asrequired by 10 CFR 50, Appendix J, Option B and TS 5.5.15. The Type B and Type C testingprogram 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 abarrier 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 theallowable 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 maximumand minimum pathway leak rate summary totals for the last three refueling outages are shownbelow.Unit 1October 2010 -As-Found Min Pathway Leakage 7.248 scfhOctober 2010 -As-Left Max Pathway Leakage 20.9 scfhOctober 2010 -As-Left Minimum Pathway Leakage 9.618 scfhApril 2012 -As-Found Min Pathway Leakage 11.607 scfhApril 2012 -As-Left Max Pathway Leakage 44.134 scfhApril 2012- As-Left Minimum Pathway Leakage 10.292 scfhOctober 2013 -As-Found Min Pathway Leakage 6.205 scfhOctober 2013 -As-Left Max Pathway Leakage 23.808 scfhOctober 2013 -As-Left Minimum Pathway Leakage 6.554 scfhThere were no Type B or C penetration test failures during the Unit 1 2013 refueling outage. Theresults 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 basedon 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 theiraccelerated testing and can return to an extend test frequency.

Leakage results during2013 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 purgeexhaust 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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-LARAttachment 1Unit 2April 2010 -As-Found Min Pathway Leakage 11.86 scfhApril 2010 -As-Left Max Pathway Leakage 23.71 scfhApril 2010 -As-Left Minimum Pathway Leakage 3.54 scfhNovember 2011 -As-Found Min Pathway Leakage 6.66 scfhNovember 2011 -As-Left Max Pathway Leakage 10.68 scfhNovember 2011 -As-Left Minimum Pathway Leakage 4.34 scfhMay 2013 -As-Found Min Pathway Leakage 7.18 scfhMay 2013 -As-Left Max Pathway Leakage 17.66 scfhMay 2013 -As-Left Minimum Pathway Leakage 4.15 scfhThere were no Type B or C penetration test failures during the Unit 2 2013 refueling outage. Theresults 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.

Leakageresults during 2013 RFO were acceptable.

Requires one more successful test to return toextended 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 2013RFO 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 purgeexhaust and supply) are tested in accordance with TS SR 3.6.3.4, which is at least everyRFO. Leakage results during 2013 RFO were acceptable.

As discussed in NUREG-1493, Type B and Type C tests can identify the vast majority (greater than95%) of all potential containment leakage paths. This amendment request adopts the guidance inNEI 94-01, Revision 3-A, in place of NEI 94-01, Revision 0 for the Type C test interval, butotherwise does not affect the scope or performance of Type B or Type C tests. Type B and Type Ctesting 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 exteriorsurfaces 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 istypically 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 Editionwith the 2003 Addenda.The examination performed in accordance with the IWE/IWL program satisfies the general visualexamination requirements specified in 10 CFR 50, Appendix J, Option B. Identification andevaluation of inaccessible areas are addressed in accordance with the requirements of 10 CFRPage 10 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 150.55a(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 of10 CFR 50.55a(b)(ix)(G) and 10 CFR 50.55a(b)(ix)(H).

Each ten-year ISI interval is divided intothree inspection periods of 3, 4 and 3 year durations for IWE. A minimum of one inspection duringeach inspection period of the ISI interval is required by the IWE program.

Each ten-year ISIinterval 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 performthe general visual examinations at least three other times before the next Type A test, if the Type Atest interval is to be extended to 15 years. The North Anna TRM surveillance requirements, TSR3.6.2.7, specifically requires a general visual examination of the accessible interior and exteriorsurfaces 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 ofMechanical Engineers (ASME) Code,Section XI, Subsection IWE/IWL program satisfy the generalvisual 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 metalliccomponents will be conducted before the next Type A test if the Type A test interval is extended to15 years. This meets the requirements of Section 9.2.3.2 of NEI 94-01, Revision 3-A andCondition 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 ASMECode, Section Xl, Subsection IWL are performed every five years, resulting in at least three IWLexaminations being performed during a 15-year Type A test interval.

Together, these examinations assure that at least three general visual examinations of theaccessible 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 isextended to 15 years, thereby meeting the requirements of Section 9.2.3.2 of NEI 94-01, Revision3-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 2were deemed susceptible to accelerated degradation and aging due to wood entrapment inside theconcrete and required augmented examinations per Category E-C. Corrective action to removethe wood was performed and the areas were re-examined in accordance with IWE-2420(b) andafter three (3) augmented examinations were performed and remained essentially unchanged inaccordance 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 secondten-year interval (2001 Edition through 2003 Addenda of ASME Section Xl), two (2) test plugs ineach unit in the containment recirculation spray sump were determined to be part of the IWEboundary 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 andthe area was overlaid with stainless steel to preclude further degradation.

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-LARAttachment 1North Anna Unit 1 has completed the examination requirements of the Interval 2, Period 2 ofContainment IWE Inservice Inspection Program.

North Anna Unit 2 is scheduled to complete theInterval 2, Period 2 of the Containment IWE Inservice Inspection Program examination requirements by October 2014. Examinations are performed to the requirements of the 2001Edition through 2003 Addenda of ASME XI as modified by the 10 CFR 50.55a(b) limitations forboth 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 Intervalexaminations, 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 wasconservatively 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 onCategory E-A, which are visual (General, VT-3 and VT-I) examinations based on Code or 10 CFRrequirements.

In accordance with the Containment Inservice Testing Program, qualified station personnel performan IWE -General Visual examination on the accessible surface area associated with theContainment 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 theseinstances, 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 werecompleted by the required August 31, 2011 date for the first five year period in the summer of 2011in accordance with Category L-A of the 2001 Edition with 2003 Addenda of ASME Xl. The second5-year concrete containment examination in accordance with Category L-A of the code isscheduled to be completed in the summer of 2016 for Units 1 and 2. The 2011 examinations onthe concrete exterior were conducted by the Responsible Engineer using the approved Code visualmethods.

During the examinations, 25 indications were observed on each unit. The Unit 1 andUnit 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 requireadditional excavation for repair. In general, the indications requiring additional inspection orexcavation involved embedded materials and loose or hollow-sounding areas. The designation ofa 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 criteriawith 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 forthis code repair.In summary, no significant defects or concerns were observed on the exterior concrete and for themost part, all observed defects were due to original construction flaws. Based on theseinspections, the conclusion was that the Unit 1 and 2 containment structures were in good materialcondition.

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-LARAttachment 1The 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/IWLinspection, additional visual inspections of the normally accessible portions of the interior andexternal 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 IGeneral Visual General VisualExamination 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 199419951996 2/27/1996 19971998 9/27/1998 1999First required IWE2000 exam 3/1/2000X Spring (N1R14)2001 First required IWL exam 9/12/2001 X Summer20022003 X Spring (N1R16) 3/3/20032004 X Fall (N1R17) 9/5/2004200520062007 10/6/2007 X Winter/Spring X Fall (N1 R19) 9/28/2007 (with Type A)200820092010 X Fall (N1R21) 10/19/2010 2011 X Summer 9/29/2011 (post earthquake) 2012201320142015 X Spring X (with IWE)2016 X (10-year) x X (if Type A)20172018 x X (with IWE)201920202021 X2022 X (15-year)

X Fall X(with Type A)202320242025 X Fall X (with IWE)2026 x20272028 X Fall X (with IWE)202920302031 X X Fall X (with IWE/IWL)203220332034 X Fall X (with IWE)2035 X20362037 X (15-Year)

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-LARAttachment 1Unit 2General Visual General VisualExamination 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 20002001 First required IWL exam-X Summer 2/21/2001 2002 8/18/2002 2003First required IWE2004 examX Spring (N2R16)200520062007 X Winter/Spring X Spring (N2R18) 3/22/2007 200820092010 X Spring (N2R20) 3129/2010 2011 X Summer 9/29/2011 (post earthquake) 20122013 4/24/2013 2014 X (15-Year)

X Fall (N2R23) X (with Type A)20152016 X2017 X Fall X (with IWE)201820192020 X Fall X (with IWE)2021 X20222023 X Fall X (with IWE)202420252026 X X Fall X (with IWE/IWL)2027 _20282029 X (15-Year)

X Fall X (with Type A)20302031 X2032 X Fall X (with IWE)If IWE/IWL examinations are performed at the same time those examinations/inspections will beused 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, abnormaldegradation of the primary containment structure identified during the conduct of IWE / IWLprogram 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 Analysis4.6.1 Methodology An evaluation has been performed to assess the risk impact of extending the North Anna PowerStation (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 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1described in EPRI TR-1009325, Revision 2-A and the NRC regulatory guidance outlined in RG1.174 on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of arequest to change the licensing basis of the plant. In addition, the methodology used for CalvertCliffs 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 alsoused 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.

ThisPRA 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 NAPSIndividual Plant Examination of External Events (IPEEE).

Though the IPEEE seismic and fireevent models have not been updated since the original IPEEE, the insights and information ofIPEEE have been used to estimate the effect on total LERF of including these external events inthe ILRT interval extension risk assessment.

In the SE issued by NRC letter dated June 25, 2008, the NRC concluded that the methodology inEPRI TR-1009325, Revision 2, is acceptable for referencing by licensees proposing to amend theirTS 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 andconditions for the use of EPRI TR-1009325, Revision 2.From Section 4.2 of SER North Anna Response1. The licensee submits documentation indicating that North Anna PRA quality is addressed inthe technical adequacy of their PRA is consistent with Section 4.6.2 belowthe requirements of RG 1.200 relevant to the ILRTExtension.

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, andsmall, and consistent with the clarification provided in these guidelines have been used for the North AnnaSection 3.2.4.5 of the SE. Specifically, a small increase plant specific assessment.

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

In addition, a smallincrease in CCFP should be defined as a valuemarginally greater than that accepted in a previous one-time ILRT extension requests.

This would require thatthe increase in CCFP be less than or equal to 1.5percentage 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 caseoperation).

In order to make the methodology (accident case 3b), and this value has been used in theacceptable, the average leak rate accident case North Anna plant specific risk assessment.

(accident case 3b) used by the licensees shall be 100 Lainstead 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 suctionupon for emergency core cooling system (ECCS) head for ECCS pump following design basis accidents.

performance.

Additional risk analysis has been performed to addressany change in risk associated with reliance oncontainment overpressure for ECCS performance.

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-LARAttachment 14.6.2 PRA QualityLevel 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 accidentsequences have been developed from internally initiated events. The sequences have beenmapped 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 PlantExamination which underwent NRC review. Review comments, current plant design, currentprocedures, plant operating data, current industry PRA techniques, and general improvements identified by the NRC have been incorporated into the current PRA model. The model ismaintained in accordance with Dominion PRA procedures.

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

The first peer review wasperformed in 2001 using the Westinghouse Owners Group Peer Review Process Guidance, andthe Facts and Observations (F&Os) were closed. A full-scope peer review was performed in 2013using 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 alsodetermined that no additional work was necessary for the 2001 peer review F&Os. The open gapsidentified by the peer review were evaluated for impact on the application.

As such, the updatedNorth 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 ResultsBased on the risk assessment results and the sensitivity calculations detailed in Attachment 4 ofthe letter, the following conclusions regarding the assessment of the plant risk are associated withextending the Type A ILRT test frequency to 15 years. These results apply to both Unit 1 andUnit 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 asresulting 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, therelevant 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 theEPRI guidance as written.

As such, the estimated change in internal events LERF isdetermined to be "very small" using the acceptance guidelines of Reg. Guide 1.174. Theincrease 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 rangeof 1.OE-06 per reactor year to 1.OE-07 per reactor year, applications will be considered onlyif 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-7per reactor year, the total LERF can be demonstrated to be well below 1.OE-5 per reactoryear. 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 is1..29E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-yearinterval 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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-LARAttachment 1" The change in dose risk for changing the Type A test frequency from three-per-ten years toone-per-fifteen years, measured as an increase to the total integrated dose risk for allaccident sequences, is 9.11 E-04 person-rem/yr or 0.18% of the total population dose usingthe 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 riskimpact assessment of the extended ILRT intervals.

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

• The increase in the conditional containment failure frequency from the three-per-ten yearfrequency to one-per-fifteen year frequency is 0.93% using the base case corrosion case inTable 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 itrepresents a small change to the NAPS risk profile.

Details of the North Anna risk assessment arecontained 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 yearsand 75 months, respectively.

NEI 94-01, Revision 3-A delineates a performance-based approachfor determining Type A, Type B, and Type C containment leakage rate surveillance testfrequencies.

Dominion is adopting the guidance of NEI 94-01, Revision 3-A for the North AnnaUnits 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 thatextension of the containment ILRT interval from 10 to 15 years represents minimal risk toincreased leakage.

The risk is minimized by continued Type B and Type C testing performed inaccordance with Option B of 10 CFR 50, Appendix J and inspection activities performed as part ofthe North Anna Power Station IWE/IWL ISI program.This experience is supplemented by risk analysis

studies, including the North Anna risk analysisprovided in Attachment

4. The findings of the North Anna risk assessment confirm the generalfindings of previous

studies, on a plant-specific basis, that extending the ILRT interval from 10 to15 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 andrequirements continue to be met.10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to besubject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment ofWater Cooled Nuclear Power Plants."

Appendix J specifies containment leakage testingrequirements, including the types required to ensure the leak-tight integrity of the primary reactorcontainment and systems and components which penetrate the containment.

In addition, Appendix J discusses leakage rate acceptance

criteria, test methodology, frequency of testing andPage 17 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1reporting 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 Atesting 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 testsmust be performed.

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

Thechange 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 incontainment 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 to15 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 thatNEI 94-01, Revision 3, describes an acceptable approach for implementing the optionalperformance-based requirements of 10 CFR 50, Appendix J, and is acceptable for referencing bylicensees proposing to amend their TS in regards to containment leakage rate testing, subject tothe limitations and conditions, noted in Section 4.0 of the SEs.EPRI TR-1009325, Revision 2, provides a risk impact assessment for optimized Integrated LeakRate Test (ILRT) intervals up to 15 years, utilizing current industry performance data and riskinformed 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 byNRC 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 theILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0of that SE.Based on the considerations above, (1) there is reasonable assurance that the health and safety ofthe public will not be endangered by operation in the proposed manner, (2) such activities willcontinue to be conducted in accordance with the site licensing basis, and (3) the approval of theproposed change will not be inimical to the common defense and security or to the health andsafety of the public.In conclusion, Dominion has determined that the proposed change does not require anyexemptions or relief from regulatory requirements, other than the TS, and does not affectconformance 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 EnergyInstitute (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 NAPSperformance-based leakage testing program in accordance with Option B of 10 CFR 50, AppendixPage 18 of 20 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 1J. 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 yearsto no longer than 15 years from the last ILRT and permit Type C testing to be performed at aninterval not to exceed 75 months.Dominion has evaluated whether or not a significant hazards consideration is involved with theproposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance ofamendment,"

as discussed below:1. Does the proposed change involve a significant increase in the probability or consequences ofan accident previously evaluated?

Response:

No.The proposed amendment involves changes to the NAPS Containment Leakage Rate TestingProgram.

The proposed amendment does not involve a physical change to the plant or a changein the manner in which the plant is operated or controlled.

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

As such, the containment and the testing requirements toperiodically demonstrate the integrity of the containment exist to ensure the plant's ability tomitigate 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, fordevelopment of the NAPS performance-based testing program.

Implementation of theseguidelines continues to provide adequate assurance that during design basis accidents, theprimary containment and its components will limit leakage rates to less than the values assumed inthe plant safety analyses.

The potential consequences of extending the ILRT interval to 15 yearshave been evaluated by analyzing the resulting changes in risk. The increase in risk in terms ofperson-rem per year within 50 miles resulting from design basis accidents was estimated to beacceptably 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 amongprevention of core damage, prevention of containment

failure, and consequence mitigation.

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

Based on the above discussion, it is concluded that the proposed change does not involve asignificant 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 anyaccident previously evaluated?

Response:

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

-LARAttachment 1requirements to periodically demonstrate the integrity of the containment exist to ensure the plant'sability to mitigate the consequences of an accident, do not involve any accident precursors orinitiators.

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

Therefore, the proposed change does not create the possibility of a new or different kind ofaccident 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 thedevelopment of the NAPS performance-based leakage testing program, and establishes a 15-yearinterval for the performance of the containment ILRT. This amendment does not alter the mannerin which safety limits, limiting safety system setpoints, or limiting conditions for operation aredetermined.

The specific requirements and conditions of the Containment Leakage Rate TestingProgram, 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 overallcontainment leakage rate limit specified by the TS is maintained, and the Type A, Type B, andType 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 ahigh 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 theILRT 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 findingof "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 releasedoffsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion setforth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b),

no environmental impactstatement or environmental assessment need be prepared in connection with the proposedamendment.

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 OfAmendment Re: Technical Specification Change To Extend The Type A Test Frequency To 15Years (TAC No. ME4090, ADAMS Accession Number ML1 10800034).

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

-LARAttachment 2Marked-up Technical Specification PageVirginia Electric and Power Company(Dominion)

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

-LARPrograms and Manuals5.55.5 Programs and Manuals5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed.

For the purpose of this program, aloss of safety function may exist when a support system isinoperable, and:a. A required system redundant to the system(s) supported by theinoperable support system is also inoperable; orb. A required system redundant to the system(s) in turn supported bythe inoperable supported system is also inoperable; orc. A required system redundant to the support system(s) for thesupported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If aloss of safety function is determined to exist by this program, theappropriate Conditions and Required Actions of the LCO in which theloss of safety function exists are required to be entered.

When aloss of safety function is caused by the inoperability of a singleTechnical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.5.5.15 Containment Leakage Rate Testing Programa. A program shall establish the leakage rate testing of thecontainment as required by 10 CFR 50.54(o) and 10 CFR 50,Appendix J, Option B, as modified by approved exemptions.

Thisprogram shall be in accordance with the guidelines contained inRegulantm u, Gu 1.163, 2Pernipplui.e-gabed Ce1l l,,iii, t Leak-TesProgram,"

dated gaptewbr

.... a.. d..ifd by the fa!8.....

NE. 94-C. 1995, Sectio 9.2.3. The first UWit 2 Type A testpeirferncd after the Oetebe 9, 1999 Typ A test shaii bperfcrncd melater than .t ..r 9, 2614.b. The calculated peak containment internal pressure for the designbasis 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 shallbe 0.1ý of containment air weight per day.centli nuedNEI 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 25.5-15Amendments FHJ-21-59 Serial No. 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 3Proposed Technical Specification PageVirginia Electric and Power Company(Dominion)

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

-LARPrograms and Manuals5.55.5 Programs and Manuals5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed.

For the purpose of this program, aloss of safety function may exist when a support system isinoperable, and:a. A required system redundant to the system(s) supported by theinoperable support system is also inoperable; orb. A required system redundant to the system(s) in turn supported bythe inoperable supported system is also inoperable; orc. A required system redundant to the support system(s) for thesupported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If aloss of safety function is determined to exist by this program, theappropriate Conditions and Required Actions of the LCO in which theloss of safety function exists are required to be entered.

When aloss of safety function is caused by the inoperability of a singleTechnical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.5.5.15 Containment Leakage Rate Testing Programa. A program shall establish the leakage rate testing of thecontainment as required by 10 CFR 50.54(o) and 10 CFR 50,Appendix J, Option B, as modified by approved exemptions.

Thisprogram shall be in accordance with the guidelines contained inNEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," datedJuly 2012.b. The calculated peak containment internal pressure for the designbasis 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, shallbe 0.1% of containment air weight per day.(continued)

North Anna Units 1 and 25.5-15Amendments Serial No. 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

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

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

-LARAttachment 4Table of Contents1.0 PURPO SE O F ANALYSIS

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

21 .1 P u rp o s e ...............................................................................................................................................

21 .2 B a c k g ro u n d .........................................................................................................................................

21 .3 C rite ria .................................................................................................................................................

32.0 M ETHO DO LO GY ...........................................................................................................................................

33.0 G RO UND RULES ..................................................................................................................................

4 ....... 44 .0 IN P U T S ..........................................................................................................................................................

54.1 General Resources Available

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

54.2 Plant-Specific Inputs ............................................................................................................................

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

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

125 .0 R E S U L T S ....................................................................................................................................................

1 55.1 Step 1 -Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year ..............................

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

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

215.4 Step 4 -Determine the Change in Risk in Terms of Large Early Release Frequency (LERF) ....... 235.5 Step 5 -Determine the Impact on the Conditional Containment Failure Probability (CCFP) ....... 245.6 Sum m ary of Results ..........................................................................................................................

245.7 External Events Contribution

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

265.8 Containm ent Overpressure Im pact on CDF .................................................................................

276 .0 S E N S IT IV IT IE S ...........................................................................................................................................

2 86.1 Sensitivity to Corrosion Im pact Assum ptions ..............................................................................

287.0 CO NCLUSIO NS ..........................................................................................................................................

2

98.0 REFERENCES

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

30ATTACHM ENT A, M AAP ANALYSES

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

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

-LARAttachment 41.0 PURPOSE OF ANALYSIS1.1 PurposeThe purpose of this analysis is to provide an assessment of the risk associated withpermanently extending the Type A integrated leak rate test (ILRT) interval from 10 years to 15years for North Anna Power Station (NAPS). The risk assessment follows the guidelines fromNEI 94-01, Revision 2-A [1], the methodology used in EPRI TR-104285

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

[18], the NRCregulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and riskinsights 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 riskimplications of corrosion-induced leakage of steel liners going undetected during the extendedtest interval

[4]. The format of this document is consistent with the intent of the Risk ImpactAssessment Template for evaluating extended integrated leak rate testing intervals provided inthe 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 apartin which the calculated performance leakage rate was less than limiting containment leakagerate of 1La.The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision0, and was established in 1995 during development of the performance-based Option B toAppendix 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 reviseleakage rate testing requirements contained in Option B to Appendix J. The basis consisted ofqualitative 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'srulemaking basis, NEI undertook a similar study. The results of that study are documented inElectric Power Research Institute (EPRI) Research Project Report TR-104285

[2], "Risk ImpactAssessment of Revised Containment Leak Rate Testing Intervals."

The NRC report on performance-based leak testing, NUREG-1493

[5], analyzed the effects ofcontainment leakage on the health and safety of the public and the benefits realized from thecontainment leak rate testing.

In that analysis, it was determined that for a representative PWRplant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latentrisks from reactor accidents.

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

In October 2008, EPRI TR-1018243

[18] was issued to develop ageneric methodology for the risk impact assessment for ILRT interval extensions to 15 yearsusing current performance data and risk informed

guidance, primarily NRC Regulatory Guide1.174 [3]. This more recent EPRI document considers the change in population dose, largeearly 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4methodology, with the affected System, Structure, or Component (SSC) being the primarycontainment boundary.

1.3 CriteriaThe acceptance guidelines in RG 1.174 [3] are used to assess the acceptability of thispermanent extension of the Type A test interval beyond that established during the Option Brulemaking 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 yearand increases in large early release frequency (LERF) less than 1.OE-07 per reactor year. Anevaluation of the CDF impact in Section 5 confirms that the change in risk is bounded by theLERF impact, so the relevant criterion is the change in LERF. RG 1.174 also defines smallchanges in LERF as below 1.OE-06 per reactor year. RG 1.174 discusses defense-in-depth andencourages 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-timerequests for extension of ILRT intervals.

Given this perspective and based on the guidance inEPRI TR-1018243

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

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

[18]) indicate arange of incremental increases in population dose that have been accepted by the NRC. Therange of incremental population dose increases is from -.0.01 to 0.2 person-rem/yr and/or 0.002to 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 thanthe NRC Safety Goal Risk. Given these perspectives, a very small population dose is definedas an increase from the baseline interval (3 tests per 10 years) dose of <1.0 person-rem peryear, or 1% of the total baseline dose, whichever is less restrictive for the risk impactassessment of the proposed extended ILRT interval.

It is noted that the methodology used inthe one-time ILRT interval extension requests assumed a EPRI TR-1018243 uses 100La. Thedose 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 forevaluating the change in risk associated with increasing the test interval to 15 years [18]. Theanalysis uses results from a Level 2 analysis of core damage scenarios from the current NAPSPRA analysis of record and subsequent containment responses resulting in various fissionproduct 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 eachof 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 theeight containment release scenario types from plant specific consequence analyses.

Page 3 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment

43. Evaluate the risk impact (i.e., the change in containment release scenario typefrequency 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) inaccordance 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 NAPSassessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failureprobability are also considered to show that defense-in-depth and the balance ofprevention and mitigation is preserved.

" Containment overpressure is credited in the ECCS and Recirculation Spray pump NPSHcalculations 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 tothe 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 riskmetrics that are similar to those used in EPRI TR-1018243

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

3.0 GROUND RULESThe 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 assumethat 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 thecalculations.

However, external events have been accounted for in the analysis basedon 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 NAPScalculation SM-1242 (referred to as the dose results from the NAPS SAMA analysis)

[22]." Accident classes describing radionuclide release end states are defined consistent withEPRI 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 Ainspection failures.

" The representative containment leakage for EPRI Accident Class 3a sequences is 10Labased on the previously approved methodology performed for Indian Point Unit 3 [6, 7]." The representative containment leakage for EPRI Accident Class 3b sequences is10OLa based on the guidance provided in EPRI TR-1018243

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

-LARAttachment 4* The EPRI Accident Class 3b sequences can be conservatively categorized as LERFbased on the previously approved methodology

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

Since the containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from thisseparate 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 valuesin each table may yield slightly different results.4.0 INPUTSThis 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 here1. 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 inthe Level 2 PRA for the size of containment leakage that is considered significant and is to beincluded in the model. The second study is applicable because it provides a basis of theprobability for significant pre-existing containment leakage at the time of a core damageaccident.

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

Thesixth 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 ofextending ILRT and local leak rate test (LLRT) intervals on at-power public risk. The eighthstudy addresses the impact of age-related degradation of the containment liners on ILRTevaluations.

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-yearextension of the ILRT interval.

Page 5 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4NUREG/CR-3539

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

This study uses information from WASH-1400

[14] asthe basis for its risk sensitivity calculations.

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

[91NUREG/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 otherrelated records to calculate the unavailability of containment due to leakage.NUREG-1273

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

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

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

[111NUREG/CR-4330 is a study that examined the risk impacts associated with increasing theallowable containment leakage rates. The details of this report have no direct impact on themodeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakagerate 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 byaccident sequences that result in failure or bypass of containment."

EPRI TR-105189

[121The 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. Thisstudy 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 onshutdown risk. The conclusion from the study is that a small but measurable safety benefit isrealized from extending the test intervals.

NUREG-1493

[51NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reducecontainment leakage testing intervals and/or relax allowable leakage rates. The NRCconclusions are consistent with other similar containment leakage risk studies:

Reduction inILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase inrisk. Given the insensitivity of risk to the containment leak rate and the small fraction of leakpaths detected solely by Type A testing, increasing the interval between integrated leak ratetests is possible with minimal impact on public risk.EPRI TR-104285

[21Extending 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 andLLRT test intervals on at-power public risk. This study combined IPE Level 2 models withNUREG- 1150 Level 3 population dose models to perform the analysis.

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

-LARAttachment 4to 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 ofcontainment response to a core damage accident:

1. Containment intact and isolated2. Containment isolation failures dependent upon the core damage accident3. Type A (ILRT) related containment isolation failures4. Type B (LLRT) related containment isolation failures5. Type C (LLRT) related containment isolation failures6. Other penetration related containment isolation failures7. Containment failures due to core damage accident phenomena

8. Containment bypassConsistent with the other containment leakage risk assessment

studies, this study concluded:

"... the proposed CLRT [containment leak rate tests] frequency changes would have aminimal safety impact. The change in risk determined by the analyses is small in bothabsolute and relative terms. For example, for the PWR analyzed, the change is about0.04 person-rem per year..."Release Category Definitions Table 4.1-1 defines the accident classes used in the ILRT extension evaluation, which isconsistent with the EPRI methodology

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

Independent (or random) isolation failures include those accidents in which the3 pre-existing isolation failure to seal (i.e., provide a leak-tight containment) is notdependent on the sequence in progress.

Independent (or random) isolation failures include those accidents in which thepre-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-testedcomponents that have isolated but exhibit excessive leakage.Independent (or random) isolation failures include those accidents in which the5 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4EPRI Class EPRI Class Description Containment isolation failures include those leak paths covered in the plant test6 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 or8 induced by phenomena) are included in Class 8. Changes in Appendix J testingrequirements do not impact these accidents.

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

[41This submittal to the NRC describes a method for determining the change in likelihood, due toextending the ILRT, of detecting liner corrosion, and the corresponding change in risk. Themethodology 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 factoredinto the risk assessment for the ILRT one-time extension.

The Calvert Cliffs analysis wasperformed 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 riskimpact assessment.

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

[181This 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 riskimpact 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 documentincludes the bases for the values assigned in determining the probability of leakage for the EPRIClass 3a and 3b scenarios in this analysis as described in Section 5.4.2 Plant-Specific InputsThe 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 ModelThe 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 averagePage 8 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4maintenance 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 2model 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 sourceterm 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 theanalyzed 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 aconservative estimation of the risk for both units. This risk impact assessment will be based onthis CDF, and it will be assumed that the results of the assessment are conservative for bothUnits. Each of the source term categories is associated with a corresponding EPRI class, andthe EPRI class frequencies are calculated by summing the associated source term categoryfrequencies.

NAPS Source Term Category Population DoseA 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 inthe IPE [23] contained twenty-four source term categories.

Ten of the STCs used thepopulation dose calculated by their respective MAAP runs. The remaining fourteen STCs usedrecommended alternate population doses from the ten STCs that were evaluated using MAAPas specified in the IPE. The STC diagram has been revised since the IPE. The latest STCDiagram 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 byassociating sequences in the current STC diagram with sequences in IPE STC diagram.

Usingcalculation SM-1242 [22] in conjunction with NAPS-LE.1

[21] and the IPE [23] allows thepopulation doses to be determined for the current STCs. The STCs which do not result in arelease 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 NAPSone-time ILRT extension)

[24] will be employed in which population dose for STC 2 from theIPE, which would be an EPRI Class 7, will be used as the EPRI Class 1 population dose. Thisapproach is conservative because the STC 2 MAAP run has characteristics that arerepresentative of the EPRI Class 1 containment

leakage, but the EPRI Class 1 assumes a muchsmaller containment leak rate.Release Category Definitions Table 4.2-1 below defines the NAPS release categories and associates them with the EPRIaccident classes used in the ILRT extension evaluation.

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

-LARAttachment 4Table 4.2-1NAPS Release Cateaorv Definitions.

Freauencv.

and Population DoseNAPS Rees 2tar eiiin raec n ouainDsNAPS Frequency Person-Rem' EPRICategory per year (50 miles) Class Description 1 6.11E-07 4.24E+023 1 No Containment Failure2 O.OOE+00 2.35E+064 7 Early Containment Failure3 6.43E-08 1.99E+045 7 Late Containment Failure4 4.17E-09 6.69E+055 7 Late Containment Failure5 3.55E-09 1.99E+044 7 Late Containment Failure6 0.OOE+00 6.69E+055 7 Late Containment Failure7 0.OOE+00 2.68E+054 7 Late Containment Failure8 1.28E-07 5.60E+045 7 Late Containment Failure9 8.01 E-08 5.60E+044 7 Late Containment Failure10 2.86E-08 1.99E+045 7 Meltthru11 6.47E-07 4.24E+025 2 No Containment Isolation 12 1.53E-09 3.86E+055 2 No Containment Isolation 13 1.15E-08 2.41 E+065 8 Event V (ISLOCA)

-attenuation 14 1.15E-08 6.15E+064 8 Event V (ISLOCA)

-no attenuation 15 7.90E-08 4.74E+064 8 Steam Generator Tube Rupture16 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 FailureCDF1.72E-06LERF I 1.36E-071. 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 doseresults 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 theyapply to North Anna can be calculated.

The frequency of each EPRI class is the sum of theassociated STC frequencies, and the doses for classes 2, 7, and 8 are frequency weighted.

Table 4.2-2Summary of Release Frequency and Population Dose Organized by EPRI ReleaseCategoryEPRI Class Frequency

(/yr) Dose (person-rem) 1 6.11 E-07 4.24E+022 6.48E-07 1.33E+037 3.09E-07 5.30E+048 1.48E-07 3.35E+064.3 Impact of Extension on Detection of Component Failures That Lead to LeakageThe ILRT can detect a number of component failures such as liner breach, failure of certainbellows arrangements and failure of some sealing surfaces, which can lead to leakage.

Theproposed 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 3Page 10 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4containment 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 EPRIguidance

[18]. For Class 3a, the probability is based on the maximum likelihood estimate offailure (arithmetic average) from the available data (i.e., 2 "small" failures in 217 tests leads to2/217=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 theNRC regulatory guide 1.174 [3]. This information includes a discussion of conservatisms in thequantitative 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) involvesconservatively multiplying the CDF by the failure probability for this class (3b) ofaccident.

This was done for simplicity and to maintain conservatism.

However,some plant-specific accident classes leading to core damage are likely to includeindividual sequences that either may already (independently) cause a LERF orcould never cause a LERF, and are thus not associated with a postulated largeType A containment leakage path (LERF). These contributors can be removedfrom 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 thecalculation of the Class 3a and 3b frequencies.

Consistent with the EPRI methodology

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

Forexample, the average time that a leak could go undetected with a three-year test interval is 1.5years (3 yr / 2), and the average time that a leak could exist without detection for a ten-yearinterval is 5 years (10 yr / 2). This change would lead to a non-detection probability that is afactor 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 abouta 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 comparedto previous submittals (e.g., the Indian Point Unit 3 request for a one-time ILRT extension thatwas approved by the NRC [7]) because it does not factor in the possibility that the failures couldbe 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 ILRTextension.

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

-LARAttachment 44.4 Impact of Extension on Detection of Steel Liner Corrosion That Leads to LeakageAn estimate of the likelihood and risk implications of corrosion-induced leakage of the steelliners occurring and going undetected during the extended test interval is evaluated using themethodology from the Calvert Cliffs liner corrosion analysis

[4]. The Calvert Cliffs analysis wasperformed 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 theILRT, of detecting corrosion of the containment steel liner. This likelihood is then used todetermine 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 flawAssumptions

• Consistent with the Calvert Cliffs analysis, a half failure is assumed for basematconcealed liner corrosion due to the lack of identified failures.

• The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffsanalysis are assumed to be applicable to the NAPS containment analysis.

Theseevents, one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from thenon-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 9years documented in Reference

[28]). In November 2006, the Turkey Point 4containment building liner developed a hole when a sump pump support plate wasmoved. In May 2009, a hole approximately 3/8" by 1" in size was identified in theBeaver Valley 1 containment liner. For risk evaluation

purposes, these two more recentevents occurring over a 9-year period are judged to be adequately represented by thetwo events in the 5.5-year period of the Calvert Cliffs analysis incorporated in the EPRIguidance.

(See Table 4.4-1, Step 1.)" Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is alsolimited 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 CalvertCliffs liner corrosion analysis was performed.

Additional success data was not used tolimit the aging impact of this corrosion issue, even though inspections were beingperformed prior to this date (and have been performed since the time frame of theCalvert Cliffs analysis),

and there is no evidence that additional corrosion issues wereidentified.

(See Table 4.4-1, Step 1.)" Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed todouble every five years. This is based solely on judgment and is included in thisanalysis to address the increased likelihood of corrosion as the steel liner ages. (SeePage 12 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 4.4-1, Steps 2 and 3) Sensitivity studies are included that address doubling thisrate every ten years and every two years.In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching theoutside atmosphere given that a liner flaw exists was estimated as 1.1% for the cylinderand dome and 0.11% (10% of the cylinder failure probability) for the basemat.

Thesevalues were determined from an assessment of the probability versus containment

pressure, and the selected values are consistent with a pressure that corresponds to theILRT target pressure of 37 psig. For NAPS, the containment failure probabilities are lessthan these values at 42.7 psig [29]. Conservative probabilities of 1% for the cylinder anddome and 0.1% for the basemat are used in this analysis, and sensitivity studies areincluded that increase and decrease the probabilities by an order of magnitude.

(SeeTable 4.4-1, Step 4)* Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crackformation) 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 failurelikelihood 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.

(SeeTable 4.4-1, Step 5) Sensitivity studies are included that evaluate total detection failurelikelihood of 5% and 15%, respectively.

" Consistent with the Calvert Cliffs analysis, all non-detectable containment failures areassumed to result in early releases.

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

-LARAttachment 4Table 4.4-1Steel Liner Corrosion Base CaseStep Description Containment Walls Containment Basemat1 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-32 Age-Adjusted Steel Year Failure Rate Year Failure RateLiner Flaw Likelihood 1 2.05E-03 1 5.13E-042 2.36E-03 2 5.89E-043 2.71E-03 3 6.77E-044 3.111E-03 4 7.77E-045 3.57E-03 5 8.93E-046 4.10E-03 6 1.03E-037 4.71E-03 7 1.18E-038 5.41E-03 8 1.35E-039 6.22E-03 9 1.55E-0310 7.14E-03 10 1.79E-0311 8.21E-03 11 2.05E-0312 9.43E-03 12 2.36E-0313 1.08E-02 13 2.71E-0314 1.24E-02 14 3.111E-03 15 1.43E-02 15 3.57E-033 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%yearsito 15 9.66% 1 to 15 years 2.41%years4 Likelihood of Breach Pressure Pressurein 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 ofStep 6 for the containment cylinder and dome and the containment basemat as summarized below for NAPS.Page 14 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Total 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, andthe result is added to the Class 3b frequency in the corrosion sensitivity studies.

The non-LERFcontainment overpressure CDF is calculated by subtracting the Class 1, Class 3b, and Class 8CDFs from the total CDF so that only Classes 2, 3a, and 7 are included in the CDF calculation.

5.0 RESULTSThe 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 1and NAPS Unit 2. The results are displayed according to the eight accident classes defined inthe 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 severeaccidents contributing to risk was considered in the following manner:* Core damage sequences in which the containment remains intact initially and in the longterm (EPRI TR-104285 Class 1 sequences).

" Core damage sequences in which containment integrity is impaired due to randomisolation failures of plant components other than those associated with Type B or Type Ctest components.

For example, liner breach or bellows leakage.

(EPRI Class 3sequences).

" 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 notsignificantly influence the results of this analysis.

" Accident sequences involving containment bypassed (EPRI Class 8 sequences),

largecontainment isolation failures (EPRI Class 2 sequences),

and small containment isolation "failure-to-seal" events (EPRI Class 4 and 5 sequences) are accounted for inthis evaluation as part of the baseline risk profile.

However, they are not affected by theILRT 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 5.0-1EPRI Accident ClassesEPRI Accident Description Class1 No Containment Failure2 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 eightaccident classes presented in Table 5.0-1.Step 2 Develop plant-specific person-rem dose (population dose) per reactor year for each ofthe eight accident classes.Step 3 Evaluate the risk impact of extending Type A test interval from three to fifteen and tento fifteen years.Step 4 Determine the change in risk in terms of Large Early Release Frequency (LERF) inaccordance 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 YearAs previously described, the extension of the Type A interval does not influence those accidentprogressions that involve large containment isolation

failures, Type B or Type C testing, orcontainment failure induced by severe accident phenomena.

For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks isincluded 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 forNAPS 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 forClasses 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 theimpact 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4With the inclusion of the EPRI 3a and 3b classes, the EPRI Class 1 frequency will be reducedby 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 isolatethe containment occurs. The frequency per year for these sequences is obtained from theRelease 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 leakagefor 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 failureprobabilities 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 is1OOLa. 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 detectedby Type B tests which are unaffected by the Type A ILRT, this group is not evaluated anyfurther 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 TypeC tests which are unaffected by the Type A ILRT, this group is not evaluated any further in thisanalysis.

Class 6 Sequences This group is similar to Class 2. These are sequences that involve core damage accidentprogression bins for which a failure-to-seal containment leakage due to failure to isolate thecontainment 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment

41018243, this accident class is not explicitly considered since it has a negligible impact on theresults.Class 7 Sequences This group consists of all core damage accident progression bins in which containment failureinduced by severe accident phenomena occurs (e.g., overpressure).

For this analysis, thefrequency is determined from Release Categories 2 through 10 from the NAPS Level 2 resultsin 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 bypassoccurs. For this analysis, the frequency is determined from Release Categories 13 through 17from 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 thepublic 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 5.1-1Accident Class Frequencies Accident Class Description Frequency (1/YR)1 No Containment Failure 5.91 E-072 Large Containment Isolation Failures (Failure to close) 6.48E-073a Small Isolation Failures (Type A test) 1.58E-083b Large Isolation Failures (Type A test) 3.96E-094 Small Isolation Failure (Type B test) N/A5 Small Isolation Failure (Type C test) N/A6 Containment Isolation Failures (personnel errors) N/A7 Severe Accident Phenomena Induced Failure 3.09E-078 Containment Bypassed 1.48E-07CDF All CET End States (including intact case) 1.72E-065.2 Step 2 -Develop Plant-Specific Person-Rem Dose (Population Dose) Per ReactorYearPlant-specific release analyses were performed to estimate the person-rem doses to thepopulation 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 R2notebook

[21], the NAPS IPE [23], and calculation SM-1325 [24]. Calculation SM-1242 containsthe dose results in Sieverts for the release categories that were evaluated in the SAMAanalysis.

The LE.1 notebook

[21] and the IPE [22] are used to associate the STCs from thecurrent STC diagram with the STCs from the previous STC diagram which was used during theSAMA analysis.

The IPE [22] is also used to identify the recommended alternate STC withrepresentative results for STCs for which a MAAP run does not exist. Since the Class 1 STCsdo 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 SAMAanalysis based on SM-1 325 [24]. The STC 2 dose is documented in SM-1 242 [22], and it wouldbe classified as a Class 7 EPRI release category.

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

-LARAttachment 4dose is conservative since the STC 2 MAAP run has characteristics that are representative ofan EPRI Class 1 containment

leakage, but the Class 7 containment leak rate is much greaterthan the Class 1 containment leak rate. The results of applying these releases to the EPRIcontainment 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 analyzedClass 5 = Not analyzedClass 6 = Not analyzedClass 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 incontainment isolation failure.(3) The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with theguidance provided in EPRI TR-1018243.

(4) The Class 7 dose is assigned from frequency weighted dose for release categories resulting incontainment failure.(5) Class 8 sequences involve containment bypass failures; as a result, the person-rem dose is not basedon normal containment leakage.

The dose for this class is assigned from the frequency weighted dosefor release categories resulting in containment bypass.In summary, the population dose estimates derived for use in the risk evaluation per the EPRImethodology

[18] containment failure classifications are provided in Table 5.2-1.Table 5.2-1Accident Class Population DoseAccident Class Description Person-Rem 1 No Containment Failure 4.24E+022 Large Containment Isolation Failures (Failure to close) 1.33E+033a Small Isolation Failures (Type A test) 4.24E+033b Large Isolation Failures (Type A test) 4.24E+044 Small Isolation Failure (Type B test) N/A5 Small Isolation Failure (Type C test) N/A6 Containment Isolation Failures (personnel errors) N/A7 Severe Accident Phenomena Induced Failure 5.30E+048 Containment Bypassed 3.35E+06The above dose estimates, when combined with the results presented in Table 5.1-1, yield theNAPS baseline mean consequence measures for each accident class. These results arepresented in Table 5.2-2.Page 19 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 5.2-2Accident 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 RemsoRRem/YR1 No Containment 4.24E+02 5.91 E-07 2.51 E-04 5.91 E-07 2.51 E-04 -3.95E-09 FailureLarge Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04Close)Small Isolation 3a Failures (liner 4.24E+03 1.58E-08 6.71 E-05 1.58E-08 6.71 E-05breach)Large Isolation 3b Failures (liner 4.24E+04 3.96E-09 1.68E-04 3.96E-09 1.68E-04 3.95E-07breach)Small Isolation 4 Failures (Failure to N/A N/A N/A N/A N/Aseal -Type B)Small Isolation 5 Failures (Failure to N/A N/A N/A N/A N/Aseal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/Adependent failures)

Failures Induced7 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

--BypassSum of AllTotal Accident Class 1.72E-06 5.14E-01 1.72E-06 5.14E-01 3.91 E-07ResultsTable 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 5.2-3Corrosion Impact on Class 3b Frequency for 3-per-10 year ILRT Frequency Metric ResultILRT Frequency 3 per 10 YearsLikelihood 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/yrClass 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 45.3 Step 3 -Evaluate Risk Impact of Extending Type A Test Interval From 10 to 15YearsThe 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 IntervalAs previously stated, Type A tests impact only Class 3 sequences.

For Class 3 sequences, therelease magnitude is not impacted by the change in test interval (a small or large breachremains 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 changedbased on the NEI guidance as described in Section 4.3 by a factor of 3.33 compared to thebase case values. The results of the calculation for a 10-year interval are presented in Table5.3-1.Table 5.3-1Accident 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/YR1 No Containment 4.24E+02 5.45E-07 2.31E-04 5.45E-07 2.31E-04

-2.38E-08 FailureLarge Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04Close)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-06Failures (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 by7 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-06Class ResultsITable 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 5.3-2Corrosion Impact on Class 3b Frequency for 1-per-10 year ILRTFrequency Metric ResultILRT Frequency 3 per 10 YearsLikelihood of Corrosion-Induced Leak (Section 4.4) 0.00556%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 1.01 E-06/yrIncrease in LERF (0.00556%

• 1.01E-06/yr) 5.62E-1 1/yrClass 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 IntervalThe risk contribution for a 15-year interval is calculated in a manner similar to the 10-yearinterval.

The difference is in the increase in probability of leakage in Classes 3a and 3b. Forthis 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 5.3-3Accident 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 PersonRem/YR1 No Containment 4.24E+02 5.12E-07 2.17E-04 5.12E-07 2.17E-04

-5.71E-08 FailureLarge Isolation 2 Failures (Failure to 1.33E+03 6.48E-07 8.65E-04 6.48E-07 8.65E-04Close)Small Isolation 3a Failures (liner 4.24E+03 7.91E-08 3.35E-04 7.91E-08 3.35E-04breach)Large Isolation 3b Failures (liner 4.24E+04 1.98E-08 8.39E-04 1.99E-08 8.44E-04 5.71 E-06breach)Small Isolation 4 Failures (Failure to N/A N/A N/A N/A N/Aseal -Type B)Small Isolation 5 Failures (Failure to N/A N/A N/A N/A N/Aseal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/Adependent failures)

Failures Induced by7 Phenomena (Early 5.30E+04 3.09E-07 1.64E-02 3.09E-07 1.64E-02and Late)8 Containment Bypass 3.35E+06 1.48E-07 4.96E-01 1.48E-07 4.96E-01Sum of AllTotal Accident Class 1.72E-06 5.15E-01 1.72E-06 5.15E-01 5.65E-06ResultsPage 22 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 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 5.3-4Corrosion Impact on Class 3b Frequency for 1-per-15 year ILRT Frequency Metric FactorILRT Frequency 1 per 15 YearsLikelihood 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 coredamage event that normally would result in only a small radioactive release from an intactcontainment could in fact result in a larger release due to the increase in probability of failure todetect a pre-existing leak. With strict adherence to the EPRI guidance, 100% of the Class 3bcontribution 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 inincreases of core damage frequency (CDF) below 1.0E-06/yr and increases in LERF below1.OE-07/yr, and small changes in LERF as below 1.OE-06/yr.

Because the ILRT does notimpact 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 intervalextension (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 to15 years is 1.58E-08/yr.

Similarly, the increase due to increasing the interval from 10 to 15years 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 avery small change when comparing the fifteen-year results to both the current ten-yearrequirement and the original three-year requirement.

If the effects due to liner corrosion are included in the 15-year interval

results, the Class 3bfrequency becomes 1.99E-08/yr as shown in Table 5.3-3. Conservatively neglecting the impactof steel liner corrosion On the Class 3b frequency for the three-year and 10-year intervals, thechange 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-yearinterval.

This is an increase in LERF of 1.35E-10/yr from the fifteen-year interval results withoutcorrosion.

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

-LARAttachment 4comparing 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 thedecision-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 justLERF. 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 thisassessment, the CCFP is defined such that containment failure includes all radionuclide releaseend states other than the intact state. The conditional part of the definition is conditional given asevere 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 theproposed change is consistent with the defense-in-depth philosophy.

CCFP = [1 -(Class 1 frequency

+ Class 3a frequency)

/ CDF]

• 100%CCFP3 = 64.64%CCFP1o = 65.18%CCFP15 = 65.56%ACCFP3-To-l5 = CCFP15 -CCFP3 = 0.92%ACCFP10.To.15 = CCFP15 -CCFP1o = 0.38%The CCFP is also calculated for the 15-year interval to evaluate the impact of the steel linercorrosion 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

-CCFP3 = 0.93%ACCFP1o-To-15+Corrosion

= CCFP15+corrosion

-CCFP1o = 0.39%The change in CCFP of approximately 0.93% by extending the test interval to 15 years from theoriginal three-per-ten year requirement is judged to be insignificant.

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

-LARAttachment 4Table 5.6-1Summa of Results for ILRT Frequency Extensions Base Case (3 per 10 years) 1 per 10 years 1 per 15 yearsWithout Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion Person- Person- Delta Person- Person- DeltaEPRI 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 peryear year peryear year year per year year yearyearyear year1 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+003a 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+003b 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-067 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+008 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+00Total 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-06Delta 5.28E-04 5.30E-04 9.06E-04 9.11 E-04Dose1 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%DeltaCCFP2 N/A N/A 0.54% 0.54% 0.92% 0.93%Class 3.96E-09 1.32E-08 1.99E-083b 3.96E-09 (9.31E-12) 1.32E-08 (5.62E-11) 1.98E-08 (1.35E-10)

LERF3D 9.27E-09 1.60E-08Delta LERF From Base Case (3 per 10 years)3 9.22E-09 (562E1 1) 1.58E-08(1.5E-10) 6.74E-09Delta LERF From 1 per 10 years3 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 45.7 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 fromexternal events is presented here.The IPEEE only evaluated the external events risk associated with NAPS Unit 1 although uniquescenarios were included for Unit 2. The Unit 2 internal fire CDF was slightly higher than the Unit 1CDF, so the Unit 2 CDF (4.08E-6/yr) was used for the external events calculation as a result. Itwas determined that the differences between Unit 1 and Unit 2 would have negligible impact on thePRA 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 arerepresentative of both Unit 1 and Unit 2.No seismic PRA quantification is available for North Anna since the seismic margins method wasused in the IPEEE [25]. A comparison of the Surry internal fire CDF and seismic CDF from theSurry IPEEE, which were estimated to be 6.3E-6/yr

[20] and 8.OE-6/yr

[27], respectively, showsthat the seismic CDF was estimated to be 27% higher than the internal fire CDF. Since there isuncertainty related to differences between Surry and North Anna's designs and seismic hazardcurves, the North Anna seismic CDF will be assumed to be 100% higher than, or double, theinternal 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 seismicexternal events contribution to the LERF increase resulting from extending the ILRT interval from10 years to 15 years.The method chosen to account for external events contributions is similar to the approach used tocalculate 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 CDFby the probability of a Class 3b release.

The same approach will be used for external events usingthe 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], sotheir impact will be assumed to be negligible compared to the impact associated with internal firesand seismic events. The North Anna IPEEE [25] did not evaluate LERF. However, the internal fireand seismic LERF will be estimated using the ratio of LERF to CDF from the internal events model.Table 5.7-1External Events Base CDF and LERFExternal Event Initiator Group CDF LERF Internal Events(CDF

• Internal Events Ratio) LERF/CDF RatioSeismic 8.16E-06 6.45E-07 7.90E-02Internal Fire 4.08E-06 3.22E-07 7.90E-02Total 1.22E-05 9.67E-07Table 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 inLERF.Page 26 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Table 5.7-2Total LERF Increase for 15-year ILRT Interval Including Internal and External EventsInitiating Class 3b Frequency

(/yr) LERFEvent CDF LERF Class 3b 3 per 10 1 per 10 1 per 15 IncreaseGroup (/yr) (/yr) Probability year yearILRT ILRT year ILRT (Iyr)Internal 1.72E- 1.36E- 0.0023 3.96E-09 1.32E-08 1.98E-08 1.58E-08Events 06 07External 1.22E- 9.67E- 0.0023 2.82E-08 9.40E-08 1.41E-07 1.13E-07Events 05 07Total 1.40E l11E- -3.22E-08 1.07E-07 1.61E-07 1.29E-0705 06As with the internal events analysis, 100% of the frequency of Class 3b sequences can be used asa very conservative first-order estimate to approximate the potential increase in LERF from theILRT interval extension (consistent with the EPRI guidance methodology).

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

Based ona 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 toincreasing the ILRT test interval from 3 to 15 years is 1.29E-07/yr and from 10 to 15 years is5.36E-08/yr.

As can be seen, even with the conservatisms included in the evaluation (per theEPRI methodology),

the estimated change in LERF is small according to RG 1.174 since it fallsbelow 1.OE-07/yr when comparing the 15-year result to the current 10-year requirement andbetween 1.OE-07/yr and 1.OE-06/yr when comparing the 15-year result to the original 3-yearrequirement.

5.8 Containment Overpressure Impact on CDFThe NAPS design basis calculations credit containment overpressure to satisfy the net positivesuction 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. Inaddition, only large LOCAs are considered in the design basis calculations since this is the mostlimiting case for the analysis.

Several cases were evaluated using MAAP in order to determine ifNPSH would be lost for the RS pumps and LHSI pumps during small, medium, and large LOCAswith 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 sizeevaluated.

Based on these results, a more detailed CDF evaluation does not need to beperformed, and the impact of the ILRT interval extension is bounded by the LERF analysis.

Page 27 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 46.0 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 usingthe assumptions described in Section 4.4 does not significantly affect the results of the ILRTextension risk assessment.

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

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

Thetotal 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 theupper 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 6.1-1Liner Corrosion Sensitivity CasesSteelIncrease in Class 3bContainment Visual Inspection Frequency (LERF) for ILRTAge 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 Totalto Corrosion IncreaseBase Case Base Case Base Case Base CaseDouble/5 Years 1.1/0.11 10% 100% 1.35E-10 1.60E-08Double/2 Years Base Base Base 1.24E-09 1.71 E-08Double/1 0 Years Base Base Base 7.28E-1 1 1.59E-08Base Base Point 1Ox Lower Base Base 2.97E-11 1.59E-08Base Base Point 10x Higher Base Base 6.10E-10 1.64E-08Base Base 5% Base 8.07E-11 1.59E-08Base Base 15% Base 1.88E-10 1.60E-08Lower BoundDouble/10 Years Base Point 1Ox Lower 5% 10% 9.65E-13 1.58E-08Upper BoundDouble/2 Years Base Point 10x Higher 15% 100% 7.88E-09 2.37E-08Page 28 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment

47.0 CONCLUSION

S Based on the results from Section 5 and the sensitivity calculations presented in Section 6, thefollowing conclusions regarding the assessment of the plant risk are associated with extending theType A ILRT test interval from the current 10 years to 15 years. These results apply to both Unit 1and 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 asresulting 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, therelevant 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 toone-per-fifteen years is conservatively estimated as 1.60E-08/yr (see Table 5.6-1) using theEPRI guidance as written.

As such, the estimated change in internal events LERF isdetermined to be "very small" using the acceptance guidelines of Reg. Guide 1.174. Theincrease 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 rangeof 1.OE-06 per reactor year to 1.OE-07 per reactor year, applications will be considered onlyif 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-7per reactor year, the total LERF can be demonstrated to be well below 1.OE-5 per reactoryear. 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 is1.29E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-yearinterval 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 toone-per-fifteen years, measured as an increase to the total integrated dose risk for allaccident sequences, is 9.11 E-04 person-rem/yr or 0.18% of the total population dose usingthe 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 riskimpact assessment of the extended ILRT intervals.

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

• The increase in the conditional containment failure frequency from the three-per-ten yearfrequency to one-per-fifteen year frequency is 0.93% using the base case corrosion case inTable 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 itrepresents a small change to the NAPS risk profile.Page 29 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4Previous 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 20years was found to lead to an imperceptible increase in risk. The estimated increase in riskis very small because ILRTs identify only a few potential containment leakage paths thatcannot be identified by Type B and C testing, and the leaks that have been found by TypeA tests have been only marginally above existing requirements.

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

Beyond testing theperformance 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 thesevere accidents evaluated for NAPS, the NAPS containment failure modes, and the localpopulation 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, PaloAlto, 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, November2002.[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 NationalLaboratory, 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 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 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 andResearch, 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, DominionResources

Services, Inc., North Anna Power Station NAPS-R07 PRA Model, October 2013.[20] Individual Plant Examination of Non-Seismic External Events and Fires, Surry PowerStation 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, NorthAnna 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 ATest Interval at North Anna Power Station, Virginia Electric and Power Company, NorthAnna Power Station, October 2001.[25] Individual Plant Examination of Non-Seismic External Events and Fires, North Anna PowerStation Units 1 and 2, Virginia Electric and Power Company, April 1994.[26] Individual Plant Examination of External Events -Seismic, North Anna Power Station Units1 and 2, Virginia Electric and Power Company, May 1997.[27] EQE Report 250226-R-001 Revision 0, Sequence Quantification, Seismic IPEEE, SurryPower 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, DominionResources

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 InternalFlooding PRA Peer Review Report, Westinghouse Electric Company LLC, 2013 PWROGPRA Peer Review, April 2014.Page 31 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4ATTACHMENT A, MAAP ANALYSESThe purpose of this attachment is to document MAAP cases analyzed in support of the North AnnaPower Station ILRT extension application.

MAAP analyses were performed for different break sizeLOCAs to demonstrate that assuming an increased leakage from containment exceeding designleakage by a factor of 100, enough NPSH would still be available to the Recirculation Spray pumpsto 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 pumpsand all four RS pumps were available to start and run on demand. The IRS pumps were assumedto start on high containment pressure signal concurrent with RWST level below 60%, and ORSpumps 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 wasestablished automatically when RWST level dropped below 23%.The design leakage from containment is assumed to be 0.1% of the free containment air weight atdesign 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 thepurposes of ILRT analyses.

According to NAPS MAAP input parameter VOLRB(1) throughVOLRB(11) that represent containment volumes in different compartments, the total modeledcontainment volume is 1,842,070 ft3 which converts to 88,693 lbs of air (see table below).Total Containment Volume and Air Weight1Compartment Weight (Ib) Volume (ft3)1 607 125702 14759 3060003 8053 1670004 2155 447005 2213 459006 2517 522007 2120 440008 1615 335009 28733 59690010 24918 51850011 1003 20800Total 88693 1842070So, 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 volumeof 1,916,000 ft3 per UFSAR Table 6.2-2, the target leakage from containment was increased to 500lbs/hr. The equivalent containment break area to result in 500 lbs/hr leakage is about 2.636E-3 ft2(obtained by iterative MAAP runs using parameter WRB(2)).

It should be noted that since thisbreak area results in 500 lbs/hr leakage at 20-25 psia of containment

pressure, it will result in ahigher leakage at containment design pressure of 60 psia, thus making the selection of this breakarea conservative for the purposes of ILRT analysis.

1 Air weight is obtained from MAAP output parameter MGRB(1) through MGRB(11) taken at time = 0Page 32 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 4The output results of cases 1 in-SLOCA, 2in-SLOCA, 4in-MLOCA, 6in-MLOCA and 31 in-LLOCA didnot include any loss of NPSH. This is well demonstrated by Figures D-1 through D-5. All MAAPinput and output files are provided below.I-- 1" Break LOCA0.EEM0U-987654321005 10 15 20 25Time (hr)Figure D-1: 1" Break LOCA, Water Level in Containment SumpPage 33 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 42" Break LOCA0.EE0987654321005 10 15 20Time (hr)Figure D-2: 2" Break LOCA, Water Level in Containment Sump254" Break LOCA9 18cL 7.E0U 5E4'( 4030 5 10 1 02Time (hr)152025Figure D-3: 4" Break LOCA, Water Level in Containment SumpPage 34 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 46" Break LOCA0.EE0U4-'987654321005 10 15 20Time (hr)Figure D-4: 6" Break LOCA, Water Level in Containment Sump25Page 35 of 36 Serial No 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 431" Break LOCA10CLE3.E4.r0U1005 10 15 20 25Time (hr)Figure D-5: 31" Break LOCA, Water Level in Containment SumpMAAP Input and Output FilesPage 36 of 36 Serial No. 14-272Docket Nos. 50-338/339 Type A Test Interval Extension

-LARAttachment 5PRA Technical AdequacyVirginia Electric and Power Company(Dominion)

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

-LARAttachment 5PRA TECHNICAL ADEQUACYThe PRA model used to analyze the risk of this application is the CAFTA accidentsequence model referred to as NAPS-R07

[19]. The effective date of this model isOctober 16, 2013. North Anna PRA Model Notebook QU.2, Rev. 6 [19] documents thequantification of the PRA model. This is the most recent evaluation of the NAPSinternal events at-power risk profile.

The PRA model is maintained and updated under aPRA configuration control program in accordance with Dominion procedures.

Plantchanges, including physical and procedural modifications and changes in performance data, are reviewed and the PRA model is updated to reflect such changes periodically byqualified 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 NAPSPRA has been updated many times, since the original IPE. A summary of the NAPSPRA 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 ofvarious elements such as ISLOCA, ATWS, flooding.

The NAPS PRA model has benefited from the following comprehensive technical PRApeer reviews.

In addition, the self-identified model issues tracked in the PRAconfiguration control program were evaluated and do not have any impact on the resultsof the application.

NEI PRA Peer ReviewThe 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 forestablishing 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 Reviewprocess uses a team composed of industry PRA and system analysts, each withPage 1 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5significant expertise in both PRA development and PRA applications.

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

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

The NAPS review team used the "Westinghouse Owners Group (WOG) PeerReview Process Guidance" as the basis for the review.The general scope of the implementation of the PRA Peer Review includes review ofeleven main technical

elements, using checklist tables (to cover the elements and sub-elements),

for an at-power PRA including internal events, internal

flooding, andcontainment 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 themodel. The 2013 Full Scope Peer Review team reviewed the F&Os and theirassociated 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 PRAStandard 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 RiskAssessment Results from Risk-Informed Activities".

This self-assessment wasdocumented and used as a planning guide for the NAPS 2009 model update.2013 NAPS PRA Full Scope Peer ReviewA full scope peer review of the NAPS PRA model against the requirements of theASME/ ANS PRA standard

[36] and any Clarifications and Qualifications provided in theNRC 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).

Thispeer 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 theseF&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.

The35 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 neededfrom these "old F&Os" and their associated dispositions.

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-LARAttachment 5Table B.1Thirtv-Four Findinas from 2013 NAPS PRA Full Scone Peer Review ["36'OtherNo. F&O # Level Affected Issue Impact on Application SRs2 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 haveinitiating 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 CDFto common cause of electrical systems nor due to routine system and LERF are bounded byalignments.

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 Ctrees. However, these common cause failures are not considered as demonstrates that an orderinitiating events, particularly for RSST 4KV transformers, vital inverters, of magnitude increase inand 125VDC battery chargers.

Also, for example, unavailability of a CDF or LERF does notbackup battery charger may drive a plant shutdown given loss of the impact acceptability of thenormally operating charger.

results for this application.

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

Basis for Significance:

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

Notebook IE. 1says that due to the independency of busses, the loss of more than onebus 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 causeinitiating events described above, as these initiators may be significant.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs4 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 genericfrequency.

The expectedBasis for Significance:

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

minimal.

As a result, thisgap has no impact on thePossible 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 ondiscussion or analysis was found to justify these credits.

CDF or LERF as this isprimarily 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 onpost-initiating event mitigation tree. the application.

Possible Resolution:

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

Page 4 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs10 AS-Al 0- Finding IE-B3 Discussion:

Differences in transient initiating event group are not clearly Loss of condenser vacuum is01 described impact of the loss of condenser vacuum which affects steam not an issue since makeup todump capability and operability of main feed water and the spurious SI the condenser is available atwhich challenges PORV open. Loss of condenser vacuum is not explicitly NAPS, so MFW can still bemodeled and is treated as a transient with MFW, which affect steam used to supply water to thedump capability and main feedwater.

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

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

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

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

gates as the %U1-SLOCA events. The same was donefor the Unit 2 initiating events. The resulting changes in CDF and LERFare bounded by thesensitivity in Attachment C.The sensitivity study inAttachment C demonstrates that an order of magnitude increase in CDF or LERFdoes not impact acceptability of the results for thisapplication.

Page 5 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs14 AS-B6-01 Finding Discussion:

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

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

System alignments could have an impact on the the application.

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

Review plant configurations or maintenance practices to see if any outliers are present that could impact the riskprofile.

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 on02, AS- integrate many other elements of PRA, but accident sequence notebook CDF or LERF as this isC2-01, 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 onC2 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 informedapplications using documents with better traceability.

Possible Resolution:

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs17 AS-C2-01 Finding Discussion:

1. Inconsistent documentation for mitigation tops with There is little to no impact ondesignators (e.g., -LATE, -EARLY, etc). Additionally, some of the CDF or LERF as this ismitigation 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 onmitigation 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 theaccident progression for each sequence or group of similar sequences.

3. Operator action is described in the accident sequence

notebook, butthere is limited timing information and no link with HRA information.

Basis for Significance:

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

Possible Resolution:

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

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

20 DA-B2-01 Finding Discussion:

This SR instructs that outliers not be included in the Any change in CDF or LERFdefinition 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 becomponents.

small and bounded by anorder of magnitude increase.

The sensitivity study inBasis 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 LERFdoes not impact acceptability of the results for thisapplication.

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs21 DA-C14- Finding Discussion:

Coincident maintenance events for intersystem events have Coincident maintenance may01 not been looked at. Need to evaluate historical maintenance schedules to result in an increase in CDFdetect patterns of typical maintenance combinations and then add these and LERF, but the impact isidentified coincident maintenance events to the model. expected to be bounded byan order of magnitude.

TheBasis for Significance:

These events could have an impact on the sensitivity study inannual 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 LERFPossible Resolution:

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

22 DA-D8-01 Finding Discussion:

No discussion of evaluation of the impact of plant There is little to no impact onmodifications on the data could be found in any of the below: CDF or LERF as this isprimarily 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 MetBasis for Significance:

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

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

Page 8 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs24 DA-D8-02 Finding Discussion:

No discussion of evaluation of the impact of plant There is little to no impact onmodifications 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 onthe application.

Basis for Significance:

Data could be impacted by a plant mod andeffect risk resultsPossible Resolution:

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs26 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 modelingconcern, and the impact ofBasis for Significance:

For large LOCA, NAPS SC. 1 R 3, Section 5.2.2, this change was less thanTable 5.2-2 shows for the injection phase that 2/2 accumulators on intact 1% increase in CDF. As aloops and 1 of 2 LHSI pumps are needed. The basis is stated to be the result, this gap has noUFSAR. 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, anemergency diesel generator.

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

Perform an analysis demonstrating that injection from 1 charging pump relative to 1 LHSI pump and 2/2 intactaccumulators has no impact on peak cladding temperature and does notimpact success, or use a T-H code such as RELAP5 to justify theminimum set of equipment, or reference a WCAP analysis, or similarplant large LOCA success criterion based on non-MAAP analysis.

Alternatively, change the success criterion for large LOCA to include acharging pump, and/or perform a review of large LOCA cut sets to boundthe potential contribution of the charging pump exclusion to CDF/LERF.

Make a note of model limitations.

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs29 SY-A14- Finding Discussion:

There was no evidence that plugging of manual valves was Manual valve plugging01 considered for instances where an exposure time is valid. For example, if failures are not expected toa manual valve is normally open in a standby train, it is susceptible to dominate the failureplugging 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, theplugging failure data may result in a failure probability higher than check increase in CDF and LERF isvalve 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 riskthat could have a very long exposure rate between tests or alignments impact is difficult to estimatesince there is uncertainty Basis for Significance:

The generic assumption about plugging of associated with which valvesmanual valves does not provide evidence that plugging was considered are in scope and whichover the exposure time for the standby trains. The system notebooks did functions

affected, it isnot seem to provide any sort of modeling notes on this topic either. If expected that the increase inusing the SY-A15 screening, it should be documented that this case CDF or LERF would bemeets SY-Al5. This could be a significant contributor for RHR HX and bounded by an order ofpump manual valves that could have a very long exposure rate between magnitude increase.

Thetests or alignments, sensitivity study inAttachment 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 LERFvalve plugging over the standby train exposure time can be screened per does not impact acceptability SY-Al 5. of the results for thisapplication.

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs31 SY-Cl-01 Finding SY-Al Discussion:

The dependency matrix appears to address dependency for There is little to no impact onfront-line systems and mechanical support systems, but appears CDF or LERF as this isincomplete 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 ononly the system name is provided, the application.

Basis for Significance:

This issue made it difficult to assess thecompleteness of the dependency analysis and made it difficult to assessthe completeness of the identification of the systems needed to provide orsupport the safety functions contained in the accident sequence analysis.

Possible Resolution:

Review and update dependency analysis forcompleteness.

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 ofGuidelines.

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

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

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

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs38 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 ofaffected HEPs and theBasis for Significance:

Potential to underestimate human error amount by which they wouldprobabilities.

change, a boundingsensitivity was performed inPossible 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 afactor of 10. The resulting changes in CDF and LERFare bounded by thesensitivity in Attachment C.The sensitivity study inAttachment C demonstrates that an order of magnitude increase in CDF or LERFdoes not impact acceptability of the results for thisapplication.

40 HR-G3-01 Finding Discussion:

Cat. II requires an evaluation of the quality of operator There is little to no impact ontraining on the HFE of interest, including whether the training is CDF or LERF as this isclassroom 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 onthe application.

Basis for Significance:

Provides documentation for the quality ofoperator training for the HFE of interest.

Possible Resolution:

Fill out the training frequency field in the HRACalculator.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs41 HR-G6-01 Finding Discussion:

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

The instructions are to review the HFEs and and their final HEPs for atheir final HEPs relative to each other to check their reasonableness reasonableness check wasgiven the scenario

context, plant history, procedures, operational performed prior to release ofpractices, 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 requiresthe HEP quantifications.

enhancement.

There is littleto no impact on CDF orBasis for Significance:

Confirm that quantifications are reasonable.

LERF as this is primarily adocumentation 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 onplant history, procedures, operational practices, and experience, the application.

42 HR-G7-01 Finding Discussion:

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

Examples include cutsets 3119, 22480, 22642, thresholds used in the22643, 22868, 23050. The applicable truncation limits used in the dependency analysis are notdependency analysis needs to be adjusted to eliminate unanalyzed considered to have anycombos in the cutsets.

significant impact on themodel results.

As a result,Basis for Significance:

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

the application.

Possible Resolution:

Lower applicable truncation limits used in thedependency 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 onaddresses assumptions and uncertainties.

Only source of model CDF or LERF as this isuncertainty 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 onthe application.

Basis for Significance:

Need better documentation of sources ofuncertainty.

Possible Resolution:

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs46 IFPP-B1-Finding IFPP-A1, Discussion:

It is suggested to add an overall site layout drawing into the There is little to no impact on01 IFPP-B2 IF. 1A notebook with the other individual building level layout drawings to CDF or LERF as this isaid 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 onAppendix 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 possiblegiven documentation updates.

The flooding notebooks seem to presentthe results more so than the starting point through the endpoint with somediscussion given in Section 2.1 of the IF.A notebook related to usingAppendix R information and the overall process.Possible Resolution:

Include a site layout drawing showing the variousbuildings involved in the flooding study and a table of such buildings andtheir disposition (i.e. include/retain, qualitatively

screened, etc.) asrequiring inclusion in the flooding analysis or not to enhance the briefmethodology given in Section 2.1 of the IF.1A notebook.

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

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs47 IFPP-B3-Finding Discussion:

No discussion is given in the various internal flooding There is little to no impact on01 notebooks with regard to the plant partitioning process or conclusions as CDF or LERF as this iswhat 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 onof their potential impacts to the analysis are given. Sources of the application.

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

Basis for Significance:

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

Possible Resolution:

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

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

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs48I FQU-A6-01FindingDiscussion:

While the flooding-specific HFEs are developed withdetailed assessments, several of the noted items in the SR were notaccounted for.Items noted from review of SR IFQU-A6:(b) The impact of the flooding on cues that the control room uses for anon-flooding HFEs is not discussed in the supporting spreadsheet of theinternal flooding HRA notebook for internal events HFEs used in theflooding analysis.

(a) The impact of the flooding on additional workload and stress in thecontrol room uses for a non-flooding HFEs is not discussed in thesupporting spreadsheet of the internal flooding HRA notebook for internalevents HFEs used in the flooding analysis.

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

This slight difference is not expected to cause significant

changes, but should be reviewed forconsistency and updated as needed.Basis for Significance:

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

Possible Resolution:

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

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

Alsoensure that the timings for event HEP-ISO-TBSWLL are correct ascurrently the time to submergence is shorter than the time available foraction.There is little to no impact onCDF or LERF as this isprimarily a documentation enhancement.

As a result,this gap has no impact onthe application.

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-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs49 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 thealternate pump cooling from firewater is still possible under flooding functions that rely oninitiating events from firewater piping. firewater are failed during afire protection piping flood.Basis for Significance:

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

CDF and LERF are boundedby the sensitivity inPossible Resolution:

Either include the firewater pipe failure lEs at the Attachment C. Themodeled firewater backup function gates for HHSI pump cooling and sensitivity study inAFW 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 LERFdoes not impact acceptability of the results for thisapplication.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs50 IFQU-B1-Finding IFQU-A5, Discussion:

Several internal flooding HRA documentation There is little to no impact on01 IFQU-B2 inconsistencies were noted during review. CDF or LERF as this isprimarily 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 aflag event-the internal flooding notebook NOTEBK-PRA-NAPS-IF.2 presents HFEHEP-ISO-TBSWLL which is not contained in the HRA calculator whichdoes contain event REC-FLD-TBSWLL,

however, neither event appearsin 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 asuggestion.

Possible Resolution:

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

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

1is treated consistently.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs52 IFSN-A5-Finding Discussion:

The critical height of all PRA-related SSCs is not given in an There is little to no impact on01 easy to identify single location such as the table listing of PRA-related CDF or LERF as this isSSCs 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 onend-state important SSCs. the application.

Basis for Significance:

SR requires spatial location of SSCs which wasnot consistently done.Possible Resolution:

Update Table 1 of the NOTEBK-PRA-NAPS-IF.1 Bnotebook 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 shown01 accumulation may be a beneficial failure for the flood room/area where that the current modelingthe accumulation would not occur due to the assumption of the door assumptions associated withfailing open immediately.

doors failing without wateraccumulation 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 onthe application.

Possible Resolution:

Include accumulation in rooms/areas with doors tothe recommended heights with consideration for door opening direction using the same EPRI methodology used in the North Anna internalflooding analysis or perform more detailed investigations of the doorfailure water accumulation heights and SSC critical heights to ensure thatbeneficial failures are not being credited.

Page 20 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs55 IFSN-B2-Finding IFEV-A2 Discussion:

The included pipe break flowrates do not always include a There is little to no impact on02 calculation for the full diameter break size, and in addition, there is no CDF or LERF as this isconsideration 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 onarea 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 caseat full diameter size. For the included flooding source systems, providethe full runout flowrate of the system pump(s) for comparison to thecalculated flowrates to ensure the appropriate flooding flowrate is beingused and include the flowrate used to determine the consequential impacts for each flooding area should be listed in the area scenariodiscussions.

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 fireprotection system inside of Aux Building not discussed.

protection system has shownthat the frequency of thisBasis for Significance:

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

failure rate of affectedequipment, and thePossible Resolution:

Assess the risk for inadvertent fire protection equipment affected by thesystem 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 impacton CDF and LERF isexpected.

The sensitivity study in Attachment Cdemonstrates that an orderof magnitude increase inCDF or LERF does notimpact acceptability of theresults for this application.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs58 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 floodNo basis is given for this assumption, and the potential of all scenarios scenarios that screened outusing a purely assumptive basis for such inherent screening of potential based on the 60 minuteimpacts should also model non-isolated scenarios for the same pipe timeframe, and the CDFbreak source. Also, the treatment is inconsistent with an IF HFE that is impact of those scenarios evaluated past 60 minutes.

was insignificant.

As aresult, this gap has noThis 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 tointernal floods risk. REC-FLD-IRR has available time of 84 minutes, yetstill 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 botha 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 on01 CDF or LERF as this isBasis 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 onthe application.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs64 LE-G1-01 Finding LE-G5 Discussion:

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

This is exacerbated by the significant CDF or LERF as this isreliance 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 ondocuments.

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 befound. Moreover, because of the conversion of the Volume numbers(e.g. LE.2 to LE.1), there is additional confusion added for LE. Many ofthe referenced sections in the self-assessment (e.g., Section 5.4.1 ofLE.1 (old LE.2)) appear to no longer exist. Finally, unlike the othertechnical elements that have completely revised the analysis, the Level 2relies 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 tableof how each SR is addressed and where the documentation can befound.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 scopein SY.2 attachment lists circular logic break gates, but further review of and impact associated withthe logic indicates the circular logic is not handled properly.

this modeling issue.However, it is expected thanA 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 the125V DC power supply with circular logic break is supplied power only circular logic break modelingfrom battery under LOOP condition which is required the EDG. However would be bounded by anthe 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 in2-1 Attachment C demonstrates that an order of magnitude Basis for Significance:

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

Identify and correct errors in circular logic application.

development.

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

-LARAttachment 5OtherNo. F&O # Level Affected Issue Impact on Application SRs68 QU-B8-01 Finding Discussion:

NASP PRA developed logic to eliminate mutually exclusive A sensitivity study wassituations to correct cutsets containing mutually exclusive events, performed to address thisHowever a mutually exclusive logic "U1-EVENTS-NO-AUTO-PRZ-PRES-modeling issue, and the CDFNX" may delete LOSC sequence because the logic produces U12-LOSS-and LERF each increased bySW-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 onseal cooling and injection, the application.

Basis for Significance:

Incorrect mutually exclusive logic deletion mayresult in improper accident sequence evaluation.

Possible Resolution:

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

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

1 or QU.2 primarily a documentation notebooks.

enhancement.

As a result,this gap has no impact onBasis 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 usermanuals and a description of how these limitations could impact theapplication of the PRA model.Page 24 of 25 Serial No 14-272Docket Nos. 50-333/339 Type A Test Interval Extension

-LARAttachment 5Enclosure 1PRA TECHNICAL ADEQUACY SENSITIVITY STUDYThis sensitivity study demonstrates the impact of an order of magnitude increase in the internalevents 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 Class3a 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 thebase Class 3a and 3b frequencies by 5. The Class 3a and 3b dose risk are multiplied by 4.24E+3person-rem and 4.24E+4 person-rem, respectively, for both the base and 15-year cases. TheALERF is calculated by taking the difference between the Class 3b frequencies for the 15-year andbase 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-yearDelta Delta %CDF 3a 3b 3a 3b 3a 3b 3a 3b LERF Dose DoseFreq Freq Dose Dose Freq Freq Dose Dose1.72E-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 1frequency.

The base Class 1 frequency is adjusted by subtracting out the base Class 3a and 3bfrequencies 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 theCCFP 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 YearAdjusted Class 1 Freq CCFP Adjusted Class 1 Freq CCFP1.61E-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 onthe 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 hasbeen 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 inLERF would result in an increase in the total population dose, but this would actually result in adecrease in the percent change in population dose due to the ILRT extension.

The change inpopulation dose, the ACCFP, and the ALERF would be unaffected since these results aredependent on the CDF and the Class 3a and 3b results.

According to RG 1.174, no changes areallowed if the total LERF exceeds 1.OE-05, and the NAPS LERF is low enough that exceeding thislimit is not a concern.

As a result, an order of magnitude increase in internal events LERF will notimpact the results of the application.

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

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

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

-LARAttachment 6Page 1 of 1List of Regulatory Commitments This table identifies actions discussed in this letter for which Dominion commits toperform.

Any other actions discussed in this submittal are described for the NRC'sinformation and are not commitments.

Type Scheduled Commitment One-time Continuing Completion DateCompliance Dominion will use the definition inSection 5 of NEI 94-01 Revision 3-A for Upon NRC approval ofcalculating the Type A leakage rate. X this LicenseAmendment Request