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 COMPANY RICHMOND, VIRGINIA 23261 August 12, 2013 U. S. Nuclear Regulatory Commission Serial No.: 13-435 Attention:

Document Control Desk NLOS/ETS:

RO Washington, DC 20555-0001 Docket Nos.: 50-280/281 License Nos.: DPR-32/37 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS I AND 2 PROPOSED LICENSE AMENDMENT REQUEST PERMANENT FIFTEEN-YEAR TYPE A TEST INTERVAL Pursuant to 10CFR50.90, Virginia Electric and Power Company (Dominion) requests license amendments in the form of changes to the Technical Specifications, for facility Operating License Numbers DPR-32 and DPR-37 for Surry Power Station Units 1 and 2, respectively.

The proposed amendments revise Surry Power Station Units 1 and 2 Technical Specification (TS) 4.4.B, "Containment Leakage Rate Testing Requirements," by replacing the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, as the implementation document used to develop the Surry performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A of NEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending the Type A primary containment integrated leak rate test (ILRT) intervals to fifteen years and the Type C local leak rate test intervals to 75 months, and incorporates the regulatory positions stated in RG 1.163.Attachment 1 provides a discussion of the change and a summary of the supporting probabilistic risk assessment (PRA). Discussion of the supporting risk assessment and documentation of the technical adequacy of the PRA model are provided in Attachments 4 and 5, respectively.

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

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

The basis for that determination is included in Attachment

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

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

Pursuant to 10CFR51.22(b), no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change. The proposed TS change has been reviewed and approved by the Facility Safety Review Committee.

Serial No.13-435 Docket Nos. 50-280/281 Page 2 of 3 The next Unit 1 ILRT is currently due no later than May 6, 2016. Based on the current outage schedule for Unit 1, the current ten-year frequency would require the next Unit 1 ILRT to be performed during the spring 2015 refueling outage. Due to lead time required to procure the services and equipment to perform a Type A test, Dominion requests approval of the proposed change by July 31, 2014.Should you have any questions or require additional information, please contact Mr. Gary D. Miller at (804) 273-2771.Respectfully, Eugene S. Grecheck Vice President

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

1. Discussion of Change 2. Marked-up Technical Specifications Page 3. Proposed Technical Specifications Page 4. Risk Assessment

5. PRA Technical Adequacy 6. List of Regulatory Commitments VICKI L. HULL Notary Public Commonwealth of Virginia 140542 My Commission Expires May 31. 2014 COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mr. Eugene S. Grecheck, who is Vice President

-Nuclear Engineering and Development, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are 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.13-435 Docket Nos. 50-280/281 Page 3 of 3 cc: U.S. Nuclear Regulatory Commission

-Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, GA 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building -7 th floor 109 Governor Street Suite 730 Richmond, VA 23219 Ms. K. R. Cotton Gross NRC Project Manager Surry U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 Dr. V. Sreenivas NRC Project Manager North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G-9A 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector Surry Power Station Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

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

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

-LAR Attachment 1 Page 1 of 20 DISCUSSION OF CHANGE 1.0 DESCRIPTION 2.0 PROPOSED CHANGE 3.0 BACKGROUND 4.0 TECHNICAL ANALYSIS 4.1 Description of Containment 4.2 Integrated Leak Rate Test History 4.3 Type B and C Testing Programs 4.4 Supplemental Inspection Requirements 4.4.1 IWE Examinations 4.4.2 IWL Examinations 4.5 Deficiencies Identified 4.6 Plant-Specific Confirmatory Analysis 4.6.1 Methodology 4.6.2 PRA Technical Adequacy 4.6.3 Conclusion of Plant-Specific Risk Assessment Results 5.0 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 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 2 of 20 DISCUSSION OF CHANGE 1.0 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 the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI)topical report NEI 94-01, Revision 3-A, as the implementation document used by Virginia Electric and Power Company (Dominion) to develop the Surry performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. Revision 3-A of NEI 94-01 describes an approach for implementing the optional performance-based requirements of Option B, including provisions for extending primary containment integrated leak rate test (ILRT) intervals to 15 years and Type C test intervals to 75 months, and incorporates the regulatory positions stated in RG 1.163. In the safety evaluations (SEs) issued by NRC letter dated June 25, 2008 and June 8, 2012, the NRC concluded that NEI 94-01, Revision 3-A, describes an acceptable approach for implementing the optional performance-based requirements of Option B of 10 CFR 50, Appendix J, and found that NEI 94-01, Revision 3-A, is acceptable for referencing by licensees proposing to amend their TS with regard to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.0 of the two SEs.In accordance with the guidance in NEI 94-01, Revision 3-A, Dominion proposes to extend the interval for the primary containment ILRTs, which are currently required to be performed at ten year intervals, to no longer than 15 years from the last ILRT for Surry Units 1 and 2. The next ILRT is currently due no later than May 6, 2016 for Unit 1 and October 26, 2015 for Unit 2. This is approximately ten years since the last ILRT for Unit 1 and 15 years for Unit 2. The current Unit 2 schedule is based on a one-time five year extension that was requested in Dominion letter dated December 17, 2007 (Serial No. 07-0802) and approved in NRC letter dated December 18, 2008. The current Unit 1 ten-year frequency requires the next ILRT to be performed during the spring 2015 refueling outage. The proposed amendment would allow the next ILRT for Surry Unit 1 to be performed within 15 years from the last ILRT completed on May 16, 2006, as opposed to the current required ten-year interval.

Additionally, this amendment would establish a performance-based 15 year ILRT frequency for Surry Units 1 and 2 consistent with the NRC approved guidance document (NEI 94-01, Revision 3-A). The performance of fewer ILRTs will result in significant savings in radiation exposure to personnel, cost, and critical path time during future refueling outages.2.0 PROPOSED CHANGE TS 4.4.B, "Containment Leakage Rate Testing Requirements," currently states: "1. The containment and containment penetrations leakage rate shall be demonstrated by performing leakage rate testing as required by 10 CFR 50 Appendix J, Option B, as modified by approved exemptions, and in accordance with the guidelines contained in Regulatory 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 the October 26, 2000 Type A test shall be performed no later than October 26, 2015."

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

-LAR Attachment 1 Page 3 of 20 The proposed change would revise this portion of TS 4.4 by replacing the reference to RG 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 by performing leakage rate testing as required by 10 CFR 50 Appendix J, Option B, 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." 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, are included in the proposed TS. With the approval of the TS change request, Surry Units 1 and 2 will have transitioned to a performance-based 15-year frequency for Type A tests and a 75 month test interval for Type C tests.Attachment 2 contains the existing TS page 4.4-1 marked-up to show the proposed changes to TS 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 the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. The testing requirements assure that periodic surveillance of containment penetrations and isolation valves is performed so that proper maintenance and repairs are performed on the systems and components penetrating containment during the service life of the containment.

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

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

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

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

-LAR Attachment 1 Page 4 of 20 Research Institute (EPRI) TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," both of which illustrated that the risk increase associated with extending the ILRT surveillance interval was very small.NEI 94-01, Revision 2, describes an approach for implementing the optional performance-based requirements of Option B described in 10 CFR 50, Appendix J, which includes provisions for extending Type A intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies.

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

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

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

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

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

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

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

The NRC final SE issued by letter dated June 8, 2012, documents the NRC's evaluation and acceptance of NEI 94-01, Revision 3, subject to the specific limitations and conditions listed in Section 4.1 of the SE. The accepted version of NEI 94-01 has subsequently been issued as Revision 3-A dated July 2012.EPRI TR-1009325, Revision 2, provides a validation of the risk impact assessment of EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," dated August 1994. The assessment validates increasing allowable extended local leak rate test (LLRT) intervals to the 120 months as specified in NEI 94-01, Revision 0. However, the industry requested that the allowable extended interval for Type C LLRTs be increased only to 75 months, to be conservative, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The NRC final SE issued by letter dated Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 5 of 20 June 8, 2012, documents the NRC's evaluation and acceptance of EPRI TR-1009325 as a validation of EPRI-1 04285, Revision 2 bases to extend Type C LLRT to 120 months, subject to the specific limitations and conditions listed in Section 4.1 of the SE.4.0 TECHNICAL ANALYSIS As required by 10 CFR 50.54(o), the Surry containments are subject to the requirements set forth in 10 CFR 50, Appendix J. Option B of Appendix J requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Currently, the Surry 10 CFR 50 Appendix J Testing Plan is based on RG 1.163, which endorses NEI 94-01, Revision 0. This license amendment request proposes to revise the Surry 10 CFR 50, Appendix J Testing Plan by implementing the guidance in NEI 94-01, Revision 3-A.In the SE issued by the NRC dated June 8, 2012, the NRC concluded that NEI 94-01, Revision 3-A, as modified to include two limitations and conditions, is acceptable for referencing by licensees proposing to amend their TS with regard to containment leakage rate testing for the optional performance-based requirements of Option B of 10 CFR 50, Appendix J.The following addresses each of the limitations and conditions of the 2008 and 2012 SEs.Limitation I Condition (from Section 4.1 of SE dated June 25, 2008) Surry Response 1. 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 of in lieu of that in ANSI/ANS-56.8-2002).

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

The definition in Rev. 2-A and 3-A are identical.

2. The licensee submits a schedule of containment A schedule of containment inspections is provided in inspections 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 and structure potentially subjected to degradation.

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

There are no primary containment surface areas that currently 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 that performed following major modifications to the required modifications to the containment structure.

containment structure, as applicable.

When Surry Units 1 and 2 replaced the reactor vessel closure head, the containment structure was modified.The design change process addressed the testing requirements of the containment structure modifications.

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

-LAR Attachment 1 Page 6 of 20 5. The normal Type A test interval should be less than Dominion acknowledges and accepts this NRC staff 15 years. If a licensee has to utilize the provisions of position, as communicated to the nuclear industry in Section 9.1 of NEI 94-01, Revision 2, related to Regulatory Issue Summary (RIS) 2008-27 dated extending the ILRT interval beyond 15 years, the December 8, 2008.licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition.

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

Surry Units 1 and 2 are not licensed applications requesting a permanent extension of the pursuant to 10 CFR Part 52.ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment 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 follow LLRTs to be increased to 75 months with the the guidance of NEI 94-01, Rev. 3-A to assess and requirement that a licensee's post-outage report monitor margin between the Type B and C leakage rate include the margin between the Type B and Type C summation and the regulatory limit. This will include leakage 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. The staff is also allowing the non-routine emergent extension out to 84 months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3-A. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g. BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval.

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

To comply with the requirement of 10 CFR 50, Appendix J, Option B,Section V.B, Surry Units 1 and 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 Surry Unit 2, the current Surry TS does not list any exceptions to the guidelines.

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

-LAR Attachment 1 Page 7 of 20 4.1 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 are soil-supported.

The base of the foundation mat is located approximately 66 feet below finished ground grade.Each containment structure has an inside diameter of 126 ft. 0 in. The spring line of the dome is 122 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 liner for the wall is 0.375-inch thick, except over the base mat, where 0.25-inch and 0.75-inch plate is used. The steel liner for the dome is 0.50-inch thick. A waterproof membrane is placed below the containment structural mat and carried up the containment wall to ground level. The membrane is attached to and envelopes the entire part of the structure below grade. The membrane protects the structure from the effects of ground water and the steel liner from external 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 hatch penetration and a 14 ft. 6 in. inside diameter equipment hatch penetration.

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

The reinforced concrete structure has been designed to withstand all loadings and stresses anticipated during the operation and life of the unit. The steel lining is attached to and supported 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 of the liner as a structural component.

No credit has been taken for the presence of the steel liner in 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 concrete shield walls. Control Rod Drive Mechanism missile protection is provided by a concrete shield on Unit 1 and a steel shield on Unit 2. The base mat liner is protected by a 1.5 to 2-foot thick concrete cover, except where a 0.75-inch-thick liner plate was used beneath the reactor vessel incore 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, the containment structure is designed for a leakage rate not to exceed 0.1% by weight 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..

The operating pressure range for the containments is greater than 10.1 psia and less than 11.3 psia partial air pressure.

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

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

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

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

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

Instrumentation constantly monitors containment pressure.

If pressure rises, an alarm annunciates as pressure approaches 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 large leak paths in the containment structure).

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

4.2 Integrated Leak Rate Test History Previous 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 air weight at the design basis loss of coolant accident pressure (La). Since the last three Surry Units 1 and 2 Type A as-found results were less than 1.0 La, a test frequency of at least once per 15 years would be in accordance with NEI 94-01, Revision 3-A.Unit I Test Date As-Found Leakage Acceptance Limit*June 1988, Measured Leakage With Upper 0.278 of La Confidence Limit (UCL) Margin Total Type C Penalty 0.036 of La TOTAL 0.314 of La 1.0 La April 1992 Measured Leakage With UCL 0.376 of La Margin Total Type C Penalty 0.010 of La TOTAL 0.386 of La 1.0 La May 2006 Measured Leakage With UCL 0.267 of La Margin 0.267_ofLa Total Type C Penalty 0.031 of La TOTAL 0.298 of La 1.0 La The total allowable "as-left" leakage is 0.75 La, (La, 0.1% of primary containment air by weight per day, is the leakage assumed in design basis accident radiological analyses) with 0.6 La, the maximum leakage from Type B and C components.

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

-LAR Attachment 1 Page 9 of 20 Unit 2 Test Date As-Found Leakage Acceptance Limit*November 1986 Measured Leakage With Upper 0.635 of La Confidence Limit (UCL) Margin Total Type C Penalty 0.003 of La TOTAL 0.638 of La 1.0 La May 1991 Measured Leakage With UCL Margin 0.414 of La Total Type C Penalty 0.004 of La TOTAL 0.418 of La 1.0 La October 2000 Measured Leakage With UCL Margin 0.050 of La Total Type C Penalty 0.010 of La TOTAL 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 the leakage assumed in design basis accident radiological analyses) with 0.6 La, the maximum leakage from Type B and C components.

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

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

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

4.3 Type B and Type C Testing Programs Surry Units 1 and 2 Appendix J, Type B and Type C leakage rate test program requires testing of electrical penetrations, airlocks, hatches, flanges, and valves within the scope of the program as required by 10 CFR 50, Appendix J, Option B and TS 6.5.16. The Type B and Type C testing program consists of local leak rate testing of penetrations with a resilient seal, expansion bellows, double gasketed manways, hatches and flanges, and containment isolation valves that serve as a barrier to the release of the post-accident containment atmosphere.

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

The combined Type B and Type C leakage acceptance criterion is 174 standard cubic feet per hour (scfh) for Surry Units 1 and 2. The maximum and minimum pathway leak rate summary totals for the last three refueling outages with Type A tests are shown below.

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

-LAR Attachment 1 Page 10 of 20 Unit 1 June 1988 -As-Found Min Pathway Leakage 177.37 scfh June 1988 -As-Left Max Pathway Leakage 39.39 scfh April 1992 -As-Found Min Pathway Leakage 56.29 scfh April 1992 -As-Left Max Pathway Leakage 28.57 scfh May 2006 -As-Found Min Pathway Leakage 10.33 scfh May 2006 -As-Left Max Pathway Leakage 16.41 scfh Unit 2 November 1986 -As-Found Min Pathway Leakage >174 scfh November 1986 -As-Left Max Pathway Leakage 88.82 scfh May 1991 -As-Found Min Pathway Leakage 20.38 scfh May 1991 -As-Left Max Pathway Leakage 26.17 scfh October 2000 -As-Found Min Pathway Leakage 2.77 scfh October 2000 -As-Left Max Pathway Leakage 36.91 scfh Each unit has 66 mechanical penetrations and 92 electrical penetrations that are local leak rate tested (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 leakage performance.

However, neither unit's overall Type B and C leakage has approached the 0.6La leakage limit.As discussed in NUREG-1493, Type B and Type C tests can identify the vast majority (greater than 95%) of all potential containment leakage paths. This amendment request adopts the guidance in NEI 94-01, Revision 3-A, in place of NEI 94-01, Revision 0, for the Type C test interval (up to 75 months), but otherwise does not affect the scope or performance of Type B or Type C tests. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

The Surry Units 1 and 2 containment structure fuel transfer tube is the only penetration that utilizes 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 weld interface between the penetration piping and the containment liner and were used to verify weld quality 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 no record of bellows leakage. Visual inspection is impossible because two of the three bellows are enclosed in sleeves in the fuel building and between the fuel and containment buildings.

The third bellow is located between the containment and the fuel transfer canal, which is a three foot opening, covered by permanent shielding.

The fuel transfer tube is sealed inside the containment building with a blind flange, equipped with a double o-ring seal, which is Type B tested.

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-LAR Attachment 1 Page 11 of 20 4.4 Supplemental Inspection Requirements Prior to initiating a Type A test, a general visual examination of accessible interior and exterior surfaces of the containment system is performed to identify any potential structural problems that could affect either the containment structure leakage integrity or the performance of the Type 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 interval IWE/IWL program is the 2001 Edition with the 2003 Addenda.The examinations performed in accordance with the IWE/IWL program satisfy the general visual examination requirements specified in 10 CFR 50, Appendix J, Option B. Identification and evaluation of inaccessible areas are addressed in accordance with the requirements of 10 CFR 50.55a(b)(2)(ix)(A) and (E). Examination of pressure-retaining bolted connections and evaluation of containment bolting flaws or degradation are performed in accordance with the requirements of 10 CFR 50.55a(b)(ix)(G) and 10 CFR 50.55a(b)(ix)(H).

Each ten-year ISI interval is divided into three approximately equal-duration inspection periods. A minimum of one inspection 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 in Section 4.1 of the NRC SE for NEI 94-01, Revision 2.Visual examinations of accessible concrete containment components in accordance with ASME Code,Section XI, Subsection IWL are performed every five years, resulting in at least three IWL examinations 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 which may affect the reactor building's structural integrity or leak tightness.

The areas that are inspected include the external surface of the building, the basement of the building, and the wall inside the main steam safety enclosure.

The examinations of the inside of the building are performed during Cold Shutdown.

The examination is conducted in accordance with approved plant 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 the accessible containment surfaces (exterior and interior) and one visual examination immediately prior to a Type A test will be conducted before the next Type A test if the Type A test interval is extended to 15 years, thereby meeting the requirements of Section 9.2.3.2 of NEI 94-01, Revision 3-A, 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 that portion inaccessible due to the 2-foot thick floor mat, which has been calculated to be 14.9% of each liner. During the 2000 refueling outages for Units 1 and 2, the containment liner/floor mat interface was inspected and evaluated, which included thickness measurements (UT). In addition, in Unit 1 several areas at the liner/floor mat interface were excavated to further assess Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 12 of 20 the condition of the liner. It was concluded that there was no significant deterioration at the liner/floor mat interface or the liner extending below the floor based on the results of the visual exam 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 these inaccessible areas. Based on this information, Surry has not implemented any new technologies to inspect the inaccessible areas to date. However, Dominion actively participates in various nuclear utility owners groups, ASME Code committees, and with NEI to maintain cognizance 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 are explored 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 surface examinations, assuming the Type A test frequency is extended to 15 years.Unit I Calendar Year Type A Test General Visual Examination of General Visual Examination of (ILRT) Accessible Exterior Surface Accessible Interior (Liner) Surface 2005 2006 05/16/06 05/07/06 2007 11/21/07 2008 2009 05/27/09 2010 2011 08/31/11 2012 2013 10/13 2014 2015 2016 08/16 10/16 2017 2018 2019 10/19 2020 2021 04/21 08/21 Unit 2 Calendar Year Type A Test General Visual Examination of General Visual Examination of (ILRT) Accessible Exterior Surface Accessible Interior (Liner) Surface 2000 10/26/00 10/07/00 2001 2002 2003 10/29/03 2004 2005 05/16/05 2006 12/31/06 10/27/06 2007 2008 2009 11/24/09 2010 2011 08/31/11 05/16/11 2012 2013 2014 04/14 2015 10/15 2016 08/16 Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 13 of 20 4.4.1 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-C examination requirements.

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

This information 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 the containment metallic liner or other IWE components.

Based upon the IWE-1241 evaluation and the first ten-year examination results, the second ten-year inspection interval also has no Category 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 liner examinations (IWE) will be completed by the required date of April 25, 2014 for Unit 1 and October 19, 2014 for Unit 2 to the requirements of the 2001 Edition through the 2003 Addenda of ASME Section Xl. The second ten-year interval IWE examination requirements will use the 2001 Edition through the 2003 Addenda of ASME Section XI as modified by the 10 CFR 50.55a(b) limitations for both units. At this time, no augmented Category E-C examinations are planned. The remaining examinations are based on Category E-A and are visual (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 an IWE -General Visual examination on the accessible surface areas associated with the Containment Liner. Most of the coating conditions noted are the result of mechanical impact damage and are not considered to be of any significance.

This is especially true on the EL -27 ft. 7 in. and EL -3 ft. 6 in. level where the lead shielding and scaffolding boxes are located. The general mechanical damage of the liner coating on EL -27 ft. 7 in. and EL -3 ft. 6 in., as well as the scarred sites on EL 18 ft. 4 in. and EL 47 ft. 4 in., have been noted during previous containment coating assessments conducted by Materials/NDE Engineering.

There were no indications of coating blisters.

Corrosion of the liner at the damaged coating sites was generally limited to superficial pitting.4.4.2 IWL Examinations The second ten-year concrete containment examinations (IWL) have specified dates of August 31, 2011 and August 31, 2016 for Units 1 and 2. General and detailed visual examinations have been and will be completed in accordance with Category L-A of the code no earlier 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-year Containment Inservice Inspection Program. Concrete containment examinations (IWL) were completed for Units 1 and 2 by the required date of August 31, 2011 in accordance with the requirements of the 2001 Edition through the 2003 Addenda of ASME Section Xl completing the second period of the second ten-year interval.

These examinations on the concrete exterior were 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.

The others 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 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 14 of 20 require 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, either alone or combined, do not adversely affect the ability of the Containment concrete structures to perform their design function.

The findings to this point are consistent with previous inspections.

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, abnormal degradation of the primary containment structure identified during the conduct of IWE/IWL program examinations or at any other times is entered into the corrective action program for evaluation to determine the cause of the degradation and to initiate appropriate corrective actions.4.6 Plant-Specific Confirmatory Analysis 4.6.1 Methodology An evaluation has been performed to assess the risk impact of extending the Surry Power Station ILRT surveillance intervals from the current ten years to 15 years. The evaluation is included as Attachment

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

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

This PRA model has been peer 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 PRA technical adequacy evaluation discussed in Attachment

5. The analyses include evaluations for the dominant external events (seismic and fire) using conservative expert judgment with the information from the Surry Individual Plant Examination of External Events (IPEEE). The original IPEEE seismic and fire event models were updated in 2006 with fault tree changes and data files from the S05A model, and insights and information from the IPEEE have been used to estimate 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 four limitations and conditions for the use of EPRI TR-1018243, Revision 2. These limitations and conditions were incorporated into Revision 2-A of EPRI TR-1018243.

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-LAR Attachment 1 Page 15 of 20 From Section 4.2 of SE Surry Response 1. The licensee submits documentation indicating that Surry PRA technical adequacy is addressed in Section the technical adequacy of their PRA is consistent with 4.6.2.the requirements of RG 1.200 relevant to the ILRT extension.

2. The licensee submits documentation indicating that EPRI Report No. 1009325, Revision 2-A, incorporates the estimated risk increase associated with these population dose and CCFP acceptance guidelines, permanently extending the ILRT surveillance interval and these guidelines have been used for the Surry plant to 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 dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive.

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

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

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

Additional risk analysis performance.

has been performed to address any change in risk associated with reliance on containment overpressure for ECCS performance and is discussed in Attachment 4.4.6.2 PRA Technical Adequacy The 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 accident sequences have been developed from internally initiated events. The sequences have been mapped to the radiological release end state (i.e., source term release to environment).

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

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

The first peer review was performed in 1998 using the Westinghouse Owners Group Peer Review Guidance, and only one Category B and three Category C Facts and Observations (F&Os) remain open. A focused peer review was performed in 2010 using the ASME PRA standard RA-Sb-2005, and 90% of the Specific Requirements (SRs) were considered Met with Category 1/11 or greater. The most 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 open gaps identified by the peer reviews are evaluated for impact on the application.

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

-LAR Attachment 1 Page 16 of 20 updated Surry PRA model is considered acceptable for use in assessing the risk impact of extending 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 Results The findings of the Surry risk assessment confirm the general findings of previous studies that the risk impact associated with extending the ILRT surveillance interval from three in ten years to 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 ten years 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 LERF as those that are less than 1.OE-7/yr.

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

In this case, the total increase in LERF for combined internal and external events was conservatively estimated as 3.25E-07/yr.

The total increase in LERF for the combined internal and external events model 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 defined as an increase of less than or equal to either 1.0 person-rem per year or 1 percent of the total 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 the guidelines of EPRI TR-1018243, Revision 2-A. Moreover, the risk impact when compared to other 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 to 1.5 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 satisfy the net positive suction head (NPSH) requirements for recirculation spray (RS) and low-head safety injection (LHSI) in recirculation mode during loss of coolant accidents (LOCAs). The change in CDF associated with the increase in the ILRT surveillance interval is 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 is negligible, and the impact of the extension is bounded by the LERF analysis.5.0 REGULATORY ANALYSIS 5.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met.

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-LAR Attachment 1 Page 17 of 20 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment.

In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing, and reporting requirements for each type of test. RG 1.163 was developed to endorse NEI 94-01, Revision 0 with certain modifications and additions.

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

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

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

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

In the SEs issued by NRC letters dated June 25, 2008 and June 8, 2012, the NRC concluded that NEI 94-01, Revision 3-A, describes an acceptable approach for implementing the optional performance-based requirements of 10 CFR 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their TS 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 be performed using the approach and methodology described in TR-1009325, Revision 2, for a proposed extension of the ILRT interval to 15 years. In the 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 interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of that SE.Based on the considerations above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will continue to be conducted in accordance with the site licensing basis, and (3) the approval of the proposed change will not be inimical to the common defense and security or to the health and safety of the public.In conclusion, Dominion has determined that the proposed change does not require any exemptions or relief from regulatory requirements, other than the TS, and does not affect conformance with any regulatory requirements/criteria.

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

-LAR Attachment 1 Page 18 of 20 5.2 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 the reference to Regulatory Guide (RG) 1.163 with a reference to Nuclear Energy Institute (NEI)topical report NEI 94-01, Revision 3-A, dated June 8, 2012 and issued July 2012, as the implementation document used by Virginia Electric and Power Company (Dominion) to develop the Surry performance-based primary containment leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. The proposed amendment would also extend the interval for the primary containment integrated leak rate test (ILRT), which is required to be performed by 10 CFR 50, Appendix J, from ten years to no longer than 15 years from the last ILRT and permit 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 the proposed 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 Rate Testing Program. The proposed amendment does not involve a physical change to the plant or a change in the manner in which the plant is operated or controlled.

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

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

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

The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A, for development of the Surry Power Station Units I and 2 performance-based containment testing program. Implementation of these guidelines continues to provide adequate assurance that during design basis accidents, the primary containment and its components will limit leakage rates to less than the values assumed in the plant safety analyses.

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

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 the proposed amendment does not significantly increase the consequences of an accident previously evaluated.

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

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-LAR Attachment 1 Page 19 of 20 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response:

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

The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) 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 of accident from any previously evaluated.

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

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

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

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

5.3 Environmental Considerations The proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

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

Therefore, pursuant to 10 CFR 51.22(b), no Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 1 Page 20 of 20 environmental 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 the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A and Type C test intervals to 15 years and 75 months, respectively.

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

Dominion is adopting the guidance of NEI 94-01, Revision 3-A for the Surry Units 1 and 2 10 CFR 50, Appendix J testing program plan.Based on the previous ILRT tests conducted at Surry Units 1 and 2, it may be concluded that extension of the containment ILRT surveillance interval from ten to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with 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 risk analysis.

The findings of the Surry risk assessment confirm the general findings of previous studies, on a plant-specific basis, that extending the ILRT surveillance interval from ten to 15 years 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 the NRC.1. Nine Mile Point Nuclear Station, Unit 2 -Issuance of Amendment Re: Extension of Primary Containment Integrated Leakage Rate Testing Interval (TAC No. ME1650, ADAMS Accession 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, ADAMS Accession Number ML 110800034) approved April 7, 2011.3. Palisades Nuclear Plant -Issuance of Amendment to Extend the Containment Type A Leak Rate Test Frequency to 15 Years (TAC No. ME5997, ADAMS Accession Number ML120740081) approved April 23, 2012.

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

Surry Power Station Units I and 2 TS 4.4-1 128 0 4.4 CONTAINMENT TESTS Applicability Applies to containment leakage testing. NEI 94-01, Revision 3-A, "Industry Guidelines for Implementing Performance-Based Option of 10 Objective FCR 50, Appendix J," dated July 2012.To assure that leakage of the primary rea or containment and associated systems is held within 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 be performed in accordance with the re uirements of 10 CFR 50, Appendix J, "Reactor Containment 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, Option B, 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 by weight 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 and valves subject to Type B and C testing when pressurized to Pa.Prior to entering an operating condition where containment integrity is required the as-left Type A leakage rate shall not exceed 0.75 La and the combined leakage rate 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.

Basis The leak tightness testing of all liner welds was performed during construction by welding a structural steel test channel over each weld seam and performing soap bubble and halogen leak tests.Amendment No. --6+

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

Surry Power Station Units I and 2 TS 4.4-1 4.4 CONTAINMENT TESTS Applicability Applies to containment leakage testing.Objective To assure that leakage of the primary reactor containment and associated systems is held within 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 be performed in accordance with the requirements of 10 CFR 50, Appendix J, "Reactor Containment 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, Option B, 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 by weight 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 and valves subject to Type B and C testing when pressurized to Pa.Prior to entering an operating condition where containment integrity is required the as-left Type A leakage rate shall not exceed 0.75 La and the combined leakage rate 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.

Basis The leak tightness testing of all liner welds was performed during construction by welding a structural steel test channel over each weld seam and performing soap bubble and halogen leak tests.Amendment No.

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

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

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

-LAR Attachment 4 Page 1 of 34 RISK ASSESSMENT 1.0 PURPOSE OF ANALYSIS 1.1 Purpose The purpose of this analysis is to provide an assessment of the risk associated with permanently extending the Type A integrated leak rate test (ILRT) interval from ten years to 15 years for Surry Power Station (Surry). The risk assessment follows the guidelines from NEI 94-01, Revision 3-A, the methodology used in EPRI TR-104285, the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174, and the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval.The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the October 2008 EPRI final report.1.2 Background Revisions to 10CFR50, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirement from three-per-ten years to at least one-per-ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage rate was less than limiting containment leakage rate of 1La.The basis for the current 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 Option B 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 revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose)associated with a range of extended leakage rate test intervals.

To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals." The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.

Consequently, it is desirable to confirm that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for Surry.Earlier ILRT frequency extension submittals have used the EPRI TR-104285 methodology to perform the risk assessment.

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

-LAR Attachment 4 Page 2 of 34 using current performance data and risk informed guidance, primarily NRC RG 1.174. This more recent EPRI document considers the change in population dose, large early release frequency (LERF), and containment conditional failure probability (CCFP), whereas TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for Surry employs the EPRI TR-1018243 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary.1.3 Criteria The 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 of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases 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 5 confirms that the change in risk is bounded by the LERF impact, so the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as increase of less than 1.0E-06 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the CCFP is also calculated to help ensure that the defense-in-depth philosophy is maintained.

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

Given this perspective and based on the guidance in EPRI TR-1018243, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small.In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate the relative change in this parameter.

While no acceptance guidelines for these additional figures of merit are published, examinations of NUREG-1493 and Safety Evaluations (SEs) for one-time interval extension (summarized in Appendix G of EPRI TR-1018243) indicate a range of incremental increases in population dose that have been accepted by the NRC. The range of incremental population dose increases is from <.0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493, Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (three tests per ten years) dose of <1.0 person-rem per year, or 1% of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.

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

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

-LAR Attachment 4 Page 3 of 34 2.0 METHODOLOGY A simplified bounding analysis approach consistent with the EPRI approach is used for evaluating the change in risk associated with increasing the test interval to 15 years. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Surry PRA analysis of record and subsequent containment responses resulting in various fission product release categories.

The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report.2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses.3. Evaluate the risk impact (i.e., the change in containment release scenario type frequency and population dose) of extending the ILRT interval to 15 years.4. Determine the change in risk in terms of LERF in accordance with RG 1.174 and compare 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 (due to liner breach) to LERF.Furthermore,* Consistent with the other industry containment leak risk assessments, the Surry assessment 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 to show that defense-in-depth and the balance of prevention and mitigation is preserved.

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

The results of this assessment are compared to the guidelines in RG 1.174 to demonstrate that the change in CDF is acceptable." This evaluation for Surry uses ground rules and methods to calculate changes in risk metrics that are similar to those used in EPRI TR-1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals.

3.0 GROUND RULES The 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 assume that the impact from the ILRT extension (with respect to percent increases in population dose) will not substantially differ if fire and seismic events were to be included in the Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 4 of 34 calculations.

However, external events have been accounted for in the analysis based on 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 in the PRA.* Accident classes describing radionuclide release end states are defined consistent with EPRI methodology and are summarized in Section 4.2.* The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures." The representative containment leakage for Class 3a sequences is 1OLa based on the previously approved methodology for Indian Point Unit 3.* The representative containment leakage for Class 3b sequences is 10OLa based on the guidance 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 the proposed ILRT extension, but is accounted for in the EPRI methodology as a separate entry for comparison purposes.

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

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

2. NUREG/CR-4220

3. NUREG-1273

4. NUREG/CR-4330

5. EPRI TR-1 05189 6. NUREG-1493

7. EPRI TR-1 04285 8. Calvert Cliffs liner corrosion analysis 9. EPRI TR-1018243 The first study is applicable because it provides one basis for the threshold that could be used in the Level 2 PRA for the size of containment leakage that is considered significant and is to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident.

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

The fourth study provides an Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 5 of 34 assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension.

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

Finally, the ninth study builds on the previous work and includes a recommended methodology and template for evaluating the risk associated with a permanent 15-year extension of the ILRT interval.NUREG/CR-3539 Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.

This study uses information from WASH-1400 as the basis for its risk sensitivity calculations.

ORNL concluded that the impact of leakage rates on light water reactor (LWR) accident risks is relatively small.NUREG/CR-4220 NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.The study reviewed over two thousand licensee event reports (LER), ILRT reports, and other related records to calculate the unavailability of containment due to leakage.NUREG-1273 A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database.

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

In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system.NUREG/CR-4330 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals.

However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: "...the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-1 05189 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because it provides insight regarding the impact of containment testing on shutdown risk. This study contains a quantitative evaluation (using the EPRI ORAM software) of the impact of extending ILRT and LLRT test intervals on shutdown risk for two reference plants (a BWR-4 and Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

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

NUREG-1493 NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/dr relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies: "Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an"imperceptible" increase in risk." Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk.EPRI TR-1 04285 Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1 150 Level 3 population dose models to perform the analysis.

The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals.

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

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

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

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

-LAR Attachment 4 Page 7 of 34 Table 4.1-1 EPRI/NEI Containment Failure Classifications EPRI Class EPRI Class Description Containment remains intact including accident sequences that do not lead to 1 containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant.2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment.

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

These are the Type B-tested components that have isolated but exhibit excessive leakage.Independent (or random) isolation failures include those accidents in which the 5 pre-existing isolation failure to seal is not dependent on the sequence in progress.This class is similar to Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.Containment isolation failures include those leak paths covered in the plant test 6 and maintenance requirements or verified per in service inspection and testing (ISI/IST) program.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 or 8 induced by phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.

Calvert Cliffs Response to Request for Additional Information Concerning the License Amendment for a One-Time Integrated Leakage Rate Test Extension This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms was factored into the risk assessment for the ILRT one-time extension.

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

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

-LAR Attachment 4 Page 8 of 34 EPRI Report No. 1009325, Revision 2-A, Risk Impact Assessment of Extended Integrated Leak Rate 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 risk impact assessments, builds on the previous EPRI risk impact assessment methodology and the NRC performance-based containment leakage test program, and considers approaches utilized in 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 document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5.4.2 Plant-Specific Inputs The plant-specific information used to perform the 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 results Surry Internal Events PRA Model The 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 average maintenance 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 2 model 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 update using revised LERF fractions.

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

The total CDF associated with the sum of release category frequencies is 7.28E-06/yr as documented in the Surry LERF model documentation.

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

Surry Source Term Category Population Dose A 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 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

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

The STC diagram was revised in the Level 2 model update using revised LERF fractions, and the number of STCs was reduced from twenty-four to twenty. The Surry LERF model documentation contains a table which associates the current STCs with the IPE STCs. Using the dose results from the Surry SAMA analysis and the one-time ILRT extension in conjunction with the Surry LERF model documentation 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 EPRI accident classes used in the ILRT extension evaluation.

These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report.Table 4.2-1 Surry Release Category Definitions, Freauencv, and Population Dose Surry Release Frequency per year son-Rem EPRI Class Description Category (50 miles)1 0.OOE+00 0.OOE+00 1 No Containment Failure 2 1.54E-07 5.98E+02 3 1 No Containment Failure 3 O.OOE+00 8.23E+05 4 7 Early Containment Failure 4 1.98E-06 2.50E+04 5 7 Late Containment Failure 5 1.29E-07 8.23E+05 5 7 Late Containment Failure 6 1.1OE-07 2.50E+04 4 7 Late Containment Failure 7 0.OOE+00 8.23E+05 5 7 Late Containment Failure 8 0.OOE+00 2.89E+05 4 7 Late Containment Failure 9 2.37E-06 7.1OE+04 5 7 Late Containment Failure 10 1.48E-06 7.1OE+04 4 7 Late Containment Failure 11 7.04E-09 2.50E+04 5 7 Melthru 12 O.OOE+00 4.71 E+05 5 2 No Containment Isolation 13 1.67E-10 4.71E+05 4 2 No Containment Isolation 14 6.89E-07 0.OOE+00 5 1 Debris Cool In-Vessel 15 0.OOE+00 1.19E+04 4 2 Debris Cool In-Vessel 16 0.OOE+00 8.23E+05 5 2 Debris Cool In-Vessel 17 1.11E-07 6.81 E+06 5 8 Event V (attenuation) 18 1.11E-07 6.81E+06 4 8 Event V (no attenuation) 19 1.11E-07 5.07E+06 4 8 SGTR 20 2.67E-08 2.54E+06 6 8 SGTR (non-LERF)

CDF 7.28E-06 1. 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 the population 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 Surry one-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 model documentation.

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

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

-LAR Attachment 4 Page 10 of 34 Using the data in Table 4.2-1, the frequency and dose for the EPRI accident classes as they apply to Surry can be calculated.

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

(/yr) Dose (person-rem) 1 8.43E-07 5.98E+02 2 1.67E-10 4.71E+05 7 6.08E-06 7.11E+04 8 3.60E-07 5.96E+06 4.3 Impact of Extension on Detection of Component Failures that Lead to Leakage The ILRT can detect a number of component failures, such as liner breach, failure of certain bellows arrangements and failure of some sealing surfaces, which can lead to leakage. The proposed ILRT test interval extension may influence the conditional probability of detecting these types of failures.

To ensure that this effect is properly accounted for, the EPRI Class 3 containment failure classification, as defined in Table 4.1-1, is divided into two sub-classes, Class 3a and Class 3b, representing small and large leakage failures, respectively.

The probability of the EPRI Class 3a and 3b failures is determined consistent with the EPRI guidance.

For Class 3a, the probability is based on the maximum likelihood estimate of failure (arithmetic average) from the available data (i.e., 2 "small" failures in 217 tests leads to 2/217=0.0092).

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

= 0.0023).The EPRI methodology contains information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC regulatory guide 1.174. This information includes a discussion of conservatisms in the quantitative 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) involves conservatively multiplying the CDF by the failure probability for this class (3b) of accident.

This was done for simplicity and to maintain conservatism.

However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage.

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

-LAR Attachment 4 Page 11 of 34 The application of this additional guidance to the analysis for Surry would result in a reduction of the CDF applied to the Class 3a and Class 3b CDFs. However, the Surry risk assessment will conservatively forgo the application of this guidance and will apply the total CDF in the calculation of the Class 3a and 3b frequencies.

Consistent with the EPRI methodology, the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection.

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

4.4 Impact of Extension on Detection of Steel Liner Corrosion that Leads to Leakage An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is evaluated using the methodology from the Calvert Cliffs liner corrosion analysis.

The Calvert Cliffs analysis was performed 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 the ILRT, of detecting corrosion of the containment steel liner. This likelihood is then used to determine the resulting change in risk. Consistent with the Calvert Cliffs analysis, the following issues are addressed:

• Differences between the containment basemat and the containment cylinder and dome* The historical steel liner flaw likelihood due to concealed corrosion* The impact of aging* The corrosion leakage dependency on containment pressure* The likelihood that visual inspections will be effective at detecting a flaw Assumptions

• Consistent with the Calvert Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures.* The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the 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 have occurred in recent years (based on a data search covering approximately 9 years Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 12 of 34 documented in NRC Docket No. 50-277). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 0.375" by 1" in size was identified in the Beaver Valley 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9-year period are judged to be adequately represented by the two events in the 5.5-year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. (See Table 4.4-1, Step 1.)* Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is also limited to 5.5 years to reflect the years since September 1996 when 10 CFR 50.55a started requiring visual inspection to the time the Calvert Cliffs liner corrosion analysis was performed.

Additional success data was not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date (and have been performed since the time frame of the Calvert Cliffs analysis), and there is no evidence that additional corrosion issues were identified. (See Table 4.4-1, Step 1.)* Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed to double every five years. This is based solely on judgment and is included in this analysis to address the increased likelihood of corrosion as the steel liner ages. (See Table 4.4-1, Steps 2 and 3.) Sensitivity studies are included that address doubling this rate every ten years and every two years." In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated as 1.1% for the cylinder and dome and 0.11% (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure, and the selected values are consistent with a pressure that corresponds to the ILRT target pressure of 37 psig. For Surry, the containment failure probabilities are less than these values at 47 psig. Conservative probabilities of 1% for the cylinder and dome and 0.1% for the basemat are used in this analysis, and sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4.)* Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crack formation) in the basemat region is considered to be less likely than the containment cylinder and dome region. (See Table 4.4-1, Step 4.)* Consistent with the Calvert Cliffs analysis, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used.To date, all liner corrosion events have been detected through visual inspection. (See Table 4.4-1, Step 5.) Sensitivity studies are included that evaluate total detection failure likelihood of 5% and 15%, respectively.

• Consistent with the Calvert Cliffs analysis, non-detectable containment failures are assumed to result in early releases.

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

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

-LAR Attachment 4 Page 13 of 34 Table 4.4-1 Steel Liner Corrosion Base Case Step Description Containment Walls Containment Basemat 1 Historical Steel Liner Events: 2 Events: 0 (assume 0.5 failures)Flaw Likelihood 2/(70

• 5.5) = 5.2E-3 0.5/(70

• 5.5) = 1.3E-3 2 Age-Adjusted Steel Year Failure Rate Year Failure Rate Liner Flaw Likelihood 1 2.05E-03 1 5.13E-04 2 2.36E-03 2 5.89E-04 3 2.71 E-03 3 6.77E-04 4 3.11E-03 4 7.77E-04 5 3.57E-03 5 8.93E-04 6 4.1OE-03 6 1.03E-03 7 4.71E-03 7 1.18E-03 8 5.41 E-03 8 1.35E-03 9 6.22E-03 9 1.55E-03 10 7.14E-03 10 1.79E-03 11 8.21E-03 11 2.05E-03 12 9.43E-03 12 2.36E-03 13 1.08E-02 13 2.71E-03 14 1.24E-02 14 3.11E-03 15 1.43E-02 15 3.57E-03 3 Flaw Likelihood at 3, 1 to 3 years 0.71% 1 to 3 years 0.18%10, and 15 years 1to 10 4.14% 1 to 10 years 1.03%years Ito 15 9.66% 1 to 15 years 2.41%years 4 Likelihood of Breach Pressure 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 of Step 6 for the containment cylinder and dome and the containment basemat as summarized below for Surry.

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-LAR Attachment 4 Page 14 of 34 Total 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, and the result is added to the Class 3b frequency in the corrosion sensitivity studies. The non-LERF containment overpressure CDF is calculated by subtracting the Class 1, Class 3b, and Class 8 CDFs from the total CDF so that only Classes 2, 3a, and 7 are included in the CDF calculation.

5.0 RESULTS The application of the approach based on the EPRI guidance 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 1 and Surry Unit 2. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes.The analysis performed examined Surry-specific accident sequences in which the containment remains intact or the containment is impaired.

Specifically, the categorization of the severe accidents contributing to risk was considered in the following manner:* Core damage sequences in which the containment remains intact initially and in the long term. (EPRI TR-104285 Class 1 sequences.)

• Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components.

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

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

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-LAR Attachment 4 Page 15 of 34 Table 5.0-1 EPRI Accident Classes EPRI Accident Description Class 1 No Containment Failure 2 Large Isolation Failures (Failure to Close)3a Small Isolation Failures (liner breach)3b Large Isolation Failures (liner breach)4 Small Isolation Failures (Failure to seal -Type B)5 Small Isolation Failures (Failure to seal-Type C)6 Other Isolation Failures (e.g., dependent failures)7 Failures Induced by Phenomena (Early and Late)8 Bypass (Interfacing System LOCA and Steam Generator Tube Rupture)CDF Sum of all accident class frequencies (including very low and no release)The steps taken to perform this risk assessment evaluation are as follows: Step 1 Quantify the base-line risk in terms of frequency per reactor year for each of the eight accident classes presented in Table 5.0-1.Step 2 Develop plant-specific person-rem dose (population dose) per reactor year for each of the eight accident classes.Step 3 Evaluate risk impact of extending Type A test interval from three to 15 and ten to 15 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 Year As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena.

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

Two failure modes were considered for the Class 3 sequences.

These are Class 3a (small breach) and Class 3b (large breach).The frequencies for the severe accident classes defined in Table 5.0-1 were developed for Surry by first determining the frequencies for Classes 1, 2, 7 and 8 using the categorized sequences and the identified correlations shown in Table 4.2-2, determining the frequencies for Classes 3a and 3b, and then determining the remaining frequency for Class 1. Furthermore, adjustments were made to the Class 3b and hence Class 1 frequencies to account for the impact of undetected corrosion of the steel liner per the methodology described in Section 4.4.

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

-LAR Attachment 4 Page 16 of 34 Class 1 Sequences This group consists of all core damage accident progression bins for which the containment remains intact (modeled as Technical Specification Leakage).

The frequency per year is initially determined from the Level 2 Release Categories 1, 2, and 14 listed in Table 4.2-1, which was 8.43E-07/yr.

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

Class 2 Sequences This group consists of all core damage accident progression bins for which a failure to isolate the containment occurs. The frequency per year for these sequences is obtained from the Release Categories 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 leakage for these sequences can be either small (in excess of design allowable but <1OLa) or large (>10OLa).The respective frequencies per year are determined as follows: PROBclass_3a

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

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

Class 3a = 0.0092

• CDF= 0.0092

• 7.28E-06/yr

= 6.71 E-08/yr Class 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 is 1OOLa. These assignments are consistent with the guidance provided in EPRI TR-1 018243.Class 4 Sequences This group consists of all core damage accident progression bins for which containment isolation failure-to-seal of Type B test components occurs. Because these failures are detected by Type B tests which are unaffected by the Type A ILRT, this group is not evaluated any further in the analysis.

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-LAR Attachment 4 Page 17 of 34 Class 5 Sequences This group consists of all core damage accident progression bins for which a containment isolation failure-to-seal of Type C test components.

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

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

For this analysis, the frequency is determined from Release Categories 3 through 11 from the Surry Level 2 results in Table 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 bypass occurs. For this analysis, the frequency is determined from Release Categories 17 through 20 from 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 the public have been derived consistent with the definitions of accident classes defined in EPRI TR-1018243.

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

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-LAR Attachment 4 Page 18 of 34 Table 5.1-1 Accident Class Frequencies Accident Class Description Frequency______ _____(II R)1 No Containment Failure 7.59E-07 2 Large Containment Isolation Failures (Failure to close) 1.67E-10 3a Small Isolation Failures (Type A test) 6.71 E-08 3b Large Isolation Failures (Type A test) 1.68E-08 4 Small Isolation Failure (Type B test) N/A 5 Small Isolation Failure (Type C test) N/A 6 Containment Isolation Failures (personnel errors) N/A 7 Severe Accident Phenomena Induced Failure 6.08E-06 8 Containment Bypassed 3.60E-07 CDF All CET End States (including intact case) 7.28E-06 5.2 Step 2 -Develop Plant-Specific Person-Rem Dose (Population Dose) Per Reactor Year Plant-specific release analyses were performed to estimate the person-rem doses to the population within a 50-mile radius from the plant. The releases are based on information contained in the dose results for the Surry SPS SAMA analysis, the Surry LERF model documentation, and the Surry one-time ILRT extension.

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

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

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

The results of applying these releases to the EPRI containment failure classification 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 analyzed Class 5 = Not analyzed Class 6 = Not analyzed Class 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 in EPRI TR-1018243.

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

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-LAR Attachment 4 Page 19 of 34 In summary, the population dose estimates derived for use in the risk evaluation per the EPRI methodology containment failure classifications are provided in Table 5.2-1.Table 5.2-1 Accident Class Population Dose Accident Class Description Person-Rem 1 No Containment Failure 5.98E+02 2 Large Containment Isolation Failures (Failure to close) 4.71 E+05 3a Small Isolation Failures (Type A test) 5.98E+03 3b Large Isolation Failures (Type A test) 5.98E+04 4 Small Isolation Failure (Type B test) N/A 5 Small Isolation Failure (Type C test) N/A 6 Containment Isolation Failures (personnel errors) N/A 7 Severe Accident Phenomena Induced Failure 7.11E+04 8 Containment Bypassed 5.96E+06 The above dose estimates, when combined with the results presented in Table 5.1-1, yield the Surry baseline mean consequence measures for each accident class. These results are presented in Table 5.2-2.

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-LAR Attachment 4 Page 20 of 34 Table 5.2-2 Accident Class Frequency and Dose Risk for 3-per-10 Year ILRT Frequency Base Case (3 per 10 years)Without Corrosion With Corrosion EPRI Change Class Description Person-Rem Frequency Person- Frequency Person- in (1/YR) Rem/YR (I1YR) Rem/YR Person-Rem/YR No Containment 1 Fl C n5.98E+02 7.59E-07 4.54E-04 7.59E-07 4.54E-04 -3.51 E-08 Failure Large 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-06 breach)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/A to seal-Type C)Other Isolation Failures (e.g.,N/6 N/A N/A N/A N/A N/A dependent failures)Failures Induced 7 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+00 Bypass Sum of All Total Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 3.48E-06 Results Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 21 of 34 Table 5.2-3 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the 3 per 10 year ILRT frequency.

Table 5.2-3 Corrosion Impact on Class 3b Frequency for 3-per-10 Year ILRT Frequency Metric Result ILRT Frequency 3 per 10 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.00096%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 6.14E-06/yr Increase in LERF (0.00096%

• 6.14E-06/yr) 5.88E-1 1/yr Class 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 Years The 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 with the ten-year interval since the base case applies to a three-year interval (i.e., a simplified representation of a three-per-ten interval).

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

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

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

The risk contribution is changed based on the NEI guidance as described in Section 4.3 by a factor of 3.33 compared to the base case values. The results of the calculation for a 10-year interval are presented in Table 5.3-1.Table 5.3-1 Accident Class Frequency and Dose Risk for 1-per-10 Year ILRT Frequency 10-Year Interval (1 per 10 years)Without Corrosion With Corrosion EPRI Change Class Description Person-Rem Frequency Person- Frequency Person- in (11YR) Rem/YR (01YR) Rem/YR Person-Rem/YR No Containment F 5.98E+02 5.64E-07 3.37E-04 5.63E-07 3.37E-04 -2.1OE-07 Failure Large Isolation 2 Failures (Failure 4.71 E+05 1.67E-10 7.87E-05 1.67E-10 7.87E-05 to Close) I IIIII Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 22 of 34 10-Year Interval (1 per 10 years)Without Corrosion With Corrosion EPRI Change Class Description Person-Rem Frequency Person- Frequency Person- in (1/YR) Remn/YR (1/YR) Rem/YR Person-Rem/YR Small Isolation 3a Failures (liner 5.98E+03 2.23E-07 1.34E-03 2.23E-07 1.34E-03 breach)Large Isolation 3b Failures (liner 5.98E+04 5.58E-08 3.34E-03 5.62E-08 3.36E-03 2.1OE-05 breach)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/A to seal-Type C)Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/A dependent failures)Failures Induced 7 by Phenomena 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+00 Bypass Sum of All Total Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 2.08E-05 Results Table 5.3-2 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the one-per-ten year ILRT frequency.

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-LAR Attachment 4 Page 23 of 34 Table 5.3-2 Corrosion Impact on Class 3b Frequency for 1-per-10 Year ILRT Frequency Metric Result ILRT Frequency 3 per 10 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.00556%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 6.30E-06/yr Increase in LERF (0.00556%

• 6.30E-06/yr) 3.51 E-1 0/yr Class 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 Interval The risk contribution for a 15-year interval is calculated in a manner similar to the ten-year interval.

The difference is in the increase in probability of leakage in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the three-year interval value, as described in Section 4.3. The results for this calculation are presented in Table 5.3-3.Table 5.3-3 Accident Class Frequency and Dose Risk for 1-per-15 Year ILRT Frequency 15-Year Interval (1 per 15 years)Without Corrosion With Corrosion EPRI Person- Change Class Description Rem Frequency Person- Frequency Person- in (IYR) Rem/YR (1/YR) Rem/YR Person-Rem/YR No Containment 1 Fiu C a e 5.98E+02 4.24E-07 2.53E-04 4.23E-07 2.53E-04 -4.98E-07 Failure Large 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 3.35E-07 2.01 E-03 3.35E-07 2.01 E-03 breach)Large Isolation 3b Failures (liner 5.98E+04 8.39E-08 5.01 E-03 8.47E-08 5.06E-03 4.98E-05 breach)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/A to seal-Type C)

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

-LAR Attachment 4 Page 24 of 34 15-Year Interval (1 per 15 years)Without Corrosion With Corrosion EPRI Person- Change Class Description Rem Frequency Person- Frequency Person- in (1/YR) Rem/YR (1/YR) Rem/YR Person-Rem/YR Other Isolation 6 Failures (e.g., N/A N/A N/A N/A N/A dependent failures)Failures Induced 7 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+00 Bypass Sum of All Total Accident Class 7.28E-06 2.58E+00 7.28E-06 2.58E+00 4.93E-05 Results Table 5.3-4 shows how the new Class 3b frequency was calculated to account for a corrosion-induced containment leak for the 1-per-15 year ILRT frequency.

Table 5.3-4 Corrosion Impact on Class 3b Frequency for 1-per-15 Year ILRT Frequency Metric Factor ILRT Frequency 1 per 15 Years Likelihood of Corrosion-Induced Leak (Section 4.4) 0.01298%Non-LERF Containment Overpressure CDF (Classes 2, 3a, and 7) 6.41 E-06/yr Increase in LERF (0.01298%*

6.41 E-06/yr) 8.32E-1 0/yr Class 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 core damage event that normally would result in only a small radioactive release from an intact containment could in fact result in a larger release due to the increase in probability of failure to detect a pre-existing leak. With strict adherence to the EPRI guidance, 100% of the Class 3b contribution would be considered LERF.Regulatory Guide 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of core damage frequency (CDF) below 1.OE-06/yr and increases in LERF below Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 25 of 34 1.OE-07/yr, and small changes in LERF as below 1.OE-06/yr.

Because the ILRT does not impact CDF, the relevant metric is LERF.For 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 interval extension (consistent with the EPRI guidance methodology).

Based on the original three-per-ten year test interval from Table 5.2-2, the Class 3b frequency is 1.68E-08/yr.

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

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

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

As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology), the estimated change in LERF is below the threshold criteria for a very small change when comparing the 15-year results to both the current ten-year requirement and the original three-year requirement.

If the effects due to liner corrosion are included in the 15-year interval results, the Class 3b frequency becomes 8.47E-08/yr as shown in Table 5.3-3. Conservatively neglecting the impact of steel liner corrosion on the Class 3b frequency for the three-year and ten-year intervals, the change 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-year interval.

This is an increase in LERF of 8.32E-10/yr from the 15-year interval results without corrosion.

These results indicate that the impact due to steel liner corrosion is very small, and the estimated change in LERF is below the threshold criteria for a very small change when comparing 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 the decision-making process is the change in the CCFP. The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can be calculated from the results of this analysis.

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

The NRC has previously accepted similar calculations as the basis for showing that the proposed change is consistent with the defense-in-depth philosophy.

CCFP = [1 -(Class 1 frequency

+ Class 3a frequency)

/ CDF]

• 100%CCFP 3 = 88.65%CCFP 1 o = 89.19%CCFP 1 5 = 89.57%ACCFP 3.To.15 = CCFP 1 5-CCFP 3= 0.92%

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-LAR Attachment 4 Page 26 of 34 ACCFP 1 0-To-1 5 = CCFP 1 5 -CCFP 1 0 = 0.38%The CCFP is also calculated for the 15-year interval to evaluate the impact of the steel liner corrosion impact on the ILRT extension.

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

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

= CCFP15+Corrosion

-CCFP 3 = 0.93%ACCFP1O0-o-15+Corrosion

= CCFP15+Corrosion

-CCFP 1 O = 0.40%The change in CCFP of approximately 0.93% by extending the test interval to 15 years from the original three-per-ten year requirement is judged to be insignificant.

5.6 Summary of Results The results from this ILRT extension risk assessment for Surry are summarized in Table 5.6-1.

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-LAR Attachment 4 Page 27 of 34 Table 5.6-1 Summa of Results for ILRT Frequency Extensions Base Case (3 per 10 years) I per 10 years 1 per 15 years Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion Person- Person- Delta Person- Person- Delta Person- Person- Delta EPRI 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 per yerya eryear year year year year year year year year 1 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+00 3a 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+00 3b 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-05 7 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+00 8 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+00 Total 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-05 Delta 3.15E-03 3.18E-03 5.42E-03 5.47E-03 Dose 1 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%Delta CCFp 2 N/A N/A 0.54% 0.54% 0.92% 0.93%Class 1.68E-08 5.62E-08 8.47E-08 3b 1.68E-08 5.58E-08 8.39E-08 LERF 3 (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 years 3 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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-LAR Attachment 4 Page 28 of 34 5.7 External Events Contribution Since the risk acceptance guidelines in RG 1.174 are intended for comparison with a full-scope assessment of risk including internal and external events, an analysis of the potential impact from external events is presented here.The method chosen to account for external events contributions is similar to the approach used to calculate the change in LERF for the internal events using the guidance in EPRI TR-1018243.

The Class 3b frequency for the internal events analysis was calculated by multiplying the total CDF by the probability of a Class 3b release. The same approach will be used for external events using the CDF for internal fires and seismic events. Other external events such as high winds, external floods, 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 internal fires and seismic events. The internal fire and seismic results from the original IPEEE were updated in 2006 and are shown in Table 5.7-1 below.Table 5.7-1 External Events Base CDF and LERF External Event Initiator Group CDF LERF Seismic 1.OOE-05 1.20E-07 Internal Fire 1.80E-05 1.00E-07 Total 2.80E-05 2.20E-07 Table 5.7-2 shows the calculation of the base Class 3b frequency for internal and external events, the increased Class 3b frequency as a result of the ILRT interval extension, and the total change in LERF.Table 5.7-2 Total LERF Increase for 15-year ILRT Interval Including Internal and External Events Class 3b Frequency

(/yr)Initiating Event Class 3b 3 per 10 1 per 10 1 per 15 LERF InitanGroupE CDF (Iyr) Probability year year yer 15 Increase (/yr)ILRT ILRT year ILRT Internal Events 7.28E-06 0.0023 1.68E-08 5.59E-08 8.39E-08 6.71 E-08 External Events 2.80E-05 0.0023 6.45E-08 2.15E-07 3.23E-07 2.58E-07 Total 3.53E-05 -- 8.13E-08 2.71 E-07 4.06E-07 3.25E-07 As with the internal events analysis, 100% of the frequency of Class 3b sequences can be used as a very conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI guidance methodology).

Based on the total three-per-ten year test interval from Table 5.7-2, the Class 3b frequency is 8.13E-08/yr.

Based on a 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 to increasing the ILRT test interval from three to 15 years is 3.25E-07/yr and from ten to 15 years is 1.35E-07/yr.

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

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-LAR Attachment 4 Page 29 of 34 The IPEEE only evaluated the external events risk associated with Surry Unit 1. However, it also determined that the differences between Unit 1 and Unit 2 would have negligible impact on the PRA 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 are representative of both Unit 1 and Unit 2.5.8 Containment Overpressure Impact on CDF The Surry design basis calculations credit containment overpressure to satisfy the net positive suction head (NPSH) requirements for recirculation spray (RS) and low-head safety injection (LHSI) in recirculation mode during loss of coolant accidents (LOCA). However, these calculations do not evaluate the effect of an increased containment leak rate on the NPSH of the pumps. In addition, only large LOCAs are considered in the design basis calculations since this is the most limiting case for the analysis.

Several cases were evaluated using MAAP in order to determine if NPSH would be lost for the RS pumps and LHSI pumps during small, medium, and large LOCAs with a 100La containment leak rate. The MAAP analysis is discussed in Enclosure A. The results of the MAAP analysis demonstrated that NPSH would not be lost for any RS or LHSI pumps during small 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 lost because the ORS flow is assisted by a flow enhancement from the CS system. As a result, the CDF 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 of the ILRT extension to 15 years.3. In order for core damage to occur, a failure of sump recirculation caused by failure of the LHSI, ORS, or CS systems is required.

The probability of any of these systems failing is 6.44E-04.

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

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-LAR Attachment 4 Page 30 of 34 Table 5.8-1 combines the above information to show the calculation of the CDF contribution of the 15-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 is calculated by multiplying the three-year interval CDF by 5.Table 5.8-1 Containment Overpressure Impact on CDF LHSI, ORS, 3-Year ILRT 15-Year Initiating Frequency Class 3b or CS Interval ILRT CDF Interval Increase Event (lyr) Probability Systems CDF CtF Iyre Fail (lyr) (Iyr) _ __ _Large 4.5E-06 2.3E-03 6.44E-04 6.67E-12 3.33E-1 1 2.67E-1 1 LOCA The three-year ILRT interval CDF for this scenario is 6.67E-12/yr, and multiplying the CDF by a factor 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 within the acceptance guidelines in RG 1.174 for a "very small" change in CDF. If the LERF fraction associated with this increase in core damage frequency is assumed to be 1.0, the ALERF would also increase by 2.67E-1 1/yr, which is taken to be a negligible change in LERF that would not impact the result of the risk impact assessment.

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

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-LAR Attachment 4 Page 31 of 34 6.0 SENSITIVITIES 6.1 Sensitivity to Corrosion Impact Assumptions The results in Tables 5.2-2, 5.3-1, and 5.3-3 show that including corrosion effects calculated using the assumptions described in Section 4.4 does not significantly affect the results of the ILRT extension risk assessment.

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

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

The total detection failure likelihood was adjusted from 10% to 15% and 5%. The results are presented in Table 6.1-1. In every case the impact from including the corrosion effects is minimal. Even the upper bound estimates with conservative assumptions for all of the key parameters yield increases in LERF due to corrosion of only 4.87E-08 /yr. The results indicate that even with conservative assumptions, the conclusions from the base analysis would not change.Table 6.1-1 Steel Liner Corrosion Sensitivity Cases Increase in Class 3b Containment Visual Inspection Frequency (LERF) for ILRT Age Breach & Non-Visual Likelihood Extension from 3-per-10 to (Step 2) (Step 4) Flaws Flaw is LERF 1-per-15 Year (/yr)(Step 5) Total Increase Due Increase to Corrosion Base Case Base Case Base Case Base Case 8.32E-10 6.79E-08 Double/5 Years 1.1/0.11 10% 100%Double/2 Years Base Base Base 7.68E-09 7.48E-08 Double/lO Years Base Base Base 4.50E-10 6.75E-08 Base Base Point 1Ox Lower Base Base 1.84E-10 6.73E-08 Base Base Point 10x Higher Base Base 3.77E-09 7.09E-08 Base Base 5% Base 4.99E-10 6.76E-08 Base Base 15% Base 1.17E-09 6.83E-08 Lower Bound Double/10 Years Base Point 10x Lower 5% 10% 5.97E-12 6.71 E-08 Upper Bound Double/2 Years Base Point 10x Higher 15% 100% 4.87E-08 1.16E-07 Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 32 of 34

7.0 CONCLUSION

S Based on the results from Section 5 and the sensitivity calculations presented in Section 6, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test 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 the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF 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 is LERF. The increase in internal events LERF, which includes corrosion, resulting from a change in the Type A ILRT test frequency from three-per-ten years to one-per-15 years is conservatively estimated as 6.79E-08/yr (see Table 5.6-1) using the EPRI guidance as written. As such, the estimated change in internal events LERF is determined to be "very small" using the acceptance guidelines of RG 1.174. The increase in LERF including both internal and external events is estimated as 3.25E-07/yr (see Table 5.7-2), which is considered 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-06 per reactor year to 1.OE-07 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.OE-05 per reactor year. The total base LERF for internal and external events is approximately 3.7E-07/yr based on Table 5.7-1 and Section 4.2. Given that the increase in LERF for the 15-year ILRT interval is 3.25E-07/yr for internal and external events from Table 5.7-2, the total LERF for the 15-year interval 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 to one-per-15 years, measured as an increase to the total integrated dose risk for all accident sequences, is 5.47E-03 person-rem/yr or 0.21% of the total population dose using the EPRI guidance with the base case corrosion case from Table 5.6-1. EPRI TR-1018243 states that a very small population dose is defined as an increase of < 1.0 person-rem per year or< 1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals.

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

• The increase in the conditional containment failure frequency from the three-per-ten year frequency to one-per-15 year frequency is 0.93% using the base case corrosion case in Table 5.6-1. EPRI TR-1018243 states that increases in CCFP of < 1.5 percentage points are very small. Therefore, this increase is judged to be very small.Therefore, increasing the ILRT interval to 15 years is considered to be insignificant since it represents a small change to the 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 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 4 Page 33 of 34 cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

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

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

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

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-LAR Attachment 4 Page 34 of 34 ENCLOSURE A Modular Accident Analysis Program (MAAP) ANALYSES MAAP analyses were performed for different break size LOCAs to demonstrate that assuming an increased leakage from containment exceeding design leakage by a factor of 100, enough NPSH would still be available to the Recirculation Spray pumps to successfully perform containment heat removal function.The MAAP cases analyzed were l in-SLOCA, 2in-SLOCA, 4in-MLOCA, 6in-MLOCA, and 31in-LLOCA, respectively for 1", 2", 4", 6" and 31" break LOCAs. LHSI pumps in the injection mode and accumulators were turned off in all cases except 31in-LLOCA, since they are only required for mitigation of Large Break LOCAs. It is modeled that both CS pumps and all four RS pumps were available to start and run on demand. The IRS pumps will start on high containment pressure signal concurrent with RWST level below 60%, and ORS pumps would start two minutes later. It was assumed that all RS pumps would fail immediately after loss of NPSH (no pump cavitation was allowed).

Sump recirculation was established automatically when RWST level dropped below 13.5%.It should be noted that an inaccuracy was indentified in the Surry MAAP parameter file about the location of the RS pumps. Parameters ZSPBCS and ZSPCCS, that are distances of IRS and ORS pumps from the bottom of containment sump, were set to negative values that means MAAP interpreted their location as above tihe bottom of the sump. This was causing a loss of NPSH on the RS pumps even without the increased leakage from the containment.

The RS pumps are vertical pumps, and stretch as long as 16 ft from the motor to the suction. The proper elevation for calculation of parameters ZSPBCS and ZSPCCS would be the suction of the pump (i.e., the centerline of the impeller).

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

-29' 4-5/8" in drawing 11448-FE-57F SH-001 Rev 4, the distance between the bottom of the containment sump and 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 any loss of NPSH. The case 31in-LLOCA reported loss of NPSH to the IRS pumps. The reason the ORS pumps had enough NPSH in this case was because they were modeled with NPSH enhancement flow from the CS system, while IRS pumps' NPSH enhancement flow was supplied from their own recirculation line.In reality, the elevation of the impeller centerline as used in the safety analyses is much lower. However, no reference could be found to support the lower elevation.

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

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

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

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

-LAR Attachment 5 Page 1 of 38 PRA TECHNICAL ADEQUACY The PRA model used to analyze the risk of the extending the Type A test interval to 15 year for Surry 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 events at-power risk profile. The PRA model is maintained and updated under a PRA configuration control program in accordance with Dominion procedures.

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

Summary of the Surry PRA History: The Level 1 and Level 2 Surry PRA analyses were originally developed and submitted to the Nuclear 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 of the 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 Rule program* 2001 -Data update; update to address more Maintenance Rule issues, address peer review 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 main control room HVAC and loss of instrument air to the model; added logic from the IPEEE fire 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 the model was converted to CAFTA* 2009 -Updated Interfacing Systems LOCA (ISLOCA) initiator frequency, added EDG and AAC diesel fails to load (FTL) basic events, and added rupture failure of the SW expansion joints for the CCW heat exchangers as flood scenarios (current model of record)The Surry PRA model has benefited from the following comprehensive technical PRA peer reviews. In addition, the self-identified model issues tracked in the PRA configuration control program were evaluated and do not have any impact on the results of the application.

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

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

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

The team used a set of checklists as a framework within which to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA products 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 Early Release Frequency (LERF).The F&Os from the PRA peer review were prioritized into four categories (A through D) based upon 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 C and D are considered minor. Subsequent to the peer review, the model has been updated to address all Category A, B, and D F&Os. There are only 1 Category B and 3 Category C F&Os that need to be addressed and they are listed in Table 1: Table 1 Category 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 LERF caused by a leak in the RCP associated with this scenario is thermal barrier heat exchanger expected to be negligible based on and a failure to isolate the CCW the low frequency of the initiating lines that provide cooling water to event and the redundancy in the heat exchanger is applicable isolating the leak. Therefore, this to Surry model and address it gap has no impact on the results appropriately.

for this application.

DE-1 Develop a system to initiating C There is no impact on CDF or event dependency matrix to LERF as this is a documentation better show the dependencies enhancement, therefore this gap modeled 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 or matrices for front-line to front-line, LERF as this is a documentation for support to front-line, and enhancement, therefore this gap initiator 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 or mission 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 gap I_ I _ Ihas no impact on this application.

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

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

-LAR Attachment 5 Page 3 of 38 2010 Surry PRA Focused Peer Review The Surry PRA model underwent a focused peer review in February 2010 using the PRA Peer Review Certification process performed by the Pressurized-Water Reactor Owners Group (PWROG). To determine whether a full scope or focused peer review was necessary, the changes to each of the model elements were reviewed to assess whether the changes involved either 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 peer review was performed on the elements shown in Table 2: Table 2 Peer Reviewed Elements Element High Level Requirement IE -Initiating Events Initiating Events Review support system initiator modeling meets SRs IE- C6, C7, C8, C9, and C12.AS -Accident Accident Sequence Review upgraded event trees for SBO, RCP Sequence 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 for IF.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.

The review process included: Review of the PRA model against the technical elements and associated supporting requirements (SRs) -Focus is on meeting capability category II At the SR level, the review team's judgment was used to assess whether the PRA meets one 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 utility The gaps identified during the 2010 Focused Peer Review that remain to be addressed are listed in Table 3:

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

-LAR Attachment 5 Page 4 of 38 Table 3 -Remaining Gaps that Need to be Addressed Importance to F&O j Element F&O Details Possible Resolution Basis of Significance ImApplication 1-5 IFSO-Al IFSO-A5 IFSO-B2 IFSN-A15 Surry PRA Notebook IF.3 documents the flood sources but does not provide sufficient information in the following areas: 1. The flood source walkdown is documented in Surry PRA Notebook IF.1, but the walkdown sheets do not contain all requested information.

For example, the columns for recording the spatial relationship between flood sources and PRA equipment are not typically completed.

2. IF.3 Tables 5.2-2 through 5.2-10 do not contain all expected information on flood sources. For example, the system pressure and temperature is not included to allow determination of which sources have the potential for pipe whip. In addition, it is not clear whether capacities listed for tanks are related to the tank volume or system volume.3. Spray/leakage impacts on equipment in the area are not clearly considered for screened sources.4. Piping connected to tanks such as the chilled water surge tanks were screened based on the capacity of the tank itself. There appears to have been no consideration of the capacity of attached makeup sources which could exceed the critical capacity.1. Clearly document in the flood source walkdown notes the spatial relationship between sources and PRA equipment to allow determination of the potential for various flood mechanisms (e.g. spray, jet impingement, pipe whip, etc.) during scenario development and initiating event frequency calculations.

2. Provide all information needed to support source characterization as noted in SR IFSO-A5 in the source tables in notebook IF.3.3. For each source, clearly identify the type of breach that could occur (e.g., leak, rupture, spray) and the basis for screening each leakage type.4. For tanks with automatic makeup supplies, consider the capacity of the makeup piping in the screening process.Specific information needed to support technical review of the flood source analysis is not clearly documented in the Surry PRA flooding notebooks.

This finding is primarily associated with enhancing documentation.

While it is possible that some new flood scenarios may be -identified, it is unlikely that they will have significant impact on CDF and LERF. As a result, this gap has no impact on the acceptability of the application results.

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

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

__~~ ~ ~ ~~~~~~ _ _I__ _ _ _ _ _ _ _ _ ai fSgiiac Application 1-6-I FEV-A5 There appear-to be inconsistencies in the application of generic failure rates to piping size ranges and some misapplication of information from a previous study for Kewaunee in calculating the flood initiating event frequencies for Surry. For example: 1. The SHP table of the "SPS IF.2 Unit-1 Main Steam Valve House Upper Elevation Piping.xls" spreadsheet uses failure rates of 1.87E-05 for piping of >2" to 6" and 3.47E-05 for piping > 6".However, Reference 6.4.9 of notebook IF.2 indicates that these values are events/year based on the piping lengths for Kewaunee, not failure rates in units of events per Reactor Operating Year-Linear Foot as used in the spreadsheet.

In addition, it was noted that it appears that the 1.87E-05/year value in Reference 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 rate applied to 6" fire protection piping is the rate associated with the >6" to 24" size range. In the SPS IF.2 Mechanical Equipment Room 2.xls the failure rate associated with the >4" to 6" range is used for 6" fire protection piping.3. Piping under 2" has been excluded from the spray frequency calculation.

However, Footnote 4 for the table in Section 5 of SPS IF.2 (carried over from EPRI 1013141) notes that for CCW and CST piping, the noted failure rates should be applied to piping under 2". In addition, where EPRI 1013141 does not provide failure rates, other sources should be considered.

1. Ensure that the correct steam line break failure rates from KPS PRA Notebook IF.4, Attachment 3 are used for calculating flood frequencies for Surry.2. Ensure that a consistent application of the piping size ranges used in presenting the pipe failure rates in IF.2 Section 5.0 is maintained in the spreadsheets associated with Surry PRA Notebook IF.2.3. Include piping under 2" diameter in the analysis for spray and minor flood initiating event frequencies or provide a basis for its exclusion.

These issues could result in flood initiating event frequencies that are conservative in some cases and non-conservative in others.The overall impact on the flooding contribution to CDF/LERF is expected to be small, but the issues need to be corrected to ensure the technical adequacy of the PRA.The overall impact on flooding contribution to CDF and LERF is expected to be small since flooding contributions for the main steam valve house and the cable spreading room are very low. With little change in CDF and LERF, this gap has no impact on the acceptability of the application results. A sensitivity study determined that including' the 2" piping in the spray and minor flood frequencies results in less than 10% increase in CDF (ref. PRACC 11074).A sensitivity study increasing the CDF and LERF values by 10% did not change the acceptability of the ILRT extension results. As a result, this gap has no impact on the acceptability of the application results.

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

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

__1-10 AS-B1 QU-A1 IFQU-A8 IFQU-A9 The Surry PRA model is constructed as a linked fault tree using the CAFTA software.

Surry PRA Notebook QU.1 documents the integration process followed for the various model elements.In general, the integration of the model appears to account for system dependencies.

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

1. The method of linking the SSIE models into the 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 be addressed 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 one of the sources of RCP Seal Cooling (e.g.,%FLOOD-AB-SPRAY-U1CCP2AB) are not being appropriately combined with other random failures which could result in loss of all seal cooling.3. Operator action to isolate a condenser waterbox during maintenance is credited following failure of the isolation valve (e.g., see BE 1CWMOV-FOCW106A combined with REC-FLD-TB-CN-WB in cutsets 379 and 6400 of the SPS MOD A U1-CDF-Avg Maintenance.CUT file). Failure of the isolation valve to close or spurious opening of the valve should be equivalent to failure of the operator action. It appears that the intent was to allow operator recovery of level switch failures which would normally close the valve automatically to terminate flooding.4. The turbine driven AFW pump loqic used 1. Consider linking the SSIE logic directly under the top of the affected support system logic in the mitigation fault tree. This will ensure that the system gate is failed by the same logic that is considered for the initiating event.2. Review all system logic used in the TB and AB flooding event trees to ensure that the flooding initiating events are appropriately combined with random system failures and that logic is not conditioned to exclude flooding events without justification.

3. Review linking of operator recovery actions to ensure that failure of the equipment needed to support success of the recovery is combined under an OR gate with the HEP.4. Note this as a source of modeling uncertainty to ensure it is evaluated for impact on applications where SBO may be an important contributor.

It appears that the integration of the linked fault tree model does not correctly capture some impacts.It is unclear to what extent this is true. The impact on total CDF appears to be small based on provided sensitivity results.However, since the extent of condition is not known, this is designated as a finding.1. No impact to CDF or LERF is expected from changing the method used to link the SSIE models into the integrated model. Therefore, this gap has no impact on this application.

2. A sensitivity study determined that the base CDF would change by less than 1% due to this model correction (Ref.PRACC 11222).Therefore, this gap has no impact on the acceptability of the application results.3. The estimated impact of this F&O is estimated to be an increase in CDF below 5E-8/yr (Ref.PRACC 11511). Given the increase in CDF is approximately 1%, this gap has no impact on the acceptability of the application results.4. The modeling of the TDAFW pump failure to run with a mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> instead of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is conservative.

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

-LAR Attachment 5 Page 7 of 38 F&O Element F&O Details Possible Resolution Basis of Significance Importance to Application 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 time conservative since the turbine driven pump is unscreened flooding events, basic event has a high only 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 a isolated prior to damage to new basic event with a 5. IF.5 details the effects of flood initiating events, additional equipment.

mission time for the Indirect effects due to submergence, spray, etc. sequence would be seem to be captured.

However, direct effects for developed.

Since the many initiators associated with service water importance of the TDAFW expansion joint failures are not captured.

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

The fact that CCW HX cooling would not added. This F&O be 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 CDF are not modeled as failing the associated HX. increase is below 1 E-8/yr (Ref. PRACC 11513).Therefore, this gap has no impact on the acceptability of the application 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 of QU.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, but and 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 change HEPs during the quantification process. importance.

has no impact on CDF or LERF, and therefore there is no impact on the acceptability of the I_ application results.

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

-LAR Attachment 5 Page 8 of 38 F&O Element F&O Details Possible Resolution Basis of Significance Importance to Application 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 a the 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 on of 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 for certain systems or initiating events, etc.)." No such discussion of model limitations was found in Surry PRA Notebook QU.4. Potential limitations in the quantification process that could impact applications could include such things as: 1. The replacement of independent HEPs by the combination dependent events which may affect the importance measures for the HEPS and evaluation of scenarios in which the failure of one of the replaced events is guaranteed, 2. Assumptions used in the baseline model regarding the probability of equipment being in the standby state which may not be appropriate for all applications, and 3. Limitations of the SPAR-H method of analyzing 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 be included in Surry SSIE models. Surry SY.2 exclusion, passive failures that impacted since passive Notebook Table 1 states that passive failure of may be important in failure frequencies are piping is assumed to have a negligible probability the SSIE model. very low. As a result, the and is not included in the models. Yet as impact of this F&O on the described in EPRI 1016741, passive failures that ILRT extension interval may be excluded from the post-initiator model results is negligible.

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

-LAR Attachment 5 Paae 9 of 38 1 1 Importance to F&O Element F&O Details Possible Resolution Basis of Significance ImApplication 2-3 IE-C1O A detailed review of SSIE cutsets identified some problems: 1. The cutsets do not include all possible combinations, for example: a. Train A CCW pump fails-to-run and Train B CCW pump fails-to-start is in the SSIE cutsets, but other failure events that could lead to Train B CCW pump fails-to-start such as AC failure and actuation signal failure are not included;b. There is an inconsistency in the modeling of the above combination when compared to the mitigating system fault tree. In the mitigating system fault tree, failure to start of the Pump B is conditioned by its standby failure (see gate 1-CC-P-1 B-FTS). In the SSIE fault tree, the standby status of Pump B is not considered (see gate U1-CC-INIT-AB);

c. Relief valve failure does not appear in the cutsets 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) that caused the errors for Loss of CCW initiating event; review other SSIE models to see whether similar problems exist; and correct the problems to make sure the cutsets are correctly representing the plant configuration.

A review of SSIE cutsets found that they might not be adequate.1. (a) Fault tree reviews indicate that these types of basic events are modeled but are truncated out of the final results.(b) The impact on CDF and LERF is expected to be insignificant.

Including the probability of the CCW pumps in standby with the initiator fault tree will result in a slight reduction in CDF.(c) Adding spurious opening of the CCW relief valves is not expected to result in an increase in CDF given the relatively low probability of RVs spuriously opening.2. A sensitivity study with the standby basic event probabilities set to 1 demonstrated that the ACDF was 2E-9.Therefore, this gap has no impact on the acceptability of the application results.

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

-LAR Attachment 5 P~nA 10 nf 3R Importance to F&O Element F&O Details Possible Resolution Basis of Significance ImApplication 3-3 IE-C9 The Surry IE analysis uses the "multiplier" method as stated in SPS IE.3, section 2.2, and references EPRI TR-1013490 to describe the approach used for converting the operating train failure rates into an annual frequency.

A later EPRI report, EPRI TR-1 016741, provides reasons why this method is not the consensus method in the industry.Change to a more accepted methodology that can avoid the disadvantages of the multiplier method, or provide detailed basis of why the industry identified problems are mitigated in the Surry PRA.EPRI TR-1 016741 offers a critical examination of modeling methods, such as the explicit event, point estimate fault tree, and multiplier methods.The multiplier method has several problems, e.g.1) violates the rare-event approximation because of the presence of a large (typically, 365-day) multiplier in the model;2) A very large disadvantage of the multiplier method is the impact on importance measure calculations and the generation of potentially undefined or erroneous importance measures (specifically, Birnbaum and Risk Achievement Worth).Using the multiplier method primarily affects the calculation of importance measures.Changing to a more accepted methodology would not impact the total CDF or LERF used for this analysis.

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

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

-LAR Attachment 5 Page 11 of 38 Importance to F&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 generic values is performed in Surry PRA Notebook Part developed with Fault Trees to 19 Fault Trees sources and similar plants III, Volume IE.3, Revision 1, Table 2-4 by generic and/or other plant data developed for is expected to render comparing 7 modeled Initiating Events with 5 to ensure reasonableness of Initiating Events were similar results to the lEs other unit results and to NUREG/CR-5750.

The results and to identify and compared to other compared.

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

plants. minimal impact on CDF or are not compared.

Other Initiating Events are LERF, therefore this gap also not compared.

has no impact on the acceptability of the results for 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 on modeled appropriately based on a review of the the event trees, initiator fault not consistently CDF or LERF as this is a fault 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 on not always a specific reference in these accident sequences.

this application.

notebooks to those procedures used to address In addition, IE-C8 the events or to identify the need for additional identified examples operator actions. where initiator trees could be missing potential operator actions.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 in documented." There is no documentation to operations and training that the interpretation which all of the HEPs and show that the interpretation of the procedures is personnel to ensure consistent of the procedures has dependent HEPs were consistent with plant operational and training interpretation of the been reviewed with increased by a factor of practices.

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

-LAR Attachment 5 Page 12 of 38 Importance to F&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 to ensure that interpretation of the procedures is consistent with plant observations and training procedures.

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 in various experience levels. The timing results analyses, or simulation from Surry PRA model, the which all of the HEPs and from the survey are used in the HRA for the similar plants (e.g. plant of time available to dependent HEPs were HEPs. Table 6.1 of HR.2 states "the response similar design and operation) complete the actions increased by a factor of times for operator actions may be estimated by to meet CC I1. were not based on 10. The results of the procedure talk through or operator surveys. applicable generic sensitivity study indicate Therefore, this is retained as a source of studies (e.g. that this F&O will not uncertainty." For the SPAR-H HEPs, time thermal/hydraulic impact the acceptability of available 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 were events. developed using the results of a 2002 survey and not on thermal/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 in of previous HEP values with current HEP values This could be performed using other to check for which all of the HEPs and is found in the QU.2 notebook supporting files but the HRA Calculator to reasonableness has dependent HEPs were no relative comparisons are made. compare to results using other not been performed.

increased by a factor of methods. 10. The results of the sensitivity study indicate that this F&O will not impact the acceptability of the application results.

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

-LAR Attachment 5 Page 13 of 38 F&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 in a table top review of the procedures as well as actions (for significant HEPs) the required time to which all of the HEPs and input from other HEPs of similar actions and on action time measurements complete actions on a dependent HEPs were events. in either walkthroughs or table top review of the increased by a factor of talkthroughs of the procedures procedures and input 10. The results of the or simulator observations.

from other sensitivity study indicate procedures.

that this F&O will not impact the acceptability of the application results.3-16 HR-I1 Several documentation issues were identified:

Revise documentation to be Documentation to 1. There is no impact on HR-12 1. Table 4 of HR.4 contains an error factor for complete and make identify, characterize, CDF or LERF as this is a each 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 on for deriving the error factor is contained in considered in the this application.

Attachment 3, HEP Replacements worksheet, in PRA, including the HR.4. inputs, methods, and 2. There is no impact on 2. Three HEPs (HEP-C-FWCOND, results should be CDF or LERF as this is a HEP-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 on late in the sequence.

This also results in the this application.

recalculation of four dependencies which contain one or more of the HEPs. The recalculation of 3. A bounding sensitivity these HEPs and the associated dependencies is study was performed in not discussed or referenced in HR.2. which all of the HEPs and 3. The SPAR-H HEPs recently added to the dependent HEPs were Surry PRA model are documented in HR.2. Four increased by a factor of HEPs noted in Table A-2 (New HEPs Added) that 10. The results of the were evaluated, do not appear in the Fault Tree. sensitivity study indicate One new HEP listed (HEP-CPORTGENRMP) that this F&O will not was not analyzed and is also not in the FT. New impact the acceptability of HEPs added for the recent model update were the application results.not necessarily covered by the 2002 survey results. System Analysis notebooks and review Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Page 14 of 38 Importance to F&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 were performed.

For the SPAR-H HEPs recently added to the SPS PRA model, the time available to complete the actions were not based on applicable 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 in recommended where more detailed analysis of industry evaluations that could consensus model and which all of the HEPs and diagnosis errors is needed" and references potentially be mitigated by seldom used in plant dependent HEPs were NUREG/CR-1 842 for more information.

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

10. The results of the somewhat 'generic' answer that is sufficient for option is to use a more documents show it sensitivity study indicate some of the broad regulatory applications for accepted method. should not be used to that this F&O will not which SPAR-H is intended, but perhaps is obtain detailed results. impact the acceptability of insufficient for detailed plant-specific evaluations Additionally, it cannot the application results.(a limitation)" and also references NUREG-1792.

be assumed that This NUREG states "detailed assessments of the conservative results significant HFE contributors should be are obtained by performed." SPAR-H as the evaluation of PSFs better than nominal can produce non-conservative values.

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

-LAR Attachment 5 Paee 15 of 38 I I Importance to F&O Element F&O Details Possible Resolution Basis of SignificanceI Application I 4-1 IFPP-B2 IFSO-A3 IFSO-B2 IFSN-A12 IFSN-B2 IFEV-B2 IFQU-B2 Criteria for screening flood areas, sources, failure mechanisms, and scenarios from further consideration 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 it has "no equipment relevant to the PRA and no significant flood sources." It is not clear whether spray is considered a "significant flood source" and whether rooms that posed a potential spray risk were screened.2. Other criteria that are not listed are being used to screen areas. In Table 5.2-1, the Emergency Diesel Generator Rooms are screened on the basis of their failure not causing a reactor trip or requiring a shutdown.

In the same table, several rooms are screened because the tanks in the room do not have sufficient volume to cause critical flood height.In addition, in several places it is noted that sources are screened because they consist of "small bore lines in this flood area which are too small to have a flood break frequency." It is not clear what constitutes "a line too small to have a break frequency." 3. NF-AA-PRA-101-2071, Section 3.2.1 says that"Information regarding the susceptibility of components to failure by spray and other physical phenomena such as jet impingement and pipe whip should be obtained." However, no notes regarding such impacts were found in the walkdown notes for areas screened from detailed analysis (e.g., area FLA5) and in other areas the relationship of flood 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 water lines in the room or the proximity of junction boxes, if any, to flood sources).1. Provide clear documentation of the screening rules used to eliminate potential flood sources, failure mechanisms, scenarios, and initiating events from the detailed analysis.2. Ensure that all of the bases used for screening areas from further consideration are captured in a section that lists them as screening criteria and provides a technically acceptable basis for each criterion.

3. Enhance the documentation to fully explain the treatment of spray in areas where detailed spray scenarios were not developed.

4. Provide justification for exclusion of jet impingement and pipe whip failure mechanisms.

Specific information needed to support technical review of the flood source analysis is not clearly documented in the Surry PRA flooding notebooks.

This is primarily a documentation issue. If any new flood scenarios are identified, it is expected that their impact will be negligible.

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

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-LAR Attachment 5 Page 16 of 38 Importance to F&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 on HR-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 a there 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 on 2052 does provide guidance for an error factor to this application.

an individual HPE, but this information is not repeated 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 of HR-H3 action HEPs for cutsets in the Surry PRA are processing recovery HEPs to should be included in the recoveries added by discussed in Notebooks HR.3 and HR.10. The Notebook HR.3. Review these the documentation, the QRECOVER fault development, application and documentation of post-processing HEPs for tree, no impact on CDF or these recovery HEPs are generally consistent dependency between them LERF is expected.

As a with industry practice.

and other HEPs in the result, this gap has no Not 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 in quantification.

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

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

-LAR Attachment 5 Page 17 of 38 2012 Surry PRA Focused Peer Review A 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 21 suggestions do not affect the technical adequacy of the PRA model and have no impact on the results of this evaluation.

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

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-LAR Attachment 5 Page 18 of 38 Table 4 Nine Findings from 2012 Surry PRA Focused Peer Review Basis of F&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 or ISLOCA F is screened even though the event include the probability of impact on CDF is LERF as this is a frequency 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 no appropriately justified using the criteria specified continued HHSI operation documented to impact on this application.

in IE-C6. given a rupture in the LHSI ensure the piping. screening criteria is met.1-6 QU-B7 This guidance does not seem to be technically Remove the mutually The impact of the A bounding sensitivity study supported by NUREG/CR-5485 Section 5.4.4 exclusive logic for common removal of the basic evaluating the removal of the which only supports removal of combinations of cause failures or modify the event combinations mutually exclusive logic for two common cause failure events where the logic to ensure only cannot be estimated common cause failures combinations include the same pump (e.g., CCF combinations of events based on available results in an increase in the of Pumps A and B in combination with CCF of including a common information, baseline CDF by less than pumps A and C). Further, NUREG/CR-5485 component and failure However, because 0.2% and LERF by less than Section 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 baseline combinations may be valid (see NUREG/CR-in combination with CCF of importance of high risk is very small, this gap has 4780, Volume 1, Section 3.3.1). Component A and B to safety significant no impact on this application.

Start) are removed, components, it is designated as a finding.1-8 DA-D5 A global assumption is made that staggered Provide justification for The alpha factors for A bounding sensitivity study testing is applicable to all common cause events application of the staggered components tested changing all CCFs from Surry 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 a isolation valves, HHSI isolation valves, and others outage frequency including higher than those less than 10% increase in the may only be tested during the outages. Additional verification that redundant tested on a baseline CDF and LERF justification 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 study month 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 or non-staggered testing LERF depending on LERF will not change the scheme to those the specific acceptability of the ILRT Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 P~cu. 1 .A f 3R Basis 19of3 F&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 impact on the acceptability of the application results.1-10 DA-D6 SY-B3 The AAC diesel is included in a common cause group with the other emergency diesel generators even though Surry notebook SY.3.EP states that"The AAC diesel has a different manufacturer for the generator and the diesel engine and is unique to both units." Surry DA.3 addresses this in an assumption that states that "If SBO diesel is modeled as one of the EDG CCF groups, because of the less similarity between the EDG and SBO diesel, the alpha factor of 3 of 3 EDGs CCF to run may be set as 1.06E-2*0.9

= 9.54E-3 and the alpha factor of AAC diesel and 2 EDGs CCF to run may be set as 1.06E-2

• 0.1 = 1.06E-3." However, there is no technical basis for the factor of 10 reduction, only a 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 to identify all legitimate common elements between the EDGs and the SBO diesel, review the CCFWIN database to exclude diesel failure mechanisms that are not common between the Surry EDGs and the SBO diesel, and calculate the actual alpha factors.The second approach would be to identify that the factor of 10 reduction in the alpha factor is an estimate without a numerical basis, which makes it a plant-specific modeling uncertainty for Surry. Then sensitivity analyses could provide some insight into the importance the assumed factor (0.1, 0.2, 0.5, etc.) would have on the results.The qualitative discussion of not all diesel CCF mechanisms existing between the EDGs and the SBO diesel is legitimate.

However, the selection of 0.1 does not have a numerical justification, and could potentially be conservative or non-conservative, and it is not apparent the degree to which it affects the results since no sensitivities were documented.

Any modeling assumption that could result in lowering the importance of the EDGs could impact applications such as MSPI.A bounding sensitivity study evaluating the common cause group of emergency generators results in no more than a 4% increase in the baseline CDF and LERF values (Ref. PRACC 16420).Based on the sensitivity study performed for 2010 F&O 1-6, a 4% increase in CDF or LERF will not change the acceptability of the ILRT extension results. As a result, this gap has no impact on the acceptability of the application results.

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-LAR Attachment 5 Page 20 of 38 Basis of F&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 or steaming effects in the Safeguards Building is not isolated ISLOCA and steam effects LERF as this is a adequately 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 no was 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 the effects of the water/steam that was already isolation valve to be failed leaked. For example, AFW pump operation due to the effects.should be shown not to be impacted, as well as potential effects on the credited isolation valve itself.The PRA staff researched the issue during the peer review and provided information that appears to justify the operability of the isolation valve, but additional analysis is required and needs 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 or DA-D6 of the CCF GARD (NF-AA-PRA-1 01-2062, Rev. independent failure data) recognized that LERF as this is a 4) 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 the probability of these events), the analyst must generic data and CCF diesel generator description adds modeling ensure that the component boundaries assumed factors. output breakers conservatism (Ref. PRACC for common cause failures are consistent with the when they are part 16422), therefore this gap boundaries used for the independent failures." of the diesel has no impact on this DOM.DA.1 Rev. 2 states "To ensure consistency component application.

between the generic database and the plant boundary in specific database, the component boundary NUREG/CR-6928) is needs to be verified.

This notebook documents conservative, for the generic database with component boundaries accuracy and defined according to NUREG/CR-6928 (Ref. 6.1). compliance with the This generic database shall be applicable to all of Dominion GARD the Dominion PRA models." and DOM.DA.1 notebook, However, Assumption 8 in Section 2.2.1 of Surry component Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Paae 21 of 38 Basis of F&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 with Generic common cause failure factors were used the data.because no plant specific common cause failures were identified.

A review of the generic common cause failures indicates that its boundaries were wider than DOM DA.1 boundaries." 2-5 SY-B3 DA-Al The CCF grouping appears to have been performed properly for pumps and some MOVs examined.However, checks of the Electric Power system model and check valves in SI and FW models show CCF combinations that are missing. In the Electric Power system model, the CCF of buses, inverters, breakers and fuel oil pump strainers (possibly other components as well) were modeled for complete failure of all in the group, but not for smaller numbers. For example, Table 3.8-1 shows 1EETFM-C8-48OTFM being comprised of eight transformers.

However, failure of a group as small as 2 (e.g., transformer 1H/1J) could be significant, as these transformers feed the 480V buses that power the 1A/2A and 1B/2B recirculation spray pumps. While it is acceptable to model CCF of combinations greater than 4 jointly (as is stated in the Section 3.2.2 of the GARD, this means creating a joint probability that sums all the 5/8, 6/8, 7/8 and 8/8 combinations into one), the individual combinations of 2, 3 and 4 still need to be captured.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.

These instances were identified in a short review of the system models, and the review team is concerned the problem is widespread.

Another item noted is Section 2.3 of the DOM.DA.3 notebook states "The Supply Breakers that feed the Emergency Buses, if there is a loss of off-site power, should be modeled for a common cause failure to open when the Emergency Diesel Generators are required to be runninq and supplvina power to the emeraencv Perform a thorough review of all system models to identify any missing CCF groups. It is acceptable to treat the combinations greater than 4 failures a single event as long as the combinations are summed and treated as complete system failure. For such cases, it is still necessary to model the combinations of 2, 3 and 4 failures.The missing CCF component groups yields non-conservative and potentially significant results.A bounding sensitivity study of additional CCFs results in a less than 10% increase in the baseline CDF and LERF values (Ref. PRACC 16423).Based on the sensitivity study performed for 2010 F&O 1-6, a 10% increase in CDF or LERF will not change the acceptability of the ILRT extension results. As a result, this gap has no impact on the acceptability of the application results.

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-LAR Attachment 5 Page 22 of 38 Basis of F&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 or DA-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 the system 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 no modeled. 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 correct DA.3 notebook.

and the model should 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 or are tabulated in Table 1 of the Surry DA.3, Rev. 5 sources of model uncertainty specific LERF as this is a notebook.

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 no approach and not a source of uncertainty for impact on this application.

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

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

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-LAR Attachment 5 Page 23 of 38 Closed PRA Model Gaps The PRA model gaps that are considered closed were not evaluated for impact on the application.

There were 0 Category A, 23 Category B, 31 Category C, and 13 Category D F&Os from 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. In addition to the closed gaps from the 1998 Peer Review, two F&Os from the 2010 Focused Peer Review are also considered closed and have been included in Table 6.Table 5 1998 NEI PRA Peer Review -Levels of Significance for F&Os A. Extremely important and necessary to address to assure the technical adequacy of the PRA 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 PRA Applications and consistency in the Industry.D. Editorial or Minor Technical Item, left to the discretion of the host utility.

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-LAR Attachment 5 Page 24 of 38 Table 6 Closed PRA Model Gaps F&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 the of the WOG and NRC models, and use of a model that includes the potential to WOG2000 RCP Seal LOCA model does not include a contribution from the possibility of early seal significantly affect (WCAP-1 5603), which has an NRC early seal failure. failure. PRA results, and SER.could therefore be Also evaluate the potential considered to have impact on the model due to a greater recent changes to the WOG significance level.seal cooling restoration Although there is emergency response currently no guidelines (advising against standard modeling restoration of seal cooling after approach, the a relatively brief cooling loss), assumptions used for the Surry model appear to be optimistic relative to assumptions used for 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 human system. 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 fault components 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 of to 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 also consideration of common cause highlight areas where CCF was miscalibration of instrumentation not included because of design channels.

diversity or other similar considerations.

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-LAR Attachment 5 Page 25 of 38 F&O Element F&O Details Possible Resolution T Basis of Plant Resolution I I Significance I AS-2 (1998)AS-5 AS-9 The models and analyses are consistent, as best as the reviewers could determine, with the as built plant, and were consistent with plant operating procedures at the time the IPE was completed.

However, there is no process in place to identify and incorporate changes in plant operation into the PRA model. This process should also include periodic review of industry standards that may impact the PRA. Some examples of where such a process could impact the model include, the timing for switchover to hot leg recirculation after event initiation (9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> in the current EOP), and a review of potential impacts on the PRA due to the power uprate program. The focus of this comment is on the lack of process more than any current discrepancies found in the model, and is related to the IPE Maintenance and Update Process elements.Establish a formal process for identifying changes to plant procedures (EOPs/AOPs), and evaluating the impact of these changes on the PRA model.This process should also include periodic review of industry standards that may affect modeling assumptions and success criteria used in the PRA. The resolution of this comment should be incorporated as an element of the PRA Maintenance and Update Process.B (It is important that the PRA model an appropriately current plant configuration, and that there is a process for determining how and when plant changes should be incorporated into the PRA models.However, this observation is not a contingent item within the review of PRA technical element AS, since it is more generically addressed within the review for element MU.)This F&O is addressed via procedure NF-AA-PRA-410, Probabilistic Risk Assessment Procedures and Methods: PRA Configuration Control Program.The purpose is to provide information and instructions for tracking the information and changes used to develop and maintain the PRA models (base models as well as Risk Monitor models). The overall objective of the PRA Configuration Control (PRACC) program is to provide a process to maintain, upgrade and update the Dominion PRA Models to support risk-informed decision-making within the scope of Regulatory Guide 1.200. The PRACC program contains the following five key elements as taken from the ASME/ANS Standard: (a) A process for monitoring PRA inputs and collecting new information (b) A process that maintains and upgrades the PRA model to be consistent with the as-built, as-operated plant (c) A process that ensures that the cumulative impact of pending changes is considered when applying the PRA (d) A process that maintains configuration control of computer codes used to support PRA quantification (e) Documentation of the Proaram Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Page 26 of 38 F&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 the the validity of the approach used for documents.

Fully incorporate following:

Alpha-factor model, INEEL defining CCF terms, by adding fail to NUREG/CR-4780 methods. data base of CCF events from start and fail to run data variables.

NUREG/CR-6268, different failure Method added value of QD and X, modes (run and demand), and but the events are not consistent (i.e. different CCF events based upon per-demand and per-hour).

population size (e.g., 2 of 3 as well as Assuming a mission time of one hour 3 of 3 CCF events. Guidance for the and a demand for the device, the CCF models was taken from terms can be added. But what if: NUREG/CR-5485, which extends the 1. Common cause failure is technology developed for dominated by running failures, NUREG/CR-4780.

there is no mission time associated with the use of the common cause term -non-conservative result.2. Running failure rate is comparable to start term, but common cause dominated by start 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 the plugging is (0.1)(1.25-7 f/hr)(2160 analysis.

beta factor could following:

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

The net the PRA results are modes (run and demand), and result is that many of the top used for ranking different CCF events based upon sequences (for the 3-year applications, such population size (e.g., 2 of 3 as well as maintenance case) involve common as Maintenance 3 of 3 CCF events. Guidance for the cause valve plugging terms. It is Rule or valve CCF models was taken from unusual to have passive equipment programs (MOV, NUREG/CR-5485, which extends the failures be so prominent in the AOV, CV).) technology developed for dominant cutsets (more prominent NUREG/CR-4780.

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

______ ________ ___________________________Significance PatRslto DA-9 than active equipment failures).

In accordance with WCAP-15676, (cont.) CCF Analysis Improvement Projects, passive equipment failure modes are no 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 from severely limits the number and type these groups or better justify requirements is NUREG/CR-6268, different failure of common cause terms used in the their exclusion, important for PRAs modes (run and demand), and model. As an evaluation tool for used for risk- different CCF events based upon plant vulnerabilities (i.e., the IPE), it informed population size (e.g., 2 of 3 as well as is more than sufficient, but as an applications.)

3 of 3 CCF events. Guidance for the evaluation tool for Risk-informed CCF models was taken from Applications, it is not enough. NUREG/CR-5485, which extends the technology developed for Events that should be considered NUREG/CR-4780.

include: Breaker fail to operate (Open/Close)

Auxiliary Feedwater Pumps (back leakage)Ventilation fans HR-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 human DE-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 of contained in the list. The procedure human error rather than equipment for system analysis (page 19 of 58) reliability.

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

-LAR Attachment 5 Page 28 of 38 F&O Element F&O Details Possible Resolution BasisPlant Resolution Significance PatR slto HR-2 standby equipment items such as (cont.) the level instrumentation in storage tanks.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 been subsequent updates of the IPE HEPs added to the implemented in the PRA model and model 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 also developed in as much detail). For be developed and reviewed as part of the HRA re-peer many of the HEPs in subsequent documented to the review exercise prior to the RG 1.200 updates, 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 the dependency among HIs contained in time between actions. HEPs focusing on following principles:

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

If two HEPs are working establishing independence of the different conclusions for two different functions, these two operator 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 on associated with more defensible analysis results is 2. Steps of procedure:

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

The time independent instruction.

If two HEPs difference of several hours between are based on two different steps or the actions was cited as the basis for two different procedures, even these the actions' independence.

Better two HEPs work for the same function, factors for independence might have they still may be justified as been 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 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Pacie 29 nf 38 F&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 the cutsets with multiple HEPs and determine if a dependency may exist between the HEPs. This process was also reviewed as part of the HRA re-peer review exercise prior to the RG 1.200 review for Surry.IE-3 (1998)IE-13 Initiating event frequencies have not been updated since the IPE submittal in 1991. As a result, recent industry information and operating experience have not been incorporated into the initiating events analysis.

This information could alter the initiating event frequencies currently contained in the model.For example:* Two plants (Salem and Wolf Creek) have experienced losses of circulating and service water that resulted in plant trips." One plant (Oconee) has experienced a small break LOCA (thermal fatigue of charging line).* One plant (WNP-2) has experienced an internal flood." A draft NUREG updating initiating events has (very recently) been issued (LOCA frequencies, particularly, have been affected).

Include an update of initiating event frequencies during the next update. Also, individual applications should be reviewed to determine if they are affected before submittal or implementation.

B (Application results may be affected by inclusion of the new information.)

The Surry initiating event frequencies were updated in the SOA-D PRA update by several sources. The rare initiator frequencies from NUREG/CR-5750 are used as priors for Bayesian updating with plant specific histories.

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

Finally, some plant unique initiating events are quantified with new fault tree models directly linked to the integrated PRA model. For each model revision, all IE frequencies are updated and documented in the IE.1 and IE.2 notebooks.

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-LAR Attachment 5 Paae 30 of 38 Basis of Plant Resolution F&O IElement F&O Details Possible Resolution Plantic Resluio IE-4 (1998)IE-7 A recent industry event (Oconee)involved a small break LOCA (>10 gpm) at the charging line connection to the RCS. The mechanism for the crack in the thermal sleeve at the connection point was thermal fatigue. Is the Surry piping subject to this type of event? If so, has it been considered in the initiating event frequency?

Evaluate the susceptibility of the Surry piping to this failure mechanism, and adjust the LOCA frequencies, as appropriate.

B (If this is a valid failure mechanism for small break LOCAs, the effect on frequency should be considered in the Surry analysis.)

The referenced Oconee event was evaluated as part of INPO SEN 163, Recurring Event, High Pressure Injection Line Leak, and as part of NRC IN 97-46, Unisolable Crack in High-Pressure Injection Piping.The design of the CVCS and HHSI systems at Surry is significantly different than that of Oconee, Unit 2.The Surry design does not include combination CVCS makeup and HHSI lines. Each unit has only one CVCS makeup line which carries full makeup flow and the CVCS system employs a regenerative heat exchanger to heat the makeup water to within 100 degrees of the RCS cold leg temperature, thereby minimizing thermal shock.The Oconee failure mechanism is not considered valid for the Surry design, and should not require LOCA frequency adjustment.

The Current Surry LOCA frequencies are developed from NUREG/CR-5750.

This NUREG observed that no small LOCA events had occurred in U. S.nuclear power plants up to 1995.However, the 1997 Oconee 2 event could possibly be categorized as a very small LOCA / leak, and four such events from 1987 -1995 are included within the NUREG/CR-5750 initiating event frequencies.

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-LAR Attachment 5 Page 31 of 38 F&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 screen states 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 of consider the screen wash system the transient further. However, clogged screens initiating frequency, can cause plant trips, and this failure particularly if there mechanism should be considered in are plant specific the development of initiating event features that could frequencies.

Recent industry events cause the likelihood at Salem and Wolf Creek illustrate a of clogged screens plant's susceptibility to clogged to be higher than the intake 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 in change been considered on the been properly accounted for in significant changes the Surry PRA Model, and on the moderator temperature the analysis.

in the moderator success criteria of hardware credited coefficient/reactivity feedback, temperature in the Surry PRA Model has been particularly for early in a core's life? coefficient

/ evaluated using MAAP 4.0.5. The Also, has the increased decay heat reactivity feedback results of the analysis show that no load been considered in the success during the early part changes are required to the current criteria for decay heat removal? of a core's life, and success criteria or HEP calculations.

can have a significant effect on success criteria requirements for emergency boration and other methods of shutting down the reactor during ATWS 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 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Paae 32 of 38 F&O Element F&O Details Possible Resolution Basis of Plant Resolution I ~Significance I considered in the PRA or the LERF assessment.

After core damage has occurred, the control room staff will continue to attempt to implement EOP actions (and now SAMG actions).Considering the EOP actions, only those that prevent core damage (have an impact on the CDF) are modeled in the Level 1 PRA.Several EOP actions that can impact the LERF are:* FR-C.1 actions to depressurize the RCS at the onset of core overheating greatly decreases the probability of a high pressure reactor vessel failure, while significantly increasing:

a) the potential for core concrete interactions, and b) the fission product release from RCS to containment (which, in turn, increases the source term for containment failures).

• FR-H.1 actions to establish some type of feedwater flow to the SGs increases the chances of SG tube failure due to thermal stresses of cold water being injected onto hot SG tubes, but can also increase the potential for arresting the core damage in-vessel.

These two aspects can impact the LERF.* ECA-0.0 actions to start sprays when offsite power is restored.This can prevent overpressure failure of containment, but can SAMG) actions in the PRA models model, S007Aa (e.g., HEP-C-FTSLPI, Operator Fails To Start Low Pressure Injection per The SAMG).L2-2 (cont.)

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

-LAR Attachment 5 Page 33 of 38 F&O Element F&O Details Possible Resolution Basis of Plant Resolution Significance PatRslto also de-inert containment and lead to a hydrogen burn. When combined with the added hydrogen from in-vessel recovery, the hydrogen burn may challenge containment.

Also, these operator actions should be substantiated by an HRA analysis to determine the HEP.The plant has also completed implementation of the SAMG. The SAMG contains a set of accident management strategies that would be implemented for each of the core damage accidents.

The implementation of some of the strategies has negative consequences that should be addressed.

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 upgrade Factors that could be affected by the appropriate, into the PRA could have a core power upgrade include the model. significant effect on moderator temperature coefficient the PRA model and (for ATWS) and the decay heat load analysis results.)(for several accident sequences).

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

-LAR Attachment 5 Page 34 of 38 F&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 PRA support 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, the minimal, whether they are still equipment failure rates, initiating adequately estimated.

event frequencies, human error probabilities and other PRA inputs (e.g., design changes) are revised to reflect 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 Risk incorporating changes based on analysis element, are actually applications that the Assessment Procedures and plant design changes. For example, applicable more broadly, within PRA models reflect Methods: PRA Configuration Control a later EOP change identifies the the context of the overall PRA recent changes to Program time 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 the 1. Develop a PRA change information and changes used to There is an advantage to identifying program that tracks identified develop and maintain the PRA operator actions to specific changes to procedures, design, models (base models as well as Risk procedure 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 Control models and documentation need to PRA. (PRACC) program is to provide a be updated periodically, process to maintain, upgrade and 2. Consider becoming part of update the Dominion PRA Models to the review cycle for selected support risk-informed decision-making changes (e.g., for risk within the scope of Regulatory Guide Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

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

________ ~~~Significance PatRslto SY-2 significant system design 1.200. The PRACC program contains (cont.) changes, PRA review is the following five key elements as required).

This will probably taken from the ASME/ANS Standard: require a change to plant, (a) A process for monitoring PRA engineering procedures.

inputs and collecting new information (b) A process that maintains and There are going to be changes upgrades the PRA model to be in plant configuration that could consistent with the as-built, as-significantly affect the PRA. A operated plant formal review by the PRA (c) A process that ensures that the group for selected changes has cumulative impact of pending the potential for saving money changes is considered when applying (change should not be made in the PRA terms of plant risk), minimizing (d) A process that maintains the effects of the change on the configuration control of computer PRA and PRA based programs codes used to support PRA and possibly identifying quantification alternative changes. (e) Documentation of the Program SY-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 system systems. 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 to removes power to the RTB shunt trip include separate logic for RTA and coils which limits operator action in RTB including the input logic signal the control room if reactor trip fails. with recovery.

The model also includes failure of the trip breaker (RTA/RTB), and RTA/RTB recovery thorough the shunt trip relay (including failure of 125 VDC, human reliability model, and failure of the shunt trip relay).

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

-LAR Attachment 5 Page 36 of 38 F&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 the to both reactor trip breakers.

Actual system function.)

design is logic train A sends signal to RTA and logic train B sends signal to RTB.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 cooling reflect recent plant dependency that currently has a System 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 seal dependent on CCW (for must be accounted coolers require CC cooling, but the B recirculation).

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

For 1 B is not dependent on CCW due to Surry Unit 2, all A/B/C pump seal a design change. What about Unit coolers require CC cooling.2? How are unit to unit differences Potentially, all Surry charging pumps identified and modeled? may be upgraded so that their CHP seal coolers can be isolated, but at Dependency table from IPE model this time, only the Surry Unit 1 B wasn't updated in SM-1 162 or SM- pump does not require CC cooling, 1165 to account for CCW which explains the difference between dependency.

Also, success criteria Surry Unit 1 and 2 charging pump CC section of system notebook was not cooling. The dependency on CC has updated. been added to the 1B pump as well, to account for the possibility that cooling might be needed if the pumps were 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 PRA and 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 screened I I ventilation dependencies modeled in dependencies where HVAC is that assumptions via engineering analysis (e.g., room Serial No 13-435 Docket Nos. 50-280/281 Type A Test Interval Extension

-LAR Attachment 5 Page 37 of 38 F&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 to assumption stating that room cooling overview of HVAC issues as determine the need is not required, but little if any basis part of a dependencies for ventilation or is provided for these assumptions.

notebook.

cooling are Based on discussions with the PRA documented.)

group engineers during this review, it appears that the HVAC requirements were adequately addressed in the modeling process, but the assumptions were not clearly documented, and no process is defined for the determination of the need 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 the with 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 were notebook, Section 2.2, and the QU.1 removed from the model during the notebook.

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

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

If however, they are not utilized in the these pressure switch failure basic quantification process. These actions events had a high importance, then are typically utilized in Initiating adding the recovery credit would be Event fault trees in conjunction with considered.

auto-start failures.

Not modeling these actions may cause cutsets not to be generated, dependencies not evaluated, and overall results impacted.

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

-LAR Attachment 5 tF&O Details [ Possible Resolution Basis of Plant Resolution F&O IElemnt FO Deails-T I Significance I 3-19 (2010)N/A The plant's approach to analyzing HEPs is more involved than the Category I requirements (it is actually closer to Category Il/111), but it does not address all of the PSFs identified for the Category Il/111 requirements (a limitation of the SPAR-H method); therefore, MET was selected for Category I.While SPAR-H methodology is close to meeting CC Il/111, one of the limitations is that the PSFs are limited to the eight chosen.Additionally, each of the eight PSFs should be evaluated for interaction impacts which are not covered by the method.N/A -This F&O was addressed by Dominion during the Peer Review.N/A -This F&O was addressed by Dominion during the Peer Review.Since this F&O relates to using SPAR-H, and F&O 3-18 indicates that SPAR-H method is not a valid method to meet Cat II, then this F&O will be closed out to F&O 3-18.

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

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

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

-LAR Attachment 6 Page 1 of 1 List 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 Date tOne-time Compliance CompletionDate Dominion will use the definition in Section 5 of NEI 94-01 Revision 3-A for Upon NRC approval of calculating the Type A leakage rate. X this License Amendment Request