ML13232A042

Surry, Units 1 and 2 - Proposed License Amendment Request Permanent Fifteen-Year Type a Test Interval

ML13232A042
Person / Time
Site:	Surry
Issue date:	08/12/2013
From:	Grecheck E S Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
13-435
Download: ML13232A042 (104)

Text

VIRGINIA ELECTRIC AND POWER COMPANYRICHMOND, VIRGINIA 23261August 12, 2013U. S. Nuclear Regulatory Commission Serial No.: 13-435Attention:

Document Control Desk NLOS/ETS:

ROWashington, DC 20555-0001 Docket Nos.: 50-280/281 License Nos.: DPR-32/37 VIRGINIA ELECTRIC AND POWER COMPANYSURRY POWER STATION UNITS I 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 DPR-32 and DPR-37 for Surry Power Station Units 1 and2, respectively.

The proposed amendments revise Surry Power Station Units 1 and 2Technical Specification (TS) 4.4.B, "Containment Leakage Rate Testing Requirements,"

by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to NuclearEnergy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used to develop the Surry performance-based leakage testing program inaccordance 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 Option B, including provisions for extending the Type A primary containment integrated leak rate test (ILRT) intervals to fifteen years and the Type C local leak ratetest intervals to 75 months, and incorporates the regulatory positions stated inRG 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 10CFR51.22(b),

no environmental impact statement orenvironmental 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. 13-435Docket Nos. 50-280/281 Page 2 of 3The next Unit 1 ILRT is currently due no later than May 6, 2016. Based on the currentoutage schedule for Unit 1, the current ten-year frequency would require the next Unit 1ILRT to be performed during the spring 2015 refueling outage. Due to lead timerequired to procure the services and equipment to perform a Type A test, Dominionrequests approval of the proposed change by July 31, 2014.Should you have any questions or require additional information, please contactMr. Gary D. Miller at (804) 273-2771.

Respectfully, Eugene S. GrecheckVice President

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

1. Discussion of Change2. Marked-up Technical Specifications Page3. Proposed Technical Specifications Page4. Risk Assessment

5. PRA Technical Adequacy6. List of Regulatory Commitments VICKI L. HULLNotary PublicCommonwealth of Virginia140542My Commission Expires May 31. 2014COMMONWEALTH OF VIRGINIACOUNTY OF HENRICOThe foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, todayby Mr. Eugene S. Grecheck, who is Vice President

-Nuclear Engineering and Development, of Virginia Electric andPower Company.

He has affirmed before me that he is duly authorized to execute and file the foregoing document inbehalf of that company, and that the statements in the document are true to the best of his knowledge and belief.Acknowledged before me this /.*??day of ,Z 2013.My Commission Expires:

r L- -i -d 10,V _otaý Public Serial No. 13-435Docket Nos. 50-280/281 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 23219Ms. K. R. Cotton GrossNRC Project Manager SurryU.S. Nuclear Regulatory Commission One White Flint NorthMail Stop 08 G-9A11555 Rockville PikeRockville, MD 20852-2738 Dr. 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 Surry Power Station Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Power Station Units 1 and 2 Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 1 of 20DISCUSSION OF CHANGE1.0 DESCRIPTION 2.0 PROPOSED CHANGE3.0 BACKGROUND 4.0 TECHNICAL ANALYSIS4.1 Description of Containment 4.2 Integrated Leak Rate Test History4.3 Type B and C Testing Programs4.4 Supplemental Inspection Requirements 4.4.1 IWE Examinations 4.4.2 IWL Examinations 4.5 Deficiencies Identified 4.6 Plant-Specific Confirmatory Analysis4.6.1 Methodology 4.6.2 PRA Technical Adequacy4.6.3 Conclusion of Plant-Specific Risk Assessment Results5.0 REGULATORY ASSESSMENT 5.1 Applicable Regulatory Requirements/Criteria 5.2 No Significant Hazards Consideration 5.3 Environmental Considerations

6.0 CONCLUSION

7.0 PRECEDENCE Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 2 of 20DISCUSSION OF CHANGE1.0 DESCRIPTION The proposed amendment revises the Surry Power Station Units 1 and 2 Technical Specification (TS) 4.4.B, "Containment Leakage Rate Testing Requirements,"

by replacing thereference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI)topical report NEI 94-01, Revision 3-A, as the implementation document used by VirginiaElectric and Power Company (Dominion) to develop the Surry performance-based leakagetesting program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A ofNEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending primary containment integrated leak rate test (ILRT) intervals to 15 years and Type C test intervals to 75 months, andincorporates the regulatory positions stated in RG 1.163. In the safety evaluations (SEs) issuedby NRC letter dated June 25, 2008 and June 8, 2012, the NRC concluded that NEI 94-01,Revision 3-A, describes an acceptable approach for implementing the optional performance-based requirements of Option B of 10 CFR 50, Appendix J, and found that NEI 94-01, Revision3-A, is acceptable for referencing by licensees proposing to amend their TS with regard tocontainment leakage rate testing, subject to the limitations and conditions noted in Section 4.0of 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 tenyear intervals, to no longer than 15 years from the last ILRT for Surry Units 1 and 2. The nextILRT is currently due no later than May 6, 2016 for Unit 1 and October 26, 2015 for Unit 2. Thisis approximately ten years since the last ILRT for Unit 1 and 15 years for Unit 2. The currentUnit 2 schedule is based on a one-time five year extension that was requested in Dominionletter dated December 17, 2007 (Serial No. 07-0802) and approved in NRC letter datedDecember 18, 2008. The current Unit 1 ten-year frequency requires the next ILRT to beperformed during the spring 2015 refueling outage. The proposed amendment would allow thenext ILRT for Surry Unit 1 to be performed within 15 years from the last ILRT completed onMay 16, 2006, as opposed to the current required ten-year interval.

Additionally, thisamendment would establish a performance-based 15 year ILRT frequency for Surry Units 1and 2 consistent with the NRC approved guidance document (NEI 94-01, Revision 3-A). Theperformance of fewer ILRTs will result in significant savings in radiation exposure to personnel, cost, and critical path time during future refueling outages.2.0 PROPOSED CHANGETS 4.4.B, "Containment Leakage Rate Testing Requirements,"

currently states:"1. The containment and containment penetrations leakage rate shall be demonstrated byperforming leakage rate testing as required by 10 CFR 50 Appendix J, Option B, asmodified by approved exemptions, and in accordance with the guidelines contained inRegulatory Guide 1.163, dated September, 1995 as modified by the following exception:

NEI 94-01-1995, Section 9.2.3: The first Unit 2 Type A test performed after theOctober 26, 2000 Type A test shall be performed no later than October 26, 2015."

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 3 of 20The proposed change would revise this portion of TS 4.4 by replacing the reference toRG 1.163 with a reference to NEI 94-01, Revision 3-A, as follows:"1. The containment and containment penetrations leakage rate shall be demonstrated byperforming leakage rate testing as required by 10 CFR 50 Appendix J, Option B, asmodified by approved exemptions, and in accordance with the guidelines contained inNEI 94-01, Revision 3-A, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 2012."Despite the different format of the Surry TSs, i.e., Surry has custom TSs, the important elements of the guidance provided in the Staff's letter to NEI dated November 2, 1995, areincluded in the proposed TS. With the approval of the TS change request, Surry Units 1 and 2will have transitioned to a performance-based 15-year frequency for Type A tests and a 75month test interval for Type C tests.Attachment 2 contains the existing TS page 4.4-1 marked-up to show the proposed changes toTS 4.4.B. Attachment 3 provides the proposed TS page.3.0 BACKGROUND The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from thecontainment, including systems and components that penetrate the containment, does notexceed the allowable leakage values specified in the TS. The testing requirements assure thatperiodic surveillance of containment penetrations and isolation valves is performed so thatproper maintenance and repairs are performed on the systems and components penetrating containment during the service life of the containment.

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

Appendix J identifies three types ofrequired tests: (1) Type A tests, intended to measure the containment overall integrated leakagerate; (2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for containment penetrations; and(3) Type C tests, intended to measure containment isolation valve leakage.

Type B and C testsidentify the vast majority of potential containment leakage paths. Type A tests identify theoverall (integrated) containment leakage rate and serve to ensure continued leakage integrity ofthe containment structure by evaluating those structural parts of the containment not covered byType B and C testing.In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing forWater-Cooled Power Reactors,"

was amended to provide a performance-based Option B forcontainment leakage testing requirements.

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

Performance-based test intervals are based on consideration of the operating history of thecomponent and resulting risk from its failure.

The use of the term "performance-based" in10 CFR 50, Appendix J refers to both the performance history necessary to extend testintervals, as well as to the criteria necessary to meet the requirements of Option B. Also in1995, RG 1.163 was issued. The RG endorsed NEI 94-01, Revision 0, "Industry Guideline forImplementing Performance-Based Option of 10 CFR 50, Appendix J," with certain modifications and additions.

Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) toreduce the test frequency from the containment Type A (ILRT) test from three tests in ten yearsto one test in ten years. This relaxation was based on an NRC risk program and Electric Power Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 4 of 20Research Institute (EPRI) TR-104285, "Risk Impact Assessment of Revised Containment LeakRate Testing Intervals,"

both of which illustrated that the risk increase associated with extending the ILRT surveillance interval was very small.NEI 94-01, Revision 2, describes an approach for implementing the optional performance-based requirements of Option B described in 10 CFR 50, Appendix J, which includes provisions 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 theappropriate testing frequency.

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

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

The NRC finalSE, issued by letter dated June 25, 2008, documents the NRC's evaluation and acceptance ofNEI 94-01, Revision 2, subject to the specific limitations and conditions listed in Section 4.1 ofthe SE. The accepted version of NEI 94-01 has subsequently been issued as Revision 2-Adated 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 ofRG 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions onPlant-Specific Changes to the Licensing Bases." The NRC's final SE, issued by letter datedJune 25, 2008, documents the NRC's evaluation and acceptance of EPRI TR-104285, Revision 2, subject to the specific limitations and conditions listed in Section 4.2 of the SE. Anaccepted version of EPRI TR-1 009325 was subsequently issued as Revision 2-A (also identified as TR-1018243) dated October 2008.NEI 94-01, Revision 3, describes an approach for implementing the optional performance-based requirements of Option B described in 10 CFR 50, Appendix J, which includes provisions 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,also discusses the performance factors that licensees must consider in determining testintervals.

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

The NRC final SE issued by letter dated June 8, 2012,documents the NRC's evaluation and acceptance of NEI 94-01, Revision 3, subject to thespecific limitations and conditions listed in Section 4.1 of the SE. The accepted version ofNEI 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,"

dated August 1994. The assessment validates increasing allowable extended local leak ratetest (LLRT) intervals to the 120 months as specified in NEI 94-01, Revision

0. However, theindustry requested that the allowable extended interval for Type C LLRTs be increased only to75 months, to be conservative, with a permissible extension (for non-routine emergentconditions) of nine months (84 months total). The NRC final SE issued by letter dated Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 5 of 20June 8, 2012, documents the NRC's evaluation and acceptance of EPRI TR-1009325 as avalidation of EPRI-1 04285, Revision 2 bases to extend Type C LLRT to 120 months, subject tothe specific limitations and conditions listed in Section 4.1 of the SE.4.0 TECHNICAL ANALYSISAs required by 10 CFR 50.54(o),

the Surry 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 Surry 10 CFR 50 Appendix J Testing Plan is based on RG 1.163, which endorsesNEI 94-01, Revision

0. This license amendment request proposes to revise the Surry 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, Revision3-A, as modified to include two limitations and conditions, is acceptable for referencing bylicensees proposing to amend their TS with regard to containment leakage rate testing for theoptional performance-based requirements of Option B of 10 CFR 50, Appendix J.The following addresses each of the limitations and conditions of the 2008 and 2012 SEs.Limitation I Condition (from Section 4.1 of SE dated June 25, 2008) Surry Response1. For calculating the Type A leakage rate, the licensee Following the NRC approval of this license amendment should use the definition in the NEI 94-01, Revision 2, request, Surry will use the definition in Section 5.0 ofin lieu of that in ANSI/ANS-56.8-2002).

NEI 94-01, Revision 3-A, for calculating the Type Aleakage rate when future Surry Type A tests areperformed (see Attachment 6, "List of Regulatory Commitments").

The definition in Rev. 2-A and 3-A areidentical.

2. The licensee submits a schedule of containment A schedule of containment inspections is provided ininspections to be performed prior to and between Section 4.4 below.Type A tests.3. The licensee addresses the areas of the containment General visual examination of accessible interior andstructure potentially subjected to degradation.

exterior surfaces of the containment system for structural problems is conducted in accordance with the SurryIWE/IWL Containment Inservice Inspection Plans whichimplement the requirements of the ASME, Section Xl,Subsections IWE and IWL, as required by10 CFR 50.55a(g).

There are no primary containment surface areas thatcurrently require augmented examinations in accordance with ASME Section Xl, IWE-1240.

4. The licensee addresses any test and inspections Surry has already replaced the steam generators thatperformed following major modifications to the required modifications to the containment structure.

containment structure, as applicable.

When Surry Units 1 and 2 replaced the reactor vesselclosure head, the containment structure was modified.

The design change process addressed the testingrequirements of the containment structure modifications.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 6 of 205. The normal Type A test interval should be less than Dominion acknowledges and accepts this NRC staff15 years. If a licensee has to utilize the provisions of position, as communicated to the nuclear industry inSection 9.1 of NEI 94-01, Revision 2, related to Regulatory Issue Summary (RIS) 2008-27 datedextending the ILRT interval beyond 15 years, the December 8, 2008.licensee must demonstrate to the NRC staff that it isan unforeseen emergent condition.

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

Surry Units 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 ofNEI 94-01, Revision 2, and EPRI ReportNo. 1009325, Revision 2, including the use of pastcontainment ILRT data.Limitation

/ Condition Surry 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, Surry will followLLRTs to be increased to 75 months with the 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 includeleakage rate summation and its regulatory limit. In corrective actions to restore margin to an acceptable

addition, a corrective action plan shall be developed level.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-A. At no time shallan extension be allowed for Type C valves that arerestricted categorically (e.g. BWR MSIVs), and thosevalves with a history of leakage, or any valves held toeither a less than maximum interval or to the baserefueling cycle interval.

Only non-routine emergentconditions allow an extension to 84 months.2. When routinely scheduling any LLRT valve interval Following the approval of the amendment, consistent withbeyond 60 months and up to 75 months, the primary the guidance of Section 11.3.2 of NEI 94-01, Rev. 3-Acontainment leakage rate testing program trending or Surry will estimate the amount of understatement in themonitoring must include an estimate of the amount of Types B and C total and include determination of theunderstatement in the Types B and C total and must acceptability in a post-outage report.be included in a licensee's post-outage report. Thereport must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actualleakage potential of the penetrations.

To comply with the requirement of 10 CFR 50, Appendix J, Option B,Section V.B, Surry Units 1and 2 TS 4.4.B 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 four exceptions described therein.

Other than the five-year extension for SurryUnit 2, the current Surry TS does not list any exceptions to the guidelines.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 7 of 204.1 Description of Containment The containment is a steel-lined, heavily reinforced concrete structure with vertical cylindrical wall and hemispherical dome supported on a flat base mat. Below grade, the containment structures are constructed inside a cofferdam of steel sheet piling. The structures aresoil-supported.

The base of the foundation mat is located approximately 66 feet below finishedground grade.Each containment structure has an inside diameter of 126 ft. 0 in. The spring line of the dome is122 ft. 1 in. above the top of the foundation mat. The inside radius of the dome is 63 ft. 0 in.The interior vertical height is 185 ft. 1 in., and the base mat is 10 ft. 0 in. thick. The steel linerfor the wall is 0.375-inch thick, except over the base mat, where 0.25-inch and 0.75-inch plate isused. The steel liner for the dome is 0.50-inch thick. A waterproof membrane is placed belowthe containment structural mat and carried up the containment wall to ground level. Themembrane is attached to and envelopes the entire part of the structure below grade. Themembrane protects the structure from the effects of ground water and the steel liner fromexternal hydrostatic pressure.

Ground water immediately adjacent to the containment structure is kept below the top surface of the foundation mat by pumping, as required.

Access to the containment structure is provided by a 7 ft. inside diameter personnel hatchpenetration and a 14 ft. 6 in. inside diameter equipment hatch penetration.

Other smallercontainment structure penetrations include hot and cold pipes, main steam and feedwater pipes,the fuel transfer tube, and electrical conductors.

The reinforced concrete structure has been designed to withstand all loadings and stressesanticipated during the operation and life of the unit. The steel lining is attached to andsupported by the concrete.

The liner functions primarily as a gastight membrane and transmits incident loads to the concrete.

The containment structure does not require the participation ofthe liner as a structural component.

No credit has been taken for the presence of the steel linerin designing the containment structure to resist seismic force or other design loads.The steel wall and dome liners are protected from potential interior missiles by interior concreteshield walls. Control Rod Drive Mechanism missile protection is provided by a concrete shieldon Unit 1 and a steel shield on Unit 2. The base mat liner is protected by a 1.5 to 2-foot thickconcrete cover, except where a 0.75-inch-thick liner plate was used beneath the reactor vesselincore instrumentation, and at a drainage trench where floor grating provides additional protection.

The design basis accident was selected as the design basis for the containment structure because all other accidents would result in lower temperatures and pressures.

The containment structure is also designed for the normal subatmospheric operating conditions.

Further, thecontainment structure is designed for a leakage rate not to exceed 0.1% by weight ofcontainment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at calculated peak pressure..

The operating pressure range for the containments is greater than 10.1 psia and less than11.3 psia partial air pressure.

The temperature of the containment air fluctuates between amaximum temperature of 125°F and a minimum of 75°F during normal operation and 60°Fduring shutdown, depending upon the ambient temperature of available service water. Thenormal operating pressure allows accessibility for inspection and minor maintenance duringoperation without requiring containment pressurization.

The containment structure is designedby ultimate strength methods conforming to ACI 318-63, Part IV-B.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 8 of 20During power operation, the Surry Units 1 and 2 containments are continuously maintained at asubatmospheric condition (TS 3.8.D.1).

Containment air partial pressure is maintained within anoperating range (10.1 psia to 11.3 psia) based on service water temperature to ensure thecontainment design pressure is not exceeded during a design basis accident.

Instrumentation constantly monitors containment pressure.

If pressure rises, an alarm annunciates as pressureapproaches the limits allowed by the TSs. Although not as significant as the differential pressure resulting from a design basis accident, the fact that the containment can be maintained subatmospheric provides a degree of assurance of containment structural integrity (i.e., no largeleak paths in the containment structure).

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

4.2 Integrated Leak Rate Test HistoryPrevious ILRT testing confirmed that the Surry containment structures' leakage is acceptable, with considerable margin, with respect to the TS acceptance criterion of 0.1% of containment airweight at the design basis loss of coolant accident pressure (La). Since the last three SurryUnits 1 and 2 Type A as-found results were less than 1.0 La, a test frequency of at least onceper 15 years would be in accordance with NEI 94-01, Revision 3-A.Unit ITest Date As-Found Leakage Acceptance Limit*June 1988, Measured Leakage With Upper 0.278 of LaConfidence Limit (UCL) MarginTotal Type C Penalty 0.036 of LaTOTAL 0.314 of La 1.0 LaApril 1992 Measured Leakage With UCL 0.376 of LaMarginTotal Type C Penalty 0.010 of LaTOTAL 0.386 of La 1.0 LaMay 2006 Measured Leakage With UCL 0.267 of LaMargin 0.267_ofLa Total Type C Penalty 0.031 of LaTOTAL 0.298 of La 1.0 LaThe total allowable "as-left" leakage is 0.75 La, (La, 0.1% of primary containment air by weight per day, is theleakage assumed in design basis accident radiological analyses) with 0.6 La, the maximum leakage from Type Band C components.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 9 of 20Unit 2Test Date As-Found Leakage Acceptance Limit*November 1986 Measured Leakage With Upper 0.635 of LaConfidence Limit (UCL) MarginTotal Type C Penalty 0.003 of LaTOTAL 0.638 of La 1.0 LaMay 1991 Measured Leakage With UCL Margin 0.414 of LaTotal Type C Penalty 0.004 of LaTOTAL 0.418 of La 1.0 LaOctober 2000 Measured Leakage With UCL Margin 0.050 of LaTotal Type C Penalty 0.010 of LaTOTAL 0.060 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 theleakage assumed in design basis accident radiological analyses) with 0.6 La, the maximum leakage from Type Band C components.

Type B and C containment penetrations tests (e.g., electrical penetrations, flanges and valves) are being performed in accordance with10 CFR 50, Appendix J. The current total penetration leakage on a minimumthan 10% of the leakage allowed for containment integrity.

airlocks, hatchesOption B ofpath basis is lessNo modifications that require a Type A test are planned prior to Unit 1 R29 (fall 2020) and Unit 2R26 (fall 2015), when the next Type A tests will be performed in accordance with this proposedchange. Any unplanned modifications to the containment prior to the next scheduled Type Atest would be subject to the special testing requirements of Section IV.A of 10 CFR 50,Appendix J. There have been no pressure or temperature excursions in the containment whichcould have adversely affected containment integrity.

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

4.3 Type B and Type C Testing ProgramsSurry Units 1 and 2 Appendix J, Type B and Type C leakage rate test program requires testingof electrical penetrations,

airlocks, hatches,

flanges, and valves within the scope of the programas required by 10 CFR 50, Appendix J, Option B and TS 6.5.16. The Type B and Type Ctesting program consists of local leak rate testing of penetrations with a resilient seal, expansion

bellows, double gasketed

manways, hatches and flanges, and containment isolation valves thatserve as a barrier to the release of the post-accident containment atmosphere.

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

The combined Type B and Type C leakage acceptance criterion is174 standard cubic feet per hour (scfh) for Surry Units 1 and 2. The maximum and minimumpathway leak rate summary totals for the last three refueling outages with Type A tests areshown below.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 10 of 20Unit 1June 1988 -As-Found Min Pathway Leakage 177.37 scfhJune 1988 -As-Left Max Pathway Leakage 39.39 scfhApril 1992 -As-Found Min Pathway Leakage 56.29 scfhApril 1992 -As-Left Max Pathway Leakage 28.57 scfhMay 2006 -As-Found Min Pathway Leakage 10.33 scfhMay 2006 -As-Left Max Pathway Leakage 16.41 scfhUnit 2November 1986 -As-Found Min Pathway Leakage >174 scfhNovember 1986 -As-Left Max Pathway Leakage 88.82 scfhMay 1991 -As-Found Min Pathway Leakage 20.38 scfhMay 1991 -As-Left Max Pathway Leakage 26.17 scfhOctober 2000 -As-Found Min Pathway Leakage 2.77 scfhOctober 2000 -As-Left Max Pathway Leakage 36.91 scfhEach unit has 66 mechanical penetrations and 92 electrical penetrations that are local leak ratetested (Type B or C). Currently there are four (4) penetrations in Unit 2 and eight (8)penetrations in Unit 1 that are being tested at an increased frequency due to leakageperformance.

However, neither unit's overall Type B and C leakage has approached the 0.6Laleakage limit.As discussed in NUREG-1493, Type B and Type C tests can identify the vast majority (greaterthan 95%) of all potential containment leakage paths. This amendment request adopts theguidance in NEI 94-01, Revision 3-A, in place of NEI 94-01, Revision 0, for the Type C testinterval (up to 75 months),

but otherwise does not affect the scope or performance of Type B orType C tests. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

The Surry Units 1 and 2 containment structure fuel transfer tube is the only penetration thatutilizes a bellows arrangement to establish seals between the containment liner, transfer cavity,spent fuel pool, and the penetration itself. Pressure test channels are installed on the weldinterface between the penetration piping and the containment liner and were used to verify weldquality during initial construction.

There are no other test devices installed on the penetration piping and bellows.

Therefore, the ability to perform local leak rate testing is not available.

Penetration integrity is verified during the performance of the ILRT (Type A). Surry has norecord of bellows leakage.

Visual inspection is impossible because two of the three bellows areenclosed in sleeves in the fuel building and between the fuel and containment buildings.

Thethird bellow is located between the containment and the fuel transfer canal, which is a three footopening, covered by permanent shielding.

The fuel transfer tube is sealed inside thecontainment building with a blind flange, equipped with a double o-ring seal, which is Type Btested.

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-LARAttachment 1Page 11 of 204.4 Supplemental Inspection Requirements Prior to initiating a Type A test, a general visual examination of accessible interior and exteriorsurfaces of the containment system is performed to identify any potential structural problemsthat could affect either the containment structure leakage integrity or the performance of theType A test. This inspection is typically conducted in accordance with Surry's Containment Inservice Inspection (ISI) Plan, which implements the requirements of ASME,Section XI,Subsection IWE/IWL.

The applicable code edition and addenda for the second ten-year intervalIWE/IWL program is the 2001 Edition with the 2003 Addenda.The examinations performed in accordance with the IWE/IWL program satisfy 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 of10 CFR 50.55a(b)(2)(ix)(A) and (E). Examination of pressure-retaining bolted connections andevaluation of containment bolting flaws or degradation are performed in accordance with therequirements of 10 CFR 50.55a(b)(ix)(G) and 10 CFR 50.55a(b)(ix)(H).

Each ten-year ISIinterval is divided into three approximately equal-duration inspection periods.

A minimum of oneinspection during each inspection period of the ISI interval is required by the IWE/IWL program.There are currently no primary containment surface areas that require augmented examination in accordance with ASME Section Xl, IWE-1240 for either unit.Subsection IWE assures that at least three general visual examinations of metallic components will be conducted before the next Type A test if the Type A test interval is extended to 15 years.This meets the requirements of Section 9.2.3.2 of NEI 94-01, Revision 3-A and Condition 2 inSection 4.1 of the NRC SE for NEI 94-01, Revision 2.Visual examinations of accessible concrete containment components in accordance with ASMECode,Section XI, Subsection IWL are performed every five years, resulting in at least three IWLexaminations being performed during a 15-year Type A test interval.

In addition to the IWL examinations, Dominion performs a visual inspection of the accessible interior and exterior of the Surry Unit 1 and 2 Containment Buildings prior to each Type A test.This examination is performed in sufficient detail to identify any evidence of deterioration whichmay affect the reactor building's structural integrity or leak tightness.

The areas that areinspected include the external surface of the building, the basement of the building, and the wallinside the main steam safety enclosure.

The examinations of the inside of the building areperformed during Cold Shutdown.

The examination is conducted in accordance with approvedplant procedures to satisfy the requirements of the 10 CFR 50 Appendix J Testing Program.The activity is coordinated with the IWL examinations to the extent possible.

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,Revision 3-A, as well as Condition 2 in Section 4.1 of the NRC SE for NEI 94-01, Revision 2.The containment liner area that the Surry IWE/IWL program identifies as inaccessible is thatportion inaccessible due to the 2-foot thick floor mat, which has been calculated to be 14.9% ofeach liner. During the 2000 refueling outages for Units 1 and 2, the containment liner/floor matinterface was inspected and evaluated, which included thickness measurements (UT). Inaddition, in Unit 1 several areas at the liner/floor mat interface were excavated to further assess Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 12 of 20the condition of the liner. It was concluded that there was no significant deterioration at theliner/floor mat interface or the liner extending below the floor based on the results of the visualexam and thickness measurements.

Inspections performed since that time have not identified any condition in the accessible areas that would suggest the presence of degradation in theseinaccessible areas. Based on this information, Surry has not implemented any newtechnologies to inspect the inaccessible areas to date. However, Dominion actively participates in various nuclear utility owners groups, ASME Code committees, and with NEI to maintaincognizance of ongoing developments within the nuclear industry.

Industry operating experience is also continuously reviewed to determine its applicability to Surry. New, commercially available technologies for the examination of the inaccessible areas of containment areexplored and considered as part of these activities.

The tables below provide dates of completed and scheduled ILRTs, completed containment surface examinations, along with an approximate schedule for future containment surfaceexaminations, assuming the Type A test frequency is extended to 15 years.Unit ICalendar Year Type A Test General Visual Examination of General Visual Examination of(ILRT) Accessible Exterior Surface Accessible Interior (Liner) Surface20052006 05/16/06 05/07/062007 11/21/0720082009 05/27/0920102011 08/31/1120122013 10/13201420152016 08/16 10/16201720182019 10/1920202021 04/21 08/21Unit 2Calendar Year Type A Test General Visual Examination of General Visual Examination of(ILRT) Accessible Exterior Surface Accessible Interior (Liner) Surface2000 10/26/00 10/07/00200120022003 10/29/0320042005 05/16/052006 12/31/06 10/27/06200720082009 11/24/0920102011 08/31/11 05/16/11201220132014 04/142015 10/152016 08/16 Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 13 of 204.4.1 IWE Examinations A review was conducted for Surry Units 1 and 2 per IWE-1241, Examination Surface Areas(1992 Edition with 1992 Addenda of ASME Section XI) for the initial ten-year Category E-Cexamination requirements.

No areas were deemed susceptible to accelerated degradation andaging; therefore, augmented examinations per Category E-C were not required.

Thisinformation is documented in the first ten-year Containment ISI Plan for Surry Units 1 and 2.The examinations performed during the first ten-year interval identified no concerns with thecontainment metallic liner or other IWE components.

Based upon the IWE-1241 evaluation andthe first ten-year examination

results, the second ten-year inspection interval also has noCategory E-C (2001 Edition through 2003 Addenda of ASME Section Xl) examination requirements.

Surry Units 1 and 2 have completed or are completing requirements of their second period,second ten-year Containment IWE Inservice Inspection Program.

Containment linerexaminations (IWE) will be completed by the required date of April 25, 2014 for Unit 1 andOctober 19, 2014 for Unit 2 to the requirements of the 2001 Edition through the 2003 Addendaof ASME Section Xl. The second ten-year interval IWE examination requirements will use the2001 Edition through the 2003 Addenda of ASME Section XI as modified by the10 CFR 50.55a(b) limitations for both units. At this time, no augmented Category E-Cexaminations are planned.

The remaining examinations are based on Category E-A and arevisual (General, VT-3, and VT-1) examinations based on Code or 10 CFR rule requirements.

In accordance with the Containment Inservice Testing Program, station personnel perform anIWE -General Visual examination on the accessible surface areas associated with theContainment Liner. Most of the coating conditions noted are the result of mechanical impactdamage and are not considered to be of any significance.

This is especially true on theEL -27 ft. 7 in. and EL -3 ft. 6 in. level where the lead shielding and scaffolding boxes arelocated.

The general mechanical damage of the liner coating on EL -27 ft. 7 in. andEL -3 ft. 6 in., as well as the scarred sites on EL 18 ft. 4 in. and EL 47 ft. 4 in., have been notedduring previous containment coating assessments conducted by Materials/NDE Engineering.

There were no indications of coating blisters.

Corrosion of the liner at the damaged coatingsites was generally limited to superficial pitting.4.4.2 IWL Examinations The second ten-year concrete containment examinations (IWL) have specified dates ofAugust 31, 2011 and August 31, 2016 for Units 1 and 2. General and detailed visualexaminations have been and will be completed in accordance with Category L-A of the code noearlier than or later than one year of the specified date for both units.Surry Units 1 and 2 have completed or are completing the requirements of their second ten-yearContainment Inservice Inspection Program.

Concrete containment examinations (IWL) werecompleted for Units 1 and 2 by the required date of August 31, 2011 in accordance with therequirements of the 2001 Edition through the 2003 Addenda of ASME Section Xl completing thesecond period of the second ten-year interval.

These examinations on the concrete exteriorwere conducted by the Responsible Engineer using the vis'ual (VT-3C and VT-1C) method.There were 47 indications identified on Unit 1; four of which were designated as code repairs.Two of the remaining 43 Unit 1 indications require excavation and further examination.

Theothers have been deemed cosmetic in nature. There were 44 indications identified on Unit 2;one of which was designated as a code repair. Three of the remaining 43 Unit 2 indications Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 14 of 20require excavation and further examination.

The others have been deemed cosmetic in nature.The conditions identified to date, resulting from the 2011-2012 IWL concrete inspection, eitheralone or combined, do not adversely affect the ability of the Containment concrete structures toperform their design function.

The findings to this point are consistent with previousinspections.

The five areas that require excavation and further evaluation are currently scheduled to be excavated and examined by December 31, 2013.Surry Units 1 and 2 do not have an un-bonded post-tensioning system. As such, examinations required by Category L-B do not apply.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 any other times is entered into the corrective action program forevaluation 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 Surry PowerStation ILRT surveillance intervals from the current ten years to 15 years. The evaluation isincluded as Attachment

4. This plant-specific risk assessment followed the guidance inNEI 94-01, Revision 3-A, the methodology described in EPRI TR-1009325, Revision 2-A, andthe NRC regulatory guidance outlined in RG 1.174 on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request to change the licensing basis of theplant. In addition, the methodology used for Calvert Cliffs Nuclear Power Plant to estimate thelikelihood and risk implication of corrosion-induced leakage of steel containment liners goingundetected during the extended ILRT surveillance interval was also used for a sensitivity analysis.

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

This PRA model has beenpeer reviewed against the ASME PRA Standard RA-Sb-2009 to meet RG 1.200, Revision 2,and gaps between the PRA model and PRA standard are addressed as a part of the PRAtechnical adequacy evaluation discussed in Attachment

5. The analyses include evaluations forthe dominant external events (seismic and fire) using conservative expert judgment with theinformation from the Surry Individual Plant Examination of External Events (IPEEE).

Theoriginal IPEEE seismic and fire event models were updated in 2006 with fault tree changes anddata files from the S05A model, and insights and information from the IPEEE have been used toestimate the effect on total LERF of including these external events in the ILRT surveillance interval extension risk assessment.

In the SE issued by NRC letter dated June 25, 2008, the NRC concluded that the methodology in EPRI Report No. 1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.2 of the SE. The following table addresses each of the fourlimitations and conditions for the use of EPRI TR-1018243, Revision

2. These limitations andconditions were incorporated into Revision 2-A of EPRI TR-1018243.

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-LARAttachment 1Page 15 of 20From Section 4.2 of SE Surry Response1. The licensee submits documentation indicating that Surry PRA technical adequacy is addressed in Sectionthe technical adequacy of their PRA is consistent with 4.6.2.the 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 these population dose and CCFP acceptance guidelines, permanently extending the ILRT surveillance interval and these guidelines have been used for the Surry plantto 15 years is small and consistent with the specific risk assessment.

clarification provided in Section 3.2.4.5 of the SE.Specifically, a small increase in population doseshould be defined as an increase in population doseof less than or equal to either 1.0 person-rem peryear or 1 percent of the total population dose,whichever is less restrictive.

In addition, a smallincrease in conditional containment failure probability (CCFP) should be defined as a value marginally greater than that accepted in a previous one-timeILRT extension requests.

This would require that theincrease 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 use of 100 La as the average leak rate for thethe increase in expected population dose (per year of pre-existing containment large leakage rate accidentreactor operation).

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

(accident case 3b) used by the licensees shall be 100La instead of 35 La.4. A licensee amendment request is required in Surry Units 1 and 2 rely on containment overpressure toinstances where containment over-pressure is relied assure adequate ECCS pump net positive suction headupon for emergency core cooling system (ECCS) following design basis accidents.

Additional risk analysisperformance.

has been performed to address any change in riskassociated with reliance on containment overpressure forECCS performance and is discussed in Attachment 4.4.6.2 PRA Technical AdequacyThe Level 1 and LERF PRA model that is used for Surry is characteristic of the as-built plant.The current internal events model (SO07Aa) 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 Surry 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.

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

The first peer reviewwas performed in 1998 using the Westinghouse Owners Group Peer Review Guidance, andonly one Category B and three Category C Facts and Observations (F&Os) remain open. Afocused peer review was performed in 2010 using the ASME PRA standard RA-Sb-2005, and90% of the Specific Requirements (SRs) were considered Met with Category 1/11 or greater.

Themost recent focused peer review was performed in 2012 using the ASME PRA Standard RA-Sb-2009, and 95.5% of the SR were considered Met with Category 1/11 or greater.

The opengaps identified by the peer reviews are evaluated for impact on the application.

As such, the Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 16 of 20updated Surry PRA model is considered acceptable for use in assessing the risk impact ofextending the Surry Units 1 and 2 containment ILRT surveillance interval to 15 years.The PRA technical adequacy is discussed in detail in Attachment 5.4.6.3 Conclusion of Plant-Specific Risk Assessment ResultsThe findings of the Surry risk assessment confirm the general findings of previous studies thatthe risk impact associated with extending the ILRT surveillance interval from three in ten yearsto one in 15 years is small. Details of the Surry risk assessment are contained in Attachment 4.The Surry plant-specific results for extending ILRT surveillance interval from the current tenyears to 15 years are summarized below.1. The increase in LERF based on consideration of internal events only is conservatively estimated as 6.79E-08/yr.

The guidance in RG 1.174 defines very small changes in LERFas those that are less than 1.OE-7/yr.

Therefore, the estimated change in LERF isdetermined to be very small using the guidelines of RG 1.174. An assessment of the impactfrom external events (seismic and fire) was also performed.

In this case, the total increasein LERF for combined internal and external events was conservatively estimated as3.25E-07/yr.

The total increase in LERF for the combined internal and external eventsmodel is determined to be "small" using the guidelines of RG 1.174.2. The calculated increase in the 50-mile population dose is 5.47E-03 person-rem per year.EPRI TR-1018243, Revision 2-A, states that a small increase in population dose is definedas an increase of less than or equal to either 1.0 person-rem per year or 1 percent of thetotal population dose (for Surry, 1 percent equals 2.58E-02 person-rem per year), whichever is less restrictive.

Thus, the calculated 50-mile population dose increase is small using theguidelines of EPRI TR-1018243, Revision 2-A. Moreover, the risk impact when compared toother severe accident risks is negligible.

3. The calculated increase in the conditional containment failure probability (CCFP) is 0.93%.EPRI TR-1018243, Revision 2-A, states that an increase in CCFP of less than or equal to1.5 percentage points is very small. Therefore, the calculated CCFP increase is determined to be very small.4. The Surry Units 1 and 2 design basis calculations credit containment overpressure to satisfythe net positive suction head (NPSH) requirements for recirculation spray (RS) andlow-head safety injection (LHSI) in recirculation mode during loss of coolant accidents (LOCAs).

The change in CDF associated with the increase in the ILRT surveillance intervalis 2.67E-11/yr, which is within the acceptance guidelines in RG 1.174 for a "very small"change in CDF. This evaluation confirms that the impact on CDF from the ILRT extension isnegligible, and the impact of the extension is bounded by the LERF analysis.

5.0 REGULATORY ANALYSIS5.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations andrequirements continue to be met.

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-LARAttachment 1Page 17 of 2010 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 of Water Cooled Nuclear Power Plants."

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

Inaddition, Appendix J discusses leakage rate acceptance

criteria, test methodology, frequency oftesting, and reporting requirements for each type of test. RG 1.163 was developed to endorseNEI 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 leakagetests must be performed.

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

The change to the Type A test frequency did not directly result in an increase incontainment leakage.

Similarly, the proposed change to the Type A test frequency will notdirectly result in an increase in containment leakage.NEI 94-01, Revision 3-A, describes an approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. The document incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A and Type C intervals to 15 years and 75 months, respectively.

NEI 94-01, Revision 3-A, delineates aperformance-based approach for determining Type A, Type B, and Type C containment leakagerate test frequencies.

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

NE 94-01, Revision 3-A, states that a plant-specific risk impact assessment should beperformed using the approach and methodology described in TR-1009325, Revision 2, for aproposed extension of the ILRT interval to 15 years. In the SE issued by NRC letter June 25,2008, the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, is acceptable for reference by licensees proposing to amend their TS to extend the ILRT surveillance intervalto 15 years, subject to the limitations and conditions noted in Section 4.0 of that SE.Based on the considerations above, (1) there is reasonable assurance that the health andsafety of the public will not be endangered by operation in the proposed manner, (2) suchactivities will continue to be conducted in accordance with the site licensing basis, and (3) theapproval of the proposed change will not be inimical to the common defense and security or tothe health and safety 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.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 18 of 205.2 No Significant Hazards Consideration A change is proposed to the Surry Power Station Units 1 and 2 Technical Specifications 4.4.B,"Containment Leakage Rate Testing Program."

The proposed amendment would replace thereference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI)topical report NEI 94-01, Revision 3-A, dated June 8, 2012 and issued July 2012, as theimplementation document used by Virginia Electric and Power Company (Dominion) to developthe Surry performance-based primary containment leakage testing program in accordance withOption B of 10 CFR 50, Appendix J. The proposed amendment would also extend the intervalfor the primary containment integrated leak rate test (ILRT), which is required to be performed by 10 CFR 50, Appendix J, from ten years to no longer than 15 years from the last ILRT andpermit Type C testing to be performed at an interval of up to 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 of amendment,"

as discussed in the following paragraphs:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No.The proposed amendment involves changes to the Surry Containment Leakage RateTesting Program.

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

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

As such, thecontainment itself and the testing requirements to periodically demonstrate the integrity ofthe containment do not involve any accident precursors or initiators.

Therefore, theprobability of occurrence of an accident previously evaluated is not significantly increased bythe proposed amendment.

The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A,for development of the Surry Power Station Units I and 2 performance-based containment testing program.

Implementation of these guidelines continues to provide adequateassurance that during design basis accidents, the primary containment and its components will limit leakage rates to less than the values assumed in the plant safety analyses.

Thepotential consequences of extending the ILRT interval to 15 years have been evaluated byanalyzing the resulting changes in risk. The increase in risk in terms of person-rem per yearwithin 50 miles resulting from design basis accidents was estimated to be acceptably smalland determined to be within the guidelines published in, RG 1.174. Additionally, theproposed change maintains defense-in-depth by preserving a reasonable balance amongprevention of core damage, prevention of containment

failure, and consequence mitigation.

Dominion has determined that the increase in Conditional Containment Failure Probability due to the proposed change would be very small. Therefore, it is concluded that theproposed amendment does not significantly increase the consequences of an accidentpreviously 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.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 19 of 202. Does the proposed change create the possibility of a new or different kind of accident fromany accident previously evaluated?

Response:

No.The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A,for the development of the Surry performance-based leakage testing program andestablishes a 15-year interval for the performance of the containment ILRT. Thecontainment and the testing requirements to periodically demonstrate the integrity of thecontainment exist to ensure the plant's ability to mitigate the consequences of an accidentand do not involve any accident precursors or initiators.

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

Therefore, the proposed change does not create the possibility of a new or different kind 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 the development of the Surry performance-based leakage testing program andestablishes a 15-year interval for the performance of the containment ILRT. Thisamendment does not alter the manner in which safety limits, limiting safety systemsetpoints, or limiting conditions for operation are determined.

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

The overall containment leakagerate limit specified by the TS is maintained, and the Type A, Type B, and Type Ccontainment 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 toprovide a high degree of assurance that the containment will not degrade in a manner that isnot detectable by an ILRT. A risk assessment using the current Surry PRA modelconcluded that extending the ILRT test interval from ten years to 15 years results in a verysmall change to the Surry risk profile.

Therefore, the proposed change does not involve asignificant 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, afinding of "no significant hazards consideration" is justified.

5.3 Environmental Considerations The proposed amendment does not involve (i) a significant hazards consideration, (ii) asignificant change in the types or significant increase in the amounts of any effluent that may bereleased

offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

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

Therefore, pursuant to 10 CFR 51.22(b),

no Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 1Page 20 of 20environmental impact statement or environmental assessment needs be prepared in connection with the proposed amendment.

6.0 CONCLUSION

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

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

Dominion is adopting the guidance ofNEI 94-01, Revision 3-A for the Surry Units 1 and 2 10 CFR 50, Appendix J testing programplan.Based on the previous ILRT tests conducted at Surry Units 1 and 2, it may be concluded thatextension of the containment ILRT surveillance interval from ten to 15 years represents minimalrisk to increased leakage.

The risk is minimized by continued Type B and Type C testingperformed in accordance with 10 CFR 50, Appendix J, Option B and inspection activities performed as part of the Surry Power Station IWE/IWL ASME Section XI Inservice Inspection (ISI) program.This experience is supplemented by risk analysis

studies, including the enclosed Surry riskanalysis.

The findings of the Surry risk assessment confirm the general findings of previousstudies, on a plant-specific basis, that extending the ILRT surveillance interval from ten to 15years results in a very small change to the Surry Units 1 and 2 risk profile.7.0 PRECEDENCE This request is similar to the following license amendments, which have been approved by theNRC.1. Nine Mile Point Nuclear Station, Unit 2 -Issuance of Amendment Re: Extension of PrimaryContainment Integrated Leakage Rate Testing Interval (TAC No. ME1650, ADAMSAccession Number ML100730032) approved March 30, 2010.2. Arkansas Nuclear One, Unit No.2 -Issuance of Amendment Re: Technical Specification Change to Extend the Type A Test Frequency to 15 Years (TAC No. ME4090, ADAMSAccession Number ML 110800034) approved April 7, 2011.3. Palisades Nuclear Plant -Issuance of Amendment to Extend the Containment Type A LeakRate Test Frequency to 15 Years (TAC No. ME5997, ADAMS Accession NumberML120740081) approved April 23, 2012.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Power Station Units I and 2 TS 4.4-1128 04.4 CONTAINMENT TESTSApplicability Applies to containment leakage testing.

NEI 94-01, Revision 3-A, "Industry Guidelines forImplementing Performance-Based Option of 10Objective FCR 50, Appendix J," dated July 2012.To assure that leakage of the primary rea or containment and associated systems is heldwithin allowable leakage rate limits; and t assure that periodic surveillance is performed to assure proper maintenance and leak re pair during the service life of the containment.

Specification A. Periodic and post-operational integra.

d leakage rate tests of the containment shall beperformed in accordance with the re uirements of 10 CFR 50, Appendix J, "ReactorContainment Leakage Testing for W er Cooled Power Reactors."

B. Containment Leakage Rate Testing equirements

1. The containment and containme I penetrations leakage rate shall be demonstrated by performing leakage rate testi g as required by 10 CFR 50 Appendix J, OptionB, as modified by approved eAl "ptions, and in accordance with the guidelines contained in R-gaat ,,,d.1 d S b, lz ,2. Leakage rate acceptance criteria are as follows:a. An overall integrated leakage rate of less than or equal to La, 0.1 percent byweight of containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, at calculated peak pressure (Pa).b. A combined leakage rate of less than or equal to 0.60 La for all penetrations andvalves subject to Type B and C testing when pressurized to Pa.Prior to entering an operating condition where containment integrity is requiredthe as-left Type A leakage rate shall not exceed 0.75 La and the combined leakagerate of all penetrations subject to Type B and C testing shall not exceed 0.6 La.3. The provisions of Specification 4.0.2 are not applicable.

BasisThe leak tightness testing of all liner welds was performed during construction by weldinga structural steel test channel over each weld seam and performing soap bubble andhalogen leak tests.Amendment No. --6+

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Power Station Units I and 2 TS 4.4-14.4 CONTAINMENT TESTSApplicability Applies to containment leakage testing.Objective To assure that leakage of the primary reactor containment and associated systems is heldwithin allowable leakage rate limits; and to assure that periodic surveillance is performed to assure proper maintenance and leak repair during the service life of the containment.

Specification A. Periodic and post-operational integrated leakage rate tests of the containment shall beperformed in accordance with the requirements of 10 CFR 50, Appendix J, "ReactorContainment Leakage Testing for Water Cooled Power Reactors."

B. Containment Leakage Rate Testing Requirements I. The containment and containment penetrations leakage rate shall be demonstrated by performing leakage rate testing as required by 10 CFR 50 Appendix J, OptionB, as modified by approved exemptions, and in accordance with the guidelines contained in NEI 94-01, Revision 3-A, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 2012.2. Leakage rate acceptance criteria are as follows:a. An overall integrated leakage rate of less than or equal to La, 0.1 percent byweight of containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, at calculated peak pressure (Pa).b. A combined leakage rate of less than or equal to 0.60 La for all penetrations andvalves subject to Type B and C testing when pressurized to Pa.Prior to entering an operating condition where containment integrity is requiredthe as-left Type A leakage rate shall not exceed 0.75 La and the combined leakagerate of all penetrations subject to Type B and C testing shall not exceed 0.6 La.3. The provisions of Specification 4.0.2 are not applicable.

BasisThe leak tightness testing of all liner welds was performed during construction by weldinga structural steel test channel over each weld seam and performing soap bubble andhalogen leak tests.Amendment No.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Power Station Units I and 2 Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 1 of 34RISK ASSESSMENT 1.0 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 ten years to15 years for Surry Power Station (Surry).

The risk assessment follows the guidelines fromNEI 94-01, Revision 3-A, the methodology used in EPRI TR-104285, the EPRI Risk ImpactAssessment of Extended Integrated Leak Rate Testing Intervals, the NRC regulatory guidanceon the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of arequest for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174, and themethodology used for Calvert Cliffs to estimate the likelihood and risk implications ofcorrosion-induced leakage of steel liners going undetected during the extended test interval.

The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the October2008 EPRI final report.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 ten-year test interval is provided in Section 11.0 of NEI 94-01,Revision 0, and was established in 1995 during development of the performance-based OptionB to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493, "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, "Risk ImpactAssessment of Revised Containment Leak Rate Testing Intervals."

The NRC report on performance-based leak testing, NUREG-1493, 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 for Surry.Earlier ILRT frequency extension submittals have used the EPRI TR-104285 methodology toperform the risk assessment.

In October 2008, EPRI TR-1018243 was issued to develop ageneric methodology for the risk impact assessment for ILRT interval extensions to 15 years Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 2 of 34using current performance data and risk informed

guidance, primarily NRC RG 1.174. This morerecent EPRI document considers the change in population dose, large early release frequency (LERF), and containment conditional failure probability (CCFP), whereas TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for Surry employs the EPRI TR-1018243 methodology, with the affectedSystem, Structure, or Component (SSC) being the primary containment boundary.

1.3 CriteriaThe acceptance guidelines in RG 1.174 are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking ofAppendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines asincreases in core damage frequency (CDF) of less than 1.OE-06 per reactor year and increases in LERF of less than 1.OE-07 per reactor year. An evaluation of the CDF impact in Section 5confirms that the change in risk is bounded by the LERF impact, so the relevant criterion is thechange in LERF. RG 1.174 also defines small changes in LERF as increase of less than1.0E-06 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of riskanalysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the CCFP is also calculated to help ensure thatthe defense-in-depth philosophy is maintained.

Regarding 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, a change in the CCFP of up to 1.5% (percentage point) is assumed to besmall.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 Evaluations (SEs) for one-timeinterval extension (summarized in Appendix G of EPRI TR-1018243) indicate a range ofincremental increases in population dose that have been accepted by the NRC. The range ofincremental population dose increases is from <.0.01 to 0.2 person-rem/yr and/or 0.002 to0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493, Figure 7-2) result in health effects that are at least two orders of magnitude lessthan the NRC Safety Goal Risk. Given these perspectives, a very small population dose isdefined as an increase from the baseline interval (three tests per ten years) dose of <1.0person-rem per year, or 1% of the total baseline dose, whichever is less restrictive for the riskimpact assessment of the proposed extended ILRT interval.

It is noted that the methodology used in the one-time ILRT interval extension requests assumed a large leak magnitude (EPRIclass 3b) of 35La, whereas the methodology in EPRI TR-1018243 uses 100La. The dose ratesare impacted by this change and will be larger than those in previous submittals.

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-LARAttachment 4Page 3 of 342.0 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. Theanalysis uses results from a Level 2 analysis of core damage scenarios from the current SurryPRA 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.

3. 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 LERF in accordance with RG 1.174 andcompare with the acceptance guidelines of RG 1.174.5. Determine the impact on the CCFP.6. Evaluate the sensitivity of the results to assumptions in the liner corrosion

analysis, external events, and the fractional contribution of increased large isolation failures (dueto liner breach) to LERF.Furthermore,

• Consistent with the other industry containment leak risk assessments, the Surryassessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and CCFP are also considered toshow that defense-in-depth and the balance of prevention and mitigation is preserved.

• Containment overpressure is credited in the ECCS and Recirculation Spray pump NPSHcalculations for Surry, so a first-order estimate of the CDF impact is evaluated as a partof the risk impact assessment.

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

" This evaluation for Surry uses ground rules and methods to calculate changes in riskmetrics that are similar to those used in EPRI TR-1018243, Risk Impact Assessment ofExtended Integrated Leak Rate Testing Intervals.

3.0 GROUND RULESThe following ground rules are used in the analysis:

• The Surry Level 1 and Level 2 internal events PRA models provide representative results.* It is appropriate to use the Surry 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 the Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 4 of 34calculations.

However, external events have been accounted for in the analysis basedon the available information from the Surry IPEEE as described in Section 5.7." The population dose results calculated for the SPS Severe Accident Mitigation Alternatives (SAMA) analysis are applied to the containment failure modes modeled inthe PRA.* Accident classes describing radionuclide release end states are defined consistent withEPRI methodology and are summarized in Section 4.2.* The representative containment leakage for Class 1 sequences is 1La. Class 3accounts for increased leakage due to Type A inspection failures.

" The representative containment leakage for Class 3a sequences is 1OLa based on thepreviously approved methodology for Indian Point Unit 3.* The representative containment leakage for Class 3b sequences is 10OLa based on theguidance provided in EPRI TR-1018243.

• The Class 3b can be conservatively categorized as LERF based on the previously approved methodology.

" 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 to the conclusions of this analysis will result from this separatecategorization.

• The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal.4.0 INPUTSThis section summarizes the general resources available as input (Section 4.1) and theplant-specific resources required (Section 4.2).4.1 General Resources Available Various industry studies on containment leakage risk assessment are briefly summarized below:1. NUREG/CR-3539

2. NUREG/CR-4220

3. NUREG-1273

4. NUREG/CR-4330

5. EPRI TR-1 051896. NUREG-1493

7. EPRI TR-1 042858. Calvert Cliffs liner corrosion analysis9. EPRI TR-1018243 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 an Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 5 of 34assessment 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) test 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.

NUREG/CR-3539 Oak 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 as thebasis for its risk sensitivity calculations.

ORNL concluded that the impact of leakage rates onlight water reactor (LWR) accident risks is relatively small.NUREG/CR-4220 NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.The study reviewed over two thousand licensee event reports (LER), ILRT reports, and otherrelated records to calculate the unavailability of containment due to leakage.NUREG-1273 A 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 NUREG/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 isdominated by accident sequences that result in failure or bypass of containment."

EPRI TR-1 05189The 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) of the impact ofextending ILRT and LLRT test intervals on shutdown risk for two reference plants (a BWR-4 and Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 6 of 34a PWR). The conclusion from the study is that a small but measurable safety benefit is realizedfrom extending the test intervals.

NUREG-1493 NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reducecontainment leakage testing intervals and/dr relax allowable leakage rates. The NRCconclusions are consistent with other similar containment leakage risk studies:"Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an"imperceptible" increase in risk."Given the insensitivity of risk to the containment leak rate and the small fraction of leak pathsdetected solely by Type A testing, increasing the interval between integrated leak rate tests ispossible with minimal impact on public risk.EPRI TR-1 04285Extending 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-1 150 Level 3 population dose models to perform the analysis.

The study also used theapproach of NUREG-1493 in calculating the increase in pre-existing leakage probability due toextending 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 yearRelease Cateqory Definitions Table 4.1-1 defines the accident classes used in the ILRT extension evaluation, which isconsistent with the EPRI methodology.

These containment failure classifications are used inthis analysis to determine the risk impact of extending the Containment Type A test interval asdescribed in Section 5 of this report.

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-LARAttachment 4Page 7 of 34Table 4.1-1EPRI/NEI Containment Failure Classifications EPRI Class EPRI Class Description Containment remains intact including accident sequences that do not lead to1 containment 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.2 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.

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.7 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 This 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 was 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.Surry has a similar type of containment, and the same methodology will be used in this riskimpact assessment.

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-LARAttachment 4Page 8 of 34EPRI Report No. 1009325, Revision 2-A, Risk Impact Assessment of Extended Integrated LeakRate Testing Intervals This report provides a risk impact assessment for the permanent extension of ILRT test intervals to 15 years. This document provides guidance for performing plant-specific supplemental riskimpact assessments, builds on the previous EPRI risk impact assessment methodology and theNRC performance-based containment leakage test program, and considers approaches utilizedin various submittals, including Indian Point 3 (and associated NRC SE) and Crystal River.The approach included in this guidance document is used in the Surry 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 Surry ILRT Extension Risk Assessment includes the following:

• Internal events PRA model results* Source term category definitions and frequencies used in the Level 2 Model* Source term category population dose within a 50-mile radius* External events PRA model resultsSurry Internal Events PRA ModelThe Level 1 and Level 2 PRA model that is used for Surry is characteristic of the as-built plant.The current internal events model (SO07Aa) is a linked fault tree model. Using the averagemaintenance model, the Unit 1 model was quantified with the total Core Damage Frequency (CDF) = 6.28E-06/yr and Large Early Release Frequency (LERF) = 1.51E-07/yr, and the Unit 2model was quantified with the CDF = 6.1OE-06/yr and LERF = 1.50E-07/yr.

Surry Source Term Cateqory Frequencies The current Level 2 release category definitions were developed in the Level 2 model updateusing revised LERF fractions.

The current source term category frequencies were developed from the relative contributions to CDF for the analyzed containment failure modes asdocumented in the Surry LERF model documentation.

The total CDF associated with the sumof release category frequencies is 7.28E-06/yr as documented in the Surry LERF modeldocumentation.

Since this CDF value is higher than the CDF for both Unit 1 and Unit 2, it istaken as a conservative estimation of the risk for both units. This risk impact assessment will bebased on this CDF, and it will be assumed that the results of the assessment are conservative for both units. Each of the source term categories is associated with a corresponding EPRIclass, and the EPRI class frequencies are calculated by summing the associated source termcategory frequencies.

Surry Source Term Category Population DoseA plant-specific population dose was developed using MAAP for the source term categories (STC) using the MACCS2 output data for the Surry SAMA analysis.

The source term category Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 9 of 34diagram in the IPE contained twenty-four source term categories.

The STC diagram wasrevised in the Level 2 model update using revised LERF fractions, and the number of STCs wasreduced from twenty-four to twenty. The Surry LERF model documentation contains a tablewhich associates the current STCs with the IPE STCs. Using the dose results from the SurrySAMA analysis and the one-time ILRT extension in conjunction with the Surry LERF modeldocumentation allows the population doses to be determined for the current STCs.Release Cateqory Definitions Table 4.2-1 below defines the Surry 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.Table 4.2-1Surry Release Category Definitions, Freauencv, and Population DoseSurry Release Frequency per year son-Rem EPRI Class Description Category (50 miles)1 0.OOE+00 0.OOE+00 1 No Containment Failure2 1.54E-07 5.98E+023 1 No Containment Failure3 O.OOE+00 8.23E+054 7 Early Containment Failure4 1.98E-06 2.50E+045 7 Late Containment Failure5 1.29E-07 8.23E+055 7 Late Containment Failure6 1.1OE-07 2.50E+044 7 Late Containment Failure7 0.OOE+00 8.23E+055 7 Late Containment Failure8 0.OOE+00 2.89E+054 7 Late Containment Failure9 2.37E-06 7.1OE+045 7 Late Containment Failure10 1.48E-06 7.1OE+044 7 Late Containment Failure11 7.04E-09 2.50E+045 7 Melthru12 O.OOE+00 4.71 E+055 2 No Containment Isolation 13 1.67E-10 4.71E+054 2 No Containment Isolation 14 6.89E-07 0.OOE+005 1 Debris Cool In-Vessel 15 0.OOE+00 1.19E+044 2 Debris Cool In-Vessel 16 0.OOE+00 8.23E+055 2 Debris Cool In-Vessel 17 1.11E-07 6.81 E+065 8 Event V (attenuation) 18 1.11E-07 6.81E+064 8 Event V (no attenuation) 19 1.11E-07 5.07E+064 8 SGTR20 2.67E-08 2.54E+0668 SGTR (non-LERF)

CDF7.28E-061. STC frequencies were taken from the Surry LERF model documentation.

2. The population dose for each STC is based on the correlation of the current STCs to the IPE STCs and thepopulation dose results from the Surry SAMA analysis.

3. The STC 2 population dose from the Surry SAMA analysis was used for the current STC 2 based on the Surryone-time ILRT extension.

4. The population dose was taken from the MAAP run for the associated STC.5. The population dose was taken from the recommended alternate STC results in the Surry LERF modeldocumentation.

6. The dose for STC 20 is assumed to be half of STC 19 since it is a non-LERF SGTR.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 10 of 34Using the data in Table 4.2-1, the frequency and dose for the EPRI accident classes as theyapply to Surry 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 DoseOrganized by EPRI Release CategoryEPRI Class Frequency

(/yr) Dose (person-rem) 1 8.43E-07 5.98E+022 1.67E-10 4.71E+057 6.08E-06 7.11E+048 3.60E-07 5.96E+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 3containment 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.

For Class 3a, the probability is based on the maximum likelihood estimate of failure(arithmetic average) from the available data (i.e., 2 "small" failures in 217 tests leads 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 contains information concerning the potential that the calculated deltaLERF values for several plants may fall above the "very small change" guidelines of the NRCregulatory guide 1.174. This information includes a discussion of conservatisms in thequantitative guidance for delta LERF. The EPRI report 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.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 11 of 34The application of this additional guidance to the analysis for Surry would result in a reduction ofthe CDF applied to the Class 3a and Class 3b CDFs. However, the Surry risk assessment willconservatively 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, 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) because it does not factor in the possibility that the failures could bedetected by other tests (e.g., the Type B local leak rate tests that will still occur.) Eliminating thispossibility conservatively overestimates the factor increases attributable to the ILRT extension.

4.4 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.

The Calvert Cliffs analysis wasperformed for a concrete cylinder and dome and a concrete

basemat, each with a steel liner.Surry 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 Surry containment analysis.

These events,one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events haveoccurred in recent years (based on a data search covering approximately 9 years Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 12 of 34documented in NRC Docket No. 50-277).

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 0.375" 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 5.5 years to reflect the years since September 1996 when 10 CFR 50.55astarted requiring visual inspection to the time the Calvert Cliffs liner corrosion analysiswas performed.

Additional success data was not used to limit the aging impact of thiscorrosion issue, even though inspections were being performed prior to this date (andhave been performed since the time frame of the Calvert Cliffs analysis),

and there is noevidence that additional corrosion issues were identified.

(See Table 4.4-1, Step 1.)* Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed 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. (SeeTable 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 Surry, the containment failure probabilities are lessthan these values at 47 psig. Conservative probabilities of 1% for the cylinder and domeand 0.1% for the basemat are used in this analysis, and sensitivity studies are includedthat 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, non-detectable containment failures areassumed to result in early releases.

This approach avoids a detailed analysis ofcontainment failure timing and operator recovery actions.

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-LARAttachment 4Page 13 of 34Table 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 2.71 E-03 3 6.77E-044 3.11E-03 4 7.77E-045 3.57E-03 5 8.93E-046 4.1OE-03 6 1.03E-037 4.71E-03 7 1.18E-038 5.41 E-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 3.11E-0315 1.43E-02 15 3.57E-033 Flaw Likelihood at 3, 1 to 3 years 0.71% 1 to 3 years 0.18%10, and 15 years 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 Likelihood Pressure Likelihood in Containment (psia) (psia)Given Steel Liner 2.OOE+01 0.1% 2.OOE+01 0.01%Flaw 6.47E+01 1.1% 6.47E+01 0.11%1.OOE+02 7.0% 1.OOE+02 0.70%1.20E+02 20.3% 1.20E+02 2.03%1.50E+02 100.0% 1.50E+02 10.00%5 Visual Inspection Detection Failure 10% 100%Likelihood 6 Likelihood of Non- 3 years 0.00077%

3 years 0.00019%Detected 0.71%

• 1.1%

• 10% 0.18%

• 0.11%

• 100%Containment 10 years 0.0045% 10 years 0.0011%Leakage 4.14%

• 1.1%

• 10% 1.03%

• 0.11%

• 100%15 years 0.0104% 15 years 0.0026%L 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 Surry.

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-LARAttachment 4Page 14 of 34Total Likelihood Of Non-Detected Containment Leakage Due To Corrosion for Surry:At 3 years :0.00077%

+ 0.00019%

= 0.00096%At 10 years : 0.0045% + 0.0011% = 0.0056%At 15 years : 0.0104% + 0.0026% = 0.0130%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.

Thenon-LERF containment overpressure CDF is calculated by subtracting the Class 1, Class 3b,and Class 8 CDFs from the total CDF so that only Classes 2, 3a, and 7 are included in the CDFcalculation.

5.0 RESULTSThe application of the approach based on the EPRI guidance 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 Surry Unit 1and Surry 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 Surry-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.

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-LARAttachment 4Page 15 of 34Table 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 theeight accident classes presented in Table 5.0-1.Step 2 Develop plant-specific person-rem dose (population dose) per reactor year foreach of the eight accident classes.Step 3 Evaluate risk impact of extending Type A test interval from three to 15 and ten to15 years.Step 4 Determine the change in risk in terms of LERF in accordance with RG 1.174.Step 5 Determine the impact on the CCFP.5.1 Step 1 -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 EPRITR-104285.

Two failure modes were considered for the Class 3 sequences.

These are Class3a (small breach) and Class 3b (large breach).The frequencies for the severe accident classes defined in Table 5.0-1 were developed forSurry 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.

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-LARAttachment 4Page 16 of 34Class 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 Categories 1, 2, and 14 listed in Table 4.2-1, which was8.43E-07/yr.

With the inclusion of the EPRI 3a and 3b classes, the EPRI Class 1 frequency willbe reduced by the EPRI Class 3a and 3b frequencies.

Class 2 Sequences This group consists of all core damage accident progression bins for which a failure to isolatethe containment occurs. The frequency per year for these sequences is obtained from theRelease Categories 12, 13, 15, and 16 listed in Table 4.2-1, which was 1.67E-10/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

• 7.28E-06/yr

= 6.71 E-08/yrClass 3b = 0.0023

• CDF= 0.0023

• 7.28E-06/yr

= 1.68E-08/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.

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-LARAttachment 4Page 17 of 34Class 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 byType C tests which are unaffected by the Type A ILRT, this group is not evaluated any further inthis analysis.

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 EPRITR-1018243, this accident class is not explicitly considered since it has a negligible impact onthe results.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 3 through 11 from the Surry Level 2 results inTable 4.2-1, and the result is 6.08E-06/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 17 through 20from the Surry Level 2 results in Table 4.2-1, and the result is 3.60E-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 EPRITR-1018243.

Table 5.1-1 summarizes these accident frequencies by accident class for Surry.

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-LARAttachment 4Page 18 of 34Table 5.1-1Accident Class Frequencies Accident Class Description Frequency

______ _____(II R)1 No Containment Failure 7.59E-072 Large Containment Isolation Failures (Failure to close) 1.67E-103a Small Isolation Failures (Type A test) 6.71 E-083b Large Isolation Failures (Type A test) 1.68E-084 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 6.08E-068 Containment Bypassed 3.60E-07CDF All CET End States (including intact case) 7.28E-065.2 Step 2 -Develop Plant-Specific Person-Rem Dose (Population Dose) Per Reactor YearPlant-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 the dose results for the Surry SPS SAMA analysis, the Surry LERF modeldocumentation, and the Surry one-time ILRT extension.

The SAMA analysis dose resultscontain the results in Sieverts for the release categories that were evaluated in the SAMAanalysis.

The Surry LERF model documentation is used to associate the STCs from the currentSTC diagram with the STCs from the previous STC diagram which was used during the SAMAanalysis.

The Class 1 dose for this analysis is taken from the STC2 Class 1 dose from theSAMA analysis.

The results of applying these releases to the EPRI containment failureclassification are as follows:Class 1 = 5.98E+02 person-rem (at 1.OLa) (1)Class 2 = 4.71 E+05 person-rem (2)Class 3a = 5.98E+02 person-rem x 1OLa = 5.98E+03 person-rem (3)Class 3b = 5.98E+02 person-rem x IOOLa = 5.98E+04 person-rem (3)Class 4 = Not analyzedClass 5 = Not analyzedClass 6 = Not analyzedClass 7 = 7.11E+04 person-rem (4)Class 8 = 5.96E+06 person-rem (5)(1) The dose for the EPRI Class 1 is taken from the Surry one-time ILRT extension.

(2) The Class 2 dose is assigned from the frequency weighted dose for release categories resulting in containment isolation failure.(3) The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with the guidance provided inEPRI TR-1018243.

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

The dose for this class is assigned from the frequency weighted dose for release categories resulting in containment bypass.

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-LARAttachment 4Page 19 of 34In summary, the population dose estimates derived for use in the risk evaluation per the EPRImethodology 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 5.98E+022 Large Containment Isolation Failures (Failure to close) 4.71 E+053a Small Isolation Failures (Type A test) 5.98E+033b Large Isolation Failures (Type A test) 5.98E+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 7.11E+048 Containment Bypassed 5.96E+06The above dose estimates, when combined with the results presented in Table 5.1-1, yield theSurry baseline mean consequence measures for each accident class. These results arepresented in Table 5.2-2.

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-LARAttachment 4Page 20 of 34Table 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 ChangeClass Description Person-Rem Frequency Person- Frequency Person- in(1/YR) Rem/YR (I1YR) Rem/YR Person-Rem/YRNo Containment 1 Fl C n5.98E+02 7.59E-07 4.54E-04 7.59E-07 4.54E-04

-3.51 E-08FailureLarge Isolation 2 Failures (Failure 4.71 E+05 1.67E-10 7.87E-05 1.67E-10 7.87E-05

--to Close)Small Isolation 3a Failures (liner 5.98E+03 6.71 E-08 4.01 E-04 6.71E-08 4.01 E-04 --breach)Large Isolation 3b Failures (liner 5.98E+04 1.68E-08 1.OOE-03 1.68E-08 1.01E-03 3.51E-06breach)Small Isolation 4 Failures (Failure N/A N/A N/A N/A N/A --to seal -Type B)Small Isolation 5 Failures (Failure N/A N/A N/A N/A N/Ato seal-Type C)Other Isolation Failures (e.g.,N/6 N/A N/A N/A N/A N/Adependent failures)

Failures Induced7 by Phenomena 7.11E+04 6.08E-06 4.32E-01 6.08E-06 4.32E-01(Early and Late)Containment 8 Bypass 5.96E+06 3.60E-07 2.14E+00 3.60E-07 2.14E+00BypassSum of AllTotal Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 3.48E-06Results Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 21 of 34Table 5.2-3 shows how the new Class 3b frequency was calculated to account for acorrosion-induced containment leak for the 3 per 10 year 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) 6.14E-06/yr Increase in LERF (0.00096%

• 6.14E-06/yr) 5.88E-1 1/yrClass 3B Frequency (Without Corrosion) 1.68E-08/yr Class 3B Frequency (With Corrosion)

(1.68E-08/yr

+ 5.88E-1 1/yr) 1.68E-08/yr 5.3 Step 3 -Evaluate Risk Impact of Extending Type A Test Interval from Ten to 15 YearsThe next step is to evaluate the risk impact of extending the test interval from its current ten-year value to 15 years. To do this, an evaluation must first be made of the risk associated withthe 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 inTable 5.3-1.Table 5.3-1Accident Class Frequency and Dose Risk for 1-per-10 Year ILRT Frequency 10-Year Interval (1 per 10 years)Without Corrosion With Corrosion EPRI ChangeClass Description Person-Rem Frequency Person- Frequency Person- in(11YR) Rem/YR (01YR) Rem/YR Person-Rem/YRNo Containment F 5.98E+02 5.64E-07 3.37E-04 5.63E-07 3.37E-04

-2.1OE-07 FailureLarge Isolation 2 Failures (Failure 4.71 E+05 1.67E-10 7.87E-05 1.67E-10 7.87E-05to Close) I IIIII Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 22 of 3410-Year Interval (1 per 10 years)Without Corrosion With Corrosion EPRI ChangeClass Description Person-Rem Frequency Person- Frequency Person- in(1/YR) Remn/YR (1/YR) Rem/YR Person-Rem/YRSmall Isolation 3a Failures (liner 5.98E+03 2.23E-07 1.34E-03 2.23E-07 1.34E-03breach)Large Isolation 3b Failures (liner 5.98E+04 5.58E-08 3.34E-03 5.62E-08 3.36E-03 2.1OE-05breach)Small Isolation 4 Failures (Failure N/A N/A N/A N/A N/Ato seal -Type B)Small Isolation 5 Failures (Failure N/A N/A N/A N/A N/Ato seal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/Adependent failures)

Failures Induced7 by Phenomena 7.11E+04 6.08E-06 4.32E-01 6.08E-06 4.32E-01(Early and Late)Containment 8 Bpass 5.96E+06 3.60E-07 2.14E+00 3.60E-07 2.14E+00BypassSum of AllTotal Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 2.08E-05ResultsTable 5.3-2 shows how the new Class 3b frequency was calculated to account for acorrosion-induced containment leak for the one-per-ten year ILRT frequency.

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-LARAttachment 4Page 23 of 34Table 5.3-2Corrosion Impact on Class 3b Frequency for 1-per-10 Year ILRT Frequency 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) 6.30E-06/yr Increase in LERF (0.00556%

• 6.30E-06/yr) 3.51 E-1 0/yrClass 3B Frequency (Without Corrosion) 5.58E-08/yr Class 3B Frequency (With Corrosion)

(5.58E-08/yr

+ 3.51 E-1 0/yr) 5.62E-08/yr Risk Imoact due to 15-Year Test IntervalThe risk contribution for a 15-year interval is calculated in a manner similar to the ten-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 three-year intervalvalue, 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 Person- ChangeClass Description Rem Frequency Person- Frequency Person- in(IYR) Rem/YR (1/YR) Rem/YR Person-Rem/YRNo Containment 1 Fiu C a e 5.98E+02 4.24E-07 2.53E-04 4.23E-07 2.53E-04

-4.98E-07 FailureLarge Isolation 2 Failures (Failure 4.71 E+05 1.67E-10 7.87E-05 1.67E-10 7.87E-05to Close)Small Isolation 3a Failures (liner 5.98E+03 3.35E-07 2.01 E-03 3.35E-07 2.01 E-03breach)Large Isolation 3b Failures (liner 5.98E+04 8.39E-08 5.01 E-03 8.47E-08 5.06E-03 4.98E-05breach)Small Isolation 4 Failures (Failure N/A N/A N/A N/A N/Ato seal -Type B)Small Isolation 5 Failures (Failure N/A N/A N/A N/A N/Ato seal-Type C)

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-LARAttachment 4Page 24 of 3415-Year Interval (1 per 15 years)Without Corrosion With Corrosion EPRI Person- ChangeClass Description Rem Frequency Person- Frequency Person- in(1/YR) Rem/YR (1/YR) Rem/YR Person-Rem/YROther Isolation 6 Failures (e.g., N/A N/A N/A N/A N/Adependent failures)

Failures Induced7 by Phenomena 7.11 E+04 6.08E-06 4.32E-01 6.08E-06 4.32E-01(Early and Late)Containment 8 Bypas n 5.96E+06 3.60E-07 2.14E+00 3.60E-07 2.14E+00BypassSum of AllTotal Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 4.93E-05ResultsTable 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 year 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) 6.41 E-06/yrIncrease in LERF (0.01298%*

6.41 E-06/yr) 8.32E-1 0/yrClass 3B Frequency (Without Corrosion) 8.39E-08/yr Class 3B Frequency (With Corrosion)

(8.39E-08/yr

+ 8.32E-10/yr) 8.47E-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.OE-06/yr and increases in LERF below Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 25 of 341.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 Surry, 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 originalthree-per-ten year test interval from Table 5.2-2, the Class 3b frequency is 1.68E-08/yr.

Basedon a ten-year test interval from Table 5.3-1, the Class 3b frequency is 5.58E-08/yr, and basedon a 15-year test interval from Table 5.3-3, it is 8.39E-08/yr.

Thus, the increase in the overallprobability of LERF due to Class 3b sequences that is due to increasing the ILRT test intervalfrom three to 15 years is 6.71E-08/yr.

Similarly, the increase due to increasing the interval fromten to 15 years is 2.80E-08/yr.

As can be seen, even with the conservatisms included in theevaluation (per the EPRI methodology),

the estimated change in LERF is below the threshold criteria for a very small change when comparing the 15-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 8.47E-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 ten-year intervals, thechange in LERF associated with the 15-year interval including the effects of steel liner corrosion is 6.79E-08/yr compared to the three-year interval and 2.88E-08/yr compared to the ten-yearinterval.

This is an increase in LERF of 8.32E-10/yr from the 15-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 whencomparing the 15-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 CCFP. The change in CCFP is indicative of theeffect of the ILRT on all radionuclide

releases, not just LERF. The CCFP can be calculated from the results of this analysis.

One of the difficult aspects of this calculation is providing adefinition of the "failed containment."

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

The NRC has previously accepted similar calculations 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 = 88.65%CCFP1o = 89.19%CCFP15 = 89.57%ACCFP3.To.15 = CCFP15-CCFP3= 0.92%

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 26 of 34ACCFP10-To-15 = CCFP15 -CCFP10 = 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 three-year and ten-year intervals, which will result in a greater change inCCFP.CCFPi5+corrosion

= 89.58%ACCFP3-To-15+Cor.osion

= CCFP15+Corrosion

-CCFP3 = 0.93%ACCFP1O0-o-15+Corrosion

= CCFP15+Corrosion

-CCFP1O = 0.40%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 Surry are summarized in Table 5.6-1.

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-LARAttachment 4Page 27 of 34Table 5.6-1Summa of Results for ILRT Frequency Extensions Base Case (3 per 10 years) I per 10 years 1 per 15 yearsWithout Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion Person- Person- Delta Person- Person- Delta Person- Person- DeltaEPRI Frequency Rem per Frequency Rem per person- Frequency Rem per Frequency Rem per person- Frequency Rem per Frequency Rem per person-Class (per year) year (per year) year rem per (per year) year (per year) year rem per (per year) year (per yr) rem peryerya eryear year year year year yearyear year year1 7.59E-07 4.54E-04 7.59E-07 4.54E-04

-3.51E-08 5.64E-07 3.37E-04 5.63E-07 3.37E-04

-2.1OE-07 4.24E-07 2.53E-04 4.23E-07 2.53E-04

-4.98E-07 2 1.67E-10 7.87E-05 1.67E-10 7.87E-05 0.OOE+00 1.67E-10 7.87E-05 1.67E-10 7.87E-05 0.OOE+00 1.67E-10 7.87E-05 1.67E-10 7.87E-05 0.OOE+003a 6.71E-08 4.01E-04 6.71E-08 4.01E-04 0.OOE+00 2.23E-07 1.34E-03 2.23E-07 1.34E-03 0.00E+00 3.35E-07 2.01 E-03 3.35E-07 2.01E-03 0.00E+003b 1.68E-08 1.00E-03 1.68E-08 1.01E-03 3.51E-06 5.58E-08 3.34E-03 5.62E-08 3.36E-03 2.10E-05 8.39E-08 5.01E-03 8.47E-08 5.06E-03 4.98E-057 6.08E-06 4.32E-01 6.08E-06 4.32E-01 0.OOE+00 6.08E-06 4.32E-01 6.08E-06 4.32E-01 0.OOE+00 6.08E-06 4.32E-01 6.08E-06 4.32E-01 0.00E+008 3.60E-07 2.14E+00 3.60E-07 2.14E+00 0.OOE+00 3.60E-07 2.14E+00 3.60E-07 2.14E+00 0.OOE+00 3.60E-07 2.14E+00 3.60E-07 2.14E+00 0.00E+00Total 7.28E-06 2.58E+00 7.28E-06 2.58E+00 3.48E-06 7.28E-06 2.58E+00 7.28E-06 2.58E+00 2.08E-05 7.28E-06 2.58E+00 7.28E-06 2.58E+00 4.93E-05Delta 3.15E-03 3.18E-03 5.42E-03 5.47E-03Dose1 N/A N/A 0.12% 0.12% 0.21% 0.21%CCFP 88.65% 88.65% 89.19% 89.19% 89.57% 89.58%DeltaCCFp2 N/A N/A 0.54% 0.54% 0.92% 0.93%Class 1.68E-08 5.62E-08 8.47E-083b 1.68E-08 5.58E-08 8.39E-08LERF3 (5.88E-11)

(3.51E-10)

(8.32E-10)

Delta LERF From Base Case (3 per 10 years)3 3.91 E-08 3.94E-08 6.71 E08 6.79E-08(3.51E-10)

(8.32E-10)

Delta LERF From 1 per 10 years3 N/A 2.80E-08 2.88E-08(8.32E-1 0)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.

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-LARAttachment 4Page 28 of 345.7 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 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-1018243.

TheClass 3b frequency for the internal events analysis was calculated by multiplying the total CDF bythe probability of a Class 3b release.

The same approach will be used for external events usingthe CDF for internal fires and seismic events. Other external events such as high winds, externalfloods, transportation, and nearby facility accidents were considered and screened in the IPEEE,so their impact will be assumed to be negligible compared to the impact associated with internalfires and seismic events. The internal fire and seismic results from the original IPEEE wereupdated in 2006 and are shown in Table 5.7-1 below.Table 5.7-1External Events Base CDF and LERFExternal Event Initiator Group CDF LERFSeismic 1.OOE-05 1.20E-07Internal Fire 1.80E-05 1.00E-07Total 2.80E-05 2.20E-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.Table 5.7-2Total LERF Increase for 15-year ILRT Interval Including Internal and External EventsClass 3b Frequency

(/yr)Initiating Event Class 3b 3 per 10 1 per 10 1 per 15 LERFInitanGroupE CDF (Iyr) Probability year year yer 15 Increase

(/yr)ILRT ILRT year ILRTInternal Events 7.28E-06 0.0023 1.68E-08 5.59E-08 8.39E-08 6.71 E-08External Events 2.80E-05 0.0023 6.45E-08 2.15E-07 3.23E-07 2.58E-07Total 3.53E-05

-- 8.13E-08 2.71 E-07 4.06E-07 3.25E-07As 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 8.13E-08/yr.

Based ona ten-year test interval, it is 2.71 E-07/yr, and based on a 15-year test interval, it is 4.06E-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 three to 15 years is 3.25E-07/yr and from ten to 15 years is1.35E-07/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 fallsbetween 1.OE-07/yr and 1.OE-06/yr when comparing the 15-year result to both the current ten-yearrequirement and the original three-year requirement.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 29 of 34The IPEEE only evaluated the external events risk associated with Surry Unit 1. However, it alsodetermined that the differences between Unit 1 and Unit 2 would have negligible impact on thePRA results, so the IPEEE CDF and LERF was 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 2.5.8 Containment Overpressure Impact on CDFThe Surry 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 is discussed in Enclosure A. The resultsof the MAAP analysis demonstrated that NPSH would not be lost for any RS or LHSI pumps duringsmall and medium LOCAs. For large LOCAs, NPSH was lost for the inside recirculation spray(IRS) pumps only, and the outside recirculation spray (ORS) and LHSI pump did not lose NPSH.Although the NPSH for the IRS pumps was lost, the NPSH for the ORS pumps was not lostbecause the ORS flow is assisted by a flow enhancement from the CS system. As a result, theCDF impact analysis assumes that a containment flaw which would result in a large containment leak during the accident will result in loss of the IRS pumps during a large LOCA.The following inputs are used for the CDF impact evaluation:

1. The scenarios of interest include only large LOCA scenarios.

The frequency associated with this break size is 4.5E-06/yr.

2. The containment isolation failure that leads to the reduction in containment overpressure can be assumed to be represented by the EPRI Class 3b contribution.

The representative Class 3b probability is 2.3E-3 and is increased by a factor of five to represent the impact ofthe ILRT extension to 15 years.3. In order for core damage to occur, a failure of sump recirculation caused by failure of theLHSI, ORS, or CS systems is required.

The probability of any of these systems failing is6.44E-04.

This probability was calculated by creating the gate below in the Surry PRAmodel. Note that the loop A large LOCA initiator is set to 1.0 while the B and C loopinitiators are set to 0. This is done in order to calculate the failure probability of the systemsrather than a frequency and to prevent failure modes from being counted more than once.

Serial No 13-435Docket Nos. 50-2801281 Type A Test Interval Extension

-LARAttachment 4Page 30 of 34Table 5.8-1 combines the above information to show the calculation of the CDF contribution of the15-year ILRT interval.

The three-year ILRT interval CDF is calculated by multiplying the frequency, Class 3b probability, and the probability of the system failures.

The 15-year ILRT interval iscalculated by multiplying the three-year interval CDF by 5.Table 5.8-1Containment Overpressure Impact on CDFLHSI, ORS, 3-Year ILRT 15-YearInitiating Frequency Class 3b or CS Interval ILRT CDFInterval IncreaseEvent (lyr) Probability Systems CDF CtF IyreFail (lyr) (Iyr) _ __ _Large 4.5E-06 2.3E-03 6.44E-04 6.67E-12 3.33E-1 1 2.67E-1 1LOCAThe three-year ILRT interval CDF for this scenario is 6.67E-12/yr, and multiplying the CDF by afactor of five to account for the increase in Class 3b leakage probability associated with extending the ILRT interval from three years to 15 years results in a CDF of 3.33E-11/yr for this scenario.

The change in CDF associated with the increase in the ILRT interval is 2.67E-1 1/yr, which is withinthe acceptance guidelines in RG 1.174 for a "very small" change in CDF. If the LERF fractionassociated with this increase in core damage frequency is assumed to be 1.0, the ALERF wouldalso increase by 2.67E-1 1/yr, which is taken to be a negligible change in LERF that would notimpact the result of the risk impact assessment.

Based on these results, a more detail CDFevaluation does not need to be performed, and the impact of the ILRT interval extension isbounded by the LERF analysis.

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-LARAttachment 4Page 31 of 346.0 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 4.87E-08

/yr. The results indicate that even with conservative assumptions, the conclusions from the base analysis would not change.Table 6.1-1Steel Liner Corrosion Sensitivity CasesIncrease 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 Year (/yr)(Step 5) Total Increase DueIncrease to Corrosion Base Case Base Case Base Case Base Case 8.32E-10 6.79E-08Double/5 Years 1.1/0.11 10% 100%Double/2 Years Base Base Base 7.68E-09 7.48E-08Double/lO Years Base Base Base 4.50E-10 6.75E-08Base Base Point 1Ox Lower Base Base 1.84E-10 6.73E-08Base Base Point 10x Higher Base Base 3.77E-09 7.09E-08Base Base 5% Base 4.99E-10 6.76E-08Base Base 15% Base 1.17E-09 6.83E-08Lower BoundDouble/10 Years Base Point 10x Lower 5% 10% 5.97E-12 6.71 E-08Upper BoundDouble/2 Years Base Point 10x Higher 15% 100% 4.87E-08 1.16E-07 Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 32 of 3

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 frequency to 15 years. These results apply to both Unit 1 and Unit 2.RG 1.174 provides guidance for determining the risk impact of plant-specific changes to thelicensing basis. RG 1.174 defines very small changes in risk as resulting in increases ofCDF below 1.OE-06/yr and increases in LERF below 1.OE-07/yr.

Since the ILRT extension was demonstrated to have a negligible impact on CDF for Surry, the relevant criterion isLERF. The increase in internal events LERF, which includes corrosion, resulting from achange in the Type A ILRT test frequency from three-per-ten years to one-per-15 years isconservatively estimated as 6.79E-08/yr (see Table 5.6-1) using the EPRI guidance aswritten.

As such, the estimated change in internal events LERF is determined to be "verysmall" using the acceptance guidelines of RG 1.174. The increase in LERF including bothinternal and external events is estimated as 3.25E-07/yr (see Table 5.7-2), which isconsidered a "small" change in LERF using the acceptance guidelines of RG 1.174.* RG 1.174 also states that when the calculated increase in LERF is in the range of 1.OE-06per reactor year to 1.OE-07 per reactor year, applications will be considered only if it can bereasonably shown that the total LERF is less than 1.OE-05 per reactor year. The total baseLERF for internal and external events is approximately 3.7E-07/yr based on Table 5.7-1and Section 4.2. Given that the increase in LERF for the 15-year ILRT interval is3.25E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-yearinterval can be estimated as 6.95E-07/yr.

This is well below the RG 1.174 acceptance criteria for total LERF of 1.OE-05.* The change in dose risk for changing the Type A test frequency from three-per-ten years toone-per-15 years, measured as an increase to the total integrated dose risk for all accidentsequences, is 5.47E-03 person-rem/yr or 0.21% of the total population dose using the EPRIguidance with the base case corrosion case from Table 5.6-1. EPRI TR-1018243 statesthat a very small population dose is defined as an increase of < 1.0 person-rem per year or< 1 % of the total population dose, whichever is less restrictive for the risk impactassessment of the extended ILRT intervals.

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

• The increase in the conditional containment failure frequency from the three-per-ten yearfrequency to one-per-15 year frequency is 0.93% using the base case corrosion case inTable 5.6-1. EPRI TR-1018243 states that increases in CCFP of < 1.5 percentage pointsare 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 Surry risk profile.Previous Assessments The NRC in NUREG-1493 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 that Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 33 of 34cannot 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 Surry confirm these general findings on a plant specific basis considering thesevere accidents evaluated for Surry, the Surry containment failure modes, and the localpopulation surrounding Surry within 50 miles.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 4Page 34 of 34ENCLOSURE AModular Accident Analysis Program (MAAP) ANALYSESMAAP analyses were performed for different break size LOCAs to demonstrate that assuming anincreased leakage from containment exceeding design leakage by a factor of 100, enough NPSHwould still be available to the Recirculation Spray pumps to successfully perform containment heatremoval 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. LHSI pumps in the injection mode andaccumulators were turned off in all cases except 31in-LLOCA, since they are only required formitigation of Large Break LOCAs. It is modeled that both CS pumps and all four RS pumps wereavailable to start and run on demand. The IRS pumps will start on high containment pressuresignal concurrent with RWST level below 60%, and ORS pumps would start two minutes later. Itwas assumed that all RS pumps would fail immediately after loss of NPSH (no pump cavitation was allowed).

Sump recirculation was established automatically when RWST level dropped below13.5%.It should be noted that an inaccuracy was indentified in the Surry MAAP parameter file about thelocation of the RS pumps. Parameters ZSPBCS and ZSPCCS, that are distances of IRS and ORSpumps from the bottom of containment sump, were set to negative values that means MAAPinterpreted their location as above tihe bottom of the sump. This was causing a loss of NPSH onthe RS pumps even without the increased leakage from the containment.

The RS pumps arevertical pumps, and stretch as long as 16 ft from the motor to the suction.

The proper elevation forcalculation of parameters ZSPBCS and ZSPCCS would be the suction of the pump (i.e., thecenterline of the impeller).

Based on drawing 11448-FP-60D Rev 14, that elevation can beconservatively 1 assumed to be -31' -7". Since the bottom of the sump is at elevation

-29' 4-5/8" indrawing 11448-FE-57F SH-001 Rev 4, the distance between the bottom of the containment sumpand the RS pumps (parameters ZSPBCS and ZSPCCS) is calculated as 2.2 ft.The results of cases lin-SLOCA, 2in-SLOCA, 4in-MLOCA, and 6in-MLOCA did not include anyloss of NPSH. The case 31in-LLOCA reported loss of NPSH to the IRS pumps. The reason theORS pumps had enough NPSH in this case was because they were modeled with NPSHenhancement flow from the CS system, while IRS pumps' NPSH enhancement flow was suppliedfrom their own recirculation line.In reality, the elevation of the impeller centerline as used in the safety analyses is much lower. However, noreference could be found to support the lower elevation.

Therefore, the -31 '-7" elevation was considered appropriate for use in this analysis.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Power Station Units 1 and 2 Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 1 of 38PRA TECHNICAL ADEQUACYThe PRA model used to analyze the risk of the extending the Type A test interval to 15 year forSurry Units 1 and 2 is the CAFTA accident sequence model referred to as S007Aa. The effective date of this model is September 30, 2009. Surry PRA Model Notebook QU.2, Rev.5 documents the quantification of the PRA model. This is the most recent evaluation of the Surry internal eventsat-power risk profile.

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

Plant changes, including physical andprocedural modifications and changes in performance data, are reviewed and the PRA model isupdated to reflect such changes periodically by qualified personnel, with independent reviews andapprovals.

Summary of the Surry PRA History:The Level 1 and Level 2 Surry PRA analyses were originally developed and submitted to theNuclear Regulatory Commission (NRC) in 1991 as the Individual Plant Examination (IPE)submittal.

The Surry PRA has been updated many times, since the original IPE. A summary ofthe Surry PRA history is as follows:* Original IPE (August 1991)* Individual Plant Examination External Events (IPEEE) 1991 through 1994* 1998 -Data update; update to address issues needed to support the Maintenance Ruleprogram* 2001 -Data update; update to address more Maintenance Rule issues, address peerreview Facts and Observations (F&Os)* 2002 -Update RCP seal LOCA model due to installation of high temperature o-rings;added internal

flooding, additional changes for Maintenance Rule and Safety Monitor* 2004 -Update to address applicable F&Os from North Anna peer review* 2005 -Update to include plant changes to reduce turbine building flood risk* 2006 -Data update and update to address MSPI requirements

• 2006 -Update to support ESGR chilled water Tech Spec change; added loss of maincontrol room HVAC and loss of instrument air to the model; added logic from the IPEEEfire and seismic models* 2009 -Data update; addressed American Society of Mechanical Engineers (ASME)PRA Standard SRs that were not met; extensive changes throughout the model as themodel was converted to CAFTA* 2009 -Updated Interfacing Systems LOCA (ISLOCA) initiator frequency, added EDGand AAC diesel fails to load (FTL) basic events, and added rupture failure of the SWexpansion joints for the CCW heat exchangers as flood scenarios (current model ofrecord)The Surry PRA model has benefited from the following comprehensive technical PRA peerreviews.

In addition, the self-identified model issues tracked in the PRA configuration controlprogram were evaluated and do not have any impact on the results of the application.

1998 NEI PRA Peer ReviewThe Surry internal events PRA received a formal industry PRA model peer review in 1998. Thepurpose of the PRA peer review process is to provide a method for establishing the technical Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 2 of 38quality of a PRA model for the spectrum of potential risk-informed plant licensing applications forwhich the PRA model may be used. The PRA peer review process used a team composed ofindustry PRA and system analysts, each with significant expertise in both PRA modeldevelopment and PRA applications.

This team provided both an objective review of the PRAtechnical elements and a subjective assessment, based on their PRA experience, regarding theacceptability of the PRA elements.

The team used a set of checklists as a framework withinwhich to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRAproducts available.

The Surry review team used the "Westinghouse Owner's Group (WOG)Peer Review Process Guidance" as the basis for the review.The general scope of the PRA peer review included a review of eleven main technical

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

for an at-power PRA including internal events, internal

flooding, and containment performance, with focus on Large EarlyRelease Frequency (LERF).The F&Os from the PRA peer review were prioritized into four categories (A through D) basedupon importance to the completeness of the model. Categories A and B F&Os are considered significant enough that the technical adequacy of the model may be impacted.

Categories Cand D are considered minor. Subsequent to the peer review, the model has been updated toaddress all Category A, B, and D F&Os. There are only 1 Category B and 3 Category C F&Osthat need to be addressed and they are listed in Table 1:Table 1Category B and C F&Os that Need to be Addressed F&O Description Significance Importance to Applications IE-5 Determine if an ISLOCA pathway B The increase in CDF and LERFcaused by a leak in the RCP associated with this scenario isthermal barrier heat exchanger expected to be negligible based onand a failure to isolate the CCW the low frequency of the initiating lines that provide cooling water to event and the redundancy inthe heat exchanger is applicable isolating the leak. Therefore, thisto Surry model and address it gap has no impact on the resultsappropriately.

for this application.

DE-1 Develop a system to initiating C There is no impact on CDF orevent dependency matrix to LERF as this is a documentation better show the dependencies enhancement, therefore this gapmodeled for each initiator.

(PRA has no impact on this application.

Configuration Control Database(PRACC) record 4023)DE-4 Develop master dependency C There is no impact on CDF ormatrices for front-line to front-line, LERF as this is a documentation for support to front-line, and enhancement, therefore this gapinitiator to system dependencies.

has no impact on this application.

(PRACC record 4023)SY-13 Update references that support C There is no impact on CDF ormission times that are less than LERF as this is a documentation 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. (PRACC record 4012) enhancement, therefore this gapI_ I _ Ihas no impact on this application.

Records have been added in the PRACC database to track the above tasks to completion.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 3 of 382010 Surry PRA Focused Peer ReviewThe Surry PRA model underwent a focused peer review in February 2010 using the PRA PeerReview Certification process performed by the Pressurized-Water Reactor Owners Group(PWROG).

To determine whether a full scope or focused peer review was necessary, thechanges to each of the model elements were reviewed to assess whether the changes involvedeither of the following:

• new methodology

• significant change in the scope or capability If changes to an element involved either a new methodology or a significant scope or capability change, then the element requires a peer review as required in the ASME PRA standard (RA-Sb-2005).

Based on the assessment of the changes to each PRA model element, a peerreview was performed on the elements shown in Table 2:Table 2Peer Reviewed ElementsElement High Level Requirement IE -Initiating Events Initiating Events Review support system initiator modeling meetsSRs IE- C6, C7, C8, C9, and C12.AS -Accident Accident Sequence Review upgraded event trees for SBO, RCPSequence Seal, LOCA, SGTR and ATWS meets all HLRs for AS.HR -Human Reliability Human Reliability Review implementation of SPAR-H methodology Analysis meets Analysis HLR-HR-G.

IF -Internal Flooding Internal Flooding Review internal flooding model meets all HLR5 forIF.QU -Quantification Quantification Review conversion to CAFTA meets HLRs for QU-B,C, and D.The AS and IF elements required a full review against all of the high level requirements (HLRs).However, changes in the IE, HR and QU elements only required specific HLR verification.

Thereview process included:

Review of the PRA model against the technical elements and associated supporting requirements (SRs) -Focus is on meeting capability category IIAt the SR level, the review team's judgment was used to assess whether the PRA meetsone of the three capability categories for each of the SRs.Evaluation of the PRA model is supported by:-NEI 05-04 process-Addendum to ASME/ANS PRA Standard RA-S-2008

-SR interpretations from ASME website-NRC clarifications and qualifications as provided in Appendix A of RG 1.200, Rev. 2-Reviewers' experience and knowledge

-Consensus with fellow reviewers

-Input and clarifications from the host utilityThe gaps identified during the 2010 Focused Peer Review that remain to be addressed arelisted in Table 3:

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-LARAttachment 5Page 4 of 38Table 3 -Remaining Gaps that Need to be Addressed Importance toF&O j Element F&O Details Possible Resolution Basis of Significance ImApplication 1-5IFSO-AlIFSO-A5IFSO-B2IFSN-A15Surry PRA Notebook IF.3 documents the floodsources but does not provide sufficient information in the following areas:1. The flood source walkdown is documented inSurry PRA Notebook IF.1, but the walkdownsheets do not contain all requested information.

For example, the columns for recording thespatial relationship between flood sources andPRA equipment are not typically completed.

2. IF.3 Tables 5.2-2 through 5.2-10 do notcontain all expected information on floodsources.

For example, the system pressure andtemperature is not included to allowdetermination of which sources have thepotential for pipe whip. In addition, it is not clearwhether capacities listed for tanks are related tothe tank volume or system volume.3. Spray/leakage impacts on equipment in thearea are not clearly considered for screenedsources.4. Piping connected to tanks such as the chilledwater surge tanks were screened based on thecapacity of the tank itself. There appears to havebeen no consideration of the capacity of attachedmakeup sources which could exceed the criticalcapacity.

1. Clearly document in theflood source walkdown notesthe spatial relationship between sources and PRAequipment to allowdetermination of the potential for various flood mechanisms (e.g. spray, jet impingement, pipe whip, etc.) duringscenario development andinitiating event frequency calculations.

2. Provide all information needed to support sourcecharacterization as noted inSR IFSO-A5 in the sourcetables in notebook IF.3.3. For each source, clearlyidentify the type of breach thatcould occur (e.g., leak,rupture, spray) and the basisfor screening each leakagetype.4. For tanks with automatic makeup supplies, consider thecapacity of the makeup pipingin the screening process.Specific information needed to supporttechnical review of theflood source analysisis not clearlydocumented in theSurry PRA floodingnotebooks.

This finding is primarily associated withenhancing documentation.

While itis possible that some newflood scenarios may be -identified, it is unlikely thatthey will have significant impact on CDF andLERF. As a result, thisgap has no impact on theacceptability of theapplication results.

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-LARAttachment 5Paae 5 of 38F&O Element F&O Details Possible Resolution Basis of Significance Applicetto

__~~ ~ ~ ~~~~~~ _ _I__ _ _ _ _ _ _ _ _ ai fSgiiac Application 1-6-I FEV-A5There appear-to be inconsistencies in theapplication of generic failure rates to piping sizeranges and some misapplication of information from a previous study for Kewaunee incalculating the flood initiating event frequencies for Surry. For example:1. The SHP table of the "SPS IF.2 Unit-1 MainSteam Valve House Upper Elevation Piping.xls" spreadsheet uses failure rates of 1.87E-05 forpiping of >2" to 6" and 3.47E-05 for piping > 6".However, Reference 6.4.9 of notebook IF.2indicates that these values are events/year based on the piping lengths for Kewaunee, notfailure rates in units of events per ReactorOperating Year-Linear Foot as used in thespreadsheet.

In addition, it was noted that itappears that the 1.87E-05/year value inReference 6.4.9 should have been 1.87E-04/year.2. In the "SPS IF.2 Cable Spreading Room.xls" spreadsheet, it is noted that the failure rateapplied to 6" fire protection piping is the rateassociated with the >6" to 24" size range. In theSPS IF.2 Mechanical Equipment Room 2.xls thefailure rate associated with the >4" to 6" range isused for 6" fire protection piping.3. Piping under 2" has been excluded from thespray frequency calculation.

However, Footnote4 for the table in Section 5 of SPS IF.2 (carriedover from EPRI 1013141) notes that for CCWand CST piping, the noted failure rates shouldbe applied to piping under 2". In addition, whereEPRI 1013141 does not provide failure rates,other sources should be considered.

1. Ensure that the correctsteam line break failure ratesfrom KPS PRA Notebook IF.4,Attachment 3 are used forcalculating flood frequencies for Surry.2. Ensure that a consistent application of the piping sizeranges used in presenting thepipe failure rates in IF.2Section 5.0 is maintained inthe spreadsheets associated with Surry PRA Notebook IF.2.3. Include piping under 2"diameter in the analysis forspray and minor flood initiating event frequencies or provide abasis for its exclusion.

These issues couldresult in flood initiating event frequencies thatare conservative insome cases and non-conservative in others.The overall impact onthe floodingcontribution toCDF/LERF isexpected to be small,but the issues need tobe corrected to ensurethe technical adequacy of the PRA.The overall impact onflooding contribution toCDF and LERF isexpected to be smallsince floodingcontributions for the mainsteam valve house andthe cable spreading roomare very low. With littlechange in CDF andLERF, this gap has noimpact on theacceptability of theapplication results.

Asensitivity studydetermined that including' the 2" piping in the sprayand minor floodfrequencies results in lessthan 10% increase inCDF (ref. PRACC 11074).A sensitivity studyincreasing the CDF andLERF values by 10% didnot change theacceptability of the ILRTextension results.

As aresult, this gap has noimpact on theacceptability of theapplication results.

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-LARAttachment 5Pace 6 of 38F&O [ Element F&O Details Possible Resolution Basis of Significance Importance to___~~~ I__I_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Application

__1-10AS-B1QU-A1IFQU-A8IFQU-A9The Surry PRA model is constructed as a linkedfault tree using the CAFTA software.

Surry PRANotebook QU.1 documents the integration process followed for the various model elements.

In general, the integration of the model appearsto account for system dependencies.

However,the following issues related to linking of theintegrated model were identified:

1. The method of linking the SSIE models intothe integrated model is not clear and it is difficult to trace.2. The modeling of loss of RCP seal cooling(gate U1-LOSC) was not conditioned to beaddressed for flooding initiators (i.e., gate U1-LOSC requires input from gate Ul-TRANSIENTS to make up the AND logic and gate U1-TRANSIENTS does not include flooding initiators as an input). Therefore, flood events that fail oneof the sources of RCP Seal Cooling (e.g.,%FLOOD-AB-SPRAY-U1CCP2AB) are not beingappropriately combined with other randomfailures which could result in loss of all sealcooling.3. Operator action to isolate a condenser waterbox during maintenance is creditedfollowing failure of the isolation valve (e.g., seeBE 1CWMOV-FOCW106A combined with REC-FLD-TB-CN-WB in cutsets 379 and 6400 of theSPS MOD A U1-CDF-Avg Maintenance.CUT file). Failure of the isolation valve to close orspurious opening of the valve should beequivalent to failure of the operator action. Itappears that the intent was to allow operatorrecovery of level switch failures which wouldnormally close the valve automatically toterminate flooding.

4. The turbine driven AFW pump loqic used1. Consider linking the SSIElogic directly under the top ofthe affected support systemlogic in the mitigation faulttree. This will ensure that thesystem gate is failed by thesame logic that is considered for the initiating event.2. Review all system logicused in the TB and ABflooding event trees to ensurethat the flooding initiating events are appropriately combined with random systemfailures and that logic is notconditioned to excludeflooding events withoutjustification.

3. Review linking of operatorrecovery actions to ensure thatfailure of the equipment needed to support success ofthe recovery is combinedunder an OR gate with theHEP.4. Note this as a source ofmodeling uncertainty to ensureit is evaluated for impact onapplications where SBO maybe an important contributor.

It appears that theintegration of thelinked fault tree modeldoes not correctly capture some impacts.It is unclear to whatextent this is true. Theimpact on total CDFappears to be smallbased on providedsensitivity results.However, since theextent of condition isnot known, this isdesignated as afinding.1. No impact to CDF orLERF is expected fromchanging the methodused to link the SSIEmodels into the integrated model. Therefore, thisgap has no impact on thisapplication.

2. A sensitivity studydetermined that the baseCDF would change byless than 1% due to thismodel correction (Ref.PRACC 11222).Therefore, this gap hasno impact on theacceptability of theapplication results.3. The estimated impactof this F&O is estimated to be an increase in CDFbelow 5E-8/yr (Ref.PRACC 11511). Giventhe increase in CDF isapproximately 1%, thisgap has no impact on theacceptability of theapplication results.4. The modeling of theTDAFW pump failure torun with a mission time of24 hours instead of 4hours is conservative.

The basic approach takenfor adding different running failure basicevents with different Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 7 of 38F&O Element F&O Details Possible Resolution Basis of Significance Importance toApplication 1-10 under gate U1-SGC-BO is based on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 5. Ensure that all direct effects mission times is that if the(cont.) mission time. This may be somewhat are identified and modeled for 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission timeconservative since the turbine driven pump is unscreened flooding events, basic event has a highonly credited for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> in SBO. whether or not the break is risk importance, then aisolated prior to damage to new basic event with a5. IF.5 details the effects of flood initiating events, additional equipment.

mission time for theIndirect effects due to submergence, spray, etc. sequence would beseem to be captured.

However, direct effects for developed.

Since themany initiators associated with service water importance of the TDAFWexpansion joint failures are not captured.

For running failure basicexample, IF.5 Table 2.3.4-4 shows that isolable events is not significant, aevent %FLOOD-TB-SW-XJ-SHD will fail ESGR if separate basic event wasnot isolated.

The fact that CCW HX cooling would not added. This F&Obe failed, even if the break is isolated, is not question is considered shown or apparently modeled.

Likewise, the Closed.individual CCW HX inlet expansion joint failures

5. The estimated CDFare not modeled as failing the associated HX. increase is below 1 E-8/yr(Ref. PRACC 11513).Therefore, this gap hasno impact on theacceptability of theapplication results.1-16 QU-D6 Significant initiating events, sequences, and Modify the quantification The SR is technically This finding is associated cutsets are documented in Surry PRA Notebook process to ensure that the met, but the process with a method ofQU.2 Sections 2.3.1, 2.3.2 and 2.3.3. Basic event independent basic events for performing the quantification associated importance factors are discussed in Section 2.3.4 replaced by the dependent quantification should with dependent HEPs, butand included in Attachment

3. However, it is combinations are retained for be improved to allow the SR was considered noted that the HEP importance factors are importance analysis.

determination of technically met.affected by the replacement of the independent independent HEP Addressing this changeHEPs during the quantification process.

importance.

has no impact on CDF orLERF, and therefore thereis no impact on theacceptability of theI_ application results.

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-LARAttachment 5Page 8 of 38F&O Element F&O Details Possible Resolution Basis of Significance Importance toApplication 1-17 QU-F5 --Dominion procedure NF-AA-PRA-282 states that Add a discussion of limitations No documentation There is no impact on"Based on the results of the sensitivity

studies, in the quantification process could be found CDF or LERF as this is athe analyst should document the insights from that could affect applications addressing the SR. documentation the sensitivity analyses.

The discussion should to Surry PRA Notebook QU.4. enhancement, therefore also highlight any potential limitations of the use this gap has no impact onof the PRA model for applications (e.g., as a this application.

result of significant sensitivity to particular modeling assumptions, as a result of limitations of the scope or level of detail for the model forcertain systems or initiating events, etc.)." Nosuch discussion of model limitations was found inSurry PRA Notebook QU.4. Potential limitations in the quantification process that could impactapplications could include such things as:1. The replacement of independent HEPs by thecombination dependent events which may affectthe importance measures for the HEPS andevaluation of scenarios in which the failure of oneof the replaced events is guaranteed,

2. Assumptions used in the baseline modelregarding the probability of equipment being inthe standby state which may not be appropriate for all applications, and3. Limitations of the SPAR-H method ofanalyzing HEPs.2-2 IE-C10 Some failure modes such as passive failures Include passive failures in The Surry SSIE The CDF and LERF are(piping failure, relief valve failure, etc.) are not SSIE models or justify their models do not include not expected to beincluded in Surry SSIE models. Surry SY.2 exclusion, passive failures that impacted since passiveNotebook Table 1 states that passive failure of may be important in failure frequencies arepiping is assumed to have a negligible probability the SSIE model. very low. As a result, theand is not included in the models. Yet as impact of this F&O on thedescribed in EPRI 1016741, passive failures that ILRT extension intervalmay be excluded from the post-initiator model results is negligible.

may be important in the SSIE model. I Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Paae 9 of 381 1 Importance toF&O Element F&O Details Possible Resolution Basis of Significance ImApplication 2-3IE-C1OA detailed review of SSIE cutsets identified someproblems:

1. The cutsets do not include all possiblecombinations, for example:a. Train A CCW pump fails-to-run and Train BCCW pump fails-to-start is in the SSIE cutsets,but other failure events that could lead to Train BCCW pump fails-to-start such as AC failure andactuation signal failure are not included;

b. There is an inconsistency in the modeling ofthe above combination when compared to themitigating system fault tree. In the mitigating system fault tree, failure to start of the Pump B isconditioned by its standby failure (see gate1-CC-P-1 B-FTS). In the SSIE fault tree, thestandby status of Pump B is not considered (seegate U1-CC-INIT-AB);

c. Relief valve failure does not appear in thecutsets for the loss of CCW SSIE.2. Cutsets including both PROB-xxxxxB-STDBY (Train B) and -PROBxxxxxA-STDBY (Train A)events may be underestimating the impact.Investigate the reason(s) thatcaused the errors for Loss ofCCW initiating event; reviewother SSIE models to seewhether similar problemsexist; and correct the problemsto make sure the cutsets arecorrectly representing theplant configuration.

A review of SSIEcutsets found thatthey might not beadequate.

1. (a) Fault tree reviewsindicate that these typesof basic events aremodeled but aretruncated out of the finalresults.(b) The impact on CDFand LERF is expected tobe insignificant.

Including the probability of theCCW pumps in standbywith the initiator fault treewill result in a slightreduction in CDF.(c) Adding spuriousopening of the CCW reliefvalves is not expected toresult in an increase inCDF given the relatively low probability of RVsspuriously opening.2. A sensitivity study withthe standby basic eventprobabilities set to 1demonstrated that theACDF was 2E-9.Therefore, this gap hasno impact on theacceptability of theapplication results.

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-LARAttachment 5P~nA 10 nf 3RImportance toF&O Element F&O Details Possible Resolution Basis of Significance ImApplication 3-3IE-C9The Surry IE analysis uses the "multiplier" method as stated in SPS IE.3, section 2.2, andreferences EPRI TR-1013490 to describe theapproach used for converting the operating trainfailure rates into an annual frequency.

A laterEPRI report, EPRI TR-1 016741, providesreasons why this method is not the consensus method in the industry.

Change to a more acceptedmethodology that can avoidthe disadvantages of themultiplier method, or providedetailed basis of why theindustry identified problemsare mitigated in the SurryPRA.EPRI TR-1 016741offers a criticalexamination ofmodeling methods,such as the explicitevent, point estimatefault tree, andmultiplier methods.The multiplier methodhas several problems, e.g.1) violates the rare-event approximation because ofthe presence of alarge (typically, 365-day) multiplier in themodel;2) A very largedisadvantage of themultiplier method isthe impact onimportance measurecalculations and thegeneration ofpotentially undefined or erroneous importance measures(specifically, Birnbaumand Risk Achievement Worth).Using the multiplier method primarily affectsthe calculation ofimportance measures.

Changing to a moreaccepted methodology would not impact the totalCDF or LERF used forthis analysis.

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

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-LARAttachment 5Page 11 of 38Importance toF&O Element F&O Details Possible Resolution Basis of Significance Application 3-4 IE-C12 Comparison of IE frequency to industry mean Compare Initiating Events Results for only 7 of Comparison with genericvalues is performed in Surry PRA Notebook Part developed with Fault Trees to 19 Fault Trees sources and similar plantsIII, Volume IE.3, Revision 1, Table 2-4 by generic and/or other plant data developed for is expected to rendercomparing 7 modeled Initiating Events with 5 to ensure reasonableness of Initiating Events were similar results to the lEsother unit results and to NUREG/CR-5750.

The results and to identify and compared to other compared.

There isremaining 12 Initiating Events (with Fault Trees) explain the differences.

plants. minimal impact on CDF orare not compared.

Other Initiating Events are LERF, therefore this gapalso not compared.

has no impact on theacceptability of the resultsfor this application.

3-9 AS-A5 System specific design attributes appear to be Strengthen the linkage from EOPs and AOPs are There is no impact onmodeled appropriately based on a review of the the event trees, initiator fault not consistently CDF or LERF as this is afault trees. SPS AS.1, AS.2, SC.1, and SC.2 trees and system fault trees to referenced in AS.1 or documentation provide the majority of information to properly the associated procedures and SC.1, the primary enhancement, therefore define the accident sequences.

However, there is the key safety functions.

notebooks relating to this gap has no impact onnot always a specific reference in these accident sequences.

this application.

notebooks to those procedures used to address In addition, IE-C8the events or to identify the need for additional identified examplesoperator actions.

where initiator treescould be missingpotential operatoractions.3-11 HR-E3 System Analysis notebooks indicate that "formal Perform and document No documentation A bounding sensitivity interviews with the plant staff are not talkthroughs with plant was found to indicate study was performed indocumented."

There is no documentation to operations and training that the interpretation which all of the HEPs andshow that the interpretation of the procedures is personnel to ensure consistent of the procedures has dependent HEPs wereconsistent with plant operational and training interpretation of the been reviewed with increased by a factor ofpractices.

An Operator Survey on HEP timing procedures and sequence of plant operations or 10. The results of thewas performed in 2002 and is the basis for HEP events, training personnel for sensitivity study indicatetiming. the new HEPs added that this F&O will notusing the SPAR-H impact the acceptability ofSurvey results are not a substitute for face-to-method. the application results.face interviews/discussions or simulations toobtain adequate interpretation of the applicable procedures and sequence of events. New HEPsadded for the recent model update using SPAR-Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 12 of 38Importance toF&O Element F&O Details Possible Resolution Basis of Significance Application 3-11 H relied primarily on engineering judgment(cont.) without plant operations and training input toensure that interpretation of the procedures isconsistent with plant observations and trainingprocedures.

3-13 HR-G4 In 2002, an operator survey was complete to Perform appropriate realistic For the SPAR-H HEPs A bounding sensitivity document timing estimates from operators of generic thermal/hydraulic recently added to the study was performed invarious experience levels. The timing results analyses, or simulation from Surry PRA model, the which all of the HEPs andfrom the survey are used in the HRA for the similar plants (e.g. plant of time available to dependent HEPs wereHEPs. Table 6.1 of HR.2 states "the response similar design and operation) complete the actions increased by a factor oftimes for operator actions may be estimated by to meet CC I1. were not based on 10. The results of theprocedure talk through or operator surveys.

applicable generic sensitivity study indicateTherefore, this is retained as a source of studies (e.g. that this F&O will notuncertainty."

For the SPAR-H HEPs, time thermal/hydraulic impact the acceptability ofavailable is based on engineering judgment.

The analysis or simulations the application results.delay (TMelay),

action(TM) and response times from similar plants)(T1/2) are conservative estimates based on a but on engineering table top review of the procedures as well as judgment.

In addition, input from other HEPs of similar actions and prior HEPs wereevents. developed using theresults of a 2002survey and not onthermal/hydraulic analysis.

3-14 HR-G6 SPS HR.2 does not check the consistency of the Perform reasonableness A review of the Surry A bounding sensitivity post-initiator HEP quantifications.

A comparison check for the SPAR-H HEPs. HEPs relative to each study was performed inof previous HEP values with current HEP values This could be performed using other to check for which all of the HEPs andis found in the QU.2 notebook supporting files but the HRA Calculator to reasonableness has dependent HEPs wereno relative comparisons are made. compare to results using other not been performed.

increased by a factor ofmethods.

10. The results of thesensitivity study indicatethat this F&O will notimpact the acceptability ofthe application results.

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-LARAttachment 5Page 13 of 38F&O Element F&O Details Possible Resolution Basis of Significance Importance to________Application 3-15 HR-G5 The delay (TDelay),

action TM and response To meet CC II, base the The newly added A bounding sensitivity times (T1/2) are conservative estimates based on required time to complete the SPAR-H HEPs based study was performed ina table top review of the procedures as well as actions (for significant HEPs) the required time to which all of the HEPs andinput from other HEPs of similar actions and on action time measurements complete actions on a dependent HEPs wereevents. in either walkthroughs or table top review of the increased by a factor oftalkthroughs of the procedures procedures and input 10. The results of theor simulator observations.

from other sensitivity study indicateprocedures.

that this F&O will notimpact the acceptability ofthe application results.3-16 HR-I1 Several documentation issues were identified:

Revise documentation to be Documentation to 1. There is no impact onHR-12 1. Table 4 of HR.4 contains an error factor for complete and make identify, characterize, CDF or LERF as this is aeach of the analyzed groupings of dependent corrections as needed. and quantify the pre- documentation operator errors. However, there is no explanation initiator, post-initiator, enhancement, therefore of how the error factor was derived.

The equation and recovery actions this gap has no impact onfor deriving the error factor is contained in considered in the this application.

Attachment 3, HEP Replacements worksheet, in PRA, including theHR.4. inputs, methods, and 2. There is no impact on2. Three HEPs (HEP-C-FWCOND, results should be CDF or LERF as this is aHEP-C-1AFW, and HEP-C- BAF) related to a complete and documentation loss of feedwater sequence are recalculated in accurate.

enhancement, therefore QU.1 based on longer SG dryout times that occur this gap has no impact onlate in the sequence.

This also results in the this application.

recalculation of four dependencies which containone or more of the HEPs. The recalculation of 3. A bounding sensitivity these HEPs and the associated dependencies is study was performed innot discussed or referenced in HR.2. which all of the HEPs and3. The SPAR-H HEPs recently added to the dependent HEPs wereSurry PRA model are documented in HR.2. Four increased by a factor ofHEPs noted in Table A-2 (New HEPs Added) that 10. The results of thewere evaluated, do not appear in the Fault Tree. sensitivity study indicateOne new HEP listed (HEP-CPORTGENRMP) that this F&O will notwas not analyzed and is also not in the FT. New impact the acceptability ofHEPs added for the recent model update were the application results.not necessarily covered by the 2002 surveyresults.

System Analysis notebooks and review Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 14 of 38Importance toF&O Element F&O Details Possible Resolution Basis of Significance Application 3-16 of HR.2 does not indicate that simulator (cont.) observations or talk-throughs with operators wereperformed.

For the SPAR-H HEPs recentlyadded to the SPS PRA model, the time available to complete the actions were not based onapplicable generic studies (e.g. thermal hydraulic analysis or simulations from similar plants).3-18 HR-G1 Surry GARD NF-AA-PRA-101-2052 states in The SPAR-H methodology has The SPAR-H A bounding sensitivity Section 3.5, "the SPAR-H model is not some limitations noted by methodology is not a study was performed inrecommended where more detailed analysis of industry evaluations that could consensus model and which all of the HEPs anddiagnosis errors is needed" and references potentially be mitigated by seldom used in plant dependent HEPs wereNUREG/CR-1 842 for more information.

The detailed benchmarking against specific utility PRAs. increased by a factor ofNUREG states "This approach results in a other accepted methods.

An Referenced

10. The results of thesomewhat

'generic' answer that is sufficient for option is to use a more documents show it sensitivity study indicatesome of the broad regulatory applications for accepted method. should not be used to that this F&O will notwhich SPAR-H is intended, but perhaps is obtain detailed results.

impact the acceptability ofinsufficient for detailed plant-specific evaluations Additionally, it cannot the application results.(a limitation)"

and also references NUREG-1792.

be assumed thatThis NUREG states "detailed assessments of the conservative resultssignificant HFE contributors should be are obtained byperformed."

SPAR-H as theevaluation of PSFsbetter than nominalcan produce non-conservative values.

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-LARAttachment 5Paee 15 of 38I I Importance toF&O Element F&O Details Possible Resolution Basis of SignificanceI Application I 4-1IFPP-B2IFSO-A3IFSO-B2IFSN-A12IFSN-B2IFEV-B2IFQU-B2Criteria for screening flood areas, sources, failuremechanisms, and scenarios from furtherconsideration are not clear. Examples include:1. The next to last paragraph of Section 2.1 in IF.3,Revision 2, states that an area can be screened if ithas "no equipment relevant to the PRA and nosignificant flood sources."

It is not clear whetherspray is considered a "significant flood source" andwhether rooms that posed a potential spray riskwere screened.

2. Other criteria that are not listed are being used toscreen areas. In Table 5.2-1, the Emergency DieselGenerator Rooms are screened on the basis of theirfailure not causing a reactor trip or requiring ashutdown.

In the same table, several rooms arescreened because the tanks in the room do nothave sufficient volume to cause critical flood height.In addition, in several places it is noted that sourcesare screened because they consist of "small borelines in this flood area which are too small to have aflood break frequency."

It is not clear whatconstitutes "a line too small to have a breakfrequency."

3. NF-AA-PRA-101-2071, Section 3.2.1 says that"Information regarding the susceptibility ofcomponents to failure by spray and other physicalphenomena such as jet impingement and pipe whipshould be obtained."

However, no notes regarding such impacts were found in the walkdown notesfor areas screened from detailed analysis (e.g.,area FLA5) and in other areas the relationship offlood sources to targets for spray is not defined(e.g., IF.3 Section 5.2.8 does not discuss potential spray of the reactor trip breakers by chilled waterlines in the room or the proximity of junction boxes,if any, to flood sources).

1. Provide clear documentation of the screening rules used toeliminate potential floodsources, failure mechanisms, scenarios, and initiating eventsfrom the detailed analysis.

2. Ensure that all of the basesused for screening areas fromfurther consideration arecaptured in a section that liststhem as screening criteria andprovides a technically acceptable basis for eachcriterion.

3. Enhance the documentation to fully explain the treatment ofspray in areas where detailedspray scenarios were notdeveloped.

4. Provide justification forexclusion of jet impingement and pipe whip failuremechanisms.

Specific information needed to supporttechnical review of theflood source analysis isnot clearly documented in the Surry PRAflooding notebooks.

This is primarily adocumentation issue. Ifany new flood scenarios are identified, it is expectedthat their impact will benegligible.

As a result, thisgap has no impact on theacceptability of theapplication results.

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-LARAttachment 5Page 16 of 38Importance toF&O Element F&O Details Possible Resolution Basis of Significance Application 4-5 HR-12 Although error factors are provided for individual Add a section to HR.2 and to Review requirements There is no impact onHR-13 HEPs in HR.2 and dependent HEPs in HR.4, HR.4 that discusses the call for description of CDF or LERF as this is athere is no discussion in either notebook development of error factors how the uncertainties documentation regarding how the error factors were assigned.

for individual and dependent and/or error factors enhancement, therefore PRA guidance document NF-AAA-PRA-101-HEPs, respectively, were derived, this gap has no impact on2052 does provide guidance for an error factor to this application.

an individual HPE, but this information is notrepeated or referenced in HR.2.4-7 HR-12 " The development and application of recovery Add a discussion of post- All recovery HEPs Based on initial review ofHR-H3 action HEPs for cutsets in the Surry PRA are processing recovery HEPs to should be included in the recoveries added bydiscussed in Notebooks HR.3 and HR.10. The Notebook HR.3. Review these the documentation, the QRECOVER faultdevelopment, application and documentation of post-processing HEPs for tree, no impact on CDF orthese recovery HEPs are generally consistent dependency between them LERF is expected.

As awith industry practice.

and other HEPs in the result, this gap has noNot discussed,

however, are those recovery respective cutsets.

Document impact on this application.

HEPs that were added to the cutsets after initial the results of this review inquantification.

There is no indication that the Notebook HR.3.post-processing recovery HEPs have beenexamined to determine whether dependencies exist between them and other HEPs in therespective cutsets.

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-LARAttachment 5Page 17 of 382012 Surry PRA Focused Peer ReviewA focused scope Peer Review of the Surry PRA model against the requirements of the ASME/ANS PRA standard and any Clarifications and Qualifications provided in the NRC endorsement of the Standard contained in Revision 2 to RG 1.200 was conducted in June, 2012.In the course of this review, thirty (30) new F&Os were prepared, including twenty-one (21)suggestions, and nine (9) findings.

Many of these F&Os involve documentation issues. The 21suggestions do not affect the technical adequacy of the PRA model and have no impact on theresults of this evaluation.

The following 9 findings have been evaluated as described in Table 4below.

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-LARAttachment 5Page 18 of 38Table 4Nine Findings from 2012 Surry PRA Focused Peer ReviewBasis ofF&O Element F&O Details Possible Resolution Significance Importance to Application 1-2 IE-C6 Scenario 1 in AS.2, Attachment 3, Appendix Expand the discussion to The calculated There is no impact on CDF orISLOCA F is screened even though the event include the probability of impact on CDF is LERF as this is afrequency would be greater than 1.OE-06 operator failure to secure small (<1 %), the documentation enhancement (calculated as 3.85E-06).

This scenario should be HHSI and other failure impact needs to be (Ref. PRACC 16415),reconsidered to ensure the screening is modes that would result in more fully therefore this gap has noappropriately justified using the criteria specified continued HHSI operation documented to impact on this application.

in IE-C6. given a rupture in the LHSI ensure thepiping. screening criteria ismet.1-6 QU-B7 This guidance does not seem to be technically Remove the mutually The impact of the A bounding sensitivity studysupported by NUREG/CR-5485 Section 5.4.4 exclusive logic for common removal of the basic evaluating the removal of thewhich only supports removal of combinations of cause failures or modify the event combinations mutually exclusive logic fortwo common cause failure events where the logic to ensure only cannot be estimated common cause failurescombinations include the same pump (e.g., CCF combinations of events based on available results in an increase in theof Pumps A and B in combination with CCF of including a common information, baseline CDF by less thanpumps A and C). Further, NUREG/CR-5485 component and failure However, because 0.2% and LERF by less thanSection 5.2 notes that NUREG/CR-4780, Volume mode (e.g., Component A this process may. 0.7% (Ref. PRACC 16418).1 discusses conditions under which these Independent Failure to Start impact the Since the increase in baselinecombinations may be valid (see NUREG/CR-in combination with CCF of importance of high risk is very small, this gap has4780, Volume 1, Section 3.3.1). Component A and B to safety significant no impact on this application.

Start) are removed, components, it isdesignated as afinding.1-8 DA-D5 A global assumption is made that staggered Provide justification for The alpha factors for A bounding sensitivity studytesting is applicable to all common cause events application of the staggered components tested changing all CCFs fromSurry DA.3 Revision 5, Section 2.2.1, Item 1). testing assumption to on a non-staggered "staggered basis" to "non-Typically, some components such as containment components tested on an basis are typically staggered basis" results in aisolation valves, HHSI isolation valves, and others outage frequency including higher than those less than 10% increase in themay only be tested during the outages.

Additional verification that redundant tested on a baseline CDF and LERFjustification for application of the staggered testing components are tested by staggered basis. values (Ref. PRACC 16419).assumption to those components tested on an 18 different personnel at Therefore, this could Based on the sensitivity studymonth basis during outages is needed. different times or apply be a significant performed for 2010 F&O 1-6,alpha factors based on a impact on CDF or a 4% increase in CDF ornon-staggered testing LERF depending on LERF will not change thescheme to those the specific acceptability of the ILRT Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5P~cu. 1 .A f 3RBasis 19of3F&O Element F&O Details Possible Resolution Basis of Importance to Application

_____ ______ _________________________________________________

ignficace

_Significance_____

1-8 components.

components extension results.

As a(cont.) affected.

result, this gap has no impacton the acceptability of theapplication results.1-10DA-D6SY-B3The AAC diesel is included in a common causegroup with the other emergency diesel generators even though Surry notebook SY.3.EP states that"The AAC diesel has a different manufacturer forthe generator and the diesel engine and is uniqueto both units."Surry DA.3 addresses this in an assumption thatstates that "If SBO diesel is modeled as one of theEDG CCF groups, because of the less similarity between the EDG and SBO diesel, the alphafactor of 3 of 3 EDGs CCF to run may be set as1.06E-2*0.9

= 9.54E-3 and the alpha factor ofAAC diesel and 2 EDGs CCF to run may be setas 1.06E-2

• 0.1 = 1.06E-3."

However, there is notechnical basis for the factor of 10 reduction, onlya qualitative discussion, yet this is dispositioned as not being a source of uncertainty.

There are two approaches that can be considered.

The most defensible approach would be toidentify all legitimate common elementsbetween the EDGs and theSBO diesel, review theCCFWIN database toexclude diesel failuremechanisms that are notcommon between theSurry EDGs and the SBOdiesel, and calculate theactual alpha factors.The second approachwould be to identify that thefactor of 10 reduction in thealpha factor is an estimatewithout a numerical basis,which makes it a plant-specific modelinguncertainty for Surry. Thensensitivity analyses couldprovide some insight intothe importance theassumed factor (0.1, 0.2,0.5, etc.) would have on theresults.The qualitative discussion of not alldiesel CCFmechanisms existing betweenthe EDGs and theSBO diesel islegitimate.

However, theselection of 0.1does not have anumerical justification, andcould potentially beconservative ornon-conservative, and it is notapparent thedegree to which itaffects the resultssince nosensitivities weredocumented.

Any modelingassumption thatcould result inlowering theimportance of theEDGs could impactapplications suchas MSPI.A bounding sensitivity studyevaluating the common causegroup of emergency generators results in no morethan a 4% increase in thebaseline CDF and LERFvalues (Ref. PRACC 16420).Based on the sensitivity studyperformed for 2010 F&O 1-6,a 4% increase in CDF orLERF will not change theacceptability of the ILRTextension results.

As aresult, this gap has no impacton the acceptability of theapplication results.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 20 of 38Basis ofF&O Element F&O Details Possible Resolution Significance Importance to Application 2-2 IE-C3 The issue of ISLOCA flood propagation and For the successfully Flood propagation There is no impact on CDF orsteaming effects in the Safeguards Building is not isolated ISLOCA and steam effects LERF as this is aadequately addressed.

Section 2.4 of the IE.1 sequences, consider may not be an issue, documentation enhancement notebook states that flooding/spatial effects need potential flood and steam but it cannot be (Ref. PRACC 16421),not be considered because an unisolated ISLOCA effects from water that determined for therefore this gap has nowas assumed to go directly to core damage. leaked out the break prior certain without impact on this application.

However, if there is a successful isolation prior to to isolation.

Also, consider further evaluation.

core damage, there is still a question about the the potential for theeffects of the water/steam that was already isolation valve to be failedleaked. For example, AFW pump operation due to the effects.should be shown not to be impacted, as well aspotential effects on the credited isolation valveitself.The PRA staff researched the issue during thepeer review and provided information thatappears to justify the operability of the isolation valve, but additional analysis is required andneeds to be documented.

2-3 DA-A2 Regarding component boundaries, Section 3.3.1 Review CCF (and even the While it is There is no impact on CDF orDA-D6 of the CCF GARD (NF-AA-PRA-1 01-2062, Rev. independent failure data) recognized that LERF as this is a4) states, "When defining common cause failure for component boundary modeling extra documentation enhancement events (and utilizing generic data concerning the consistency with the events (such as and as stated in theprobability of these events),

the analyst must generic data and CCF diesel generator description adds modelingensure that the component boundaries assumed factors.

output breakers conservatism (Ref. PRACCfor common cause failures are consistent with the when they are part 16422), therefore this gapboundaries used for the independent failures."

of the diesel has no impact on thisDOM.DA.1 Rev. 2 states "To ensure consistency component application.

between the generic database and the plant boundary inspecific

database, the component boundary NUREG/CR-6928) isneeds to be verified.

This notebook documents conservative, forthe generic database with component boundaries accuracy anddefined according to NUREG/CR-6928 (Ref. 6.1). compliance with theThis generic database shall be applicable to all of Dominion GARDthe Dominion PRA models."

and DOM.DA.1notebook,

However, Assumption 8 in Section 2.2.1 of Surry component Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Paae 21 of 38Basis ofF&O Element F&O Details Possible Resolution Significance Importance to Application 2-3 DA.3 Rev. 5 states "CCF data boundaries were boundaries should(cont.) not compared to the boundaries of DOM DA.1. be consistent withGeneric common cause failure factors were used the data.because no plant specific common cause failureswere identified.

A review of the generic commoncause failures indicates that its boundaries werewider than DOM DA.1 boundaries."

2-5SY-B3DA-AlThe CCF grouping appears to have been performed properly for pumps and some MOVs examined.

However, checks of the Electric Power system modeland check valves in SI and FW models show CCFcombinations that are missing.

In the Electric Powersystem model, the CCF of buses, inverters, breakersand fuel oil pump strainers (possibly other components as well) were modeled for complete failure of all in thegroup, but not for smaller numbers.

For example, Table3.8-1 shows 1EETFM-C8-48OTFM being comprised ofeight transformers.

However, failure of a group assmall as 2 (e.g., transformer 1H/1J) could be significant, as these transformers feed the 480V buses that powerthe 1A/2A and 1B/2B recirculation spray pumps. Whileit is acceptable to model CCF of combinations greaterthan 4 jointly (as is stated in the Section 3.2.2 of theGARD, this means creating a joint probability that sumsall the 5/8, 6/8, 7/8 and 8/8 combinations into one), theindividual combinations of 2, 3 and 4 still need to becaptured.

The other logic reviewed that are missing combinations are seen under gates 1-SI-82, 1-SI-236, 1-FW-27, 1-FW-28, 1-FW-29 and 1-FW-61/1-FW-62.

Theseinstances were identified in a short review of the systemmodels, and the review team is concerned the problemis widespread.

Another item noted is Section 2.3 of the DOM.DA.3notebook states "The Supply Breakers that feed theEmergency Buses, if there is a loss of off-site power,should be modeled for a common cause failure to openwhen the Emergency Diesel Generators are required tobe runninq and supplvina power to the emeraencv Perform a thorough reviewof all system models toidentify any missing CCFgroups. It is acceptable totreat the combinations greater than 4 failures asingle event as long as thecombinations are summedand treated as completesystem failure.

For suchcases, it is still necessary tomodel the combinations of2, 3 and 4 failures.

The missing CCFcomponent groupsyields non-conservative andpotentially significant results.A bounding sensitivity studyof additional CCFs results ina less than 10% increase inthe baseline CDF and LERFvalues (Ref. PRACC 16423).Based on the sensitivity studyperformed for 2010 F&O 1-6,a 10% increase in CDF orLERF will not change theacceptability of the ILRTextension results.

As aresult, this gap has no impacton the acceptability of theapplication results.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 22 of 38Basis ofF&O Element F&O Details Possible Resolution Significance Importance to Application 2-5 buses." This was not modeled in the EP fault trees(cont.) (they would be expected under gates 1-EP-BKR-15H8-FTO and 1-EP-BKR-15J8-FTO-LC, etc.).2-8 SY-B3 The DOM.DA.3 R3 notebook Section 2.3 states Update the model to be This is presented as There is no impact on CDF orDA-Al that CCF of air-cooled transformers would not be consistent with the DOM a finding because LERF as this is conservative modeled.

There is no mention of this in the EP DA.3 guidelines, the PRA staff and will be removed from thesystem notebook.

Many of the transformers identified that the model (Ref. PRACC 16424),modeled in the PRA are air-cooled but have CCF assumption in the therefore this gap has nomodeled.

The Surry PRA model would need to DA.3 Rev. 3 impact on this application.

be updated to match the assumption in the DOM notebook is correctDA.3 notebook.

and the modelshould be updated.2-9 DA-E3 EPRI generic CCF sources of model uncertainty Evaluate the plant-specific Sources of There is no impact on CDF orare tabulated in Table 1 of the Surry DA.3, Rev. 5 sources of model uncertainty specific LERF as this is anotebook.

DA-A-2 notes that component uncertainty related to the to the Surry CCF documentation enhancement boundaries are not consistent with the failure Surry CCF analysis.

analysis need to be (Ref. PRACC 16425),data, but states that this is a consensus model considered.

therefore this gap has noapproach and not a source of uncertainty for impact on this application.

Surry. This should be considered a source ofmodel uncertainty and/or be corrected.

Missing from the evaluation of sources of modeluncertainty are all Surry-specific assumptions, including those tabulated in Surry DA.3 Rev. 5Section 2.2.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 23 of 38Closed PRA Model GapsThe PRA model gaps that are considered closed were not evaluated for impact on theapplication.

There were 0 Category A, 23 Category B, 31 Category C, and 13 Category D F&Osfrom the 1998 NEI PRA Peer Review. Since Category C and D F&Os are considered minor(see Table 5), only the resolutions to the Category B F&Os have been included in Table 6. Inaddition to the closed gaps from the 1998 Peer Review, two F&Os from the 2010 Focused PeerReview are also considered closed and have been included in Table 6.Table 51998 NEI PRA Peer Review -Levels of Significance for F&OsA. Extremely important and necessary to address to assure the technical adequacy of thePRA or the quality of the PRA or the quality of the PRA update process.

(Contingent Item for Certification.)

B. Important and necessary to address, but may be deferred until the next PRA update(Contingent Item for Certification.)

C. Marginal importance, but considered desirable to maintain maximum flexibility in PRAApplications and consistency in the Industry.

D. Editorial or Minor Technical Item, left to the discretion of the host utility.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 24 of 38Table 6Closed PRA Model GapsF&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance AS-8 AS-1 2 The RCP seal LOCA model appears Consider an evaluation of the B (The treatment of RCP Seal LOCA methodology for the(1998) to include an optimistic interpretation sensitivity of the PRA results to RCP seal LOCA has current Surry PRA is based on theof the WOG and NRC models, and use of a model that includes the potential to WOG2000 RCP Seal LOCA modeldoes not include a contribution from the possibility of early seal significantly affect (WCAP-1 5603), which has an NRCearly seal failure.

failure.

PRA results, and SER.could therefore beAlso evaluate the potential considered to haveimpact on the model due to a greaterrecent changes to the WOG significance level.seal cooling restoration Although there isemergency response currently noguidelines (advising against standard modelingrestoration of seal cooling after approach, thea relatively brief cooling loss), assumptions usedfor the Surry modelappear to beoptimistic relative toassumptions usedfor other PRAs.)DA-6 DA-1 1 The models for the EDGs do include Update the models to include B Miscalibration of instrumentation (1998) common cause failures of fuel oil common cause instrumentation channels is resolved as a humansystem. In general the models do miscalibration.

Documentation reliability rather than an equipment consider common/shared should at least include a common cause fault. The HEP faultcomponents and support systems qualitative discussion of the behaves the same as an equipment explicitly.

The models do not appear potential impact of common CCF, but is quantified on the basis ofto include the effects of common maintenance crews and similar human error rather than equipment maintenance crews or I&C procedures.

The reliability.

technicians.

Specifically, there is no documentation should alsoconsideration of common cause highlight areas where CCF wasmiscalibration of instrumentation not included because of designchannels.

diversity or other similarconsiderations.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 25 of 38F&O Element F&O Details Possible Resolution T Basis of Plant Resolution I I Significance IAS-2(1998)AS-5AS-9The models and analyses areconsistent, as best as the reviewers could determine, with the as builtplant, and were consistent with plantoperating procedures at the time theIPE was completed.

However, thereis no process in place to identify andincorporate changes in plantoperation into the PRA model. Thisprocess should also include periodicreview of industry standards thatmay impact the PRA. Someexamples of where such a processcould impact the model include, thetiming for switchover to hot legrecirculation after event initiation (9hours in the current EOP), and areview of potential impacts on thePRA due to the power uprateprogram.

The focus of this commentis on the lack of process more thanany current discrepancies found inthe model, and is related to the IPEMaintenance and Update Processelements.

Establish a formal process foridentifying changes to plantprocedures (EOPs/AOPs),

andevaluating the impact of thesechanges on the PRA model.This process should alsoinclude periodic review ofindustry standards that mayaffect modeling assumptions and success criteria used in thePRA. The resolution of thiscomment should beincorporated as an element ofthe PRA Maintenance andUpdate Process.B (It is important that the PRA modelan appropriately current plantconfiguration, andthat there is aprocess fordetermining howand when plantchanges should beincorporated into thePRA models.However, thisobservation is not acontingent itemwithin the review ofPRA technical element AS, since itis more generically addressed within thereview for elementMU.)This F&O is addressed via procedure NF-AA-PRA-410, Probabilistic RiskAssessment Procedures and Methods:PRA Configuration Control Program.The purpose is to provide information andinstructions for tracking the information and changes used to develop andmaintain the PRA models (base modelsas well as Risk Monitor models).

Theoverall objective of the PRA Configuration Control (PRACC) program is to provide aprocess to maintain, upgrade and updatethe Dominion PRA Models to support risk-informed decision-making within thescope of Regulatory Guide 1.200. ThePRACC program contains the following five key elements as taken from theASME/ANS Standard:

(a) A process for monitoring PRA inputsand collecting new information (b) A process that maintains andupgrades the PRA model to be consistent with theas-built, as-operated plant(c) A process that ensures that thecumulative impact of pending changes isconsidered when applying the PRA(d) A process that maintains configuration control of computer codes used to supportPRA quantification (e) Documentation of the Proaram Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 26 of 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance DA-8 DA-12 (Implementation of NUREG/CR-4780 Reevaluate CCF analysis as B The common cause fault (CCF)(1998) DE-9 methodology)

Reviewers question described in Surry guidance approach is revised to incorporate thethe validity of the approach used for documents.

Fully incorporate following:

Alpha-factor model, INEELdefining CCF terms, by adding fail to NUREG/CR-4780 methods.

data base of CCF events fromstart and fail to run data variables.

NUREG/CR-6268, different failureMethod added value of QD and X, modes (run and demand),

andbut the events are not consistent (i.e. different CCF events based uponper-demand and per-hour).

population size (e.g., 2 of 3 as well asAssuming a mission time of one hour 3 of 3 CCF events. Guidance for theand a demand for the device, the CCF models was taken fromterms can be added. But what if: NUREG/CR-5485, which extends the1. Common cause failure is technology developed fordominated by running failures, NUREG/CR-4780.

there is no mission timeassociated with the use of thecommon cause term -non-conservative result.2. Running failure rate iscomparable to start term, butcommon cause dominated bystart terms -overly conservative result.DA-9 DA-9 The common cause failure Consider the use of a more B (The over The common cause fault (CCF)(1998) probability of valves failing due to realistic beta factor in the conservatism in the approach is revised to incorporate theplugging is (0.1)(1.25-7 f/hr)(2160 analysis.

beta factor could following:

Alpha-factor model, INEELhrs), or about 1 E-4. The 0.1 beta cause erroneous data base of CCF events fromfactor used for this calculation may conclusions when NUREG/CR-6268, different failurebe overly conservative.

The net the PRA results are modes (run and demand),

andresult is that many of the top used for ranking different CCF events based uponsequences (for the 3-year applications, such population size (e.g., 2 of 3 as well asmaintenance case) involve common as Maintenance 3 of 3 CCF events. Guidance for thecause valve plugging terms. It is Rule or valve CCF models was taken fromunusual to have passive equipment programs (MOV, NUREG/CR-5485, which extends thefailures be so prominent in the AOV, CV).) technology developed fordominant cutsets (more prominent NUREG/CR-4780.

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-LARAttachment 5Page 27 of 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution

______ ________

___________________________Significance PatRsltoDA-9 than active equipment failures).

In accordance with WCAP-15676, (cont.) CCF Analysis Improvement

Projects, passive equipment failure modes areno longer modeled.DE-3 DE-8 The methods used to determine CCF The generic data base B (A careful The common cause fault (CCF)(1998) groups are simplistic.

Determination development project identifies consideration of approach was revised to incorporate of the set of active components a large number of common- common cause the following:

Alpha-factor model,based on 1% contribution to CDF cause groups. Incorporate modeling INEEL data base of CCF events fromseverely limits the number and type these groups or better justify requirements is NUREG/CR-6268, different failureof common cause terms used in the their exclusion, important for PRAs modes (run and demand),

andmodel. As an evaluation tool for used for risk- different CCF events based uponplant vulnerabilities (i.e., the IPE), it informed population size (e.g., 2 of 3 as well asis more than sufficient, but as an applications.)

3 of 3 CCF events. Guidance for theevaluation tool for Risk-informed CCF models was taken fromApplications, it is not enough. NUREG/CR-5485, which extends thetechnology developed forEvents that should be considered NUREG/CR-4780.

include:Breaker fail to operate(Open/Close)

Auxiliary Feedwater Pumps(back leakage)Ventilation fansHR-2 HR-4 Table D.1-1 of Section D.1 of the Provide the basis for excluding B (The lack of Miscalibration of instrumentation (1998) HR-7 Surry IPE lists the pre-initiator errors miscalibration events, or miscalibration His channels is resolved as a humanDE-7 considered in the analysis.

The list develop appropriate events for could be significant.

reliability rather than an equipment SY-8 contains only mispositioning events inclusion in the next update of The actual effect is common cause fault. The HEP fault(valves, blank flanges, etc.). No the PRA model. not known.) behaves the same as an equipment instrument miscalibration events are CCF, but is quantified on the basis ofcontained in the list. The procedure human error rather than equipment for system analysis (page 19 of 58) reliability.

indicates that common cause Hisshould be modeled for miscalibration of instruments used to initiateI__ Isystems following an action or in any Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 28 of 38F&O Element F&O Details Possible Resolution BasisPlant Resolution Significance PatR sltoHR-2 standby equipment items such as(cont.) the level instrumentation in storagetanks.HR-4 HR-15 HEP development for the IPE model Perform and document B (HEPs can have a The HEP events developed since the(1998) was extensively documented; development of HEPs that significant effect on IPE have received detailed analysis.

however, HEPs developed for arise from model updates.

model results.

For Surry, the HEPs have beensubsequent updates of the IPE HEPs added to the implemented in the PRA model andmodel were not as well documented model as the result are discussed in the HR-series (and by implication, were not of updates should notebooks.

This process was alsodeveloped in as much detail).

For be developed and reviewed as part of the HRA re-peermany of the HEPs in subsequent documented to the review exercise prior to the RG 1.200updates, a value of 0.1 was used. It same level as the review for Surry.is not clear whether this is a IPE HEPs.)screening value or some other value.HR-5 HR-26 In a sensitivity analysis (SM-1 174, Reevaluate dependence B (Reevaluating The dependency among the HEPs is(1998) Addendum A) to evaluate without excessive emphasis on dependence among being evaluated based on thedependency among HIs contained in time between actions.

HEPs focusing on following principles:

cutsets, time between actions was factors other thanlisted as the major factor in time could produce 1. Functions:

If two HEPs are workingestablishing independence of the different conclusions for two different functions, these twooperator actions.

In most cases, about dependency.

HEPs will be justified as independent time (itself) is not an adequate factor, The effect of a HEPs.but is a parameter which can be reevaluation onassociated with more defensible analysis results is 2. Steps of procedure:

Becausefactors.

For example, one cutset not known.) operators are trained to followcontained two HEPs -- one for early procedure step by step, on the view ofSG isolation following a SGTR and operators, each step is a new andone for late SG isolation.

The time independent instruction.

If two HEPsdifference of several hours between are based on two different steps orthe actions was cited as the basis for two different procedures, even thesethe actions' independence.

Better two HEPs work for the same function, factors for independence might have they still may be justified asbeen different clues calling for the independent HEPs.need to isolate the SG or actuation of the TSC, or additional/new crew A sensitivity analysis was performed for the late isolation.

All of these are and has been incorporated into the Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Pacie 29 nf 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance HR-5 related to time, but time (itself) is not PRA quantification process for(cont.) the factor. subsequent updates to review thecutsets with multiple HEPs anddetermine if a dependency may existbetween the HEPs. This process wasalso reviewed as part of the HRA re-peer review exercise prior to the RG1.200 review for Surry.IE-3(1998)IE-13Initiating event frequencies have notbeen updated since the IPEsubmittal in 1991. As a result, recentindustry information and operating experience have not beenincorporated into the initiating eventsanalysis.

This information could alterthe initiating event frequencies currently contained in the model.For example:* Two plants (Salem and WolfCreek) have experienced lossesof circulating and service waterthat resulted in plant trips." One plant (Oconee) hasexperienced a small breakLOCA (thermal fatigue ofcharging line).* One plant (WNP-2) hasexperienced an internal flood." A draft NUREG updatinginitiating events has (veryrecently) been issued (LOCAfrequencies, particularly, havebeen affected).

Include an update of initiating event frequencies during thenext update. Also, individual applications should bereviewed to determine if theyare affected before submittal orimplementation.

B (Application results may beaffected by inclusion of the newinformation.)

The Surry initiating event frequencies were updated in the SOA-D PRAupdate by several sources.

The rareinitiator frequencies from NUREG/CR-5750 are used as priors for Bayesianupdating with plant specific histories.

The moderate frequency transient initiating event frequencies arecreated from plant specific data(1990-2000 LERs) and a non-informative gamma prior distribution.

Finally, some plant unique initiating events are quantified with new faulttree models directly linked to theintegrated PRA model. For eachmodel revision, all IE frequencies areupdated and documented in the IE.1and IE.2 notebooks.

J L Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Paae 30 of 38Basis of Plant Resolution F&O IElement F&O Details Possible Resolution Plantic ResluioIE-4(1998)IE-7A recent industry event (Oconee)involved a small break LOCA (>10gpm) at the charging line connection to the RCS. The mechanism for thecrack in the thermal sleeve at theconnection point was thermalfatigue.

Is the Surry piping subject tothis type of event? If so, has it beenconsidered in the initiating eventfrequency?

Evaluate the susceptibility ofthe Surry piping to this failuremechanism, and adjust theLOCA frequencies, asappropriate.

B (If this is a validfailure mechanism for small breakLOCAs, the effecton frequency shouldbe considered in theSurry analysis.)

The referenced Oconee event wasevaluated as part of INPO SEN 163,Recurring Event, High PressureInjection Line Leak, and as part ofNRC IN 97-46, Unisolable Crack inHigh-Pressure Injection Piping.The design of the CVCS and HHSIsystems at Surry is significantly different than that of Oconee, Unit 2.The Surry design does not includecombination CVCS makeup and HHSIlines. Each unit has only one CVCSmakeup line which carries full makeupflow and the CVCS system employs aregenerative heat exchanger to heatthe makeup water to within 100degrees of the RCS cold legtemperature, thereby minimizing thermal shock.The Oconee failure mechanism is notconsidered valid for the Surry design,and should not require LOCAfrequency adjustment.

The CurrentSurry LOCA frequencies aredeveloped from NUREG/CR-5750.

This NUREG observed that no smallLOCA events had occurred in U. S.nuclear power plants up to 1995.However, the 1997 Oconee 2 eventcould possibly be categorized as avery small LOCA / leak, and four suchevents from 1987 -1995 are includedwithin the NUREG/CR-5750 initiating event frequencies.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 31 of 38F&O Element F&O Details Possible Resolution BasisPlant Resolution Significance IE-8 IE-13 The FMEA portion of the Initiating Determine the plant's B (Not considering The current Surry PRA Model,(1998) Events notebook (page 12 of 28) susceptibility to clogged intake the potential effect S007Aa does include CW screenstates that screen wash pumps do screens, and update the of clogged intake plugging (e.g., basic event 1 FSSCN-not have to operate during an initiating event frequency as screens could result PL-1 FSS8A) for accident initiation accident.

The implication is that appropriate, in an and mitigation.

because of this there is no need to underestimation ofconsider the screen wash system the transient further.

However, clogged screens initiating frequency, can cause plant trips, and this failure particularly if theremechanism should be considered in are plant specificthe development of initiating event features that couldfrequencies.

Recent industry events cause the likelihood at Salem and Wolf Creek illustrate a of clogged screensplant's susceptibility to clogged to be higher than theintake screens.

industry average.)

IE-9 IE-16 The reactor core has been upgraded Ensure that the effects of B (Increases in core The effect of the 4.5% core power(1998) to 2586 MWt. Has the effect of this increased core power have power can result in uprate on the timing of HEPs used inchange been considered on the been properly accounted for in significant changes the Surry PRA Model, and on themoderator temperature the analysis.

in the moderator success criteria of hardware creditedcoefficient/reactivity

feedback, temperature in the Surry PRA Model has beenparticularly for early in a core's life? coefficient

/ evaluated using MAAP 4.0.5. TheAlso, has the increased decay heat reactivity feedback results of the analysis show that noload been considered in the success during the early part changes are required to the currentcriteria for decay heat removal?

of a core's life, and success criteria or HEP calculations.

can have asignificant effect onsuccess criteriarequirements foremergency borationand other methodsof shutting down thereactor duringATWS events.)L2-2 L2-8 The consequences of operator Include appropriate B SAMG actions have been(1998) L2-10 actions after core damage are not consideration of EOP (and also incorporated into the Surry PRA Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Paae 32 of 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution I ~Significance Iconsidered in the PRA or the LERFassessment.

After core damage hasoccurred, the control room staff willcontinue to attempt to implement EOP actions (and now SAMGactions).

Considering the EOP actions, onlythose that prevent core damage(have an impact on the CDF) aremodeled in the Level 1 PRA.Several EOP actions that can impactthe LERF are:* FR-C.1 actions to depressurize theRCS at the onset of coreoverheating greatly decreases theprobability of a high pressurereactor vessel failure, whilesignificantly increasing:

a) thepotential for core concreteinteractions, and b) the fissionproduct release from RCS tocontainment (which, in turn,increases the source term forcontainment failures).

• FR-H.1 actions to establish sometype of feedwater flow to the SGsincreases the chances of SG tubefailure due to thermal stresses ofcold water being injected onto hotSG tubes, but can also increasethe potential for arresting the coredamage in-vessel.

These twoaspects can impact the LERF.* ECA-0.0 actions to start sprayswhen offsite power is restored.

This can prevent overpressure failure of containment, but canSAMG) actions in the PRAmodelsmodel, S007Aa (e.g., HEP-C-FTSLPI, Operator Fails To Start Low PressureInjection per The SAMG).L2-2(cont.)

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 33 of 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance PatRsltoalso de-inert containment and leadto a hydrogen burn. Whencombined with the addedhydrogen from in-vessel

recovery, the hydrogen burn may challenge containment.

Also, these operator actions shouldbe substantiated by an HRA analysisto determine the HEP.The plant has also completed implementation of the SAMG. TheSAMG contains a set of accidentmanagement strategies that wouldbe implemented for each of the coredamage accidents.

Theimplementation of some of thestrategies has negativeconsequences that should beaddressed.

MU-2 MU-4 The core power has been upgraded.

At the next upgrade, evaluate B (Inclusion of the See discussion for equivalent F&O(1998) Effects of this change have not been the effects of the core upgrade effects of a core IE-9.incorporated into the PRA model. and incorporate, as power upgradeFactors that could be affected by the appropriate, into the PRA could have acore power upgrade include the model. significant effect onmoderator temperature coefficient the PRA model and(for ATWS) and the decay heat load analysis results.)

(for several accident sequences).

I I Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 34 of 38F&O Element F&O Details Possible Resolution BasisPlant Resolution Significance MU-3 MU-4 Requirements for review of operating Develop additional guidance on B (A comprehensive PRA Procedure NF-AA-PRA-410, (1998) experience, plant procedures, and the review process review of plant provides guidance for monitoring plant-controlled documents in requirements, describing which experience and changes in new or change PRAsupport of a PRA update are not data should be reviewed and changes is essential Inputs. Including Technical detailed in the PRA guidance how the review should be to help assure that Specifications, Design Changes,documents.

documented.

the model update Procedures and Operating adequately Experience.

MU-3 represents current(cont.) plant configuration.)

MU-4 MU-5 Activities to evaluate the effects on Revisit initiator frequencies, B (Data must be The Dominion Fleet PRA models are(1998) the PRA of changes to equipment equipment failure rates, and kept current to keep updated to reflect the as-built as-failure rates, initiator frequencies, human error probabilities with the model current.)

operated plant every 3 to 5 years.and human error probabilities are each update to determine During these model updates, theminimal, whether they are still equipment failure rates, initiating adequately estimated.

event frequencies, human errorprobabilities and other PRA inputs(e.g., design changes) are revised toreflect the as-built as-operated plant.SY-2 SY-5 The program does not appear to The following suggestions, B (It is important to This F&O is addressed via procedure (1998) have a formal requirement for while directed to the systems risk-informed NF-AA-PRA-410, Probabilistic Riskincorporating changes based on analysis

element, are actually applications that the Assessment Procedures andplant design changes.

For example, applicable more broadly, within PRA models reflect Methods:

PRA Configuration Controla later EOP change identifies the the context of the overall PRA recent changes to Programtime to hot leg recirculation Maintenance and Update the plant.)switchover as 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. The model process.

The purpose is to provide information says 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. and instructions for tracking the1. Develop a PRA change information and changes used toThere is an advantage to identifying program that tracks identified develop and maintain the PRAoperator actions to specific changes to procedures, design, models (base models as well as Riskprocedure steps. The downside is, etc. Develop a process for Monitor models).

The overall objective procedures change. Thus, the incorporating changes into the of the PRA Configuration Controlmodels and documentation need to PRA. (PRACC) program is to provide abe updated periodically, process to maintain, upgrade and2. Consider becoming part of update the Dominion PRA Models tothe review cycle for selected support risk-informed decision-making changes (e.g., for risk within the scope of Regulatory Guide Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 35 of 38F&O Element F&O Details Possible Resolution BasisPlant Resolution

________

~~~Significance PatRsltoSY-2 significant system design 1.200. The PRACC program contains(cont.) changes, PRA review is the following five key elements asrequired).

This will probably taken from the ASME/ANS Standard:

require a change to plant, (a) A process for monitoring PRAengineering procedures.

inputs and collecting new information (b) A process that maintains andThere are going to be changes upgrades the PRA model to bein plant configuration that could consistent with the as-built, as-significantly affect the PRA. A operated plantformal review by the PRA (c) A process that ensures that thegroup for selected changes has cumulative impact of pendingthe potential for saving money changes is considered when applying(change should not be made in the PRAterms of plant risk), minimizing (d) A process that maintains the effects of the change on the configuration control of computerPRA and PRA based programs codes used to support PRAand possibly identifying quantification alternative changes.

(e) Documentation of the ProgramSY-4 SY-1 2 The RPS model does not properly

1. Review the RPS system B (Support system The current Surry PRA model,(1998) identify the required support and include DC power dependencies must S007Aa, includes support systemsystems.

RPS logic receives power dependency.

be appropriately dependencies.

This was corrected from Class 1 E 125V DC buses 1A accounted for in the several model revisions ago.and 1 B. Failure of the DC buses models.)

Including fault trees RP1 revised toremoves power to the RTB shunt trip include separate logic for RTA andcoils which limits operator action in RTB including the input logic signalthe control room if reactor trip fails. with recovery.

The model alsoincludes failure of the trip breaker(RTA/RTB),

and RTA/RTB recoverythorough the shunt trip relay(including failure of 125 VDC, humanreliability model, and failure of theshunt trip relay).

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 36 of 38F&O Element F&O Details Possible Resolution BasisPlant Resolution Significance SY-5 SY-5 The RPS logic model is incorrect.

Correct the logic model. B (System models See response to SY-4.(1998) The fault tree indicates that success must correctly of either logic train allows challenge represent theto both reactor trip breakers.

Actual system function.)

design is logic train A sends signal toRTA and logic train B sends signal toRTB.SY-1 1 SY-5 Review of HHSI: SM-1 162, SPPR Set up Unit 2 model, or B (The PRA models Surry charging pumps have seal(1998)97-018, S2.07.1 (page 7 of 27). address impact on CDF. must adequately coolers with a CC coolingreflect recent plant dependency that currently has aSystem notebook update states 1A configuration; unit- difference between Units 1 and 2.and 1C charging pumps are to-unit differences For Surry Unit 1, the A & C pump sealdependent on CCW (for must be accounted coolers require CC cooling, but the Brecirculation).

What about Unit 2? for.) pump seal coolers are isolated.

For1 B is not dependent on CCW due to Surry Unit 2, all A/B/C pump seala design change. What about Unit coolers require CC cooling.2? How are unit to unit differences Potentially, all Surry charging pumpsidentified and modeled?

may be upgraded so that their CHPseal coolers can be isolated, but atDependency table from IPE model this time, only the Surry Unit 1 Bwasn't updated in SM-1 162 or SM- pump does not require CC cooling,1165 to account for CCW which explains the difference betweendependency.

Also, success criteria Surry Unit 1 and 2 charging pump CCsection of system notebook was not cooling.

The dependency on CC hasupdated.

been added to the 1B pump as well,to account for the possibility thatcooling might be needed if the pumpswere used for high head recirculation with hot sump water.TH-2 TH-8 Several HVAC systems are modeled Develop more detailed B (It is important to HVAC dependencies are documented (1998) in detail and are well documented.

documentation for modeling demonstrate that all in SPS-SY.1, System Analysis

-These include ESGR room cooling assumptions regarding HVAC HVAC Dependency Table. The Surry PRAand the Auxiliary Building Ventilation requirements.

Provide basis dependencies have model includes HVAC dependencies System, but these are the only for excluding HVAC been examined, and for each room that was not screenedI I ventilation dependencies modeled in dependencies where HVAC is that assumptions via engineering analysis (e.g., room Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5Page 37 of 38F&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance TH-2 the PRA. Some of the systems not modeled explicitly.

It may made in the heat calculations).

(cont.) models provide a one line be appropriate to include an analyses toassumption stating that room cooling overview of HVAC issues as determine the needis not required, but little if any basis part of a dependencies for ventilation oris provided for these assumptions.

notebook.

cooling areBased on discussions with the PRA documented.)

group engineers during this review, itappears that the HVAC requirements were adequately addressed in themodeling

process, but theassumptions were not clearlydocumented, and no process isdefined for the determination of theneed for room cooling.3-5 N/A Recovery events are added to N/A -This F&O was addressed N/A -This F&O was The two recovery actions that the(2010) cutsets based on post-processing by Dominion during the Peer addressed by reviewer identified as not being in thewith QRECOVER and plant-specific Review. Dominion during the Surry PRA model but were calculated rule file as discussed in SPS HR.3 Peer Review. in the HR.3 model notebook werenotebook, Section 2.2, and the QU.1 removed from the model during thenotebook.

Some recovery actions transition from the Winnupra model to(e.g., REC-FTSCC and REC- the Cafta model. Since the standbyFTSBC) should be modeled as pumps get an auto-start signal if theHEPs in the FT so all pertinent running pump fails, these recoveries cutsets are generated and were AND'd with the failure of thedependency assessed.

pressure switch. Since these werenot showing up in the cutsets, it wasREC-FTSCC and REC-FTSBC are determined that credit for the operatorlisted in HR.3 as recovery events; recovery would not be included.

Ifhowever, they are not utilized in the these pressure switch failure basicquantification process.

These actions events had a high importance, thenare typically utilized in Initiating adding the recovery credit would beEvent fault trees in conjunction with considered.

auto-start failures.

Not modelingthese actions may cause cutsets notto be generated, dependencies notevaluated, and overall resultsimpacted.

Serial No 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

-LARAttachment 5tF&O Details [ Possible Resolution Basis of Plant Resolution F&O IElemnt FO Deails-T I Significance I3-19(2010)N/AThe plant's approach to analyzing HEPs is more involved than theCategory I requirements (it isactually closer to Category Il/111),

butit does not address all of the PSFsidentified for the Category Il/111requirements (a limitation of theSPAR-H method);

therefore, METwas selected for Category I.While SPAR-H methodology is closeto meeting CC Il/111, one of thelimitations is that the PSFs arelimited to the eight chosen.Additionally, each of the eight PSFsshould be evaluated for interaction impacts which are not covered bythe method.N/A -This F&O was addressed by Dominion during the PeerReview.N/A -This F&O wasaddressed byDominion during thePeer Review.Since this F&O relates to usingSPAR-H, and F&O 3-18 indicates thatSPAR-H method is not a valid methodto meet Cat II, then this F&O will beclosed out to F&O 3-18.

Serial No. 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Surry Station Units 1 and 2 Serial No. 13-435Docket Nos. 50-280/281 Type A Test Interval Extension

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

Type Scheduled Commitment Continuing Completion DatetOne-time Compliance CompletionDate 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