ML14111A291

License Amendment Request to Extend Containment Leakage Test Frequency

ML14111A291
Person / Time
Site:	Beaver Valley
Issue date:	04/16/2014
From:	Larson E A FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-14-121
Download: ML14111A291 (234)

Text

FENOCTM Firs/Energy Nuclear Operating Company Eric A. Larson Site Vice President April16, 2014 L-14-121 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Beaver Valley Power Station, Unit Nos. 1 and 2 BVPS-1 Docket No. 50-334, License No. DPR-66 BVPS-2 Docket No. 50-412, License No. NPF-73 Beaver Valley Power Station P.O. Box 4 Shippingport, PA 15077 10 CFR 50.90 724-682-5234 Fax: 724-643-8069 License Amendment Request to Extend Containment Leakage Test Frequency Pursuant to 10 CFR 50.90, FirstEnergy Nuclear Operating Company (FENOC) hereby requests an amendment to the facility operating licenses for Beaver Valley Power Station, Unit No. 1 (BVPS-1) and Unit No.2 (BVPS-2).

The proposed license amendment would revise Technical Specification 5.5.12, "Containment Leakage Rate Testing Program," Item a, by deleting reference to the BVPS-1 exemption letter dated December 5, 1984, and requiring compliance with Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Based Option of 10 CFR Part 50, Appendix J," instead of Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," including listed exceptions.

The FENOC evaluation of the proposed changes is enclosed.

Approval of the proposed amendment is requested by April 6, 2015 to support related testing activities to be conducted during the next BVPS-1 refueling outage (1 R23), which is currently scheduled to begin in April 2015. Once approved, the amendment shall be implemented within 30 days of receipt. There are no regulatory commitments contained in this letter. If there are any questions or if additional information is required, please contact Mr. Thomas A Lentz, FENOC Fleet Licensing, at 330-761-6071.

Beaver Valley Power Station, Unit Nos. 1 and 2 Letter L-14 -121 Page2 I declare under penalty of perjury that the foregoing is true and correct. Executed on Aprilllz_, 2014. Sincerely, ?:aL Eric A. Larson

Enclosure:

FENOC Evaluation of the Proposed Amendment cc: NRC Region I Administrator NRC Resident Inspector NRC Project Manager Director BRP/DEP Site BRP/DEP Representative FENOC Evaluation of the Proposed Amendment Page 1 of 54

Subject:

License Amendment Request to Change Technical Specification 5.5.12, "Containment Leakage Rate Testing Program," to Incorporate a

Based Option for Containment Leakage Rate Testing Table of Contents 1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION

2.1 Proposed

Change 2.2 Description of Containment Buildings

3. TECHNICAL EVALUATION 3.1 Leak Test History 3.1.1 Type A Testing 3.1.2 Type B and C Testing 3.2 Containment Inspections

3.2.1 Containment

lnservice Inspection

3.2.2 Containment

Structural Integrity Test Test Description Recent Examination Results Supplemental Inspection Requirement

3.2.3 Containment

Liner Test Channel Plugs 3.2.4 Containment Liner Corrosion 2006 3.2.5 Containment Liner Corrosion 2009 3.2.6 Containment Liner Corrosion 2013 3.2.7 Inaccessible Areas . 3.2.8 Containment Coatings Inspections

3.2.9 License

Renewal Commitments 3.3 NRC Information Notice 92-20, Inadequate Local Leak Rate Testing 3.4 NRC Limitations and Conditions 3.4.1 June 25, 2008 NRC Safety Evaluation 3.4.2 June 8, 2012 NRC Safety Evaluation FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 2 of 54 3.5 Plant-Specific Confirmatory Analysis 3.5.1 Methodology

3.5.2 Probabilistic

Risk Assessment (PRA) Technical Adequacy 3.5.3 Conclusion of Plant-Specific Risk Assessment Results 3.6 Conclusion

4. REGULATORY EVALUATION

4.1 Significant

Hazards Consideration 4.2 Applicable Regulatory Requirements I Criteria 4.3 Conclusions

5. ENVIRONMENTAL CONSIDERATION ATTACHMENTS

1. Proposed Facility Operating License Change (Mark-up)

2. Proposed Facility Operating License Change (Re-Typed)

3. Plant Specific Confirmatory Analysis (PRA) BVPS-1 4. Plant Specific Confirmatory Analysis (PRA) BVPS-2 5. Documentation of BVPS-1 Probabilistic Risk Assessment (PRA) Technical Adequacy 6. Documentation of BVPS-2 Probabilistic Risk Assessment (PRA) Technical Adequacy FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 3 of 54 1.

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.90, FirstEnergy Nuclear Operating Company (FENOC) hereby requests an amendment to the facility operating licenses for Beaver Valley Power Station, Unit No. 1 (BVPS-1) and Unit No. 2 (BVPS-2).

The proposed license amendment would revise BVPS-1 and BVPS-2 Technical Specification 5.5.12, "Containment Leakage Rate Testing Program," to follow guidance developed by the Nuclear Energy Institute (NEI), NEI 94-01, Revision 3-A "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." The proposed license amendment would also revise BVPS-1 and BVPS-2 Technical Specification 5.5.12.a by deleting reference to the BVPS-1 exemption letter dated December 5, 1984, since the exemption is no longer necessary.

The purpose of the NEI 94-01 guidance is to assist licensees in the implementation of Option B to 10 CFR 50, Appendix J, "Leakage Rate Testing of Containment of Light Water Cooled Nuclear Power Plants," (hereafter referred to as Appendix J, Option B). Revision 2-A of NEI 94-01 added guidance for extending containment integrated leak rate test (ILRT or Type A test) surveillance intervals beyond ten years, and Revision 3-A of NEI 94-01 adds guidance for extending containment isolation valve (Type C test) local leakage-rate test (LLRT) surveillance intervals beyond sixty months. This amendment will allow extension of the Type A test interval up to one test in 15 years and extension of the Type C test interval up to 75 months, based on acceptable performance history as defined in NEI 94-01, Revision 3-A. 2. DETAILED DESCRIPTION

2.1 Proposed

Change The proposed license amendment would revise BVPS-1 and BVPS-2 Technical Specification 5.5.12, "Containment Leakage Rate Testing Program," Item a, by deleting reference to the BVPS-1 exemption letter dated December 5, 1984, and changing the wording to indicate that the program shall be in accordance with NEI 94-01, Revision 3-A, instead of Nuclear Regulatory Commission (NRC) Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," and listed exceptions.

Appendix J, Option A,Section III.D.1.(a) of 10 CFR 50 requires that: After the preoperational leakage rate tests, a set of three Type A tests shall be performed, at approximately equal intervals during each 1 0-year service period. The third test of each set shall be conducted when the plant is shutdown for the 1 year plant inservice inspections.

The December 5, 1984 letter (Agencywide Documents Access and Management System [ADAMS] Accession No. ML003766713) provided an exemption that allowed FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 4 of 54 performance of the BVPS-1 Type A test at a 40 plus or minus 10 month frequency, not necessarily in conjunction with any inservice inspection schedule as required by the regulation.

The proposed amendment would require that Type A tests be performed in accordance with Appendix J, Option B,Section III.A.(2) at a periodic interval based on the historical performance of the overall containment system as a barrier to fission product releases to reduce the risk from reactor accidents.

Therefore, the exemption to Appendix J, Option A requirements provided in the December 5, 1984 letter is no longer necessary, and the reference to this letter is to be removed from Technical Specification 5.5.12.a.

Current Technical Specification 5.5.12.a, "Containment Leakage Rate Testing Program," states in part that: A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. . . . This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September, 1995, as modified by the following exceptions:

1. For Unit 1, the next Type A test performed after the May 29, 1993 Type A test shall be performed no later than May 28, 2008. 2. For Unit 2, the next Type A test performed after the November 10, 1993 Type A test shall be performed no later than November 9, 2008. The proposed amendment would change this wording to indicate that the program shall be in accordance with Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," and delete reference to Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," and listed exceptions.

Attachment 1 provides a copy of Technical Specification page 5.5-19 marked to show the proposed changes. Text to be deleted is marked with a line through the letters, and text to be added is shown underlined.

Technical Specification page 5.5-19 re-typed to present what the page will look like after the proposed changes are incorporated is provided in Attachment

2. 2.2 Description of Containment Buildings The BVPS-1 and BVPS-2 containment buildings are reinforced concrete, steel-lined vessels with a flat base, cylindrical walls, and a hemispherical dome. The foundation mat is a soil bearing concrete slab approximately 1 0-feet thick. The inside faces of the containment wall, dome, and mat are lined with steel liner plates. The containment buildings do not require the participation of the liner as a structural component.

No credit is taken for the presence of the steel liner in designing the containment buildings to resist earthquake forces or other design loads. The liner plate serves as an impervious FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 5 of 54 membrane whose function is to act as a gas tight boundary and to transmit loads to the concrete.

The cylindrical portion of the liner is 3/8-inch thick, the hemispherical dome liner is 1/2-inch thick and the floor liner covering the mat is 1/4-inch thick. The floor liner plate is covered with a thick layer of reinforced concrete that insulates it from temperature effects. All welded seams in the mat, cylindrical liner wall, hemispherical dome, and liner penetrations were originally covered with continuously welded test channels.

These channels were used to check leak tightness of the welds during liner erection.

Test ports and 1/8-inch National Pipe Thread Taper (NPT) pipe plugs are provided for each zone of test channels.

The test port plugs remain in place during normal operation and subsequent Type A leak rate testing. The test channels for the cylindrical wall and penetrations are mounted inside the containment building.

The test channels for the dome area are mounted on the exterior of the dome liner. The test channels for the containment building floor liner plate are covered with concrete with test ports that extend up to the containment building concrete floor. The test channels are capable of withstanding all loads that could be imposed upon them during normal and upset conditions without impairing the performance of the containment building liner itself and provide additional protection in the form of a redundant barrier to the steel liner welds. Access to the containment building is provided by a 7 foot inside diameter personnel hatch penetration and a 14 foot 6 inch inside diameter equipment hatch penetration.

The emergency air lock is a 5 foot inside diameter subassembly of the equipment hatch. Some of the other smaller containment penetrations include hot and cold process pipes, main steam and feedwater pipes, the fuel transfer tube, and electrical penetrations.

The calculated peak containment internal pressure for the design basis loss of coolant accident (Pa) is 43.1 pounds per square inch gauge (psig) for BVPS-1 and 44.8 psig for BVPS-2. The maximum allowable containment leakage rate (La) at Pa, is 0.10 percent of containment air weight per day. Principal containment building dimensions (approximate size) and design pressure are as follows:

• Inside Diameter 126 feet

• Liner Plate Thickness

• Interior Vertical Height 185 feet o Floor Liner 1/4 inch

• Dome Inside Radius 63 feet o Hemispherical Dome Liner 1/2 inch

• Vertical Wall Thickness 4.5 feet o Cylindrical Liner 3/8 inch

• Dome Thickness 2.5 feet

• Internal Free Volume

• Liner Plate Floor Covering 2 feet

• Foundation Slab Thickness 10 feet

• Design Pressure 45 psig o BVPS-1 1,751,734 cubic feet o BVPS-2 1,750,867 cubic feet FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 6 of 54 During power operation, the BVPS-1 and BVPS-2 containments are continuously maintained at a pressure from 12.8 pounds per square inch absolute (psia) to 14.2 psia in accordance with Technical Specification limiting condition for operation

3.6.4. Surveillance

Requirement (SR) 3.6.4.1 requires verification that containment pressure is within limits every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Verifying that containment pressure is within limits ensures that unit operation remains within the limits assumed in the containment analysis.

The 12-hour Frequency of this SR was developed based on operating experience related to trending of containment pressure variations during the applicable MODES. Furthermore, the 12-hour Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

The fact that the containment can be maintained subatmospheric provides a degree of assurance of containment structural integrity (that is, no large leak paths). This pressure requirement also complements the visual inspections of the interior and exterior of the containment structure for those areas that are accessible and those areas that may be inaccessible for visual examination.

3. TECHNICAL EVALUATION 3.1 Leak Test History 3.1.1 Type A Testing The historical results of the Type A Tests for BVPS-1 and BVPS-2 are included in the tables provided below. The reported leak rate is at the 95 percent upper confidence level and includes any Type B and Type C Penalties.

The last BVPS-1 and BVPS-2 Type A tests were completed on April 15, 2006 and May 11, 2008, respectively.

Previous Type A testing confirmed that the BVPS-1 and BVPS-2 containment structure leakage is acceptable, with considerable margin, with respect to the Technical Specification acceptance criterion of 0.1 percent of containment air weight per day at the design basis loss of coolant accident pressure (Pa). Since the last two BVPS-1 and BVPS-2 Type A test as-found results, as shown in the tables provided below, were less than 1.0 La, a test frequency of at least once per 10 years is justified in accordance with NEI 94-01, Revision 0. For BVPS-1, no modifications that require a Type A test are planned prior to April of 2016, which is when the next BVPS-1 Type A test is currently due. For BVPS-2, steam generator replacement will take place during the spring 2017 refueling outage (2R 19). To facilitate the removal and replacement of the steam generators, a construction opening will be made in the reactor containment building.

Following the replacement of the construction opening and restoration of the concrete structure, the next BVPS-2 Type A test will be performed prior to returning the unit to service.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 7 of 54 Repair or replacement activities (including any unplanned activities) performed on the pressure retaining boundary of the containment buildings prior to the next scheduled Type A test would be subject to the leakage test requirements of American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code)Section XI, Paragraph IWE-5221, "Leakage Test." There have been no pressure or temperature excursions in the containment that could have adversely affected containment integrity.

There is no anticipated addition or removal of plant hardware within containment that could affect leak-tightness that would not be challenged by local leak rate testing. Following the approval of this license amendment, the next BVPS-1 Type A test must be performed on or before April15, 2021 and the next BVPS-2 Type A test must be performed on or before May 11, 2023. BVPS-1 Type A Test Historical Results Test As Found As Found As Left Completion Leak Rate Acceptance Leak Rate Date* Criteria 8/15/1975 0.0454 s 0.075 0.0133 o/owt/day o/owt/day o/owt/day 11/23/1978 0.0406 s 0.075 0.0362 o/owt/day o/owt/day o/owt/day 5/14/1982 0.0376 s 0.075 0.0258 o/owt/day o/owt/day o/owt/day 8/3/1986 0.0143 s 0.075 0.0128 o/owt/day o/owt/day o/owt/day 12/7/1989 0.0317 s 0.075 0.0310 o/owt/day o/owt/day o/owt/day 5/29/1993 0.0150 s 0.075 0.0133 o/owt/day o/owt/day o/owt/day 4/15/2006 0.0428 s 0.1 0.0350 o/owt/day o/owt/day o/owt/day

• Date depressurization of containment completed o/owt/day

= Percent containment air weight per day psia = Pounds per square inch absolute Pre-operational Type A Test As Left Acceptance Criteria s 0.075 o/owt/day s 0.075 o/owt/day s 0.075 o/owt/day s 0.075 o/owt/day s 0.075 o/owt/day s 0.075 o/owt/day s 0.075 o/owt/day Pressure at Start of Test 54.20 psia 53.37 psia 54.54 psia 55.50 psia 56.52 psia 57.51 psia 59.57 psia The BVPS-1 pre-operational Type A test was successfully completed with a calculated total time leakage rate of 0.454 La. During the test, leakage was detected on a hand hole cover and a secondary manway cover of steam generator 1 RC-E-1 B. The containment was depressurized to repair the leakage. Following the repairs, the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 8 of 54 containment was re-pressurized to full test pressure and the test was successfully performed.

First Periodic Type A Test The first periodic Type A test for BVPS-1 was performed during the November 1978 surveillance outage. During the test, leakage from the personnel airlock automatic equalizing valves was identified.

The valves had been locally leak tested from inside the airlock out; however during the Type A test, pressure was being applied from outside the airlock. The valves were manually isolated for the test and have since been removed from the airlock. Also during the test, the containment air ejector penetration was found to be leaking. The outside containment isolation valve for this penetration was found closed past its shut position (butterfly valve). The valve was reseated and the stop readjusted.

The test was restarted following this adjustment; however it was evident that the resolution of the data acquisition equipment was not sufficient enough to provide consistent data. The containment building was depressurized while the data acquisition equipment was modified.

During this time period, a number of activities were performed.

These activities included:

repair of the seats of the containment isolation valves for the containment air ejector penetration (these valves are now locally leak tested following operation prior to entering Mode 4), local pressurization of each steam generator and repair of any leakage identified, and refilling of all penetrations that are required to be in service following a loss of coolant accident.

The resolution of the test equipment was increased and a second pressure-monitoring instrument was added. The test was successfully completed.

Second Periodic Type A Test The second periodic Type A test for BVPS-1 was performed during the second refueling outage. During the test, leakage was detected on one of the four recirculation spray heat exchanger metal expansion joints. The heat exchanger was isolated and the test successfully completed with a measured total time leakage rate of 0.376 La. Following the test, the metal expansion joint which had been damaged during the outage was replaced and locally leak tested. The recirculation spray heat exchanger metal expansion joints are now locally tested in accordance with Appendix J, Option B as a Type B component.

Third Periodic Type A Test The third periodic Type A test for BVPS-1 was performed during the fifth refueling outage. The containment building temperature stabilization took a significant time to achieve due to fluctuating chilled water temperature to the containment air recirculation fans. The fans were secured and the test successfully completed.

The containment air recirculation fans are no longer operated during the Type A leak test. Fourth Periodic Type A Test The fourth periodic Type A test for BVPS-1 was performed during the seventh refueling outage. During the test, leakage was detected from the seal on outside recirculation FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 9 of 54 spray pump 1 RS-P-28. The pump was isolated from the test boundary; however the measured leakage rate did not improve significantly.

Further investigation located leakage at the fuel transfer tube penetration.

The containment was depressurized to repair this leakage path. Following depressurization, it was noted that one of the two fuel transfer tube blind flange gaskets had become dislodged.

Leakage had not been previously detected during the local leak test since the dislodged gasket was blocking the test connection port. With the test port blocked, the area between the two flange gaskets was not pressurized and as a result flange gasket leakage was not detected.

The fuel transfer tube blind flange was reinstalled and successfully leak tested. The recirculation spray pump seal was also repaired and locally tested. The containment was re-pressurized and the test successfully completed with a measured mass point leakage rate of 0.317 La. The fuel transfer tube blind flange was modified during the eighth refueling outage by installing two test connections to allow air to be introduced into one connection and to verify that air is exiting through the second connection.

The two connections allow for positive verification that the two gaskets are installed correctly and not obstructing the flow of air. The outside recirculation spray pump seals are currently locally leak tested each refueling outage. Fifth Periodic Type A Test The fifth periodic Type A test for BVPS-1 was performed during the ninth refueling outage (1 R9). Following completion of the leakage portion of the test, the superimposed leakage test was performed.

However, due to temperature stabilization problems, the superimposed leakage did not fall within the range of the acceptance criteria.

The Type A leak test was restarted for an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and the superimposed leakage verification test was successfully completed.

Sixth Periodic Type A Test The sixth periodic Type A test for BVPS-1 was performed during the 17th refueling outage (1 R17) following the completion of steam generator replacement activities and the restoration of the containment construction opening. The calculated peak accident pressure increased from 40.0 psig to 43.3 psig for the Containment Atmospheric Conversion Project. Therefore, during 1 R17 the containment penetrations were locally leak tested to a pressure slightly higher than 43.3 psig. The test pressure was slightly higher to account for test instrument inaccuracy.

The as-found leakage rate in percent containment air weight per day, was calculated using the pre-containment atmospheric conversion maximum allowable leakage rate (La).

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 10 of 54 BVPS-2 Type A Test Historical Results Test As Found As Found As Left Completion Leak Rate Acceptance Leak Rate Date* Criteria 2/15/1987 0.0611 :5 0.075 0.05798 %wt/day %wt/day %wt/day 11/2/1990 0.0704 :5 0.075 0.0692 %wt/day o/owt/day o/owt/day 11/11/1993 0.0410 :5 0.075 0.0401 o/owt/day

%wt/day o/owt/day 5/11/2008 0.0588 :5 0.1 0.0587 %wt/day o/owt/day

%wt/day

• Date depressurization of containment completed o/owt/day

= Percent containment air weight per day psia = Pounds per square inch absolute Pre-operational Type A Test As Left Acceptance Criteria :5 0.075 %wt/day :5 0.075 o/owt/day

5 0.075 o/owt/day

5 0.075 %wt/day Pressure at Start of Test 61.46 psia 61.01 psia 61.18 psia 60.65 psia The BVPS-2 pre-operational Type A test was successfully completed with a calculated total time leakage rate of 0.611 La. During the test, leakage was detected past demineralized water isolation valve 2RSS-4 and at a compression fitting on the seal of outside recirculation spray pump 2RSS-P21 B. These two leakage paths were isolated and the test was successfully completed.

Following completion of the Type A leak test, components 2RSS-4 and 2RSS-P21 B were repaired and local leak rate tested. These components are locally leak tested during each refueling outage. First Periodic Type A Test The first periodic Type A test for BVPS-2 was performed during the second refueling outage. During the test, a high mass trend change indicated that leakage out of containment was occurring.

An investigation of all potential leakage paths was performed with no significant leakage identified.

The possibility of leakage into the steam generator secondary side was investigated due to an unexplained steam generator level instrumentation fluctuation.

To assess this potential leakage path, the secondary sides of the 21A and 21 C steam generators were pressurized with air. The change in mass trend appeared to be improving following this activity.

The containment building was then depressurized to identify the exact leakage path(s). Several packing leaks and two transmitter vent connections were found to be leaking and repaired.

The containment building was re-pressurized, and after approximately eleven hours of stabilization, the temperature criteria were met. However, due to temperature stabilization problems, the superimposed leakage did not fall within the range of the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 11 of 54 acceptance criteria.

The Type A test was restarted and the superimposed leakage test was successfully completed.

Second Periodic Type A Test The second periodic Type A test for BVPS-2 was performed during the fourth refueling outage. After approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />, the temperature stabilization criteria were met. Following temperature stabilization, the Type A leak test was started and successfully completed.

Third Periodic Type A Test The third periodic Type A test for BVPS-2 was performed during the 13th refueling outage (2R 13) in the spring of 2008. During the temperature stabilization phase of the test, leakage past the inside containment isolation valves for Penetration 90, "Containment Purge Exhaust," and Penetration 91, "Containment Purge Supply," was allowing the volume between the inside and outside containment isolation valves to slowly pressurize.

Since this was anticipated, test gauges were installed on these penetrations prior to the test to monitor the penetration for leakage. To minimize the test stabilization time, the volume between the two containment isolation valves was locally pressurized to approximately 1.5 psig below the containment test pressure.

Also, during the temperature stabilization phase of the test, leakage was noted at demineralized water vent valve 2RSS-1 01. This valve was opened per the test procedure to identify any demineralized water system leakage past the isolation valves to the recirculation spray pumps. Leakage at 2RSS-1 01 was measured with a rotameter to be 1.8 standard cubic feet per minute. Closing valve 2RSS-5 tightly stopped demineralized water system leakage to the recirculation spray pumps. The 2R13 Type A test was successfully completed.

3.1.2 Type B and C Testing The Type Band Type C containment leakage rate testing program for BVPS-1 and BVPS-2 requires pneumatic tests intended to detect or measure leakage across pressure-retaining or leakage limiting boundaries and containment isolation valves. As discussed in NUREG-1493, "Performance-Based Containment Leak-Test Program," Type B and Type C tests can identify the vast majority of potential containment leakages.

A review of the Type B and Type C test results from the spring of 2003 through the fall of 2013 has shown a large amount of margin between the actual as-found and as-left outage summations and the Technical Specification leakage rate acceptance criteria (that is, less than 0.6 La).

• The as-found minimum pathway leak rate average for BVPS-1 shows an average of 19.9 percent of 0.6 La with a high of 33.2 percent or 0.2 La.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 12 of 54

• The as-left maximum pathway leak rate average for BVPS-1 shows an average of 38.9 percent of 0.6 La with a high of 52.8 percent or 0.32 La.

• The as-found minimum pathway leak rate average for BVPS-2 shows an average of 23.9 percent of 0.6 La with a high of 65.0 percent or 0.39 La.

• The as-left maximum pathway leak rate average for BVPS-2 shows an average of 31.3 percent of 0.6 La with a high of 41.0 percent or 0.25 La. The as-found minimum pathway summations for BVPS-1 and BVPS-2 represent the high quality of maintenance of Type B and Type C test components while the as-left maximum pathway summations represent the effective management of the Containment Leakage Rate Testing Program by the program owner. BVPS-1 Type B And Type C Leak Rate Summation History Refueling As-Found Percentage of As-Left Percentage of Outage Min Path 0.6 La Max Path 0.6 La 1R15 454.47 SCFD 11.6% 1 ,409.58 SCFD 35.9% Spring 2003 1R16 543.81 SCFD 13.8% 1,074.90 SCFD 27.4% Fall2004 1R17 1,305.76 SCFD 33.2% 1,560.95 SCFD 37.7% Spring 2006 1R18 853.52 SCFD 20.7% 2,180.47 SCFD 52.8% Fall2007 1R19 581.92 SCFD 14.1% 1,330.50 SCFD 32.2% Spring 2009 1R20 858.60 SCFD 21.0% 1,563.58 SCFD 38.2% Fall2010 1R21 818.46 SCFD 20.0% 1,879.23 SCFD 45.9% Spring 2012 1R22 1,007.97 SCFD 24.6% 1,680.68 SCFD 41.0% Fall2013 SCFD = Standard Cubic Feet per Day FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 13 of 54 BVPS-2 Type B And Type C Leak Rate Summation History Refueling As-Found Percentage of As-Left Percentage of Outage Min Path 0.6 La Max Path 0.6 La 2R10 689.08 SCFD 16.6% 1,318.30 SCFD 31.7% Fa112003 2R11 2706.1 SCFD 65.0% 1,374.06 SCFD 33.0% Spring 2005 2R12 966.01 SCFD 23.2% 1,742.53 SCFD 41.0% Fall2006 2R13 664.99 SCFD 15.8% 1,308.06 SCFD 31.0% Spring 2008 2R14 814.81 SCFD 19.3% 1,173.47 SCFD 27.8% Fall2009 2R15 522.17 SCFD 12.4% 1,046.45 SCFD 24.8% Spring 2011 2R16 620.00 SCFD 14.7% 1 ,264.61 SCFD 30.0% Fall2012 SCFD =Standard Cubic Feet per Day Conditions associated with the Appendix J testing program have been documented in the FENOC corrective action program. A description of each relevant condition, including two program changes, are provided below. BVPS-1 Component Cooling Water Supply to the 1A Reactor Coolant Pump (Penetration

58) As-found testing of Penetration 58 was performed on February 25, 2006 (spring 2006 refueling outage, 1 R 17). Following this test, relief valve RV-1 CC-275 (Penetration 58 thermal relief valve) was replaced with a new style relief valve. This new valve was successfully Type C leak tested on March 7, 2006. Due to misinterpretation of the work performed (repair versus replacement)

Penetration 58 was placed on extended frequency, which deferred testing from the fall 2007 refueling outage ( 1 R 18). During a pre-outage review of the Type B and C leak tests to be performed during the spring 2009 refueling outage (1 R19), it was discovered that testing to return relief valve RV-1 CC-275 to Appendix J, Option B extended frequency was inadvertently missed during the fall 2007 refueling outage (1 R18). Option B of NEI 94-01, Revision 0, requires the performance of two consecutive periodic as-found Type C tests prior to placing a new valve on extended frequency.

The Type C testing frequency established in NEI 94-01, Revision 0, for valves not on extended frequency is 30 months. Consistent with standard scheduling practices for FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 14 of 54 Technical Specification required surveillances, the Type C test frequencies may be extended by up to 25 percent of the test interval, not to exceed 15 months. Applying the extension to the 30-month interval, the next required Type C test of the relief valve was April 22, 2009. Since refueling outage 1 R 19 was to begin on April 20, 2009, Penetration 58 was added to the scope of 1 R 19. Following successful as-found Type C leak tests of relief valve RV-1 CC-275 during 1 R 19 and the fall 2010 refueling outage (1 R20), Penetration 58 could be returned to an extended test frequency.

An extent of condition evaluation was performed for all Type C tested components in BVPS-1, and no additional instances were found. During 1 R 19, as-found leak testing of Penetration 58 was performed on April 27, 2009 with an acceptable leakage rate. During 1 R20, as-found leak test of Penetration 58 was performed on October 13, 2010 with acceptable leakage rates. Penetration 58 was returned to extended frequency.

BVPS-1 Electrical Penetration 1 RCP-3F During the spring 2012 refueling outage (1 R21) performance of procedure "Containment Electrical Penetrations Type 'B' Leak Test" an as-found leak rate of 54 SCFD was recorded for the canister of penetration 1 RCP-3F. This leakage rate exceeded the administrative maximum allowable leakage rate of 3.0 SCFD. The source of the leakage could not be located. Since penetration 1 RCP-3F could not be repaired with available parts, a replacement penetration was ordered and a work order was generated for replacement of the electrical penetration during 1 R22. During the fall 2013 refueling outage (1 R22), the as-found leakage measured for the canister of containment electrical penetration 1 RCP-3F was 46.62 SCFD, which exceeded the administrative limit of 3.0 SCFD. Following the unsatisfactory as-found leakage test, the replacement penetration was installed.

Following replacement, both the canister and a-rings were tested and found satisfactory per the leakage acceptance criteria.

The measured leakage rate of the canister was 0.0509 SCFD and the measured leakage rate of the a-rings was 0.0509 SCFD. BVPS-1 Electrical Penetration 1 RCP-13F During the spring 2012 refueling outage (1 R21 ), containment electrical penetration 1 RCP-13F exceeded its administrative limit of less than or equal to 3.0 SCFD with a measured canister leakage rate of 11.9 SCFD. The source of leakage was identified to be at the test connection.

A work order was executed to epoxy the test connection and retest the penetration.

The as-left leak test of 1 RCP-13F was satisfactory with a measured leakage rate of 0.1 SCFD.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 15 of 54 BVPS-1 Nitrogen Supply to the Pressurizer Relief Tank (Penetration

49) On April12, 2012 (during 1R21) while as-found Type C leak testing of Penetration 49 (per procedure, "Type C Leak Test"), trip valve TV-1 RC-1 01, the outside containment isolation valve, exceeded its administrative limit of less than or equal to 80 SCFD with a measured leakage rate of 135.12 SCFD. The inside valve (check valve 1RC-68) passed the Type C leak test with a measured leakage rate of 16.89 SCFD. Valve TV-1 RC-1 01 was repaired during 1 R21. Following the maintenance, the as-left leak test of Penetration 49 was performed on May 5, 2012 with acceptable leakage rates measured.

Since TV-1 RC-1 01 exceeded its as-found leak test administrative limit, it will be placed on nominal (30 month) testing frequency for 1 R22 and the spring 2015 refueling outage (1 R23). Air Operated Valve (AOV) Program Requirement Change There was a change in philosophy for the Appendix J and AOV Programs in 2012. Actuator packing adjustments were previously considered a non-impact adjustment for both programs.

Such packing adjustments were viewed as simply returning the packing to its previous condition.

A challenge was presented suggesting that, without test data, there is no way to determine if the packing was tightened too much. Actuator packing will relax as a result of valve stroking.

This results in reduced friction and can cause packing leaks. Tightening the packing nut will eliminate such packing leaks but will also increase the friction attributed to the packing. It is expected that tightening the packing will raise the friction to approximately its previous value but it could be slightly higher. If it is higher than when last tested per the Appendix J or AOV Program, retesting or evaluation is required.

Containment isolation valves at BVPS that are air-operated are classified as either Category 1 or 2 in the AOV Program. Following the program change, the pneumatic actuator packing adjustments are considered to impact Type C leak test limits and the AOV Program limit on total valve friction.

These packing adjustments are accompanied by AOV diagnostic testing. In addition, AOVs that are also containment isolation valves require Type C testing unless previous AOV diagnostic testing provides a seat load measurement that can be directly linked to an acceptable Type C test. BVPS-1 Air Recirculation Cooling Water Out (Penetration

11) and Discharge from Containment Sump Pumps (Penetration

38) During an evaluation of Condition Report, "Actuator Packing Adjustments for Category 1 and 2 [air operated valves] AOVs," two past cases of actuator packing adjustments on containment isolation valves were found at BVPS-1 where a subsequent Type C leak test was not performed.

An evaluation of the impact of those two actuator packing adjustments on Type C leak test limits for penetrations 11 and 38 follows.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 16 of 54 BVPS-1 Penetration 11 Penetration 11 was last Type C leak tested on October 11, 2007. On October 5, 2010 the actuator packing was adjusted on trip valve operator BV-TV-1 CC-11 OD-OPER. This is an inside containment isolation valve where normal chilled water flow tends to open the valve. This packing adjustment was unsuccessful in eliminating the air leak and on October 21, 2010 an additional ring of packing was added and the packing nut was tightened sufficiently to eliminate the air leak. No subsequent Type C leak test was performed.

As indicated previously, Penetration 11 was Type C leak tested on October 11, 2007 at which time the leak rate was 2.4 SCFD, which was less than 1 percent of the administrative limit of 640 SCFD. Diagnostic testing of this air operated valve on October 12, 2007 indicated a seat load of 7,503 pounds. The reference calculation indicates that a seat load of approximately 5,403 pounds is needed to achieve an American National Standards Institute Standard (ANSI) 816.104 class IV shutoff. This seat load was calculated for conditions where the pressure differential across the valve was 132 pounds per square inch (psi), significantly greater than the design basis accident pressure of 44.5 psi used for Type C testing. It is an engineering judgment that it is not credible that an actuator packing adjustment could have created the additional friction of over 2,000 pounds required to reduce the seat load below 5,403 pounds. Additionally, significant increases in actuator packing friction would result in increased valve stroke times and, in extreme cases, could cause the valve to partially stroke or not stroke at all. Acceptable valve strokes were performed on October 22, 2010 (the day after the actuator packing adjustment).

The as-found and as-left leak test of Penetration 11 during the spring 2012 refueling outage (1R21) was performed on April19, 2012 with acceptable leakage rates measured.

BVPS-1 Penetration 38 Penetration 38 was Type C leak tested on September 29, 2007. On January 24, 2008 the actuator packing was adjusted on trip valve operator BV-TV-1DA-100B-OPER.

This is an outside containment isolation valve where the containment sump pump discharge flow tends to open the valve. The actuator packing nut was tightened sufficiently to successfully eliminate the air leak. No subsequent Type C leak test was performed.

In October 2011, it was again identified that the actuator packing had relaxed resulting in a new actuator packing air leak. When Penetration 38 was Type C leak tested on September 29, 2007, the leak rate was 0.96 SCFD. This leak rate is less than 1 percent of the administrative limit of 160 SCFD. Diagnostic testing of this air operated valve on March 31, 2006 indicated a seat load of 1,352 pounds. The reference calculation indicates that a seat load of 467 pounds is needed to achieve an ANSI 816.104 class IV shutoff. This seat load was calculated for conditions where the differential pressure across the valve was 62 psi, FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 17 of 54 which is greater than the design basis accident pressure of 44.5 psi used for Type C testing. It is an engineering judgment that it is not credible that an actuator packing adjustment could create the additional friction of over 885 pounds required to reduce the seat load below 467 pounds. Additionally, significant increases in actuator packing friction would result in increased valve stroke times and, in extreme cases, could cause the valve to partially stroke or not stroke at all. Acceptable valve strokes were observed on January 24, 2008 (the day of the actuator packing adjustment) and timed on February 11, 2008. The as-found leak test of Penetration 38 during 1R21 was performed on Apri118, 2012 with acceptable leakage rates measured.

During a containment sump pump-out, a local operator reported that thermal relief valve RV-1 DA-101 was spraying on pump start. As a result, RV-1 DA-1 01 was replaced.

Following the replacement, the as-left leak test of Penetration 38 was performed on May 4, 2012 with acceptable leakage rates measured.

BVPS-2 Penetration 43 The as-found leak test of BVPS-2 Penetration 43 was performed on October 23, 2009 with acceptable leakage rates measured for solenoid operated valve 2CVS-SOV1 02 (outside containment isolation valve). Check valve 2CVS-93 (inside containment isolation valve) exceeded its administrative limit with a leak rate of 238.07 SCFD, and was replaced.

During as-left testing 2CVS-93 failed to pressurize.

Foreign material was found in the check valve. The foreign material was removed and the valve was repaired.

Both 2CVS-93 and 2CVS-SOV1 02 were as-left tested on November 5, 2009 with acceptable leakage rates measured.

3.2 Containment

Inspections General visual examinations of the accessible surfaces of the containment buildings reinforced concrete are performed in accordance with the Primary Containment lnservice Inspection Program. These examinations are performed to assess the general structural condition of the containment building reinforced concrete and to satisfy the visual examination requirements of ASME Code Section XI, Subsection IWL. These examinations are performed in sufficient detail to identify areas of concrete deterioration and distress.

Detailed visual examinations are performed to determine the magnitude and extent of deterioration and distress of suspect concrete surfaces initially detected by general visual examinations.

The conditions reported during the examinations are evaluated to determine acceptability.

The conditions are acceptable if it is determined that there is no evidence of damage or degradation sufficient to warrant further evaluation or performance of repair and replacement activities.

These concrete examinations are performed on a five year frequency.

The metal containment liner is visually examined under two separate programs.

The first is the Primary Containment lnservice Inspection Program discussed in Section 3.2.1. This program includes provisions to satisfy the visual examination FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 18 of 54 requirements of ASME Code Section XI, Subsection IWE and 10 CFR 50, Appendix J, Option B. A visual examination is made of the accessible interior surfaces of containment in order to identify evidence of deterioration that may affect the containment structural integrity or leak tightness.

If signs of corrosion are evident that exceed the acceptance standard (IWE-3500), they must be either corrected by a repair or replacement activity or deemed acceptable for continued service by an engineering evaluation.

Both Regulatory Guide 1.163, September 1995, and the ASME Code require a general visual examination of the accessible liner surfaces three times in a ten year period. The second program is the Containment Coatings Inspection and Assessment Program discussed in Section 3.2.8. This program mandates a visual inspection and assessment of the protective coatings on the containment structure and equipment in the readily accessible areas of the reactor containment building.

The examination areas are selected such that all painted surfaces are inspected over a two outage timeframe.

This program is implemented to ensure that the integrity of the coatings is maintained and was established in response to NRC Generic Letter 2004-02. The inspection frequency of the above programs ensures that when an area of concern is identified, it only affects a small localized area. Corrective action is taken following any signs of paint blistering, peeling, or corrosion.

3.2.1 Containment

lnservice Inspection Program The requirements of American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) Section Ill were used as a guide in the design and construction of the BVPS primary containment structures. However, they were not built as Section Ill Class MC (Metal Containment), or Class CC (Concrete Containment) components.

The BVPS-1 Containment was built as a Pennsylvania State Special Number 4630. The BVPS-2 Containment was built as Pennsylvania State Special Number 4875. For the purposes of this plan, the BVPS-1 and BVPS-2 Containment Buildings are classified as Class CC components with metallic liners. The Primary Containment lnservice Inspection (lSI) Program applies to the containment vessel (ASME Code Section XI, Subsection IWE) and the containment reinforced concrete (ASME Code Section XI, Subsection IWL ). ASME Code Section XI, Subsection IWE specifies that examinations will be performed on the pressure retaining boundary of the containment vessel, which includes the accessible surfaces of the liner plate, integral attachments and structures that are part of the reinforcing structure, surfaces of pressure retaining welds, pressure retaining bolted connections, and the moisture barrier, which prevents moisture intrusion at the concrete-to-metal interface at the basement floor. Also, the containment surfaces that may require augmented examination are included in this program.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 19 of 54 ASME Code Section XI, Subsection IWL specifies that examinations will be performed on the surfaces of the reinforced concrete of the containment building.

This program does not include Item Numbers El.12 (Wetted Surfaces of Submerged Areas), E1.20 (BWR Vent System), and Examination Category L-B (Unbounded Tensioning System). These circumstances and components do not exist at BVPS. In accordance with the NRC final rule amending 10 CFR 50.55a that was effective September 9, 1996, the IWE Program was developed with an initial interval start date of February 1, 2000; the initial interval start date for the IWL Program was June 1, 2000. As required by the rulemaking, the 1992 Edition, 1992 Addenda of ASME Code Section XI was the basis for the programs.

The required Subsection IWE exams were completed for the first two 40-Month Periods. Two Subsection IWL examinations have been completed in accordance with the original IWL Program. For ease of administration, the Subsection IWE and IWL interval dates and ASME Code Section XI Code Editions were synchronized with the remainder of the ASME Code Section XI subsections.

The subsequent interval start date for the Subsection IWE and IWL programs was April 1, 2008 at BVPS-1 and August 29, 2008 at BVPS-2; the subsequent interval code of record is ASME Code Section XI, 2001 Edition, 2003 Addenda and implemented in accordance with procedure 1/2-ADM-2099, "Primary Containment lSI Program." Inspection Interval and Inspection Periods The required Subsection IWE and IWL examinations are scheduled and tracked using a database.

The current and the next containment in-service inspection intervals for BVPS-1 and BVPS-2 are summarized in the tables below: Current IWE/IWL Interval Component ID Description Item Exam Scheduled Number Method Outage 1-CNMT-LINER Containment liner E1.11 GV 1 R19, 1 R21, 1R23 1-CNMT -LINER-AREA-3 Containment liner, E1.11 UTT 1R19, 1R21, Area 3 1R23 1-CNMT -MOISTBARR Moisture barrier E1.30 GV 1 R19, 1 R21, 1R23 1-CNMT-BLDFLG Fuel canal blind flange E1.11 VT-3 1R19, 1R21, bolting 1R23 1-CNMT-EQUHATCH Equipment hatch E1.11 VT-3 1R19, 1R21, bolting 1R23 FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 20 of 54 Current IWE/IWL Interval Component ID Description Item Number 1-CNMT -SPARE-PENE-Electrical penetration E1.11 BOLTING bolting, spares only 1-CNMT -CONCRETE Containment concrete L 1.11 2-CNMT-LINER Containment liner E1.11 2-CNMT -MOISTBARR Moisture barrier E1.30 2-CNMT -BLDFLG Fuel canal blind flange E1.11 bolting 2-CNMT-EQUHATCH Equipment hatch E1.11 bolting 2-CNMT -ELEC-PENE-Electrical penetration E1.11 BOLTING bolting 2-CNMT -CONCRETE Containment concrete L 1.11 Exam Scheduled Method Outage GV 1R19, 1R21, 1R23 VT-3 1R19 GV 2011,2016 GV 2R13, 2R15, 2R17, 2R19 GV 2R13, 2R15, 2R17, 2R19 VT-3 2R14, 2R16, 2R18 VT-3 2R14, 2RI6, 2R18 GV 2R15, 2R17, 2R19 VT-3 2R14 GV 2011,2016 Item Number Refers to item numbers listed in ASME Code Section XI, Table IWE-2500-1, and Table IWL-2500-1, both titled "Examination Categories" Exam Method GV -General Visual; UTT -ultrasonic thickness test; and VT examination method defined in ASME Code Section XI, Paragraph IWA-2213, "VT -3 Examination" Schedule The scheduled dates or refueling outages for inspections during the current Containment lnservice Inspection Interval are based on requirements of ASME Code Section XI, Tables IWE-2500-1, and Table IWL-2500-1.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 21 of 54 Next IWE/IWL Interval Component ID Description Item Number 1-CNMT-LINER Containment liner E1.11 1-CNMT -LINER-AREA-3 Containment liner, E1.11 Area 3 1-CNMT -MOISTBARR Moisture barrier E1.30 1-CNMT -BLDFLG Fuel canal blind flange E1.11 bolting 1-CNMT-EQUHATCH Equipment hatch E1.11 bolting 1-CNMT -SPARE-PENE-Electrical penetration E1.11 BOLTING bolting, spares only 1-CNMT -CONCRETE Containment concrete L 1.11 2-CNMT-LINER Containment liner E1.11 2-CNMT -MOISTBARR Moisture barrier E1.30 2-CNMT -BLDFLG Fuel canal blind flange E1.11 bolting 2-CNMT-EQUHATCH Equipment hatch E1.11 bolting 2-CNMT-ELEC-PENE-Electrical penetration El.ll BOLTING bolting 2-CNMT -CONCRETE Containment concrete E1.11 Exam Scheduled Method Outage GV 1 R25, 1R28, 1R30 UTT 1 R25, 1R28, 1R30 GV 1R25, 1R28, 1R30 VT-3 1R25, 1R28, 1R30 VT-3 1R25, 1R28, 1R30 GV 1 R25, 1 R27, VT-3* 1R29 GV 2021, 2026 GV 2R21, 2R23, 2R25 GV 2R21, 2R23, 2R25 VT-3 2R20, 2R23, 2R24 VT-3 2R20, 2R23, 2R24 GV 2R21, 2R23, VT-3* 2R25 GV 2021, 2026 Item Number Refers to item numbers listed in ASME Code Section XI, Table IWE-2500-1, and Table IWL-2500-1, both titled "Examination Categories" Exam Method GV -General Visual; UTT -ultrasonic thickness test; and VT-3-examination method defined in ASME Code Section XI, Paragraph IWA-2213, "VT -3 Examination" Schedule The scheduled dates for inspections during the next Containment lnservice Inspection Interval are proposed dates in that the next interval inspection program has not been approved at this time.

• VT-3 examination is performed once per 10-year interval.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 22 of 54 Containment Surfaces Subject To Augmented Examinations BVPS-1 and BVPS-2 have no areas subject to ASME Code Section XI, Subsection IWE, augmented examinations.

The 75 random and the 8 non-random examinations of each unit discussed in Section 3.2.9 are required by a license condition for license renewal. 3.2.2 Containment Structural Integrity Test Test Description Containment Structural Integrity Test procedures for BVPS-1 and BVPS-2 are utilized to perform general visual observations of the accessible interior and exterior surfaces of the containment structure in order to identify evidence of deterioration that may affect the containment structural integrity or leak tightness in accordance with the following.

• Technical Specification Surveillance Requirement 3.6.1.1 requires, in part, visual examinations in accordance with the Containment Leak Rate Testing Program.

• Technical Specification 5.5.12.a requires, in part, visual examinations in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September, 1995. (Regulatory Position 3 requires that these examinations should be conducted prior to initiating a Type A test and during two other refueling outages before the next Type A test if the interval for the Type A test has been extended to 10 years, in order to allow for early uncovering of evidence of structural deterioration.)

• ASME Code Section XI, Subsections IWE and IWL require visual examinations.

General visual observations of the accessible interior and exterior surfaces of the containment structure are performed on a frequency that meets ASME Code Section XI, Subsections IWE and IWL, and 10 CFR 50 Appendix J, Option B. With the implementation of the proposed change, Technical Specification 5.5.12 will be revised by replacing the reference to Regulatory Guide 1.163 with reference to NEI 94-01, Revision 3-A. A general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity is required by NEI 94-01, Revision 3-A, prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. Recent Examination Results The following is a summary of results of examinations that were recently performed.

BVPS-1, Examinations Completed May 6, 2012 An examination was successfully completed during the spring 2012 refueling outage (1 R21) for both the exterior concrete surfaces and interior steel liner of the BVPS-1 FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 23 of 54 containment building.

The conditions identified were minor in nature and would not affect the structural integrity of the containment building.

Identified conditions were documented in condition reports. Inspection of the Reactor Containment Cylindrical Steel Liner and Containment Test Channel Vent Plugs Twenty-two deficiencies were identified on the containment cylindrical steel liner. Prior to repair, the deficiencies were examined by a qualified VT -3 inspector.

Most of the areas identified involved topcoat debonding from the primer. At these locations the primer was intact so no bare metal was exposed. One item involved degraded caulking at the wall to floor intersection and the caulking was replaced.

One item previously identified during the fall2010 refueling outage (1R20) was repaired, re-inspected and found to be satisfactory.

Another item identified boric acid on the keyway floor. The boric acid was cleaned. Following cleaning an as-left visual inspection was performed by a qualified NDE inspector, and no degradation was observed.

The other identified deficiencies were repaired, re-inspected, and found to be satisfactory.

Inspection of the Reactor Containment Dome Steel Liner Two deficiencies were identified on the containment dome steel liner. The two deficiencies were determined to be stains on the surface paint and were wiped off. Inspection of the Reactor Containment Exterior Cylindrical Concrete Structure Several concrete deficiencies were identified on the exterior cylindrical portion of the containment building.

Most of these deficiencies were identified and addressed prior to the spring 2012 refueling outage (1 R21 ). An engineering evaluation of the identified cylindrical concrete deficiencies was performed.

The evaluation concluded that the deficiencies were not structurally significant and would not impact the containment structural integrity.

Inspection of the Reactor Containment Exterior Concrete Dome Structure Several concrete deficiencies were identified on the exterior dome portion of the containment building.

A engineering evaluation of the identified concrete dome deficiencies was performed.

The evaluation concluded that the deficiencies were not structurally significant and would not impact the containment structural integrity.

Conclusion BVPS-1 containment structural integrity tests were successfully completed on May 7, 2012. In one case boric acid was cleaned, and the area inspected with satisfactory results. Two other deficiencies involved stains that were wiped off. Other identified deficiencies were accepted by an engineering evaluation or repaired in accordance with ASME Code Section XI, Subsection IWE and IWL. The BVPS-1 FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 24 of 54 containment building continues to remain capable of performing its safety-related functions.

BVPS-2, Examinations Completed March 31, 2011 An examination was successfully completed during spring 2011 refueling outage (2R15) for both the exterior concrete surfaces and interior steel liner of the BVPS-2 containment building.

The conditions identified were all minor in nature and would not affect the structural integrity of the containment building.

All conditions identified were documented in condition reports. Inspection of the Reactor Containment Cylindrical Steel Liner and Containment Test Channel Vent Plugs Eighteen deficiencies were identified on the containment cylindrical steel liner. Prior to repair, these deficiencies were examined by a qualified VT -3 inspector and found to be satisfactory.

The eighteen deficiencies were addressed by coating repairs, re-inspected and found to be satisfactory.

Inspection of the Reactor Containment Dome Steel Liner No deficiencies were identified on the containment dome steel liner. Inspection of the Reactor Containment Exterior Cylindrical Concrete Structure Several cylindrical concrete deficiencies were identified.

An engineering evaluation of the identified cylindrical concrete deficiencies was performed.

The evaluation concluded that the deficiencies were not structurally significant and would not impact the containment structural integrity.

Although, not structurally significant, it was recommended that six areas be repaired to prevent further deterioration.

Two areas involve rusting inserts for construction forms that were grouted over after use. Two areas involve rusted embedded plates within the safeguards structure.

Two areas involve concrete popouts or spalls. The size of these spalls are no larger than a half dollar and about one inch deep. While the missing concrete was not structurally significant these areas were repaired.

Inspection of the Reactor Containment Exterior Concrete Dome Structure Several concrete dome deficiencies were identified.

An engineering evaluation of the identified concrete deficiencies was performed.

The evaluation concluded that the deficiencies were not structurally significant and would not impact the containment structural integrity.

Conclusion BVPS-2 containment structural integrity tests were successfully completed on April 5, 2011. Identified deficiencies were accepted by an engineering evaluation or corrected by repair in accordance with ASME Code Section XI, Subsection IWE and FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 25 of 54 IWL. The BVPS-2 containment building continues to remain capable of performing its safety-related functions.

Supplemental Inspection Requirement With the implementation of the proposed change, Technical Specification 5.5.12 will be revised by replacing the reference to Regulatory Guide 1.163 with reference to NEI 94-01, Revision 3-A. This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. The performance of containment structural integrity tests are utilized to perform general visual observations of the accessible interior and exterior surfaces of the containment structures.

These examinations are also utilized to perform inspections in accordance with ASME Code Section XI, Subsections IWE and IWL. Additionally, the tests will continue to be performed to meet the requirements of Technical Specification 5.5.12 with the incorporation of NEI 94-01, Revision 3-A guidelines.

3.2.3 Containment

Liner Test Channel Plugs The reactor containment building has a continuously welded carbon steel liner that acts as a leak-tight membrane.

Welded seams were originally covered with continuously welded leak test channels that were installed to facilitate leak testing of welds during liner erection.

Since initial construction, several test channels have been removed at BVPS-1. Also, test channels were not installed on liner plate seams associated with the BVPS-1 Steam Generator Replacement Project construction opening. Channels in the hemispherical dome and containment mat are covered with concrete while those on the cylindrical liner wall are exposed. Test ports that were provided for leak testing were sealed with vent plugs after the completion of the testing. These plugs were to remain in place during subsequent Type-A leak rate testing. During the second refueling outage for BVPS-2 in 1990, the results of an inspection performed prior to the Type A containment leakage rate test showed that 25 test channel vent plugs were missing. During a BVPS-1 shutdown in 1991, it was determined that 27 vent plugs in the containment floor liner test channels were missing. The missing test channel vent plugs allowed moisture and condensation inside the test channels, leading to minor corrosion of the liner. The test channels were evaluated to determine the impact to the containment liner, and the evaluation results were submitted to the NRC with a BVPS-1 and BVPS-2 license amendment request dated October 1, 1990. The requested amendments were approved by the NRC and documented in a June 23, 1992 safety evaluation (ADAMS Accession No.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 26 of 54 ML003767919).

After further evaluation, it was concluded that these initial evaluations contained some nonconservative assumptions with regard to the corrosion rates in the test channels.

Corrective action was taken to arrest the corrosion rate in the affected test channels, by evacuating or flushing, filling with inert gas, and sealing the test channels.

The further evaluation and corrective actions are documented in a December 30, 1992 letter to the NRC (ADAMS Accession No. 9301140069).

These corrosion rate analyses meet the 10 CFR 54.3 definition of time-limited aging analyses and must be evaluated for the period of extended operation.

The minimum required thickness for the Containment liner has been determined for the various portions of the liner. The limiting liner portion is the liner floor plate, which has a fabrication thickness of 0.25 inches and a minimum required thickness of 0.125 inches. Thus, the corrosion allowance is 0.125 inches (125 mils). The inerting and sealing of the test channels significantly reduced the theoretical corrosion rates in the channels.

For BVPS-1 the total estimated penetration due to corrosion of the inerted channel was estimated at 69.2 mils for 43 years of plant operation.

The maximum expected corrosion rate for the carbon steel liner in this low oxygen environment was determined to be 0.39 mils per year. Therefore, projecting the expected corrosion penetration with the maximum expected corrosion rate to the end of the period of extended operation results in an additional 7.8 mils of corrosion.

Adding this to the previous expected corrosion penetration depths yields 77.0 mils of corrosion penetration.

For BVPS-2 the total estimated penetration due to corrosion of the inerted channel was estimated at 82.7 mils for 43 years of plant operation.

The maximum expected corrosion rate for the carbon steel liner in this low oxygen environment was determined to be 0.39 mils per year. Therefore, projecting the expected corrosion penetration with the maximum expected corrosion rate to the end of the period of extended operation results in an additional 7.8 mils of corrosion.

Adding this to the previous expected corrosion penetration depths yield 90.5 mils of corrosion penetration.

These results are well within the corrosion allowance of 125 mils. Therefore, the BVPS-1 and BVPS-2 containment liner corrosion analysis has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

3.2.4 Containment

Liner Corrosion 2006 During the spring 2006 refueling outage (1R17), a temporary construction opening was created in the BVPS-1 containment structure for the replacement of the steam generators and reactor vessel head. Three areas of corrosion were identified on the containment liner plate during creation of the opening. These areas were on the outside of the liner, that is, on the side in contact with the concrete.

Loss of material was identified for all three areas of corrosion.

Visual examinations and wall thickness measurement of the three areas revealed the following conditions:

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 27 of 54 Area 1 was approximately 2 feet by 2 feet and was located near the center of the plate. The corroded area had an irregular surface with isolated pits. Ultrasonic wall thickness measurements were made using the autoscan process. The minimum reported thickness in the corroded area was 0.225 inches at a pit. Area 2 was approximately 1 foot 6 inches by 2 feet and was located near the right edge of the plate approximately one-third of the way up the plate. The corroded area had an irregular surface with isolated pits. The corroded area spanned portions of two liner plates and the weld joining them. There was a long, narrow, valley-like thinned area in one of the plates. Ultrasonic wall thickness measurements were made using the autoscan process. The minimum reported thickness in the corroded area was 0.151 inches at a pit away from the valley-like area. Because of the presence of a leak chase behind the weld, the autoscan could not measure the thickness at the weld or on the second plate. However, the degree of pitting observed visually on the weld and adjacent plate appeared to be less than on the scanned plate. Area 3 was approximately 8 inches by 1 foot and was located near the upper left corner of the plate. There is a lifting lug welded to the plate to aid in removal, and the lug encroaches on one end of the corroded area. The degree of corrosion observed in Area 3 was much less than what was seen in the two other areas. Area 3 was not selected for laboratory analysis, since the relatively shallow corrosion was unlikely to shed light on the corrosion mechanism.

A manual ultrasonic examination performed on this area confirmed the lesser degree of thinning.

The plate was essentially at nominal thickness with six small pits (minimum thickness of 0.330 inches) reported.

Areas 1 and 2 were selected for laboratory analysis because of the greater degree of degradation.

The size of each removed sample included the entire degraded area and the autoscan reference starting point. The sections of the liner, identified as Areas 1 and 2, removed for analysis were replaced with new plate material.

The process and procedures, including inspection and NDE, were the same as those used for reinstallation of the liner plate cut from the construction opening. Laboratory examination was performed on the two areas, Areas 1 and 2, with significant material loss. The laboratory examination characterized the corrosion as general pitting corrosion (rusting).

Laboratory examination was also performed on concrete samples removed from the construction opening. The lab analysis did not identify a probable cause for the corrosion.

A structural evaluation of the liner was prepared by Stone & Webster Engineering, the original architect and engineering firm for the containment structure.

The Stone & Webster report concluded that the design basis for the containment liner was not adversely affected by the as-found conditions.

The thickness of the remaining sound FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 28 of 54 metal is adequate to maintain the design safety function of the liner as a leak tight membrane.

Since there is reasonable assurance that the corrosion occurred early in plant life and has likely abated, monitoring the liner surface in accordance with the ASME Code Section XI program ensures the leak tight function of the liner. The BVPS-1 procedure "Containment Structural Integrity Test," was augmented to include follow up examinations by a qualified inspector for potentially flawed areas discovered during inspection.

The spring 2006 refueling outage (1R17) inspection was completed and the results were documented in the corrective action program. Follow up inspections of suspect areas by a qualified inspector were completed during 1 R 17. Included in the restoration of the construction opening was a scheduled Type A integrated leak rate test following restoration.

The Type A test results satisfied the leakage rate acceptance criteria of Technical Specifications.

The disposition of Area 3 was to accept the area as-is. The remaining wall thickness in Area 3 was greater than the minimum uniform plate thickness of 0.278 inches. This is a conservative value since the report "Containment Liner Degradation First Energy Nuclear Operating Company Beaver Valley Unit 1, dated March 8, 2006," demonstrates that the required thickness for localized thinning could be much less. A pit with a radius of 0.75 inches and a plate thickness of 0.090 inches would withstand design accident conditions.

The area was scheduled to be inspected for the next three consecutive 40 month periods. Baseline thickness measurements were established by ultrasonic test after the construction opening liner plate was restored and the interior surface painted. Markings on the liner were established for repeatability of the ultrasonic test measurements over the required intervals.

Ultrasonic test thickness measurements of Area 3 were added to the inservice inspection examination schedule for refueling outages in the spring of 2009 (1R19), spring of 2012 (1R21), and spring of 2015 (1R23). These outages were contained in each of the next three consecutive 40 month periods. It was concluded that the as-found condition in 1 R 17 was acceptable and that the liner plate remained capable of performing its design basis function.

No evidence of loss of material was found during the 1 R19 and 1 R21 examinations.

An assessment of the operability of the BVPS-2 containment was performed in response to the BVPS-1 issue. This assessment showed reasonable assurance of liner integrity and as such was determined to be operable.

This event is also documented in the NRC "Containment Liner Corrosion Operating Experience Summary, Technical Letter Report-Revision 1 ,"dated August 2, 2011 (ADAMS Accession No. ML 112070867).

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 29 of 54 3.2.5 Containment Liner Corrosion 2009 On April21, 2009, during the 1R19 refueling outage, an ASME Code Section XI Subsection IWE General Visual Examination was performed on the interior containment liner, and an indication was identified.

After cleaning the area and removal of the corrosion products, a rectangular 1 inch by 3/8 inch (0.375 square inch) hole was discovered that penetrated through the containment steel liner plate. The cause. of the hole was pitting type corrosion (rust) originating from the concrete side of the liner plate. The corrosion was caused by foreign material (wood) that was in contact with the containment carbon steel liner. The wood was left behind as a result of inadequate housekeeping practices during the original construction of the containment wall. The hole was repaired by replacing the affected portion of the liner and was followed by testing per ASME Code Section XI requirements with satisfactory results. Corrective actions initiated for the event included performance of volumetric testing of the replaced area during the fall 2010 refueling outage (1 R20). Also, additional 100 percent visual examinations of the accessible portions of the liner, identical to that of the IWE General Visual Inspection, were performed during the next BVPS-1 and BVPS-2 refueling outages (1 R20 and 2R14, respectively).

Large Early Release Frequency (LERF) Significance During a design basis accident, the containment pressure is bounded by containment design pressure of 45 psig. At this design basis accident pressure with the BVPS-1 containment free air volume (and assuming no credit for the containment concrete wall which would act to restrict radioactive releases), the probabilistic risk assessment concluded that the containment liner opening needs to be at least 2 inches internal diameter (approximately

3.1 square

inches in area) in order to be considered as an LERF concern. This LERF equivalent diameter was determined using the guidance of Westinghouse topical report WCAP-16378-P, "Westinghouse Owners Group Definition for Large Early Release Frequency (LERF)," that references NUREG-1493, "Performance-Based Containment Leak-Test Program." WCAP-16378-P also mentions that, as a rule of thumb, the NRC has accepted a 2-inch internal diameter pipe size as the lower bound of a large release. Additionally, NRC Inspection Manual Chapter 0308, Appendix H, "Technical Basis for Containment Integrity Significance Determination Process," also recognizes that the 100 percent volume per day leakage rate is approximately equivalent to a hole size in containment of 2.5 to 3.0 inches in diameter for pressurized water reactors with large dry containments.

Since the equivalent diameter of the identified liner opening was 0.69 inch, the hole did not impact the LERF. Therefore, this event was considered to have very low safety significance.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 30 of 54 Core Damage Frequency (CDF) Significance The as-found BVPS-1 containment liner hole area of approximately 0.375 square inches will not impact containment overpressure for the design basis loss of coolant accident, and therefore, will not impact the net positive suction head of engineered safety features pumps (low head safety injection and recirculation spray pumps) taking suction from the containment sump. Also with the hole being located at containment elevation 746 feet, most of the containment release through the opening would be a mixture of steam and air. Therefore, the containment sump inventory accumulated at elevation 692 feet will not be lost through this containment liner opening at elevation 7 46 feet. The makeup system to the refueling water storage tank, can provide additional water inventory to the containment sump to account for any steam leakage lost, if necessary.

Based on the above, the as-found liner hole will not impact the core damage frequency.

A 2009 review of the BVPS-1 procedure, "Containment Leakage Rate Testing Program," indicated that the maximum allowable containment leakage rate, La, at Pa (calculated peak containment internal pressure for the BVPS-1 design basis loss of coolant accident of 43.1 psig), shall be 0.10 percent of containment air weight per day as defined by Technical Specification 5.5.12.c.

This containment total allowable La is equal to 6,831 SCFD. A review of the previous Type A leak rate test performed during 1 R17, (April15, 2006) indicated that the as-left leakage rate was 2,393 SCFD. This shows that there is margin of 4,438 SCFD to the Technical Specification allowable limit. In addition, over the previous 10 years (2000 to 2009), BVPS-1 averaged a local leak rate (for Type B and C testing) of approximately 37 percent of the allowable containment leakage rate of 0.6 La. This is based on the maximum pathway leakage measured during refueling outages. The past results of the Type A containment integrated leak rate tests performed for BVPS-1 (1978 to 2009) were reviewed.

Based on the low leak rate and stable trend, it was concluded that no previous issues had challenged the design integrity of the liner plate. Plant personnel observed that paint still covered the affected area during the as-found inspection of the area containing the liner deficiency.

When the blistered area was touched, the intact paint blister ruptured.

This as-found condition indicated that there was reasonable assurance that no leakage was experienced through the containment liner area containing the through wall liner corrosion since the last Type A test. Review of operating experience indicated that a similar through-wall containment liner corrosion condition had occurred at the North Anna, Unit No. 2, Brunswick, Unit No. 2, and D. C. Cook, Unit No. 2, power plants. The North Anna, Unit No. 2, liner hole size was approximately 1/4 inch in diameter.

Testing was performed at North Anna, Unit No. 2 (following discovery of the liner hole), at various pressures up to and including the designed peak accident pressure of 45 psig. At 45 psig, leakage was measured to be 21 standard cubic feet per hour (504 SCFD). The BVPS-1 containment design and atmosphere conditions are similar to North Anna, Unit No. 2. The leakage from the 0.69 inch equivalent diameter liner hole at BVPS-1 is FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 31 of 54 projected to be 160 standard cubic feet per hour (3,840 SCFD) based on extrapolating North Anna's test results. Combining this leakage rate and the as-left leakage rate of 2,393 SCFD, the new total leakage rate would be 6,233 SCFD. This total leakage rate is less than the Technical Specification maximum allowable containment leakage rate (La) of 6,831 SCFD. Based on the projected leakage rate and findings, there is reasonable assurance that the containment air leakage since the last Type A test would not exceed the maximum leakage rate allowed by Technical Specification 5.5.12.c.

This event is also documented in the "Containment Liner Corrosion Operating Experience Summary, Technical Letter Report-Revision 1," dated August 2, 2011 (ADAMS Accession No. ML 112070867).

3.2.6 Containment

Liner Corrosion 2013 During the BVPS-1 2013 refueling outage, a containment coatings inspection was performed on the interior containment liner, and an indication was identified on October 4, 2013. After cleaning the area and removal of the corrosion products, a hole initially determined to be approximately 0.40 inch by 0.28 inch in size was discovered in the containment steel liner plate. UT examinations performed on the liner in the vicinity of the hole indicated that wall thinning may have occurred below the level of the containment basement floor, requiring concrete to be excavated for access to a lower portion of the liner. The affected portion of the liner was removed and sent for examination.

The examination report identified two definite through wall holes and a third hole was found after removing the liner plate section around the second hole. For conservatism this third area has been included in the safety significance and past operability determinations.

The total area of missing metal was calculated to be 0.395 square inch. The three holes were found to be of very low safety significance.

The cause of the holes was pitting type corrosion (rust), stemming from an electrolytic corrosion cell within a localized area originating from foreign material (rayon) that was in contact with the outside surface of the containment carbon steel liner. The rayon was left behind as a result of inadequate housekeeping practices during the original construction of the containment wall. The holes were repaired by replacing the affected portion of the liner followed by satisfactory testing per ASME Code Section XI requirements.

Corrective actions initiated for the event include performance of volumetric testing of the replaced area during the next BVPS-1 refueling outage, scheduled for 2015. Additional corrective actions were assigned to the site aging-management program owner to evaluate whether changes are necessary to the aging management program due to the as-found condition.

This evaluation is scheduled for completion in April 2014. Eight non-random UT examinations were performed during the fall 2013 refueling outage (1 R22). The areas examined were located on the lower elevation of the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 32 of 54 containment building (elevation corresponding to the through wall holes), and were spaced approximately equidistant around the containment as access permitted.

A manual UT thickness examination was performed on 1 00 percent of the surface of the eight one-foot-square areas. There was no thickness measured below the nominal thickness, and there was no evidence of wall loss. Safety Significance The BVPS-1 containment liner holes (with a combined total area of approximately 0.395 square inches) that were found during 1 R22 are not expected to impact containment overpressure or net positive suction head for engineered safety features pumps taking suction from the containment sump. This conclusion is based on a response to NRC additional questions relative to containment overpressure credit dated January 25, 2006 (ADAMS Accession No. ML060330262).

This response stated that based on a study that was done to determine the impact of operation of the BVPS-1 recirculation spray pumps under accident conditions with failures of containment isolation (for example, pre-existing holes) for a range of sizes of one inch through three inches in diameter, that there was an insignificant impact on the calculated net positive suction head margin, for the limiting outside recirculation spray pump case. The first containment liner hole was located about 7 inches above the containment basement floor, so sump inventory could be lost through the hole. However, this leakage is expected to be insignificant due to the relatively small hole area, and approximate 4.5 foot thick concrete shell backing. The other containment liner holes were located about 2 inches below the containment basement concrete floor line, so no significant sump inventory would be lost through these holes. Therefore, sump inventory and available net positive suction head margins would not be significantly impacted, and the containment liner holes would not impact the core damage frequency.

The leakage limit applicable throughout the operating period since the last successful leakage surveillance (Type A test) performed during the spring 2006 refueling outage (1 R17) on April15, 2006 is the 0.10 percent of containment air weight per day (La) defined by Technical Specification 5.5.12.c for Mode 1 through 4 operations.

According to the Unit 1 Containment Leakage Rate Testing Program, this total allowable La limit is equal to 6831 SCFD. The as-left leakage rate data from that April 15, 2006 Type A test was 0.0350 percent containment air weight per day or 2393 SCFD. Thus, at the time there existed a 4438 SCFD margin to the Technical Specification allowable limit of 1.0 La. Since the last Type A test in 2006, Beaver Valley Unit 1 has averaged a Local Leak Rate (Type B & C) of approximately 42 percent (1703 SCFD) of the allowable containment leakage rate of 0.6 La (4098 SCFD). These results are based on the maximum pathway leakage measured during refueling outages, including the spring 2006 refueling outage (1 R17) through spring 2012 refueling outage (1 R21 ). The past results of the Type A containment integrated leak rate test performed for BVPS-1 from 1978 through 2009 were also reviewed.

Based on the low leak rate and stable trend, it FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 33 of 54 is concluded that no previous issues have challenged the design integrity of the liner plate. The assumed leakage that could be passed through the total of the three holes, is approximately 4053 SCFD, based on extrapolating North Anna's test results as discussed previously.

Combining this leakage rate and the as-left leakage rate of 2,393 SCFD, the new total leakage rate would be 6,446 SCFD. This total leakage rate is less than the Technical Specification maximum allowable containment leakage rate (La) of 6,831 SCFD. Based on the projected leakage rate and findings, there is reasonable assurance that the containment air leakage since the last Type A test would not exceed the maximum leakage rate allowed by Technical Specification 5.5.12.c.

The plant risk associated with the BVPS-1 containment liner holes discovered on October 4, 2013 during the 1 R22 planned visual inspections of the internal containment liner and protective coatings, and the follow-up lab analysis is considered to be very low. This is based on the total area of the containment liner holes not impacting the likelihood of core damage and being much less than the calculated area required to exceed 100 percent of the containment volume leakage per day. Therefore, the safety significance of the event would be classified as very low safety significance.

3.2.7 Inaccessible

Areas For Class CC and MC applications, FENOC shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, BVPS shall provide the following in the lSI Summary Report, as required by 10 CFR 50.55a(b)(2)(viii)(E) and 10 CFR 50.55a(b)(2)(ix)(A):

• A description of the type and estimated extent of degradation, and the conditions that led to the degradation;

• An evaluation of each area, and the result of the evaluation, and;

• A description of necessary corrective actions. FENOC has not needed to implement any new technologies to perform inspections of any inaccessible areas at this time. However, FENOC actively participates in various nuclear utility owners groups and ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry.

Industry operating experience is also continuously reviewed to determine its applicability to BVPS. Adjustments to inspection plans and availability of new, commercially available technologies for the examination of the inaccessible areas of the containment would be explored and considered as part of these activities.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 34 of 54 3.2.8 Containment Coatings Inspections The site Containment Coatings Inspection and Assessment Program defines the requirements and responsibilities for a program to implement inspections during refueling outages for the purpose of assessing the condition of the protective coatings on structures and equipment in the reactor containment buildings.

These inspections assure compliance with NRC Generic Letter 2004-02, "Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Water Reactors." Containment coatings inspections are a scheduled activity conducted during refueling outages. The examination areas are selected such that all painted surfaces are inspected over a two outage timeframe.

This is done to comply with the recommendations of Nuclear Energy Institute document NEI 04-07, "Containment Sump Evaluation Methodology." If normally accessible areas are inaccessible during an inspection, then they may be omitted from the current inspection.

Inaccessible areas shall be identified as inaccessible in the inspection report and the inaccessible areas should be scheduled to be included in the next unit inspection.

Identified, degraded, or questionable coatings shall be remediated prior to the unit entering Mode 4 at the end of an outage. The remediation may include recoating the affected area with a qualified coating system, or removal of the degraded or questionable coatings to a sound and tightly adhered condition.

Results of Recent Coatings Inspections BVPS-1 -Fa112013 Refueling Outage The condition of the protective coatings inspected during fall 2013 refueling outage was typical and expected for the vintage of the coatings.

In general the coatings were found to be performing well. Abrasion damage was the most common condition found. Floors and walls had numerous small nicks, scratches, and impact marks from material handling.

Most of these spots were small in size and the paint tightly adhered around the area. Some of the coating abrasion spots therefore did not require repair. Areas of cracking, peeling, blistering, and flaking paint were found. Most spots were small in size and some originated from abrasion or impact. In most of these cases it was found that the topcoat was de-bonded from the primer. On steel surfaces where the primer was penetrated, light surface rust was found in some cases. The rust was easily removed by light brushing or sanding. The rust was surface rust only and did not reduce the section or thickness of the steel. Conditions identified were minor in nature and limited in their extent. The coatings were found to be performing acceptably and no negative trends were identified.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 35 of 54 Coating conditions that would contribute to coating failure and contribute to the debris load transported to the sump were noted for repair. These conditions included peeling, blistering, flaking, cracked or lifted paint. When scraped during repair, coatings were found to be adherent.

In a few areas the repair area grew beyond the visible degraded area when prepared for repair. Those areas that did expand were taken back to sound coating during the repair. Repair of those areas identified as requiring repair was completed.

One of the items identified was a paint blister on the containment liner plate. Further investigation revealed a paint blister with corrosion products and subsequent discovery of a through liner hole. The degraded liner plate was removed and replaced, and the repaired area was painted. This item is discussed further in Section 3.2.6. BVPS-2-Fall2012 Refueling Outage The condition of the protective coatings inspected during the fall 2012 refueling outage was typical and expected for the vintage of the coatings.

Abrasion damage was the most common condition found. Floors and walls had numerous small nicks, scratches and impact marks from material handling.

Most of these spots were small in size and the paint tightly adhered around the area. Areas of cracking, peeling and flaking paint were found. Most spots were small in size and some originated from abrasion or impact. In most of these cases it was found that the topcoat was pulled away from the primer. On steel surfaces, where the primer was penetrated, light surface rust was found in some cases. The rust was easily removed by light brushing or scraping.

The rust was surface rust only and did not reduce the thickness of the steel. Conditions identified were minor in nature and very limited in their extent. The coatings were found to be performing well and no negative trends were identified.

Observed coating conditions that would contribute to coating failure were noted for repair. These conditions included peeling or flaking paint, and cracked or lifted paint. Those areas requiring repair were placed in a work order for repair of the coatings.

When scraped during repair, coatings were found to be adherent.

The repair area did not grow beyond the visible degraded area when prepared for repair, indicative of a strong bond between the paint layers. All areas were taken back to sound coating during the repair. Four areas were inaccessible for coatings repair, all requiring scaffold to access. Repair of these areas was deferred until the spring 2014 refueling outage. Accessible areas requiring repair were repaired during the fall 2012 refueling outage. 3.2.9 License Renewal Commitments License renewal activities led to various commitments related to the BVPS containments.

The following provides a status of actions that were identified and committed to by FENOC in the BVPS-1 License Renewal Application.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 36 of 54 BVPS-1 Updated Final Safety Analysis Report (UFSAR) Commitment 32: Supplemental volumetric examinations will be performed on the BVPS-1 containment liner prior to the period of extended operation.

A minimum of seventy-five (one foot square) randomly selected (as described in FENOC Letter L-09-205) sample locations will be examined (as described in FENOC Letter L-09-243).

If degradation is identified, it will be addressed through the corrective action program (as described in FENOC Letter L-09-243).

Status: Thirty-eight of the seventy-five randomly selected examinations were performed during the 2010 refueling outage as part of the sample plan and were completed with no evidence of loss of material.

Thirty-seven of the seventy-five randomly selected examinations were examined during the 2012 refueling outage as part of the sample plan and were completed with no evidence of loss of material.

Based on the 2010 and 2012 random examination results, a 95 percent confidence level has been achieved that 95 percent of the unexamined accessible containment liner is not degraded.

Since there was no evidence of degradation, no additional sampling or successive examinations are required.

BVPS-1 UFSAR Commitment 33: Supplemental volumetric examinations will be performed on the Unit 1 containment liner. A minimum of 8 non-randomly selected locations will be examined, focusing on areas most likely to experience degradation based on past operating experience (as described in FENOC Letter L-09-242).

If degradation is identified, it will be addressed through the corrective action program. Status: Eight examinations at non-random locations were performed during the fall 2010 refueling outage. Two examinations at non-random locations were completed prior to the outage, in May 2010. The locations selected included irregular contours of the liner, repainted areas of the liner, areas adjacent to the discovered through-wall hole, the below-grade area between elevations 725 feet and 735 feet, and the area below the 2006 steam generator replacement opening. All 10 locations examined online and during the 2010 refueling outage were completed with no evidence of loss of material.

BVPS-1 UFSAR Commitment 34: A summary of results for each phase of volumetric testing (described in Unit 1 Commitments No. 32 and No. 33) will be documented in a letter to the NRC. Status: By letter dated February 14, 2011 (ADAMS Accession No. ML 110470404), FENOC submitted the BVPS-1 containment liner random and non-random examinations report for the fall 2010 refueling outage. By letter dated July 11, 2012 (ADAMS Accession No. ML 12195A155), FENOC submitted the BVPS-1 containment liner random and random examinations report for the spring 2012 refueling outage. In response to a FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 37 of 54 request for additional information from the NRC staff, FENOC submitted supplemental information regarding these exams by letter dated March 4, 2013 (ADMAS Accession No. ML 13064A333).

The NRC staff review of the information in the letters referenced above was documented in a letter dated Apri130, 2013 (ADAMS Accession No. ML 13112A275).

This NRC staff review concluded that FENOC provided the information described in Commitment 34 of Appendix A of NUREG-1929, Supplement 1, "Safety Evaluation Report Related to the License Renewal of Beaver Valley Power Station, Units 1 and 2," (ADMAS Accession No. ML093140250).

The NRC staff also concluded that the information provided demonstrates that the licensee has completed the actions described in Commitment Nos. 32, 33, and 34 of NUREG-1929, Supplement 1, Appendix A. BVPS-1 UFSAR Commitment 35: FENOC will evaluate if an appropriate/applicable statistical method exists to gain additional insight into potential liner degradation.

Data gathered will be evaluated and used to determine the general state of the liner. Status: FENOC activities related to this commitment are in progress with a scheduled completion date of January 29, 2016. The following provides a status of actions that were identified and committed to by FENOC in the BVPS-2 License Renewal Application:

BVPS-2 UFSAR Commitment 33: Supplemental volumetric examinations will be performed on the Unit 2 containment liner prior to the period of extended operation.

A minimum of seventy-five (one foot square) randomly selected (as described in FENOC Letter L-09-205) sample locations will be examined (as described in FENOC Letter L-09-243).

If degradation is identified, it will be addressed through the corrective action program (as described in FENOC Letter L-09-243).

Status: Sixty-one of the 75 randomly selected examinations were performed during the spring 2011 refueling outage. Sixty of 61 locations examined as part of the sample plan were completed with no evidence of loss of material.

The ultrasonic test (UT) examination of Location 2RN-063 revealed an area of lower than expected thickness and is addressed below. Examination of random location (2RN-063) required additional actions during the spring 2011 refueling outage. Manual UT examination of location 2RN-063 identified an indication on the inaccessible side of the liner, having a general thickness below the statistical screening criterion.

The lowest thickness measured within the 2RN-063 FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 38 of 54 examination area was 0.310 inch. A subsequent autoscan examination of 2RN-063 verified the presence of the indication along with an approximately 2 inch (vertical) by 10 inch (horizontal) area, extending beyond location 2RN-063, with lower thickness than the surrounding area. The general thickness of this 2 inch by 10 inch area was between 0.300 inch and 0.400 inch. The lowest thickness observed within the extended area was 0.267 inch at a localized point. The minimum design thickness for the general wall of the liner at this location is 0.213 inch. The localized point dimension is 0.250 inch in the vertical axis by 0.300 inch in the horizontal axis. For a localized point having these dimensions, the minimum required thickness is 0.032 inch. The apparent cause of the thinner liner thickness cannot be determined with certainty since the concrete covering of the liner precludes access to visually examine the area. Location 2RN-063 and the extended area is to be examined for at least the following three successive inspection periods as required by the renewed operating license to ensure that the degradation is not progressing.

The results of these successive examinations will determine the extent of potential examination scope expansion.

The first of the three examinations was completed during fall 2012 and found no evidence of loss of material.

The random sample plan is scheduled to be completed by May 27, 2027. BVPS-2 UFSAR Commitment 34: Supplemental volumetric examinations will be performed on the Unit 2 containment liner. A minimum of 8 non-randomly selected locations will be examined, focusing on areas most likely to experience degradation based on past operating experience (as described in FENOC Letter L-09-242).

If degradation is identified, it will be addressed through the corrective action program. Status: Eight non-random locations were examined during the spring 2011 refueling outage. The locations selected included irregular contours of the liner, non-coated below grade areas and repainted areas of the liner. Acceptance criterion for the examinations had been established as 90 percent of the nominal wall thickness (0.337 inches). All eight non-random locations were completed with no evidence of loss of material.

BVPS-2 UFSAR Commitment 35: A summary of results for each phase of volumetric testing (described in Unit 2 Commitments No. 33 and No. 34) will be documented in a letter to the NRC. Status: FENOC letter dated June 27, 2011, submitted the spring 2011 refueling outage liner exam report to the NRC, ML 111790129.

The remaining exam results are scheduled to be provided to the NRC by May 27, 2027. BVPS-2 UFSAR Commitment 36:

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 39 of 54 FENOC will evaluate if an appropriate/applicable statistical method exists to gain additional insight into potential liner degradation.

Data gathered will be evaluated and used to determine the general state of the liner. Status: FENOC activities related to this commitment are in progress with a scheduled completion date of May 27, 2027. 3.3 NRC Information Notice 92-20, "Inadequate Local Leak Rate Testing" NRC Information Notice 92-20 was issued to alert licensees to problems involving local leak rate testing of containment penetrations under 10 CFR 50, Appendix J. Problems were identified with the testing of two-ply stainless steel bellows used on piping penetrations at some plants. Specifically, local leak rate testing could not be relied upon to accurately measure the leakage rate that would occur under accident conditions since, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations.

Any two-ply bellows of similar construction may be susceptible to this problem. BVPS-1 piping and ventilation penetrations are of the rigid welded type and are welded to the reactor containment building steel liner. Several penetrations are equipped with bellows assemblies; however, only the recirculation spray heat exchanger metal expansion joints require the performance of Type B leak testing. These metal expansion joints are of the single ply design and are Type B tested in accordance with the containment leak rate testing program. Testing is accomplished by draining the associated heat exchanger below the level of the metal expansion joint, pressurizing the tube side of the heat exchanger with air to 44.5 psig, and the checking for leakage by performing a soap bubble leak check of the entire metal expansion joint to ensure no leakage is present. The acceptance criteria is no visible leakage. BVPS-2 piping and ventilation penetrations are of the rigid welded type and are welded to the reactor containment building steel liner. Several penetrations are also equipped with bellows assemblies; however, none of the bellows assemblies are part of the reactor containment building pressure boundary and do not require local leakage rate testing. No further action is required at BVPS regarding NRC Information Notice 92-20. 3.4 NRC Limitations and Conditions Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," (September 1995) provides a method acceptable to the NRC for implementing the performance-based option (Option B) of 10 CFR 50, Appendix J. The regulatory positions stated in Regulatory Guide 1.163 (September 1995) as modified by NRC safety evaluations of June 25, 2008 (ADAMS Accession No. ML0811401

05) and June 8, 2012 (ADAMS Accession No. ML 121 030286) are incorporated in Nuclear Energy FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 40 of 54 Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." The FENOC response to the limitations and conditions on the use of NEI 94-01 discussed in the June 25, 2008, and June 8, 2012 NRC safety evaluations is provided below. 3.4.1 June 25, 2008 NRC Safety Evaluation The limitations and conditions from the June 25, 2008 safety evaluation are presented in the table below with the FENOC response for BVPS. June 25, 2008 NRC Safety Evaluation (SE) Limitations and Conditions Limitation/Condition (From Response for BVPS Section 4.0 of Safety Evaluation)

1. For calculating the Type A BVPS will utilize the definition in NEI 94-01, leakage rate, the licensee should Revision 3-A, Section 5.0. This definition has use the definition in the NEI remained unchanged from Revision 2-A to TR 94-01, Revision 2, in lieu of Revision 3-A of NEI 94-01. that in ANSI/ANS-56.8-2002. (Refer to SE Section 3.1.1.1 ). 2. The licensee submits a schedule Reference Sections 3.2.1 and 3.2.2. of containment inspections to be General visual observations of the accessible performed prior to and between interior and exterior surfaces of the Type A tests. (Refer to SE containment structure shall continue to be Section 3.1.1.3).

performed in accordance with containment structural integrity test procedures to meet the requirements of the proposed revision to Technical Specification 5.5.12, the inspection requirements of ASME Code Section XI, subsections IWE and IWL, and NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2. 3. The licensee addresses the Reference Sections 3.2.1, through 3.2.9. areas of the containment General visual observations of the accessible structure potentially subjected to interior and exterior surfaces of the degradation. (Refer to SE containment structure shall continue to be Section 3.1.3). performed in accordance with containment structural integrity test procedures to meet the requirements of the proposed revision to Technical Specification 5.5.12, the inspection requirements of subsections IWE and IWL, and NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 41 of 54 Limitation/Condition (From Response for BVPS Section 4.0 of Safety Evaluation)

4. The licensee addresses any tests BVPS-2 steam generator replacement is and inspections performed scheduled to be implemented during the following major modifications to spring 2017 refueling outage (2R19). To the containment structure, as facilitate the removal and replacement of the applicable. (Refer to SE steam generators, a construction opening will Section 3.1.4). be made in the reactor containment.

Following the replacement of the construction opening and restoration of the concrete structure, the next BVPS-2 Type A test will be performed prior to returning the unit to service. 5. The normal Type A test interval BVPS will follow the requirements of should be less than 15 years. If NEI 94-01, Revision 3-A, Section 9.1. This a licensee has to utilize the requirement has remained unchanged from provision of Section 9.1 of NEI Revision 2-A to Revision 3-A of NEI 94-01. TR 94-01, Revision 2, related to In accordance with the Section 3.1.1.2 of the extending the ILRT interval NRC safety evaluation dated June 25, 2008 beyond 15 years, the licensee (ADAMS Accession No. ML081140105), must demonstrate to the NRC FENOC will also demonstrate to the NRC staff staff that it is an unforeseen that an unforeseen emergent condition exists emergent condition. (Refer to SE in the event an extension beyond the 15 year Section 3.1.1.2).

interval is required.

Justification for such an extension request will be in accordance with the staff position in Regulatory Issue Summary (RIS) 2008-27. 6. For plants licensed under 10 Not applicable.

BVPS was not licensed under CFR Part 52, applications 1 0 CFR Part 52. requesting a permanent extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI TR 94-01, Revision 2, and [Electric Power Research Institute]

EPRI Topical Re_port No. TR-1 009325, FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 42 of 54 Limitation/Condition (From Response for BVPS Section 4.0 of Safety Evaluation)

Revision 2, ["Risk-Impact Assessment of Extended Integrated Leak Rate Testing Intervals,"]

including the use of past containment ILRT data. 3.4.2 June 8, 2012 NRC Safety Evaluation The two conditions from Section 4.0 of the June 8, 2012 safety evaluation are stated below with the FENOC response for BVPS. Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g. BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval.

Only non-routine emergent conditions allow an extension to 84 months. This is Topical Report Condition

1. Response to Condition 1 Condition one presents three (3) separate issues that are addressed as follows: ISSUE 1 -The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. Response to Condition 1, Issue 1 The post-outage report shall include the margin between the Type B and Type C minimum pathway leak rate summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La. ISSUE 2-A corrective action plan shall be developed to restore the margin to an acceptable level.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 43 of 54 Response to Condition 1, Issue 2 When the potential leakage understatement adjusted Type B and Type C minimum pathway leak rate total is greater than the BVPS administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the BVPS administrative leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and the manner of timely corrective action (as deemed appropriate) that best focuses on the prevention of future component leakage performance issues. ISSUE 3 -Use of the allowed 9 month extension for eligible Type C valves is only authorized for non-routine emergent conditions.

Response to Condition 1, Issue 3 BVPS will apply the 9 month grace period only to eligible Type C components and only for non-routine emergent conditions.

Such occurrences will be documented in the record of tests. Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations.

Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRT's being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leak rates for the just tested penetrations are summed with the as-left minimum pathway leak rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves which, in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable.

Routine and appropriate maintenance may extend this increasing leakage potential.

Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential.

This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations.

Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 94-01, Revision 3, Section 12.1.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 44 of 54 When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B & C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

This is Topical Report Condition

2. Response to Condition 2 Condition 2 presents two separate issues that are addressed as follows: ISSUE 1 -Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 94-01, Revision 3, Section 12.1. Response to Condition 2, Issue 1 The change in going from a 60 month extended test interval for Type C tested components to a 75 month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25 percent in the local leak rate test periodicity.

As such, FENOC will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the as-left leakage total for each Type C component currently on the 75 month extended test interval.

This will result in a combined conservative Type C total for all 75 month local leak rate tests being carried forward and included whenever the total leakage summation is required to be updated (either while operating on-line or following an outage). When the potential leakage understatement adjusted leak rate total for those Type C components being tested on a 75 month extended interval is summed with the non-adjusted total of those Type C components being tested at less than the 75 month interval and the total of the Type B tested components, if the minimum pathway leak rate is greater than the BVPS administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the administrative leakage limit. The corrective action plan shall focus on those components that have contributed the most to the increase in the leakage summation value and the manner of timely corrective action (as deemed appropriate) that best focuses on the prevention of future component leakage performance issues. ISSUE 2 -When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Type B & C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 45 of 54 Response to Condition 2, Issue 2 If the potential leakage understatement adjusted minimum pathway leak rate is less than the administrative leakage summation limit of 0.50 La, then the acceptability of the 75-month local leak rate test extension for all affected Type C components has been adequately demonstrated and that the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, Issues 1 and 2, which deal with the minimum pathway leak rate Type 8 and Type C summation margin, NEI 94-01, Revision 3-A, also has the following margin related requirement contained in Section 12.1, "Report Requirements." A post-outage report shall be prepared presenting results of the previous cycle's Type B and Type C tests, and Type A, Type 8 and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met, and serve as a record that continuing performance is acceptable.

The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type 8 and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type 8 and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level. In the event an adverse trend in the potential leakage understatement adjusted Type B and Type C summation is identified, an analysis and a corrective action plan shall be prepared to restore the margin to an acceptable level thereby eliminating the adverse trend. The corrective action plan shall focus on those components that have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues. An adverse trend is defined as three consecutive increases in the final pre-reactor coolant system Mode change Type B and Type C minimum pathway leak rate summation value adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La. 3.5 Plant-Specific Confirmatory Analysis 3.5.1 Methodology An evaluation has been performed to assess the risk impact of extending the BVPS-1 and BVPS-2 Type A test interval from the current 10 years to 15 years. A simplified bounding analysis consistent with the Electric Power Research Institute (EPRI) approach was used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in:

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 46 of 54

• Appendix H of Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals:

Revision 2-A of 1009325," EPRI Topical Report TR-1 018243, dated October 2008,

• Electric Power Research Institute, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," EPRI Topical Report TR-104285, dated August 1994,

• Nuclear Regulatory Commission, "Performance-Based Containment Leak-Test Program," NUREG-1493, dated September 1995, and the

• Calvert Cliffs liner corrosion analysis described in a letter to the NRC dated March 27, 2002 (ADAMS Accession No. ML020920100).

The analysis uses results from a Level 2 analysis of core damage scenarios from the current BVPS-1 and BVPS-2 probabilistic risk assessment models and subsequent containment responses resulting in various fission product release categories (including intact containment or negligible release).

In the safety evaluation issued by NRC letter dated June 25, 2008 (ADAMS Accession No. ML081140105), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, is acceptable for referencing by licensees proposing to amend their Technical Specifications to permanently extend the Type A surveillance test interval to 15 years, subject to the conditions noted in Section 4.2 of the safety evaluation.

The following table addresses each of the four conditions for the use of EPRI TR-1 009325, Revision 2. EPRI TR-1009325, Revision 2, Limitations and Conditions Conditions Response for BVPS (From Section 4.2 of Safety Evaluation)

1. The licensee submits documentation BVPS PRA technical adequacy is indicating that the technical adequacy of addressed in Section 3.5.2. their [probabilistic risk assessment]

PRA is consistent with the requirements of [Regulatory Guide] RG 1.200 relevant to the [integrated leakage rate test] ILRT extension application.

2. The licensee submits documentation EPRI TR-1 009325, Revision 2-A, indicating that the estimated risk incorporates these population dose and increase associated with permanently conditional containment failure extending the ILRT surveillance interval probability acceptance guidelines, and to 15 years is small, and consistent with these guidelines have been used for the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 47 of 54 Conditions Response for BVPS (From Section 4.2 of Safety Evaluation) the clarification provided in Section BVPS plant specific assessments.

3.2.4.5 of this [safety evaluation]

SE. Specifically, a small increase in population dose should be defined as an The increase in population dose is increase in population dose of less than discussed in Section 3.5.3. 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 The increase in the conditional probability]

CCFP should be defined as a containment failure probability is value marginally greater than that discussed in Section 3.5.3. accepted in a previous one-time 15 year ILRT extension requests.

This would require that the increase in CCFP be less than or equal to 1.5 percentage point. 3. The methodology in EPRI Report No. EPRI TR-1009325, Revision 2-A, 1009325, Revision 2, is acceptable incorporated the use of 1 00 La as the except for the calculation of the increase average leak rate for the pre-existing in expected population dose (per year of containment large leakage rate accident reactor operation).

In order to make the case (accident case 3b), and this value methodology acceptable, the average has been used in the BVPS plant specific leak rate for the pre-existing containment risk assessment.

large leak rate accident case (accident case 3b) used by the licensees shall be 1 00 La instead of 35 La. 4. A [licensee amendment request] LAR For BVPS, the mitigation of design basis is required in instances where accidents rely on containment containment over-pressure is relied upon overpressure in the calculation of for [emergency core cooling system] available net positive suction head for ECCS performance.

the recirculation spray (RS) pumps (at both Units) and low head safety injection pumps (at BVPS-1) when taking suction from the containment sump during the safety injection recirculation phase. EPRI TR-1 009325, Revision 2-A, states that for those _plants that credit FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 48 of 54 Conditions Response for BVPS (From Section 4.2 of Safety Evaluation) containment overpressure for the mitigation of design basis accidents, a brief description of whether overpressure is required should be included, as well as a discussion of the combined impacts from the ILRT extension on CDF and LERF, and comparison with the Regulatory Guide 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," acceptance guidelines.

The results of this assessment are discussed in Attachments 3 and 4, Section 6.3, "Potential Impact From Loss of Containment Overpressure." 3.5.2 Probabilistic Risk Assessment (PRA) Technical Adequacy BVPS-1 and BVPS-2 have Level 2 PRA models that include both internal and external events. Severe accident sequences have been developed from internally and externally initiated events, including internal floods, internal fires, and seismic events. The sequences have been developed to determine the frequency for the radiological release end states to the environment.

Information developed for the BVPS license renewal effort to support the Level 2 release categories is also used in this analysis.

The BVPS PRA models are highly detailed and include a wide variety of initiating events, modeled systems, operator actions, and common cause events. The BVPS-1 and BVPS-2 PRA models of record and supporting documentation have been maintained as a living program, with updates directed every other refueling cycle (approximately every three years) to reflect the as-built, as-operated plant. The BVPS Individual Plant Examination (IPE) and Individual Plant Examination of External Events (IPEEE) PRA models underwent NRC reviews, and updates to these models have been the subject of several assessments to establish the technical adequacy of the PRA. Documentation of BVPS-1 and BVPS-2 PRA technical adequacy was previously submitted to the NRC in support of the license amendment request for adoption of TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control -Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b," by FENOC letter dated October 18, 2013 (ADAMS Accession No. ML 13295A006).

This previously submitted documentation of PRA technical adequacy is deemed to be applicable for this FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 49 of 54 Type A test interval extension submittal since the PRA models have not changed. The previously provided information for BVPS-1 and BVPS-2 is included as Attachment 5 and Attachment 6, respectively.

The PRA models are considered to be fundamentally compliant with Regulatory Guide 1.200, Revision 1 for the scope of this application, and meet Capability Category II requirements of Part 2 "Internal Events" and Part 3 "Internal Flood" of the ASME/ANS PRA Standard (RA-Sb-2005).

The current BVPS seismic and internal fire PRA models have not been assessed against the requirements of the ASME/ANS PRA Standard, but have been subject to independent review by external events experts and maintained in the current PRA model of record. Therefore, the BVPS seismic and internal fire PRA models are of sufficient scope to adequately address the seismic and internal fire risk associated with this risk-informed application.

These PRA models, in combination with the maintenance and update processes provide a robust basis for concluding that the Level 2 full power internal events, seismic, and internal fire PRA models are considered acceptable for use in risk-informed processes, such as assessing the risk impact for extending the BVPS-1 and BVPS-2 containment Type A test interval from 10 years to 15 years 3.5.3 Conclusion of Plant-Specific Risk Assessment Results The findings of the BVPS risk assessment confirm the general findings of previous studies that the risk impact associated with extending the Type A test interval from three in ten years to one in 15 years is small. The BVPS plant-specific results for extending the Type A test interval from the current 10 years to 15 years are summarized below: Core damage frequency is not significantly impacted by the proposed change. Both BVPS-1 and BVPS-2 rely on containment overpressure to assure adequate net positive suction head is available for emergency core cooling system pumps taking suction from the containment sump following design basis accidents.

Regulatory Guide 1.17 4 provides guidance for determining the risk impact of specific changes to the licensing basis. Regulatory Guide 1.17 4 defines very small changes in risk as resulting in increases of CDF less than 1.0 x 1 o-6 per reactor year and increases in LERF less than 1.0 x 1 o-7 per reactor year. When accounting for the loss of containment overpressure and the impact on the systems that require this contribution for available net positive suction head, the change in total (internal plus external)

CDF of 3.58 x 1 o-7 per year for BVPS-1 and 6.02 x 1 o-7 per year for BVPS-2, meets the Regulatory Guide 1.174 acceptance guidelines for very small changes in CDF at both units, and confirms that the impact on CDF from the Type A test extension is negligible.

Thus, the relevant acceptance criterion is LERF. The increase in LERF based on consideration of internal events only resulting from a change in the Type A test interval from three in ten years to one in fifteen years with FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 50 of 54 corrosion included is conservatively estimated as 6. 72 x 1 o-8 per year for BVPS-1 and 3.80 x 1 o-8 per year for BVPS-2, which falls within the very small change region of the acceptance guidelines in Regulatory Guide 1.17 4. Regulatory Guide 1.17 4 also states that when the calculated increase in LERF is in the range of 1.0 x 1 o-s to 1.0 x 1 o-7 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.0 x 1 o-5 per reactor year. When the external events contribution is also considered, the total increase in LERF due to both internal and external events including corrosion goes to 2.10 x 1 o-7 per year, with an associated total LERF of 3.06 x 1 o-7 per year for BVPS-1, and 1.54 x 1 o-7 per year, with an associated total LERF of 3.71 x 10-7 per year for BVPS-2. As such, the estimated change in total LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.17 4, and is well below the Regulatory Guide 1.17 4 acceptance criteria for total LERF of 1.0 x 1 o-5. Sensitivity analysis using the EPRI Expert Elicitation methodology, estimate the change in total LERF as 2.48 x 1 o-8 per year for BVPS-1 and 1.82 x 1 o-8 per year for BVPS-2, which falls within the very small change region. The calculated increase in the total 50-mile population dose risk for changing the Type A test frequency from three-per-1 0-years to once-per-15-years is measured as an increase to the total integrated dose risk for all accident sequences.

The total 50-mile population dose risk increase (relative to the base case with corrosion) is 2.26 x 1 o-2 person-rem per year for BVPS-1 and 1.66 x 10-2 person-rem per year for BVPS-2 using the EPRI guidance.

EPRI TR-1 009325, Revision 2-A, states that a very small population dose is defined as an increase of less than or equal to 1.0 person-rem per year, or less than or equal to 1 percent of the total population dose, whichever is less restrictive.

Thus, the calculated 50-mile population dose increase at both BVPS-1 and BVPS-2 is small using the guidelines of EPRI TR-1009325, Revision 2-A. Moreover, the risk impact when compared to other severe accident risks is negligible.

The increase in the conditional containment failure probability from the three-per years to once-per-15-years interval including corrosion effects is 0.93 percent for BVPS-1 and 0.92 percent for BVPS-2. EPRI TR-1009325, Revision 2-A, states that increases in conditional containment failure probability of less than or equal to 1.5 percentage points are very small. Therefore this increase is judged to be very small at both BVPS-1 and BVPS-2. Increasing the Type A test interval on a permanent basis to a once-in-fifteen years frequency is not considered to be significant since it represents only a small change in the BVPS-1 and BVPS-2 risk profiles.

Details of the BVPS risk assessments are contained in Attachment 3 for BVPS-1, and Attachment 4 for BVPS-2. 3.6 Conclusion NEI 94-01, Revision 3-A, describes an NRC accepted approach for implementing the performance-based requirements of Appendix J, Option B. It incorporates the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 51 of 54 regulatory positions stated in Regulatory Guide 1.163 and includes provisions for extending Type A test intervals to 15 years and Type C test intervals to 75 months. 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.

Based on the previous Type A tests conducted at BVPS-1 and BVPS-2, extension of the containment Type A test interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with Appendix J, Option B, and the overlapping inspection activities performed as part of the following BVPS-1 and BVPS-2 inspection programs:

• Primary Containment lnservice Inspection Program

• Containment Structural Integrity Tests

• Containment Coatings Inspection and Assessment Program This experience is supplemented by risk analysis studies, including the BVPS-1 and BVPS-2 risk analysis provided in Attachments 3 and 4. The findings of the risk assessment confirm the general findings of previous studies, on a plant-specific basis, that extending the Type A test interval from 10 to 15 years results in a very small change to the BVPS-1 and BVPS-2 risk profiles.

4. REGULATORY EVALUATION An amendment is proposed to the Beaver Valley Power Station, Unit No. 1 (BVPS-1) and Unit No.2 (BVPS-2), Technical Specification 5.5.12, "Containment Leakage Rate Testing Program." The proposed amendment to the Technical Specification would revise BVPS Technical Specification 5.5.12, by deleting reference to the BVPS-1 exemption letter dated December 5, 1984, and replacing the reference to Nuclear Regulatory Commission (NRC) Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," with a reference to Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," as the implementation document used by BVPS to implement the BVPS-1 and BVPS-2 performance-based containment leakage rate testing program. 4.1 Significant Hazards Consideration First Energy Nuclear Operating Company has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No.

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 52 of 54 The proposed amendment adopts the NRC-accepted guidelines of NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," for development of the Beaver Valley Power Station, Unit No. 1 (BVPS-1) and Unit No.2 (BVPS-2) performance-based containment testing program. NEI 94-01 allows, based on risk and performance, an extension of Type A and Type C containment leak test intervals.

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 findings of the Beaver Valley Power Station risk assessment confirm the general findings of previous studies that the risk impact with extending the containment leak rate is small. Per the guidance provided in Regulatory Guide 1.17 4, Revision 3-A, an extension of the leak test interval in accordance with NEI 94-01 results in an estimated change within the very small change region. Since the change is implementing a performance-based containment testing program, the proposed amendment does not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled.

The requirement for leakage rate acceptance will not be changed by this amendment.

Therefore, the containment will continue to perform its design function as a barrier to fission product releases.

Therefore, the proposed amendment does not significantly increase the probability or consequences of an accident previously evaluated.

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

Response:

No. The proposed change to implement a performance-based containment testing program, associated with integrated leakage rate test frequency, does not change the design or operation of structures, systems, or components of the plant. In addition, the proposed changes would not impact any other plant system or component.

The proposed changes would continue to ensure containment integrity and would ensure operation within the bounds of existing accident analyses.

There are no accident initiators created or affected by these changes. Therefore, the proposed changes will not create the possibility of a new or different kind of accident from any accident previously evaluated.

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

FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 53 of 54 3. Does the proposed change involve a significant reduction in a margin of safety? Response:

No. The proposed change to implement a performance-based containment testing program, associated with integrated leakage rate test frequency, does not affect plant operations, design functions, or any analysis that verifies the capability of a structure, system, or component of the plant to perform a design function.

In addition, this change does not affect safety limits, limiting safety system setpoints, or limiting conditions for operation.

The specific requirements and conditions of the Technical Specification Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained.

The overall containment leak rate limit specified by Technical Specifications is maintained.

This ensures that the margin of safety in the plant safety analysis is maintained.

The design, operation, testing methods and acceptance criteria for Type A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by implementation of a performance-based containment testing program. Therefore, the proposed amendment does not involve a significant reduction in a margin of safety. Based on the above, FirstEnergy Nuclear Operating Company concludes that the proposed amendment does not involve a 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.

4.2 Applicable

Regulatory Requirements I Criteria The proposed amendment has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leakage through the primary reactor containment and systems and components penetrating primary containment shall not exceed allowable leakage rate values and periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of the containment, and systems and components penetrating primary containment.

In addition, Appendix J discusses leakage rate test methodology, frequency of testing, and reporting requirements for each type of test. Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," (September 1995) provides a method acceptable to the NRC for implementing the FENOC Evaluation of the Proposed Amendment Beaver Valley Power Station, Unit Nos. 1 and 2 Page 54 of 54 performance-based option (Option B) of 10 CFR 50, Appendix J. The regulatory positions stated in Regulatory Guide 1.163 (September 1995) as modified by NRC Safety Evaluations of June 25, 2008 (ADAMS Accession No. ML081140105) and June 8, 2012 (ADAMS Accession No. ML 121030286) are incorporated in Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." The proposed license amendment would revise BVPS-1 and BVPS-2 Technical Specification 5.5.12, "Containment Leakage Rate Testing Program," Item a, by deleting reference to the BVPS-1 exemption letter dated December 5, 1984, and changing the wording to indicate that the program shall be in accordance with Nuclear Energy Institute (NEI) topical report NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," instead of Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," and listed exceptions.

The purpose of NEI 94-01 is to assist licensees in the implementation of Option B to 10 CFR Part 50, Appendix J. The NRC staff has reviewed NEI 94-01, Revision 3, and found that this guidance, as modified to include two limitations and conditions, is acceptable for referencing by licensees proposing to amend their Technical Specifications in regards to containment leakage rate testing. Based on the foregoing, the proposed amendment will continue to ensure compliance with 10 CFR 50.54(o), and Option B of 10 CFR Part 50, Appendix J. 4.3 Conclusions In conclusion, based on the considerations discussed 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 compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. 5. ENVIRONMENTAL CONSIDERATION The proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

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

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

Attachment 1 Proposed Facility Operating License Change (Mark-up) ( 1 page follows)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued) 5.5.12 c. The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system. Containment Leakage Rate Testing Program a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

For Unit 1, exemptions to Appendix J of 10 CFR 50 are dated November 19, 1984, December 5, 1984, and July 26, 1995. For Unit 2, exemptions to Appendix J of 10 CFR 50 are as stated in the Operating License. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," dated September, 1 995, as modified by the following e*ceptions:

1. F'or Unit 1, the nex-t Type A test performed after the May 29, 1993 Type A test shall be performed no later than May 28, 2008. 2. F'or Unit 2, the nex-t Type A test performed after the November 10, 1993 Type /\ test shall be performed no later than November 9, 2008. NEI 94-01. Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50. Appendix J," dated July 2012. b. The calculated peak containment internal pressure for the design basis loss of coolant accident, P a, is 43.1 psig (for Unit 1) and 44.8 psig (for Unit 2). c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day. d. Leakage rate acceptance criteria are: 1. Containment leakage rate acceptance criterion is ::;; 1.0 La. However, during the first unit startup prior to MODE 4 entry following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type Band C tests and::;; 0.75 La for Type A tests. 2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is ::;; 0.05 La when tested at ;;:: P a* Beaver Valley Units 1 and 2 5.5-19 Amendments 70 Attachment 2 Proposed Facility Operating License Change (Re-Typed) ( 1 page follows)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) {continued) 5.5.12 c. The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system. Containment Leakage Rate Testing Program a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54{o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

For Unit 1, exemptions to Appendix J of 10 CFR 50 are dated November 19, 1984, and July 26, 1995. For Unit 2, exemptions to Appendix J of 1 0 CFR 50 are as stated in the Operating License. This program shall be in accordance with the guidelines contained in NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 2012. b. The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 43.1 psig {for Unit 1) and 44.8 psig {for Unit 2). c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day. d. Leakage rate acceptance criteria are: 1. Containment leakage rate acceptance criterion is :;; 1.0 La. However, during the first unit startup prior to MODE 4 entry following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type Band C tests and:;; 0.75 La for Type A tests. 2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is:;; 0.05 La when tested Pa. Beaver Valley Units 1 and 2 5.5-19 Amendments TBD I TBD Attachment 3 Plant Specific Confirmatory Analysis (PRA) BVPS-1 (65 pages follow)

PRA APPLICATIONS ANAL YSJS/ASSESSMENT COVER SHEET Analysis/Assessment Sequence No.: PRA-BV1 "13*028-ROO Rev.: QQ__ Ref. PRA Tracking#:

'-=N'"""/A-'-----------------* (if applicable)

Subject:

BVPS-1 Risk Assessment for Extending ILRT Interval to One in 15 Years

Description:

• The purpose of this analysis is to provide a risk assessment of extending the currently allowed contajnment Type A Integrated teak rate test (ILRT) to a permanent fifteen ears. Documents Used by this Analysis/Assessment:

See Section 8 References.

Documents Supported by this Analysis/Assessment:

BVPS-1 ILRT LAR Documents Superseded by this Analysis/Assessment:

Preparer:

F. William Etzel (f tri<f Reviewer:

R. J. Stremple t'j.ltit; Additional Reviews (If required)

Performed by: S. T. Leung d:. tiJ Zf/&r S 11-,er Approved:

K. Ra mond Fine Supervisor An Date: 11/7/13 Date: ll/9/13 Date: ,,jaf,g Date: 'LL'ir'Lr3 I

1. 1 .1 1.2 1.3 2. 3. 4. 4.1 4.2 4.3 4.4 5. 5.1 5.2 5.3 5.4 5.5 5.6 6. 6.1 6.2 6.3 PRA-BV1-13-028-ROO Page ii of iii PRA APPLICATIONS ANALYSIS/ASSESSMENT TABLE OF CONTENTS PURPOSE OF ANALYSIS ....................................................................

1 PURPOSE ......................................................................................................

1 BACKGROUND

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

1 ACCEPTANCE CRITERIA ............................................................................

3 METHODOLOGY

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

5 GROUND RULES ................................................................................

7 INPUTS ..............................................................................................

9 GENERAL RESOURCES AVAILABLE

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

9 PLANT-SPECIFIC INPUTS ........................................................................

13 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) ..............

24 IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE .............................................

25 RESULTS .........................................................................................

31 STEP 1: QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR .......................................................

33 STEP 2: DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR ........................................

38 STEP 3: EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 1 0-T0-15 YEARS .......................................................

.40 STEP 4: DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY (LERF) ..................................

.40 STEP 5: DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY (CCFP) ................................

.41

SUMMARY

OF RESULTS ..........................................................................

42 SENSITIVITIES

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

47 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS

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

.47 EPRI EXPERT ELICITATION LEAKAGE SENSITIVITY

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

50 POTENTIAL IMPACT FROM LOSS OF CONTAINMENT OVERPRESSURE

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

54 PRA-BV1-13-028-ROO Page iii of iii 7. CONCLUSIONS

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

57 8. REFERENCES

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

60 LIST OF TABLES Table 4-1. BVPS-1 Level 2 PRA Model Release Category Groups, Bins, and Frequencies

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

14 Table 4-2. Calculation of BVPS Population Dose at 50 Miles ..........................................

16 Table 4-3. Assignment of SAMA Release Category and BVPS Dose to Release Bin ..... 17 Table 4-4. EPRI Containment Failure Classification

[2] ...................................................

18 Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes ............

19 Table 4-6. BVPS-1 Level2 Release Bin Frequency and Population Dose Risk ..............

21 Table 4-7. BVPS-1 50-Mile Population Dose Risk by EPRI Accident Class ....................

23 Table 4-8. Steel Liner Corrosion Base Case ....................................................................

28 Table 5-1 . Accident Classes ............................................................................................

32 Table 5-2. BVPS-1 Categorized Accident Classes and Frequencies

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

33 Table 5-3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-1 Base Case) ......................................................................................

37 Table 5-4. BVPS-1 Population Dose Estimates for Population Within 50 Miles ...............

39 Table 5-5. Summary of BVPS-1 Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact.. ........................................................

44 Table 5-6. Summary of BVPS-1 Internal Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact.. ................................................

45 Table 5-7. Summary of BVPS-1 External Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact.. ..........................................

.46 Table 6-1. Steel Liner Corrosion Sensitivity Cases ..........................................................

50 Table 6-2. EPRI Expert Elicitation Results .......................................................................

51 Table 6-3. BVPS-1 Total Risk for ILRT Base Case, 10, and 15 Year Extensions (Based on EPRI Expert Elicitation Leakage Probabilities)

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

53 Table 6-4. Containment Overpressure Adjustment Factors .......................................

54 Table 6-5. BVPS-1 Loss of Containment Overpressure Total Risk for ILRT Base Case, 1 0, and 15 Year Extensions, Including Corrosion Impact .....................

56

1. PURPOSE OF ANALYSIS 1.1 PURPOSE PRA-BV1-13-028-ROO Page 1 of 62 The purpose of this analysis is to provide a risk assessment of extending the currently allowed containment Type A integrated leak rate test (ILRT) interval from ten years to a permanent fifteen years. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for the Beaver Valley Power Station Unit 1 (BVPS-1 ). The risk assessment follows the guidelines from NEI 94-01, Revision 3-A [1 ], the methodology used in EPRI TR-1 04285 [2], the NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" from November 2001 [3], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide (RG) 1.200 [7] as applied to ILRT interval extensions and risk insights in support of a request for a plant's licensing basis as outlined in RG 1.174 [4], 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 [5], the methodology used in EPRI 1009325, Revision 2 [26], and the methodology used in EPRI 1018243 (Revision 2-A of 1 009325) [27]. 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 EPRI 1 018243 report.

1.2 BACKGROUND

Revisions to 1 OCFR50, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirement from three in ten years to at least once in 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 1 La. The basis for the current 1 0-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," September 1995 [6], 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 PRA-BV1-13-028-ROO Page 2 of 62 Research Institute (EPRI) Research Project Report TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals." To complement the EPRI report TR-1 04285, which only considered changes to the ILRT testing intervals based on population dose, EPRI report 1018243 was developed that considers population dose, large early release frequency (LERF) and containment conditional failure probability (CCFP). EPRI report 1018243 indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to fifteen years is small. However, a plant specific confirmatory analysis is required.

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

[6], 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 for a representative PWR plant (i.e., Surry) that containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for BVPS-1. The guidance provided in Appendix H of EPRI 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325, for performing risk impact assessments in support of ILRT extensions builds on the EPRI Risk Assessment methodology, EPRI TR-1 04285. This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment.

The associated change to NEI 94-01 will require that visual examinations be conducted during at least three other outages, and in the outage during which the ILRT is being conducted.

These requirements will not be changed as a result of the extended ILRT interval.

In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.

1.3 ACCEPTANCE

CRITERIA PRA-BV1-13-028-ROO Page 3 of 62 The acceptance guidelines in RG 1.17 4 are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 1.0E-06 per reactor year and increases in large early release frequency (LERF) less than 1.0E-07 per reactor year. RG 1.17 4 also defines small changes in LERF as below 1.0E-06 per reactor year. When the calculated increase in LERF is in the range of 1.0E-07 per reactor year to 1.0E-06 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.0E-05 per reactor year. Since the Type A test does not impact CDF, with the exception of a loss of containment overpressure that is discussed in Section 6.4, the relevant criterion is the change in LERF. 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 depth philosophy, are met. Therefore, the increase in the CCFP that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.

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

In context, it is noted that a CCFP of 1/1 0 ( 1 0%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate the relative change in this parameter.

While no acceptance guidelines for these additional figures of merit are published, examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extension (summarized in Appendix G) indicate a range of incremental increases in population dose that have been accepted by the NRC 1* 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

[6], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of ::;;1.0 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.

1 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 this document uses 1 OOLa. The dose rates are impacted by this change and will be larger than those in previous submittals.

PRA-BV1-13-028-ROO Page 4 of 62 In the current BVPS-1 design basis accident (DBA) loss-of-coolant accident (LOCA) analysis, containment overpressure is credited in calculating the available net positive suction head (NPSH) for both the recirculation spray (RS) pumps and low head safety injection (LHSI) pumps when taking suction from the containment sump. Therefore, an assessment of the impacts on CDF resulting from a loss of containment overpressure due to a large containment failure is provided in Section 6.3. The impact on CDF can then be accounted for in a similar fashion to the LERF contribution as the EPRI Class 3b contribution changes for various ILRT test intervals.

The combined impacts on CDF and LERF will then be considered in this ILRT evaluation and compared with the RG 1.174 acceptance guidelines.

2. METHODOLOGY PRA-BV1-13-028-ROO Page 5 of 62 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 fifteen years. The approach is consistent with that presented in Appendix H of EPRI 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325 [27], EPRI TR-1 04285 [2], NUREG-1493

[6], and the Calvert Cliffs liner corrosion analysis [5]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current PRA-BV1-AL-R05a (BV1 REV5A) PRA model and subsequent containment response resulting in various fission product release categories (including intact containment or negligible release).

This risk assessment is applicable to BVPS-1. 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 fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis, to the fractional contribution of increased large leakage failures (due to liner breach) to LERF, and to the loss of containment overpressure due to EPRI Class 3b liner breach on CDF and LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore,

• Consistent with the other industry containment leak risk assessments, the BVPS-1 assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and PRA-BV1-13-028-ROO Page 6 of 62 conditional containment failure probability are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.

• This evaluation for BVPS-1 uses ground rules and methods to calculate changes in risk metrics that are similar to those used in Appendix H of EPRI Report No. 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325 [27].

3. GROUND RULES The following ground rules are used in the analysis:

PRA-BV1-13-028-ROO Page 7 of 62

• The technical adequacy of the PRA-BV1-AL-R05a (BV1 REV5A) PRA model is consistent with the requirements of RG 1.200, Revision 1 as is relevant to this ILRT interval extension.

• Although the BV1 REV5A PRA model is only RG 1.200, Revision 1 compliant for internal events, it also includes fire and seismic external events. FirstEnergy Nuclear Operating Company (FENOC) considers these BVPS-1 external event PRA models of sufficient quality and detail to adequately assess the impact from the seismic and internal fire risk associated with this ILRT interval extension, using the methodology provided in EPRI 1018243. Since the risk acceptance guidelines in RG 1.174 are intended for comparison with a full-scope assessment of risk, the total impact from internal and external events will be evaluated for the extended ILRT intervals.

• The BVPS-1 Level 1 and Level 2 PRA models provide representative results that can be used to estimate the impact of an ILRT interval extension.

• Dose results for the containment failures modeled in the PRA can be characterized by information provided in the BVPS Environmental Report for License Renewal (Attachment C, Severe Accident Mitigation Alternatives)

[19].

• The use of the 50-mile lifetime dose commitment from all pathways (L-EFFECTIVE TOT LIF) using 2047 estimated population data from the License Renewal Application

[19] is appropriate for this analysis to estimate the 50-mile population dose.

• Accident classes describing radionuclide release end states are defined consistent with EPRI methodology

[2] and are summarized in Section 4.2.

• The representative containment leakage for Class 1 sequences is 1 La. Class 3 accounts for increased leakage due to Type A inspection failures.

• The representative containment leakage for Class 3a sequences is 10 La based on the previously approved methodology performed for Indian Point Unit 3 [8, 9].

• The representative containment leakage for Class 3b sequences is 100 La based on the guidance provided in EPRI Report No. 1009325, Revision 2.

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

[8, 9].

• 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 PRA-BV1-13-028-ROO Page 8 of 62 containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from this separate categorization.

• The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal.

• The EPRI guidance [27] will be used as a first order estimate of the impact from a loss of containment overpressure.

It will be assumed that the EPRI Class 3b contribution leads to a loss of containment overpressure, which will then lead to a loss of all systems that credit this containment overpressure in calculating the available NPSH when taking suction from the containment sump.

• An evaluation of the risk impact of the ILRT on shutdown risk is addressed using the generic results from EPRI TR-1 05189 [14].

4. INPUTS PRA-BV1-13-028-ROO Page 9 of 62 This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539

[1 0] 2. NUREG/CR-4220

[11] 3. NUREG-1273

[12] 4. NUREG/CR-4330

[13] 5. EPRI TR-1 05189 [14] 6. NUREG-1493

[6] 7. EPRI TR-1 04285 [2] 8. NEI Interim Guidance [3][20] 9. Calvert Cliffs liner corrosion analysis [5] 10. EPRI Report 1018243 (Revision 2-A of 1 009325), Appendix H [27] 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 existing containment leakage at the time of a core damage accident.

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

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

The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study includes the NEI recommended methodology (promulgated in two letters) for evaluating the risk associated with obtaining a one-time extension of the ILRT interval.

The ninth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations.

Finally, the tenth 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

{1 01 PRA-BV1-13-028-ROO Page 10 of 62 Oak Ridge National Laboratory documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.

This study uses information from WASH-1400

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

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

{111 NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. NUREG-1273

[121 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

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

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

[141 The EPRI study TR-1 05189 is useful to the ILRT test interval extension risk assessment because it provides insight regarding the impact of containment testing on shutdown risk. This study contains a quantitative evaluation (using the EPRI ORAM software) for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The conclusion from the study is that a small but measurable safety benefit is realized from extending the test intervals.

NUREG-1493

[61 PRA-BV1-13-028-ROO Page 11 of 62 The first ILRT survey was performed in early 1994 [8] and represented the NEI (known as NUMARC at that time) input used in NUREG-1493.

NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies: Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-1 04285 [21 Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-1 05189 study), the EPRI TR-1 04285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150

[15] Level 3 population dose models to perform the analysis.

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

EPRI TR-1 04285 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 PRA-BV1-13-028-ROO Page 12 of 62 small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NEI Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals

[31[201 The guidance provided in this document builds on the EPRI risk impact assessment methodology

[2] and the NRC performance-based containment leakage test program [6], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER). Calvert Cliffs Response to Request for Additional Information Concerning the License Amendment for a One-Time Integrated Leakage Rate Test Extension

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

The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concreie basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility.

The BVPS-1 containment structure is a steel-lined, reinforced concrete cylinder with a hemispherical dome and a flat reinforced concrete foundation mat, which is similar to the Calvert Cliffs type of containment.

EPRI Report 1018243 (Revision 2-A of 1009325).

Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals.

Appendix H [271 This report provides a generally applicable assessment of the risk involved in extension of ILRT test intervals to permanent 15-year intervals.

Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology

[2] and the NRC performance-based containment leakage test program [6], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER). The approach included in this guidance document is used in the BVPS-1 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 P RA-BV 1-13-028-ROO Page 13 of 62 The plant-specific information used to perform the BVPS-1 ILRT Extension Risk Assessment includes the following:

• BVPS-1 PRA model results and release category definitions

[17]

• Population dose within a 50-mile radius [19]

• ILRT results to demonstrate adequacy of the administrative and hardware issues [28][29] 1 BVPS-1 PRA Model Results The BVPS-1 PRA model of record, PRA-BV1-AL-R05a (BV1 REV5A), and supporting documentation

[17] have been maintained as a living program to reflect the as-built, operated plant. The latest update to the BVPS-1 PRA model occurred on January 11, 2013. The BV1 REV5A PRA model includes both internal and external events (seismic and internal fire), and provides Level1 and Level 2 results. The BVPS-1 PRA model is highly detailed and includes a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA quantification process used is based on the large linked event tree methodology, which is a well-known and accepted methodology in the industry.

The BVPS-1 PRA model uses Binary Decision Diagram (BOD) methodology to quantify the faults trees, which computes the top event probability exactly and without requiring frequency or cutset order truncation.

The 1 E-14 truncation level used for the BVPS-1 PRA model sequence quantification is more than 9 orders of magnitude less than the baseline total (internal plus external)

CDF of 2.26E-05 per year. This is more than sufficient to provide a converged value of CDF, since decreasing the truncation level by a decade from 1 E-14 to 1 E-15 only results in an increase in CDF of 0.01 %. The BVPS-1 Level 2 PRA Model that is used was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. The Level 2 model is directly linked to the Level 1 PRA model, and was quantified with a total (internal plus external)

Large Early Release Frequency (LERF) = 4.42E-08/yr, Small Early Release Frequency (SERF) = 1.07E-05/yr, Late Containment Failure Frequency (LATE) = 1.03E-05/yr, and Long-Term Containment Integrity Frequency (LONG) = 1.54E-06/yr.

Table 4-1 summarizes the BV1 REV5A results in terms of release category group, release bin, and bin frequencies for both internal and external events together (Total), and separately.

1 The two most recent Type A tests at BVPS Unit 1 [28] [29] have been successful, so the current Type A test interval requirement is 10 years.

PRA-BV1-13-028-ROO Page 14 of 62 Table 4-1 BVPS-1 Level2 PRA Model Release Category Groups, Bins, and Frequencies Total Bin Internal External Release Events Bin Events Bin Category Release Release Bin Definition Frequency Frequency Frequency Group Bin /yr /yr /vr BV01 Large, Early Release, Containment Sprays Unavailable,.

Containment Isolation Success, RCS Pressure > 600 ps1a 9.55E-10 5.34E-10 4.21 E-10 BV01S Large, Early Release, Containment Sprays Unavailable, 5.09E-1 0 7.50E*12 5.01 E-1 0 Small Cnmt. Isolation Failure, RCS Pressure>

600 psia BV02 Large, Early Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure > 600 ps1a 5.52E*10 2.37E-11 5.28E-10 BV02S Large, Early Release, Containment Sprays Available, Small 3.14E*11 2.92E-11 2.18E-12 Cnmt. Isolation Failure, RCS Pressure>

600 psia LERF Large, Early Release, Containment Sprays Unavailable,.

BV03 Containment Isolation Success, RCS Pressure < 600 ps1a or 2.39E*12 1.62E-12 7.66E-13 Alpha Mode Containment Failure BV03S Large, Early Release, Containment Sprays Unavailable, 2.58E*12 O.OOE+OO 2.58E-12 Small Cnmt. Isolation Failure, RCS Pressure < 600 psia BV04 Large, Early Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure < 600 ps1a 6.19E-12 2.48E*12 3.71 E-12 BV04S Large, Early Release, Containment Sprays Available, Small 4.35E-10 3.76E*1 0 5.92E-11 Cnmt. Isolation Failure, RCS Pressure < 600 psia BV05 Small, Early Release, Containment Sprays Unavailable, 1.57E-10 1.02E*1 0 5.49E-11 Containment Isolation Success, RCS Pressure > 200 psia BV05S Small, Early Release, Containment Sprays Unavailable, 5.33E*09 4.95E-09 3.80E-1 0 Small Cnmt. Isolation Failure, RCS Pressure>

200 psia BV06 Small, Early Release, Containment Sprays Available, . Containment isolation Success, RCS Pressure > 200 ps1a 2.41E*12 2.29E-12 1.20E*13 BV06S Small, Early Release, Containment Sprays Available, Small 9.72E*09 8.25E-09 1.47E*09 Cnmt. Isolation Failure, RCS Pressure > 200 psia SERF BV07 Small, Early Release, Containment Sprays Unavailable,.

Containment Isolation Success, RCS Pressure < 200 ps1a 9.80E*1 0 4.55E-1 0 5.24E*10 BV07S Small, Early Release, Containment Sprays Unavailable, 1.59E-08 1.35E-08 2.34E*09 Small Cnmt. Isolation Failure, RCS Pressure < 200 psia BVOB Small, Early Release, Containment Sprays Available, 1.17E-06 3.51 E-08 1.13E-06 Containment isolation Success, RCS Pressure < 200 psia BVOBS Small, Early Release, Containment Sprays Available, Small 6.17E*08 5.27E-08 8.95E*09 Cnmt. Isolation Failure, RCS Pressure < 200 psia BV09 Large, Late Release, Containment Sprays Unavailable, O.OOE+OO O.OOE+OO O.OOE+OO Containment isolation Success, RCS Pressure > 200 psla BV09S Large, Late Release, Containment Sprays Unavailable, Small O.OOE+OO 0.00E+00 O.OOE+OO Cnmt. Isolation Failure, RCS Pressure > 200 psia BV10 Large, Late Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure > 200 ps1a 3.29E*10 5.76E-11 2.71 E-10 LATE BV10S Large, Late Release, Containment Sprays Small Cnmt. Isolation Failure, RCS Pressure > 200 ps1a O.OOE+OO O.OOE+OO O.OOE+OO BV11 Large, Late Release, Containment Sprays Unavailable, . Containment Isolation Success, RCS Pressure < 200 ps1a O.OOE+OO O.OOE+OO O.OOE+OO BV11S Large, Late Release, Containment Sprays Small Cnmt. Isolation Failure, RCS Pressure<

200 ps1a O.OOE+OO O.OOE+OO O.OOE+OO PRA-BV1-13-028-ROO Page 15 of 62 Table 4-1. BVPS-1 Level2 PRA Model Release Category Groups, Bins, and Frequencies Release Total Bin Internal External Category Release Release Bin Definition Frequency Events Bin Events Bin Bin Frequency Frequency Group /yr IYI /'j_r BV12 Large, Late Release, Containment Sprays Available, 3.62E-08 1.57E-08 2.05E-08 Containment Isolation Success, RCS Pressure < 200 psla BV12S Large, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV13 Small, Late Release, Containment Sprays Unavailable, 2.95E-06 1.81 E-06 1.14E-06 Containment Isolation Success, RCS Pressure > 200 psla BV13S Small, Late Release, Containment Sprays Unavailable, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure > 200 psia BV14 Small, Late Release, Containment Sprays Available, O.OOE+OO O.OOE+OO O.OOE+OO Containment Isolation Success, RCS Pressure > 200 psia BV14S Small, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO LATE Cnmt. Isolation Failure, RCS Pressure > 200 psia (continued)

Small, Late Release, Containment Sprays Unavailable, BV15 Containment Isolation Success, RCS Pressure < 200 psia 5.07E-06 2.38E-06 2.69E-06 BV15S Small, Late Release, Containment Sprays Unavailable, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV16 Small, Late Release, Containment Sprays Available, O.OOE+OO O.OOE+OO O.OOE+OO Containment Isolation Success, RCS Pressure < 200 psia BV16S Small, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV17 Small, Late Release, Containment Isolation Success 2.22E-06 2.46E-07 1.97E-06 (Basemat Melt-through)

BV17S Small, Late Release, Small Cnmt. Isolation Failure (Basemat O.OOE+OO O.OOE+OO O.OOE+OO Melt-through)

BV18 Large, Containment Bypass (Unscrubbed Faulted SGTR, 1.85E-08 1.79E-08 6.26E-10 Pressure-Induced SGTR, or Temperature-Induced SGTR) LERF BV19 Large, Containment Bypass (Interfacing Systems LOCA) 2.31 E-08 2.31 E-08 O.OOE+OO SERF BV20 Small, Containment Bypass (Scrubbed Faulted SGTR) 9.45E-06 1.56E-06 7.88E-06 LONG BV21 Long-Term Containment Integrity (Intact Containment) 1.54E-06 1.08E-06 4.67E-07 TOTALS 2.26E-05 7.25E-06 1.53E-05 Population Dose Calculations The BVPS 50-mile baseline population dose (person-rem) used in this ILRT extension analysis is determined from the BVPS-1 Severe Accident Mitigation Alternative (SAMA) [19] results for the 50-mile lifetime (50-year) effective dose commitments.

The results presented in the BVPS-1 SAMA, Table 3.5-1 were developed for the BVPS License Renewal using the MELCOR Accident Consequence Code System (MACCS2) computer code, and are based on the average weather conditions at BVPS from 2001 through 2005, with the projected PRA-BV1-13-028-ROO Page 16 of 62 50-mile radius population of 3,607,001 in the year 2047. The plume data used in the MACCS2 analysis was based on a composite set of source term data for BVPS-1 and BVPS-2, and is appropriate for analyzing both units. Table 4-2 shows the results of applying the BVPS-1 SAMA, Table 3.5-1 population dose (Total L-EFFECTIVE LIFE Dose in Sieverts) to obtain the population dose in person-rem at 50 miles for BVPS-1. This table also provides the representative Level 2 release bins that were analyzed with MACCS2 for the BVPS SAMA Release Category.

Table 4-2. Calculation of BVPS Population Dose at 50 Miles BVPS Composite Weather Sensitivity Results for Total BVPS BVPS Population Repre-SAMA MACCS L-EFFECTIVE LIFE Dose in Sieverts Dose at sentative Release 2 Run 50 Miles Release Category Code 2001 2002 2003 2004 2005 Average (person-Bins rem) INTACT A 8 7 8 7 7 8 8.00E+02 BV21 ECF-B 50,400 47,200 51,000 53,600 40,800 48,600 4.86E+06 BV19 VSEQ ECF-c 44,500 41,400 43,800 46,500 37,000 42,640 4.26E+06 BV18 SGTR ECF-D 86,800 84,800 86,600 76,400 77,600 82,440 8.24E+06 BV01, DCH BV03 SECF-E 50,500 48,000 47,800 46,900 44,800 47,600 4.76E+06 N/A VSEQ SECF-F 35,200 35,500 33,200 34,000 36,400 34,860 3.49E+06 BV07S LOCI SECF-K 43,800 39,800 41,300 41,000 42,700 41,720 4.17E+06 BV05S BV5 LATE-G 1,530 1,440 1,780 1,600 1,450 1,560 1.56E+05 BV10, Large BV12 LATE-H 20,200 19,200 18,800 18,600 20,500 19,460 1.95E+06 BV13, Small BV15 LATE-H2 I 19,300 17,200 17,600 16,300 17,900 17,660 1.77E+06 BV09 Burn LATE-J 7,680 7,250 7,200 7,990 6,990 7,422 7.42E+05 BV17 BMMT Since not all of the BVPS Level 2 release bins were analyzed in the SAMA, a bounding SAMA release category must be assigned to the remaining release bins. Table 4-3, shows results of these conservatively assigned bounding SAMA release categories for each Level 2 release bin, along with the associated BVPS 50-mile population dose in person-rem.

PRA-BV1-13-028-ROO Page 17 of 62 Table 4-3. Assignment of SAMA Release Category and BVPS Dose to Release Bin Analyzed SAMA Assigned BVPS Release Release Category Release Bin Bounding Population Bin Category Sub-Grouping SAMA Release Dose at 50 Miles Description Category (person-rem)

BV01 ECF-DCH LERF ECF-DCH 8.24E+06 BV01S -LERF ECF-DCH 8.24E+06 BV02 -LERF ECF-DCH 8.24E+06 BV02S -LERF ECF-DCH 8.24E+06 BV03 ECF-DCH LERF ECF-DCH 8.24E+06 BV03S -LERF ECF-DCH 8.24E+06 BV04 -LERF ECF-DCH 8.24E+06 BV04S -LERF ECF-DCH 8.24E+06 BV05 -SERF-RCS > 200 psia SECF-BV5 4.17E+06 BV05S SECF-BV5 SERF -RCS > 200 psia SECF-BV5 4.17E+06 BV06 -SERF -RCS > 200 psia SECF-BV5 4.17E+06 BV06S -SERF -RCS > 200 psia SECF-BV5 4.17E+06 BV07 -SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV07S SECF-LOCI SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV08 -SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV08S -SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV09 LATE-H2 Burn LATE-Large, No Spray LATE -H2 Burn 1.77E+06 BV09S -LATE-Large, No Spray LATE -H2 Burn 1.77E+06 BV10 LATE-Large LATE -Large, Spray LATE-Large 1.56E+05 BV10S -LATE-Large, Spray LATE-Large 1.56E+05 BV11 -LATE-Large, No Spray LATE-H2 Burn 1.77E+06 BV11S -LATE-Large, No Spray LATE-H2 Burn 1.77E+06 BV12 LATE-Large LATE-Large, Spray LATE-Large 1.56E+05 BV12S -LATE-Large, Spray LATE-Large 1.56E+05 BV13 LATE-Small LATE-Small LATE-Small 1.95E+06 BV13S -LATE-Small LATE-Small 1.95E+06 BV14 -LATE-Small LATE-Small 1.95E+06 BV14S -LATE-Small LATE-Small 1.95E+06 BV15 LATE-Small LATE-Small LATE-Small 1.95E+06 BV15S -LATE-Small LATE-Small 1.95E+06 BV16 -LATE-Small LATE-Small 1.95E+06 BV16S -LATE-Small LATE-Small 1.95E+06 BV17 LATE-BMMT LATE-Basemat Melt-Through LATE-BMMT 7.42E+05 BV17S -LATE-Basemat Melt-Through LATE-BMMT 7.42E+05 BV18 ECF-SGTR LERF-Large Cnmt Bypass -SGTR ECF-SGTR 4.26E+06 BV19 ECF-VSEQ LERF-Large Cnmt Bypass -VSEQ ECF-VSEQ 4.86E+06 BV20 -SERF-Small Cnmt Bypass -SGTR ECF-SGTR 4.26E+06 BV21 INTACT LONG -Intact Cnmt INTACT 8.00E+02 PRA-BV1-13-028-ROO Page 18 of 62 Release Category Definitions Table 4-4 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology

[2]. 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 4-4. EPRI Containment Failure Classification

[2] Class Description Containment remains intact including accident sequences that do not lead to containment 1 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 pre-existing 3 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.

This class is similar to 4 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 pre-existing 5 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 and 6 maintenance requirements or verified per in service inspection and testing (181/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 induced by 8 phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.

PRA-BV1-13-028-ROO Page 19 of 62 Application of the BVPS-1 PRA Model Results to EPRI Accident Class A major factor related to this evaluation is that the results of the BVPS-1 Level 2 PRA model release bins defined in Table 4-1 do not directly correspond to the EPRI accident classes defined in Table 4-4. In order to use the EPRI Accident Classes presented in EPRI Report 1018243, it was necessary to match the BVPS-1 Level 2 release bins to the corresponding EPRI classes. Table 4-5 provides the relationship between the EPRI accident class and the BVPS-1 Level 2 release bins, including the delineation of LERF and non-LERF frequencies for Classes 7 and 8. It should be noted that in EPRI Report 1018243, the Class 2 group consists of all core damage accident progression bins for which a pre-existing leakage due to failure to isolate the containment occurs, and were dominated by failure to close of large (>2 inches in diameter) containment isolation valves. The Class 6 group also involved failures to isolate the containment, but were typically dominated by a failure to close smaller containment isolation valves. At BVPS all non-screened containment isolation valve failures are considered to be small (< 2 inches in diameter).

Therefore, these sequences with failures of the containment isolation valves to close will be binned into the EPRI Class 6 group, and are determined directly from the BVPS-1 PRA SERF bins BV05S, BV06S, BVO?S, and BV08S. Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes BVPS EPRI BVPS Release Corresponding Release Bin Grouping using EPRI Release Accident Category Group the EPRI Accident Class Description (bold Accident Category Sub-Level2 Bins Type) Class Group Class BV01, BV01 S, BV02, Large, early containment failures due to LERF BV02S, BV03, BV03S, 7 7 LERF BV04, BV04S accident phenomenon, at any RCS pressure Small, early containment failures due to 7 non-SERF BV05, BV06 accident phenomenon, with RCS pressure > 7 LERF 200 psia SERF BV05S, BV06S Small, early containment failures due to failure to isolate, with RCS pressure > 200 psia 6 6 Small, early containment failures due to 7 non-SERF BV07,BV08 accident phenomenon, with RCS pressure < 7 LERF 200 psia SERF BV07S, BV08S Small, early containment failures due to failure to isolate, with RCS pressure < 200 psia 6 6 PRA-BV1-13-028-ROO Page 20 of 62 Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes BVPS EPRI BVPS Release Corresponding Release Bin Grouping using EPRI Release Accident Category Category Group the EPRI Accident Class Description (bold Accident Level2 Bins Type) Class Sub-Group Class LATE-BV09, BV09S, BV10, Large, late containment failures due to 7 non-BV1 OS, BV11, BV11 S, 7 LARGE accident phenomenon LERF BV12, BV12S BV13,BV13S, BV14, Small, late containment failures due to LATE-BV14S,BV15,BV15S, 7 non-accident phenomenon (including basemat melt-7 SMALL BV16, BV16S, BV17, LERF BV17S through) LERF-Large containment bypass (includes CNMT BV18, BV19 interfacing-systems LOCAs, induced SGTRs, 8 8 LERF BYPASS and unscrubbed faulted SGTRs) SERF-CNMT BV20 Small containment bypass (includes scrubbed 8 non-8 faulted SGTRs) LERF BYPASS LONG BV21 Long-Term Containment Integrity (Intact Containment) 1 1 Population Dose Risk Calculation for EPRI Accident Class The correlation between the BVPS Level 2 release bins to EPRI accident class in Table 4-5 was used along with the Level 2 release bin frequencies presented in Table 4-1 (columns 4, 5, & 6), and the bounding BVPS population dose at 50 miles assigned to the Level 2 release bins presented in Table 4-3 (column 5), to obtain a population dose risk for this ILRT analysis.

The population dose risk was calculated by multiplying the Level 2 release bin frequency by the associated release bin BVPS population dose at 50 miles. The results from these computations for the BVPS-1 total, internal, and external events are presented in Table 4-6. The bin frequencies from Table 4-1 and BVPS population dose at 50 miles from Table 4-3 are also reproduced for clarity.

PRA-BV1-13-028-ROO Page 21 of 62 Table 4-6. BVPS-1 Level 2 Release Bin Frequency and Population Dose Risk Total Internal External BVPS Total Internal Events External Release Release Release Release Release Population Population Population Events Category EPRI Sub-Class Population Group Bin Bin Freq. Bin Freq. Bin Freq. Dose at SO Dose Risk Dose Risk Dose Risk (peryr) (peryr) (peryr) Miles (per.-rern) (person-rern/yr) (person-rern/yr) (person-rern/yr)

LERF BV01 9.55E-10 5.34E-10 4.21E-10 8.24E-+{)6 CLASS 7 LERF 7.87E-03 4.40E-03 3.47E-03 LERF BV01S 5.09E-10 7.50E-12 5.01E-10 8.24E-+{)6 CLASS 7LERF 4.19E-03 6.18E-05 4.13E-03 LERF BV02 5.52E-10 2.37E-11 5.28E-10 8.24E-+{)6 CLASS 7 LERF 4.55E-03 1.96E-04 4.35E-03 LERF BV02S 3.14E-11 2.92E-11 2.18E-12 8.24E-+{)6 CLASS 7 LERF 2.59E-04 2.41E-04 1.80E-05 LERF BV03 2.39E-12 1.62E-12 7.66E-13 8.24E-+{)6 CLASS 7 LERF 1.97E-05 1.34E-05 6.32E-06 LERF BV03S 2.58E-12 O.OOE-+{)0 2.58E-12 8.24E-+{)6 CLASS 7 LERF 2.13E-05 O.OOE-+{)0 2.13E-05 LERF BV04 6.19E-12 2.48E-12 3.71E-12 8.24E-+{)6 CLASS 7 LERF 5.10E-05 2.05E-05 3.05E-05 LERF BV04S 4.35E-10 3.76E-10 5.92E-11 8.24E-+{)6 CLASS 7LERF 3.59E-03 3.10E-03 4.88E-04 SERF BVOS 1.57E-10 1.02E-10 5.49E-11 4.17E-+{)6 CLASS 7 NON-LERF 6.56E-04 4.27E-04 2.29E-04 SERF BVOSS 5.33E-09 4.95E-09 3.80E-10 4.17E-+{)6 CLASS 6 2.22E-02 2.07E-02 1.59E-03 SERF BV06 2.41E-12 2.29E-12 1.20E-13 4.17E-+{)6 CLASS 7 NON-LERF 1.01E-05 9.57E-06 S.OOE-07 SERF BV06S 9.72E-09 8.25E-09 1.47E-09 4.17E-+{)6 CLASS 6 4.05E-02 3.44E-02 6.12E-03 SERF BV07 9.80E-10 4.55E-10 5.24E-10 3.49E-+{)6 CLASS 7 NON-LERF 3.42E-03 1.59E-03 1.83E-03 SERF BV07S 1.59E-08 1.35E-08 2.34E-09 3.49E-+{)6 CLASS 6 5.53E-02 4.71E-02 8.17E-03 SERF BV08 1.17E-06 3.51E-08 1.13E-06 3.49E-+{)6 CLASS 7 NON-LERF 4.06E-+{)0 1.22E-01 3.94E-t{)O SERF BV08S 6.17E-08 5.27E-08 8.95E-09 3.49E-+{)6 CLASS 6 2.15E-01 1.84E-01 3.12E-02 LATE BV09 O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.77E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV09S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.77E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV10 3.29E-10 5.76E-11 2.71E-10 1.56E-+{)5 CLASS 7 NON-LERF 5.13E-05 8.99E-06 4.23E-05 LATE BV10S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.56E-+{)5 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV11 O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0

• 1.77E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV11S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.77E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV12 3.62E-08 1.57E-08 2.05E-08 1.56E-+{)5 CLASS 7 NON-LERF 5.64E-03 2.45E-03 3.19E-03 LATE BV12S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.56E-+{)5 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV13 2.95E-06 1.81E-06 1.14E-06 1.95E-+{)6 CLASS 7 NON-LERF 5.73E-+{)0 3.52E-+{)0 2.21E-+{)0 LATE BV13S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV14 O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV14S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV15 5.07E-06 2.38E-06 2.69E-06 1.95E-+{)6 CLASS 7 NON-LERF 9.86E-+{)0 4.63E-+{)0 5.23E-+{)0 LATE BV15S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV16 O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV16S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 1.95E-+{)6 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LATE BV17 2.22E-06 2.46E-07 1.97E-06 7.42E-+{)5 CLASS 7 NON-LERF 1.65E-+{)0 1.83E-01 1.46E-+{)0 LATE BV17S O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 7.42E-+{)5 CLASS 7 NON-LERF O.OOE-+{)0 O.OOE-+{)0 O.OOE-+{)0 LERF BV18 1.85E-08 1.79E-08 6.26E-10 4.26E-+{)6 CLASS 8 LERF 7.91E-02 7.64E-02 2.67E-03 LERF BV19 2.31E-08 2.31E-08 O.OOE-+{)0 4.86E-+{)6 CLASS 8 LERF 1.12E-01 1.12E-01 O.OOE-+{)0 SERF BV20 9.45E-06 1.56E-06 7.88E-06 4.26E-+{)6 CLASS 8 NON-LERF 4.03E-+{)1 6.66E-+{)0 3.36E-+{)1 LONG BV21 1.54E-06 1.08E-06 4.67E-07 8.00E-+{)2 CLASS 1 1.23E-03 8.61E-04 3.73E-04 TOTALS 2.26E-05 7.25E-06 1.53E-05 6.21E-+{)1 1.56E-+{)1 4.65E-+{)1 PRA-BV1-13-028-ROO Page 22 of 62 The EPRI accident sub-class release frequency for BVPS-1 was obtained by summing the assigned Level 2 release bin frequencies from Table 4-6. Likewise, the EPRI accident class population dose risk for BVPS-1 was obtained by summing the assigned BVPS population dose from Table 4-6. In the case of BVPS-1, a frequency-weighted dose is used to represent EPRI accident Class 6, Class 7 non-LERF, Class 7 LERF, and Class 8 LERF population dose since these classes are composed of multiple BVPS release category bins. Table 4-7 lists the release frequency, population dose risk, and weighted average population dose for BVPS-1 organized by EPRI release category, including the delineation of LERF and non-LERF frequencies for Classes 7 and 8. For the total (internal plus external events), the weighted average population dose (Column 5) was determined by dividing the associated population dose risk (Column 4) by the accident sub-class frequency (Column 3) for each of the EPRI accident sub-class.

An example of applying this frequency-weighted average population dose methodology to the total Class 8 LERF is calculated as follows: From Table 4-5, the Class 8 LERF is comprised of BVPS Release Category Group Level 2 Bins BV18 and BV19. From Table 4-6, the frequency for release bin BV18 is 1.85E-08 /yr and the BVPS population dose at 50 miles is 4.26E+06 person-rem, for a BVPS-1 dose risk of 1.85E-08 /yr

• 4.26E+06 person-rem

= 7.91 E-02 person-rem/yr.

Also from Table 4-6, the frequency for release bin BV19 is 2.31 E-08 /yr and the BVPS population dose at 50 miles is 4.86E+06 person-rem, for a BVPS-1 dose risk of 2.31 E-08 /yr

• 4.86E+06 person-rem

= 1.12E-01 person-rem/yr.

The frequency-weighted average population dose for Class 8 LERF = (release bin BV18 population dose risk + release bin BV19 population dose risk) I (release bin BV18 frequency

+ release bin BV19 frequency)

= (7.91 E-02 + 1.12E-01) person-rem/yr I (1.85E-08

+ 2.31 E-08) per yr = (1.91 E-01 person-rem/yr)

I (4.16E-08

/yr) 1 = 4.59E+06 person-rem The internal and external events weighted average population doses were similarly obtained for the EPRI accident sub-classes.

1 The frequencies presented in Table 4-6 are rounded to two decimal places so for this example the total frequency is 4.16E-08/yr, while the values calculated in Table 4-7 were derived from frequencies with four decimal places so the total frequency shown is 4.17E-08/yr.

Table 4-7. BVPS-1 50-Mile Population Dose Risk by EPRI Accident Class BVPS Total EPRI EPRI Weighted EPRI Accident Release Category Accident Population Average Accident Sub-Group Sub-Class Dose Risk Population Sub-Class Frequency (person-Dose Frequency Class Level2 Bins rem/yr) (person-(/yr) rem) (/yr) 1 BV21 1.54E-06 1.23E-03 8.00E+02 1.08E-06 6 BVOSS, BV06S, BV07S, 9.26E-08 3.33E-01 3.60E+06 7.94E-08 BV08S BV05, BV06, BV07, BV08, BV09, BV09S, BV1 0, BV1 OS, BV11, 7 non-BV11S,BV12,BV12S, 1.14E-05 2.13E+01 1.86E+06 4.49E-06 LERF BV13,BV13S, BV14, BV14S,BV15,BV15S, BV16, BV16S, BV17, BV17S BV01, BV01 S, BV02, 7LERF BV02S, BV03, BV03S, 2.49E-09 2.06E-02 8.24E+06 9.74E-10 BV04, BV04S 8 non-BV20 9.45E-06 4.03E+01 4.26E+06 1.56E-06 LERF 8 LERF BV18, BV19 4.17E-08 1.91 E-01 4.59E+06 4.10E-08 -_L__ --------__ L__ Internal Events Weighted Population Average Dose Risk Population (person-Dose rem/yr) (person-rem) 8.61 E-04 8.00E+02 2.86E-01 3.60E+06 8.46E+00 1.89E+06 8.03E-03 8.24E+06 6.66E+00 4.26E+06 1.89E-01 4.60E+06 -----External Events EPRI Accident Population Sub-Class Dose Risk Frequency (person-rem/yr) (/yr) 4.67E-07 3.73E-04 1.31 E-08 4.71 E-02 6.95E-06 1.28E+01 1.52E-09 1.25E-02 7.88E-06 3.36E+01 6.26E-10 2.67E-03 ----L__ --Weighted ! Average Population Dose (person* rem) 8.00E+02 3.58E+06 1.85E+06 8.24E+06 4.26E+06 4.26E+06 --"'U :0 =!> lD Ill ' !0 ...... coW 1\Jb wN o'fl """":0 0)0 1\J 0 PRA-BV1-13-028-ROO Page 24 of 62 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) 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 accident class, as defined in Table 4-4, 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 [27]. 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, Jeffery's non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5/(217+1)

= 0.0023). In a follow on letter [20] to their ILRT guidance document [3], NEI issued additional information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC RG 1.174. This additional NEI information includes a discussion of conservatisms in the quantitative guidance for delta LERF. NEI describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method. The supplemental information states: The methodology employed for determining LERF (Class 3b frequency) involves conservatively multiplying the CDF by the failure probability for this class (3b) of accident.

This was done for simplicity and to maintain conservatism.

However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage. The application of this additional guidance to the analysis for BVPS-1, as detailed in Section 5, involves the following:

• The Class 7 LERF and Class 8 LERF sequences are subtracted from the CDF that is applied to Class 3b. Class 7 LERF and Class 8 LERF events refer to sequences with either large containment failures due to severe accident phenomena or large containment bypass events. These sequences PRA-BV1-13-028-ROO Page 25 of 62 are already considered to contribute to LERF in the BVPS-1 Level 2 PRA analysis.

To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Consistent with the NEI Guidance [3], 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 I 2), and the average time that a leak could exist without detection for a ten-year interval is 5 years (1 0 yr I 2). This change would lead to a non-detection probability that is a factor of 3.33 (5.011.5) higher for the probability of a leak that is detectable only by ILRT testing. Correspondingly, an extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 (7.511.5) increase in the 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 I P3 request for a time ILRT extension that was approved by the NRC [9]) because it does not factor in the possibility that the failures could be detected by other tests (e.g., the Type B local leak rate tests that will still occur.) Eliminating this possibility conservatively over-estimates the factor increases attributable to the ILRT extension.

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 [5]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. BVPS-1 can be considered to have a similar type of containment as Calvert Cliffs. 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 PRA-BV1-13-028-ROO Page 26 of 62

• Consistent with the Calvert Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures. (See Table 4-8, Step 1.)

• The two corrosion events that were initiated from the non-visible (backside) portion of the containment liner used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the BVPS-1 containment analysis.

These events, one at North Anna Unit 2 (September 1999) caused by a timber embedded in the concrete immediately behind the containment liner, and one at Brunswick Unit 2 (April 1999) caused by a cloth work glove embedded in the concrete next to the liner, were initiated from the nonvisible (backside) portion of the containment liner. A search of the NRC website LER database (https://lersearch.inl.gov/LERSearchCriteria.aspx) for ["containment liner" AND "defect" OR "hole"] through June 25, 2013 identified that two additional events have occurred since the Calvert Cliffs analysis was performed.

In January 2000, a 3/16-inch circular through-liner hole was found at Cook Nuclear Plant Unit 2 caused by a wooden brush handle embedded immediately behind the containment liner. The other event occurred in April 2009, where a through-liner hole approximately 3/8-inch by 1-inch in size was identified in the BVPS-1 containment liner caused by pitting originating from the concrete side due to a piece of wood that was left behind during the original construction that came in contact with the steel liner. Two other containment liner through wall hole events occurred at Turkey Point Units 3 and 4 in October 2010 and November 2006, respectively.

However, these events originated from the visible side caused by the failure of the coating system, which was not designed for periodic immersion service, and are not considered to be applicable to this analysis.

More recently, in October 2013, some through-wall containment liner holes were identified at BVPS-1, with a combined total area of approximately 0.395 square inches. One of these holes, found during the visual inspections of the internal containment liner and protective coatings, was located about 7 inches above the basemat floor. The others were identified during the follow-up lab analysis, and were located about 2 inches below the basemat concrete floor line. The cause of these through wall liner holes was attributed to corrosion originating from the outside concrete surface due to the presence of rayon fiber foreign material that was left behind during the original construction and was contacting the steel liner. For risk evaluation purposes, these five total corrosion events occurring in 66 operating plants with steel containment liners over a 17.1 year period from September 1996 to October 4, 2013 (i.e., 5/(66*17.1)

= 4.43E-03) are bounded by the estimated historical flaw probability based on the two events in the 5.5 year period of the Calvert Cliffs analysis (i.e., 2/(70*5.5)

= 5.19E-03) incorporated in the EPRI guidance. (See Table 4-8, Step 1.) However, since two of these five industry corrosion events occurred PRA-BV1-13-028-ROO Page 27 of 62 at BVPS-1, a BVPS-1 upper bound sensitivity case is provided in Section 6, assuming a probability of 1.0 (1 00% certain) that another hole will occur in the cylindrical steel liner during the 15 year ILRT extension.

• 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 4-8, Steps 2 and 3.) Sensitivity studies are included in Section 6 that addresses 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% (1 0% 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 their ILRT target pressure of 64.7 psi a. For BVPS-1, probabilities of 1% for the cylinder and dome, and 0.1% for the basemat are assumed in this analysis, which are consistent with the EPRI 1018243 guidance. (See Table 4-8, Step 4.) Sensitivity studies are included in Section 6 that increase and decrease the probabilities by an order of magnitude.

• 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 4-8, 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 4-8, Step 5.) Sensitivity studies are included in Section 6 that evaluate total detection failure likelihood of 5% and 15%, respectively.

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

This approach avoids a detailed analysis of containment failure timing and operator recovery actions. That is, the probability of all non-detectable failures from the corrosion sensitivity analysis are added to the EPRI Class 3b (and subtracted from EPRI Class 1 ).

Analysis Table 4-8. Steel Liner Corrosion Base Case Step Description Containment Cylinder and Dome Historical Steel Liner Flaw Events: 2 Likelihood 1 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis -2/(70

• 5.5) = 5.19E-03 70 steel lined containments and 5.5 years). Age Adjusted Steel Liner Year Failure Rate Flaw Likelihood 1 2.05E-03 During 15-year interval, assume failure rate doubles avg 5-10 5.19E-03 2 every five years (14.9% 15 1.43E-02 increase per year). The average for 5th to 1 Oth year is set to the historical failure rate (consistent with Calvert 15 year average

= 6.44E-03 Cliffs analysis).

Flaw Likelihood at 3, 10, 0.71% (1 to 3 years) and 15 years 4.14% (1 to 10 years) Uses age adjusted liner flaw 9.67% (1 to 15 years) likelihood (Step 2), assuming (Note that the Calvert Cliffs failure rate doubles every five analysis presents the delta years (consistent with Calvert between 3 and 15 years of 3 Cliffs analysis-See Table 6 8.7% to utilize in the estimation of Reference

[5]). of the delta-LERF value. For this analysis, however, the values are calculated based on the 3, 1 0, and 15 year intervals consistent with the desired presentation of the results. PRA-BV1-13-028-ROO Page 28 of 62 Containment Basemat Events: 0 (assume half a failure) 0.5/(70

• 5.5) = 1.30E-03 Year Failure Rate 1 5.12E-04 avg 5-10 1.30E-03 15 3.58E-03 15 year average = 1.61 E-03 0.18% (1 to 3 years) 1.03% (1 to 10 years) 2.42% (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 1 5 years of 2.2% to utilize in the estimation of the delta-LERF value. For this analysis, however, the values are calculated based on the 3, 10, and 15 year intervals consistent with desired presentation of the results.

Table 4-8. Steel Liner Corrosion Base Case Step Description Containment Cylinder and Dome Likelihood of Breach in Containment Given Steel Liner Flaw The failure probability of the cylinder and dome is 4 assumed to be 1% 1.0% (compared to 1.1% in the Calvert Cliffs analysis).

The basemat failure probability is assumed to be a factor of ten less, 0.1 %, (compared to 0.11% in the Calvert Cliffs analysis).

Visual Inspection Detection 10% Failure Likelihood 5% failure to identify visual Utilize assumptions flaws plus 5% likelihood that the consistent with Calvert Cliffs flaw is not visible (not through-5 analysis.

cylinder but could be detected by ILRT) All events have been detected through visual inspection.

5% visible failure detection is a conservative assumption.

Likelihood of Non-Detected 0.00071% (at 3 years) Containment Leakage 0.71%

• 1%

• 10% 6 (Steps 3

• 4

• 5) 0.00414% (at 10 years) 4.14%

• 1%

• 10% 0.00967% (at 15 years) 9.67%

• 1%

• 10% PRA-BV1-13-028-ROO Page 29 of 62 Containment Basemat 0.1% 100% Cannot be visually inspected.

0.00018% (at 3 years) 0.18%

• 0.1%

• 100% 0.00103% (at 10 years) 1.03%

• 0.1%

• 100% 0.00242% (at 15 years) 2.42%

• 0.1%

• 100%

PRA-BV1-13-028-ROO Page 30 of 62 The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 in Table 4-8 for the containment cylinder and dome, and the containment basemat as summarized below for BVPS-1: At 3 years: 0.00071% + 0.00018% = 0.00089% At 10 years: 0.00414% + 0.00103% = 0.00517% At 15 years: 0.00967% + 0.00242% = 0.01208% The above factors are applied to those core damage accidents that are not already independently LERF or that could never result in LERF. For example, the 3-in-1 0 year case for the total risk is calculated as follows:

• Per Table 5-3, the EPRI Class 3b frequency is 5.19E-08/yr.

• As discussed in Section 5.1, the BVPS-1 CDF associated with accidents that are not independently LERF is CDF -Class 7 LERF -Class 8 LERF, or 2.26E-05/yr-2.49E-09/yr-4.17E-08/yr

= 2.25E-05/yr.

• The increase in the base case Class 3b frequency due to the induced concealed flaw issue is calculated as 2.25E-05/yr

• 8.9E-06 = 2.00E-1 0/yr, where 8.9E-06 (0.00089%)

was previously shown above to be the cumulative likelihood of non-detected containment leakage due to corrosion at 3 years.

• The 3-in-1 0 year Class 3b frequency including the corrosion-induced concealed flaw issue is calculated as 5.19E-08/yr

+ 2.00E-1 0/yr = 5.21 E-08/yr.

5. RESULTS PRA-BV1-13-028-ROO Page 31 of 62 The application of the approach based on the guidance contained in EPRI Report No. 1009325, Revision 2-A, Appendix H, EPRI TR-1 04285 [2] and previous risk assessment submittals on this subject [5, 8, 21, 22, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5-1 lists these accident classes. The analysis performed examined the BV1 REV SA specific accident sequences in which the containment remains intact or the containment is impaired.

Specifically, the break down of the severe accidents contributing to risk were considered in the following manner:

• Core damage sequences in which the containment remains intact initially and in the long term (EPRI 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 small containment isolation failures as a result of the accident sequence progression (EPRI Class 6 sequences).

For example, a 1-inch diameter containment isolation valve failing to close following a valid signal to close. These are accounted for in this evaluation as part of the baseline risk profile; however, they are not affected by the ILRT frequency change.

• Accident sequences involving failures induced by phenomena (EPRI Class 7 sequences), containment bypassed events (EPRI Class 8 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.

• All large (> 2-inch diameter) containment isolation failures (EPRI Class 2 sequences) were screened out during the BVPS-1 containment isolation analysis.

Therefore, this class is not specifically examined since it does not influence the results of this analysis.

• 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.

Table 5-1. Accident Classes Accident Classes (Containment Release Type) 1 2 3a 3b 4 5 6 7 8 CDF Description No Containment Failure Large Isolation Failures (Failure to Close) Small Isolation Failures (liner breach) Large Isolation Failures (liner breach) PRA-BV1-13-028-ROO Page 32 of 62 Small Isolation Failures (Failure to seal -Type B) Small Isolation Failures (Failure to seal-Type C) Other Isolation Failures (e.g., dependent failures)

Failures Induced by Phenomena (Early and Late) Bypass (Interfacing System LOCA) All CET End states (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 5-1. 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 3 to 15 and 1 0 to 15 years. Step 4) Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.17 4. Step 5) Determine the impact on the Conditional Containment Failure Probability (CCFP)

PRA-BV1-13-028-ROO Page 33 of 62 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 existing leaks is included in the model. (These events are represented by the Class 3 sequences in EPRI TR-1 04285). The question on containment integrity was modified to include the probability of a liner breach or bellows failure (due to excessive leakage) at the time of core damage. 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 5-1 were developed for BVPS-1 by first determining the frequencies for Classes 1, 6, 7 and 8, as shown in Table 4-7, by using the categorized sequences and the identified correlations shown in Table 4-5. Next, the frequencies for Classes 3a and 3b were determined, which were then used to revise the Class 1 frequency in order to maintain the CDF. 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. The total frequency of the categorized sequences in the BVPS-1 Level 2 PRA is 2.26E-05/yr, which is also the total CDF in the BVPS-1 Level 1 PRA, so no scaling factor is necessary.

Table 5-2 contains the frequencies from the categorized sequences based on Table 4-7. The results are summarized below and in Table 5-3. Table 5-2. BVPS-1 Categorized Accident Classes and Frequencies EPRI Accident EPRI Accident EPRI Accident EPRI BVPS Sub-Class Sub-Class Sub-Class Accident Level 2 Release Bins Frequency for Frequency for Frequency for Sub-Class Total Risk Internal Events External Events (/yr) (/yr) (/yr) 1 BV21 1.54E-06 1.08E-06 4.67E-07 6 BV05S,BV06S,BV07S, 9.26E-08 7.94E-08 1.31 E-08 BV08S PRA-BV1-13-028-ROO Page 34 of 62 Table 5-2. BVPS-1 Categorized Accident Classes and Frequencies EPRI Accident EPRI Accident EPRI Accident EPRI BVPS Sub-Class Sub-Class Sub-Class Accident Level 2 Release Bins Frequency for Frequency for Frequency for Sub-Class Total Risk Internal Events External Events {/yr) {/yr) {/yr) BV05, BV06, BV07, BV08, BV09,BV09S,BV10,BV10S, 7 non-BV11, BV11 S, BV12, BV12S, 1.14E-05 4.49E-06 6.95E-06 LERF BV13,BV13S, BV14, BV14S, BV15, BV15S, BV16,BV16S, BV17, BV17S 7 LERF BV01,BV01S,BV02,BV02S, 2.49E-09 9.74E-10 1.52E-09 BV03,BV03S,BV04,BV04S 8 non-BV20 9.45E-06 1.56E-06 7.88E-06 LERF 8 LERF BV18, BV19 4.17E-08 4.1 OE-08 6.26E-10 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 <1 0 La) or large (> 100 La). The respective frequencies per year are determined as follows: P R 0 Bclass_3a

= probability of small pre-existing containment liner leakage [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, additional consideration is made to not apply these failure probabilities on those cases that are already LERF scenarios (i.e., the Class 7 LERF and Class 8 LERF contributions).

For the total risk contribution the Class 3a and Class 3b frequencies are calculated as follows: Total Class 3a Frequency

= 0.0092 * (CDF-Class 7 LERF-Class 8 LERF) = 0.0092* (2.26E 2.49E-09-4.17E-08}

= 2.08E-07/yr PRA-BV1-13-028-ROO Page 35 of 62 Total Class 3b Frequency

= 0.0023 * (CDF-Class 7 LERF-Class 8 LERF) =0.0023 * (2.26E 2.49E-09-4.17E-08)

= 5.19E-08/yr Similarly, the Class 3a and Class 3b frequencies for the internal and external events are: Internal Class 3a Frequency

= 0.0092 * (7.25E 9.74E-1 0-4.1 OE-08) = 6.64E-08/yr Internal Class 3b Frequency

= 0.0023 * (7 .25E-06-9. 74E-1 0-4.1 OE-08) = 1.66E-08/yr External Class 3a Frequency

= 0.0092 * (1.53E 1.52E-09-6.26E-1 0) = 1.41 E-07/yr External Class 3b Frequency

= 0.0023 * (1.53E 1.52E-09-6.26E-1 0) = 3.53E-08/yr For this analysis, the associated containment leakage for Class 3a is 10 La and for Class 3b is 100 La. These assignments are consistent with the guidance provided in EPRI Report No. 1009325, Revision 2-A. Class 1 Sequences.

This group consists of all core damage accident progression bins for which the containment remains intact (modeled as Technical Specification Leakage).

The frequency per year is initially determined from the Level 2 Release Category BV21 listed in Table 5-2, minus the EPRI Class 3a and 3b frequency, calculated above. Subtracting Class 3a and Class 3b frequencies from the initial Class 1 frequency will preserve the total CDF. Therefore, the revised total Class 1 frequency is given as: Total Class 1 Frequency (revised)

= Initial Class 1 -Class 3a-Class 3b = (1.54E 2.08E-07-5.19E-08)

/yr = 1.28E-06 per year Likewise, the internal and external events revised Class 1 frequencies are: Internal Class 1 Frequency (revised)

= (1.08E 6.64E-08-1.66E-08)

/yr = 9.94E-07 per year External Class 1 Frequency (revised)=

(4.67E 1.41 E-07-3.53E-08)

/yr = 2.90E-07 per year PRA-BV1-13-028-ROO Page 36 of 62 Class 2 Sequences.

This group consists of all core damage accident progression bins for which a pre-existing leakage due to failure to isolate the containment occurs. These sequences are dominated by failure-to-close

{>2-inch diameter) containment isolation valves. Such sequences contribute to the plant LERF. For the BVPS-1 PRA model, a containment isolation analysis was performed to estimate the frequency of failure to isolate lines that could cause a significant risk of radioactive release. The results of this analysis screened-out all containment penetrations

> 2-inch diameter.

Furthermore, the Beaver Valley Power Station containments are operated at slightly sub-atmospheric pressures (BVPS Technical Specification LCO 3.6.4 [18] states that containment pressure shall 12.8 psia and::;; 14.2 psia), thus the baseline PRA models do not consider a large pre-existing loss of containment isolation to be credible.

Therefore, the frequency per year for these Class 2 sequences is assumed to be zero. The containment isolation failures for the penetrations that did not screen-out (i.e., <= 2-inch diameter) are captured in the Class 6 Sequences.

The Class 2 group is not evaluated any further in this analysis.

Class 4 Sequences.

This group consists of all core damage accident progression bins for which containment isolation failure-to-seal of Type B test components occurs. Because these failures are detected by Type B tests which are unaffected by the Type A ILRT, this group is not evaluated any further in the analysis.

Class 5 Sequences.

This group consists of all core damage accident progression bins for which a containment isolation failure-to-seal of Type C test components.

Because the failures are detected by Type C tests which are unaffected by the Type A ILRT, this group is not evaluated any further in this analysis.

Class 6 Sequences.

Similar to Class 2, the Class 6 group is comprised of isolation faults that occur as a result of the accident sequence progression, but are dominated by the failure of containment isolation valves (<=2-inch diameter) to close following an event. The leakage rate from <= 2-inch diameter holes are not considered large by the PRA LERF definition

[17]; therefore, sequences with containment isolation valve failures are placed into Class 6 to represent a small isolation failure. This value was taken directly from the BVPS-1 PRA. The frequency per year for these sequences is obtained from the Release Categories BV05S, BV06S, BVO?S, and BV08S, as listed in Table 5-2. Class 7 Sequences.

This group consists of all core damage accident progression bins that result in containment failure induced by severe accident phenomena (e.g., overpressure).

At BVPS, this group is broken into containment failures that result in LERF, and those that do not. The frequency PRA-BV1-13-028-ROO Page 37 of 62 per year for the Class 7 LEAF sequences is obtained from Release Categories BV01, BV01 S, BV02, BV02S, BV03, BV03S, BV04, and BV04S, as listed in Table 5-2. The frequency per year for the Class 7 non-LEAF sequences is obtained from Release Categories BV05, BV06, BV07, BV08, BV09, BV09S, BV10, BV10S, BV11,BV11S, BV12, BV12S, BV13, BV13S, BV14, BV14S, BV15, BV15S, BV16, BV16S, BV17, and BV17S, as listed in Table 5-2. Class 8 Sequences.

This group consists of all core damage accident progression bins in which the containment is bypassed.

At BVPS, this group is broken into containment failures that result in LEAF, and those that do not. The frequency per year for the Class 8 LEAF sequences is obtained from Release Categories BV18 and BV19, as listed in Table 5-2. The frequency per year for the Class 8 non-LEAF sequences is obtained from Release Category BV20, as listed in Table 5-2. 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-1 04285 the NEI Interim Guidance, and guidance provided in EPRI Report No. 1009325, Revision 2-A. Table 5-3 summarizes these accident frequencies by accident class for BVPS-1. Table 5*3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-1 Base Case) Total Frequency (per yr) Internal Events Frequency External Events Frequency Accident (per yr) (per yr) Classes (Cnmt. Description EPRI EPRI EPRI Release EPRI Methodology EPRI Methodology EPRI Methodology Type) Methodology Plus Methodology Plus Methodology Plus Corrosion Corrosion Corrosion 1 No Containment Failure 1.28E-06 1.28E-06 9.94E-07 9.94E-07 2.90E-07 2.90E-07 2 Large Isolation Failures N/A N/A N/A N/A N/A N/A (Failure to Close) 3a Small Isolation Failures (liner 2.08E-07 2.08E-07 6.64E-08 6.64E-08 1.41 E-07 1.41 E-07 breach) 3b Large Isolation Failures (liner 5.19E-08 5.21E-08 1.66E-08 1.67E-08 3.53E-08 3.54E-08 breach) Small Isolation Failures N/A N/A N/A N/A N/A N/A 4 (Failure to seal-Type B) Small Isolation Failures N/A N/A N/A N/A N/A N/A 5 (Failure to seal-Type C)

PRA-BV1-13-028-ROO Page 38 of 62 Table 5*3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-1 Base Case) Total Frequency (per yr) Internal Events Frequency External Events Frequency Accident (per yr) (per yr) Classes (Cnmt. Description EPRI EPRI EPRI Release EPRI Methodology EPRI Methodology EPRI Methodology Type) Methodology Plus Methodology Plus Methodology Plus Corrosion Corrosion Corrosion 6 Other Isolation Failures (e.g., 9.26E-08 9.26E-08 7.94E-08 7.94E-08 1.31 E-08 1.31 E-08 small isolation valve failures) 7 non-Failures Induced by Phenomena (Early and Late 1.14E-05 1.14E-05 4.49E-06 4.49E-06 6.95E-06 6.95E-06 LERF non-LERF)

Failures Induced by 7LERF Phenomena (Early and Late 2.49E-09 2.49E-09 9.74E-10 9.74E-10 1.52E-09 1.52E-09 LERF) 8 non-Containment Bypass (non-9.45E-06 9.45E-06 1.56E-06 1.56E-06 7.88E-06 7.88E-06 LERF LERF) 8 LERF Containment Bypass (LERF) 4.17E-08 4.17E-08 4.10E-08 4.10E-08 6.26E-10 6.26E-10 CDF All GET End states 2.26E-05 2.26E-05 7.25E-06 7.25E-06 1.53E-05 1.53E-05 5.2 STEP 2: DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR Plant-specific release analyses were performed to estimate the weighted average person-rem doses to the population within a 50-mile radius from the plant. The releases are based on a combination of the information provided by the BVPS SAMA analysis [19] and the Level 2 containment failure release frequencies and BVPS population dose risk developed in Section 4.2 of this analysis (see Table 4-7). The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with the guidance provided in EPRI Report No. 1009325, Revision 2-A. To determine the dose rates for EPRI accident Classes 3a and 3b, the population dose for EPRI accident Class 1 (assumed to be 1 La) is multiplied by the factors of 1 0 La and 100 La, respectively.

The results of applying these releases to the EPRI containment failure classifications are provided in Table 5-4. The population dose estimates derived for use in this risk evaluation per the EPRI methodology

[2] containment failure PRA-BV1-13-028-ROO Page 39 of 62 classifications are consistent with the NEI guidance [3] as modified by EPRI Report No. 1009325, Revision 2-A. Table 5-4. BVPS-1 Population Dose Estimates for Population Within 50 Miles Accident Classes Weighted Average Population Dose at 50 Miles (person-rem) (Containment Description Release Type) Total Internal Events External Events 1 No Containment Failure 8.00E+02 8.00E+02 8.00E+02 2 Large Isolation Failures (Failure to Close) N/A N/A N/A 3a Small Isolation Failures (liner breach) 8.00E+03 8.00E+03 8.00E+03 3b Large Isolation Failures (liner breach) 8.00E+04 8.00E+04 8.00E+04 4 Small Isolation Failures (Failure to seal-N/A N/A N/A Type B) 5 Small Isolation Failures (Failure to seal-N/A N/A N/A Type C) 6 Other Isolation Failures (e.g., small isolation valve failures) 3.60E+06 3.60E+06 3.58E+06 7 non-LEAF Failures Induced by Phenomena (Early and 1.86E+06 1.89E+06 1.85E+06 Late non-LERF) 7 LEAF Failures Induced by Phenomena (Early and Late LERF) 8.24E+06 8.24E+06 8.24E+06 8 non-LEAF Containment Bypass (non-LERF) 4.26E+06 4.26E+06 4.26E+06 8 LEAF Containment Bypass (LERF) 4.59E+06 4.60E+06 4.26E+06 The above dose estimates, when combined with the results presented in Table 5-3, yield the BVPS-1 baseline mean consequence measures for each accident class. These results are presented in Table 5-5 for the total BVPS-1 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

PRA-BV1-13-028-ROO Page 40 of 62 5.3 STEP 3: EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS The next step is to evaluate the risk impact of extending the test interval from its current ten-year value to fifteen-years.

To do this, an evaluation must first be made of the risk associated with the ten-year interval since the base case applies to a 3-year interval (i.e., a simplified representation of a 3-in-1 0 interval).

Risk Impact Due to 1 0-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 frequencies of Class 3a and 3b sequences are 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 1 0-year interval are presented in Table 5-5 for the total BVPS-1 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

Risk Impact Due to 15-Year Test Interval The risk contribution for a 15-year interval is calculated in a manner similar to the 1 0-year interval.

The difference is in the increase in probability of leakage in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the 3-year interval value, as described in Section 4.3. The results for this 15-year interval calculation are presented in Table 5-5 for the total BVPS-1 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

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. 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 core damage frequency (CDF) below 1.0E-06/yr and increases in LERF below 1.0E-07/yr, and small changes in LERF as below 1.0E-06/yr.

Because the ILRT does not impact CDF, the relevant metric is LERF. However, a sensitivity assessment of the impacts on CDF resulting from PRA-BV1-13-028-ROO Page 41 of 62 a loss of containment overpressure due to a large containment failure is provided in Section 6.4. For BVPS-1, 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).

The change in (Delta) LERF is determined using the equation below, where the "frequency of Class 3b frequency x" is the frequency of the EPRI accident Class 3b for the ILRT interval of interest and the "frequency of Class 3b baseline" is defined as the EPRI accident Class 3b frequency for ILRTs performed on a three-per-1 a-years basis.

LlLERF = (frequency of Class 3b new interval x) -(frequency of Class 3b baseline)

Based on the original 3-in-1 0 year test interval assessment from Table 5-5, the total Class 3b frequency from both internal and external events is 5.21 E-08/yr, which includes the corrosion effect of the containment liner. Based on a year test interval from Table 5-5, the total Class 3b frequency is 1.74E-07/yr; and, based on a fifteen-year test interval from Table 5-5, the total Class 3b frequency is 2.62E-07/yr, both of which include corrosion effects. Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years (including corrosion effects) is 2.1 OE-07/yr.

Similarly, the increase due to increasing the interval from 10 to 15 years is 8.80E-08/yr.

Table 5-6 and Table 5-7 present the Delta LERF results for the internal and external events, respectively.

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 the current 1 0-year requirement, and just above that criteria when compared to the original 3-year requirement, placing it into Region II of Figure 4 of RG 1.174 [4] (small changes in LERF). Approximately 32% of this change in LERF by increasing the ILRT test interval from 3 to 15 years (including corrosion effects) is due to internal events, while 68% is associated with external events. 5.5 STEP 5: DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY (CCFP) Another parameter that the NRC guidance in RG 1.174 states can provide input into the decision-making process is the change in the conditional containment failure probability (CCFP). The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can be calculated from the results of this analysis.

One of the difficult aspects of this calculation is providing a definition of the "failed containment." In this assessment, the CCFP is defined such that containment failure includes all radionuclide release end PRA-BV1-13-028-ROO Page 42 of 62 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 guidance [27]. Based on this guidance, the frequency of those sequences which result in no containment failure is determined by summing the Class 1 and Class 3a results. The NRC has previously accepted similar calculations

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

The change in total CCFP (including corrosion effects) from both internal and external events is calculated as follows: CCFP = [1 -(Class 1 frequency+

Class 3a frequency)

I CDF]

• 100% CCFP3 = 93.39% CCFP1o = 93.93% CCFP1s = 94.32% b.CCFP = CCFP1o-CCFP3 = 0.54% b.CCFP = CCFP1s-CCFP3 = 0.93% b.CCFP = CCFP1s-CCFP1o = 0.39% The total change in CCFP of slightly less than 1% by extending the test interval to 15 years from the original 3-in-1 0 year requirement is judged to be insignificant.

Table 5-5, Table 5-6, and Table 5-7 present the Delta CCDP results for the total, internal, and external events, respectively.

5.6

SUMMARY

OF RESULTS The results from this ILRT extension risk assessment for BVPS-1 are summarized in Table 5-5, Table 5-6, and Table 5-7 for the total, internal, and external events, respectively.

These tables provide a summary of the BVPS-1 base case, as well as the impact caused by corrosion.

The tables are divided into three columns representing the frequency of the ILRT: Base Case (3 per 10 years), Extended to 1 per 10 years, and Extended to 1 per 15 years. Each of the three columns is sub-divided further into corrosion and corrosion cases. For both the corrosion and non-corrosion cases, the frequencies of the EPRI accident classes (i.e., CDF) are provided.

In the corrosion cases, an additional column titled Dose Rate from Corrosion (person-rem per yr)" is provided.

The Dose Rate from Corrosion (person-rem per yr)" column provides the change in person-rem per year between the case with corrosion and the case without corrosion.

Negative values in this column indicate a reduction in the person-rem per year for the selected accident class. This occurs only in EPRI accident Class 1 and is a result of the reduction in the frequency of the accident Class 1 and an increase in accident Class 3b.

PRA-BV1-13-028-ROO Page 43 of 62 Negative values for the EPRI accident Class 1 "Frequency (per year)" and "Dose Rate (person-rem per year)" columns are also shown in Table 5-7 for the external event extended ILRT cases. These occur due to the increase in the Class 3a frequencies exceeding the external events Class 1 base (prior to revising) frequency of 4.67E-07/yr. (See Table 4-6 External Release Bin Frequency (per yr) for release bin BV21 ). Having these negative Class 1 frequencies preserves the BVPS-1 external events total release frequency (i.e., CDF) of 1.53E-05/yr.

A row for the totals, both frequency and dose rate, are provided on the tables. Additional summary rows are also provided.

• The change in dose rate (person-rem/year) and change as % of base total dose rate is provided below the "Total" row.

• The Conditional Containment Failure Probability (CCFP) is provided in the next row.

• The percentage point change in CCFP from the base case (8CCFP) is provided in the next row.

• The Total LERF is provided in the next row.

• Followed by the Class 3b LERF row that indicates the accident Class 3b frequency, as well as the change in the Class 3b frequency in parentheses.

This difference is calculated between the non-corrosion and corrosion cases.

• The next row, titled "Delta LERF from Base Case (3 per 10 years)," provides the change in LERF as a function of ILRT frequency from the base case. The difference between the non-corrosion and corrosion cases is provided in parentheses.

• The last row of the table, titled "Delta LERF from 1 per 10 years" provides the change in LERF as a result of changing the ILRT frequency from one in 10 years to one in 15 years. The difference between the non-corrosion and corrosion cases is provided in parentheses.

Section 4.4 presents an estimate of the likelihood and risk implications of corrosion-induced leakage of steel containment liners not being detected during the extended ILRT test intervals evaluated in this report. The analysis considers ILRT extension time, inspections, and concealed degradation in uninspectable areas. As can be seen from the total risk results provided in Table 5-5, the change from the base case of three tests per 10 years to one test per 15 years with corrosion in LERF is small, 2.1 OE-07 (the change in LERF for the same period without corrosion was 2.08E-07).

The change in delta-LERF between the 15-year corrosion and non-corrosion cases is correspondingly very small, 2.72E-09.

Table 5-5. Summary of BVPS-1 Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 1 0 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion Population EPRI Dose at tJ.Dose tJ. Dose Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) rem per year) year) rem per year) year) _yea!l .Year}_ 1 8.00E-+02 1.28E-06 1.03E-03 1.28E-06 1.03E-03 -1.60E-07 6.79E-07 5.43E-04 6.77E-07 5.42E-04 -9.32E-07 2.46E-07 1.97E-04 2.43E-07 1.95E-04 3a 8.00E-+03 2.08E-07 1.66E-03 2.08E-07 1.66E-03 N/A 6.92E-07 5.53E-03 6.92E-07 5.53E-03 N/A 1.04E-06 8.30E-03 1.04E-06 8.30E-03 3b 8.00E-+04 5.19E-08 4.15E-03 5.21E-08 4.17E-03 1.60E-05 1.73E-07 1.38E-02 1.74E-07 1.39E-02 9.32E-05 2.59E-07 2.08E-02 2.62E-07 2.10E-02 6 3.60E-+06 926E-08 3.33E-01 9.26E-08 3.33E-01 N/A 9.26E-08 3.33E-01 9.26E-08 3.33E-01 N/A 9.26E-08 3.33E-01 9.26E-08 3.33E-01 7 non-1.86E-+06 1.14E-05 2.13E-+01 1.14E-05 2.13E-+01 N/A 1.14E-05 2.13E-+01 1.14E-05 2.13E-+01 N/A 1.14E-05 2.13E-+01 1.14E-05 2.13E-+01 LERF 7 824E-+06 2.49E-09 2.06E-02 2.49E-09 2.06E-02 N/A 2.49E-09 2.06E-02 2.49E-09 2.06E-02 N/A 2.49E-09 2.06E-02 2.49E-09 2.06E-02 LERF 8 non-4.26E-+06 9.45E-06 4.03E-+01 9.45E-06 4.03E-+01 N/A 9.45E-06 4.03E-+01 9.45E-06 4.03E-+01 N/A 9.45E-06 4.03E-+01 9.45E-06 4.03E-+01 LERF 8 4.59E-+06 4.17E-08 1.91E-01 4.17E-08 1.91E-01 N/A 4.17E-08 1.91 E-01 4.17E-08 1.91E-01 N/A 4.17E-08 1.91E-01 4.17E-08 1.91E-01 LERF Total 2.26E-05 6.21 E-+01 2.26E-05 6.21E-+01 1.58E-05 2.26E-05 6.22E-+01 2.26E-05 622E-+01 9.22E-05 2.26E-05 6.22E-+01 2.26E-05 6.22E-+01

b. Dose Rate 1.31E-02 1.32E-02 2.24E-02 2.26E-02 (%tJ. Dose Rate) N/A N/A (0.02%) (0.02%) (0.04%) (0.04%) CCFP 93.39% 93.39% 93.93% 93.93% 94.31% 94.32% b. CCFP N/A N/A 0.54% 0.54% 0.92% 0.93% Total LERF 9.60E-08 9.62E-08 2.17E-07 2.18E-07 3.04E-07 3.06E-07 Class 3b LERF 5.21E-08 1.74E-07 2.62E-07 5.19E-08 1.73E-07 2.59E-07 (tJ. w/Corrosion)

(2.00E-10)

(1.16E-09)

(2.72E-09)

Delta LERF from Base Case [3 per 10 years] 1.22E-07 2.10E-07 1.21E-07 2.08E-07 (tJ. w/Corrosion)

(9.65E-10)

(2.52E-09)

Delta LERF from 1 per 10 years 8.80E-08 N/A 8.65E-08 (tJ. w/Corrosion)

(1.56E-09) tJ.Dose Rate from Corrosion (person-rem per year) -2.18E-06 N/A 2.18E-04 I N/A N/A N/A N/A N/A 2.15E-04 -u :n :t> OJ -u:S: Ill 1 <C ...... CDC:.U o'P -:n OlO 1\) 0 Table 5-6. Summary of BVPS-1 Internal Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 1 0 years Extended to 1 per 15 years I Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population

!!.Dose !!.Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) year) year) 1 8.00E-+02 3a 8.00E-+03 N/A N/A 3b 8.00E-+04 6 3.60E-+06 N/A N/A 7 non-1.89E-+06 8.46E-+OO 8.46E-+OO N/A 8.46E-+OO 8.46E-+OO N/A 8.46E-+OO 8.46E-+OO LERF 7 824E-+06 9.74E-10 9.74E-10 N/A 9.74E-10 9.74E-10 N/A 9.74E-10 9.74E-10 LERF 8 non-4.26E-+06 6.66E-+OO 6.66E-+OO N/A 6.66E-+OO 6.66E-+OO N/A 6.66E-+OO 6.66E-+OO LERF 8 4.60E-+06 N/A N/A LERF Total 1.56E-+01 1.56E-+01 1.56E-+01 1.56E-+01 1.56E-+01 1.56E-+01 ll Dose Rate N/A N/A (%!!.Dose Rate) (0.03%) (0.03%) (0.05%) (0.05%) CCFP 85.37% 85.37% 85.91% 85.91% 86.29% 86.30% ll CCFP N/A N/A 0.53% 0.54% 0.92% 0.93% Total LERF Class 3b LERF

(!!. w/Corrosion)

(6.40E-11)

(3.73E-10)

(8.70E-10)

Delta LERF from Base Case [3 per 10 years]

(!!. w/Corrosion)

(3.09E-10)

(8.06E-10)

Delta LERF from 1 per 1 0 years N/A

(!!. w/Corrosion)

(4.98E-10)

---

!!.Dose Rate from Corrosion (person-rem per year)

N/A N/A N/A N/A N/A N/A "U :Il 1> OJ -u::: Sll ' <C ...... cow -1>-6 011\) o'f' -::n mo 1\)Q Table 5-7. Summary of BVP5-1 External Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 10 years Extended to 1 per 15 years Weighted Average Wrthout Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population t:.Dose Dose at t:.Dose Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) year) year) 1 8.00E-+02 2.90E-07 2.32E-04 2.90E-07 2.32E-04 -1.09E-07

-1.21E-07

-9.72E-05

-1.22E-07

-9.78E-05

-6.34E-07

-4.15E-07

-3.32E-04

-4.17E-07

-3.34E-04 3a 8.00E-+03 1.41E-07 1.13E-03 1.41E-07 1.13E-03 N/A 4.70E-07 3.76E-03 4.70E-07 3.76E-03 N/A 7.06E-07 5.65E-03 7.06E-07 5.65E-03 3b 8.00E-+04 3.53E-08 2.82E-03 3.54E-08 2.83E-03 1.09E-05 1.18E-07 9.41 E-03 1.18E-07 9.47E-03 6.34E-05 1.76E-07 1.41E-02 1.78E-07 1.43E-02 6 3.58E-+06 1.31E-08 4.71E-02 1.31E-08 4.71E-02 N/A 1.31E-08 4.71 E-02 1.31E-08 4.71E-02 N/A 1.31E-08 4.71E-02 1.31E-08 4.71E-02 7 non-1.85E-+06 6.95E-06 1.28E-+01 6.95E-06 1.28E-+01 N/A 6.95E-06 1.28E-+01 6.95E-06 1.28E-+01 N/A 6.95E-06 1.28E-+01 6.95E-06 1.28E-+01 LERF 7 8.24E-+06 1.52E-09 125E-02 1.52E-09 1.25E-02 N/A 1.52E-09 1.25E-02 1.52E-09 1.25E-02 N/A 1.52E-09 1.25E-02 1.52E-09 1.25E-02 LERF 8 non-4.26E-+06 7.88E-06 3.36E-+01 7.88E-06 3.36E-+01 N/A 7.88E-06 3.36E-+01 7.88E-06 3.36E-+01 N/A 7.88E-06 3.36E-+01 7.88E-06 3.36E-+01 LERF 8 4.26E-+06 6.26E-10 2.67E-03 6.26E-10 2.67E-03 N/A 6.26E-10 2.67E-03 6.26E-10 2.67E-03 N/A 6.26E-10 2.67E-03 6.26E-10 2.67E-03 LERF Total 1.53E-05 4.65E-+01 1.53E-05 4.65E-+01 1.08E-05 1.53E-05 4.65E-+01 1.53E-05 4.65E-+01 6.27E-05 1.53E-05 4.66E-+01 1.53E-05 4.66E-+01 l:J. Dose Rate 8.89E-03 8.94E-03 1.52E-02 1.54E-02 (%!:. Dose Rate) N/A N/A (0.02%) (0.02%) (0.03%) (0.03%) CCFP 97.18% 97.18% 97.72% 97.73% 98.11% 98.12% l:J.CCFP N/A N/A 0.54% 0.54% 0.92% 0.93% Total LERF 3.74E-08 3.76E-08 1.20E-07 1.21E-07 1.79E-07 1.80E-07 Class 3b LERF 3.54E-08 1.18E-07 1.78E-07 3.53E-08 1.18E-07 1.76E-07 (t:. w/Corrosion)

(1.36E-10)

(7.92E-10)

(1.85E-09)

Delta LERF from Base Case [3 per 10 years] 8.30E-08 1.43E-07 8.23E-08 1.41E-07 (t:. w/Corrosion)

(6.56E-10)

(1.71E-09)

Delta LERF from 1 per 10 years 5.99E-08 N/A 5.88E-08 (t:. w/Corrosion)

(1.06E-09)

!:.Dose Rate from Corrosion (person-rem per

-1.48E-06 N/A 1.48E-04 N/A N/A N/A N/A I N/A 1.47E-04 ! -u ::D Ill -u:S: Ill ' (C .... CDVJ -1'>-6 cnN oCf' -::D OlO 1\)0

6. SENSITIVITIES PRA-BV1-13-028-ROO Page 47 of 62 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS The results in Tables 5-5, 5-6 and 5-7 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, assuming that the first year failure rates for the cylinder and dome start out as the baseline value presented in Section 4.4 as 2.5E-03/yr and the basemat starts out as the baseline value of 5.12E-04/yr.

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% for the cylinder and dome, while keeping the basemat at the baseline 100% value. Additionally, both a lower and upper bound sensitivity were performed by biasing all sensitivity parameters to their lower or upper values. A special BVPS-1 upper bound sensitivity case was also performed assuming a probability of 1.0 (1 00% certain) that another hole will occur in the cylindrical steel liner during the 15 year ILRT extension (see corrosion analysis Table 4-8, Step 3}, and that Steps 4 and 5 are set at the upper bound parameters.

The use of the upper bound parameters for Steps 4 and 5 in the Calvert Cliffs analysis is justified for the BVPS-1 upper bound analysis for the following reasons: * *It is known that all of the identified BVPS-1 through-wall liner holes had areas well below that which could exceed 1 La, so it is reasonable to use the same 10% upper bound parameter for estimating the BVPS-1 likelihood that the undetected hole would be large enough to exceed the 100 La containment leakage rate for Class 3b sequences (Table 4-8, Step 4).

• All five of the events reporting back-side corrosion-induced through-wall liner holes were identified during visual inspections of the liner and protective coating examinations.

Therefore, the same 15% upper bound parameter for estimating the visual inspection detection failure likelihood is also reasonable for BVPS-1 (Table 4-8, Step 5). Applying all of these parameters to the BVPS-1 upper bound analysis equates to a 1.5% likelihood of having corrosion-induced, non-detected leakage in the containment liner and dome large enough to exceed the 100 La containment leakage rate for Class 3b sequences, for the 15 year I LRT extension case.

PRA-BV1-13-028-ROO Page 48 of 62 The significance of containment liner degradation and through-wall corrosion of the steel liner due to the presence of debris has also been addressed in recent studies. A report prepared for the NRC titled "Containment Building Liner Corrosion

-Corrosion and Leak Rate Models" [30] presents an argument that through-wall liner back-side corrosion could be caused by a macrocell process resulting from the presence of debris in contact with the liner. In this report a loss-of-coolant accident (LOCA) in a containment with a breached liner was evaluated to determine how corrosion could affect containment leakage. Some major findings of this study are as follows:

• Macrocell corrosion is a feasible process explaining the observed instances of liner through-wall corrosion.

• The contact between the debris and the liner will control the area of damage. In the limit when the contact radius becomes very small, the corrosion rate becomes negligible (i.e., the liner would exhibit passive corrosion).

Therefore, the contact area between the debris and the liner defines an upper bound for liner area compromised by corrosion.

• The gap distance between the liner and the concrete (referred to aperture) is the most important parameter controlling leak rates, under the implicit assumption of impermeable concrete.

• The area of the corrosion damage on the liner controls leak rates only when the area is small (e.g., smaller than 0.16 square inches). When the area is large, leak rates are controlled by the aperture and are mostly proportional to the cube of the aperture.

• The aperture at the pathway entry is expected to be small, because macrocell corrosion requires a tight contact between the liner and the debris, and corrosion products expand in volume. Another study presented in NUREG/CR-6920

[31] provides a perspective on the risk associated with a degraded reinforced concrete containment (similar to NUREG-1150 and the BVPS-1 containments) caused by the corrosion of the steel liner, with respect to the guidelines given in RG 1.17 4 [4]. Although this study did not address through-wall liner corrosion, it did evaluate two cases where the corrosion was assumed to have penetrated 65% of the liner thickness near the basemat or the midheight locations.

Some major points of this study are as follows:

• Multiple finite element analyses of the containment within a Latin Hypercube Simulation (LHS) framework enabled the development of fragility curves for this type of containment under the specific degradation scenarios.

PRA-BV1-13-028-ROO Page 49 of 62

• The degradation cases for this type of containment show shifts in the fragility curves, but not approaching the design pressure even at low probabilities.

• Using the best estimate fragility curves, there is no change in LERF relative to the un-damaged containment in either case where corrosion exists near the basemat or at the midheight, even with the corrosion assumed to have penetrated 65% of the liner thickness.

Consequently, the effects of the change in LERF due to liner corrosion clearly fall within RG 1.174 Region Ill for the LERF acceptance criteria.

• Because the types of degradation considered in this study were only postulated to affect the containment liner, and not the main load-bearing structural system, they only contribute to leakage failures.

As a result, the maximum calculated change in the mean Small Early Release Frequency between the 65% corrosion at the midheight case when compared to the un-damaged containment is only 1 .02E-07 /yr.

• This risk of small early releases is still quite small, and the risk criteria of RG 1.174 would be easily satisfied, even if SERF and LlSERF were used in place of LERF and LlLERF. The findings from these studies serve to show that even with the presence of containment liner degradation and through-wall corrosion of the steel liner, the likelihood that a hole contributes to the LERF is very small, so a 1.5% likelihood of having corrosion-induced, non-detected leakage in the containment liner and dome large enough to exceed the 100 La containment leakage rate for Class 3b sequences is justifiable.

For the BVPS-1 upper bound sensitivity case it is also assumed that there is a probability of 0.01 (1% chance) that another hole will occur in the cylindrical steel liner during the baseline 3 year ILRT, and a probability of 0.5 (50% chance) that another hole will occur in the cylindrical steel liner during a 10 year ILRT interval.

The results of the increase in total Class 3b frequency from both internal and external events are presented in Table 6-1. In every case the impact from including the corrosion effects is very minimal. Even the upper bound estimates with very conservative assumptions for all of the key parameters yield increases in LERF due to corrosion of only 3.48E-07/yr, while the BVPS-1 upper bound sensitivity case has an increase in LERF due to corrosion of only 3.84E-07/yr.

The results indicate that even with very conservative assumptions, the conclusions from the base analysis would not change.

Table 6-1 Steel Liner Corrosion Sensitivity Cases Containment Age Breach Visual Inspection

& (Step 3 in the Non-Visual Flaws corrosion (Step 4 in the (Step 5 in the corrosion analysis) analysis) corrosion analysis)

Base Case Base Case Base Case Doubles (1% Cylinder, (1 0% Cylinder, every 5 yrs 0.1% Basemat) 100% Basemat) Doubles every 2 yrs Base Base Doubles every 10 yrs Base Base Base Base 15% Cylinder, 1 00% Basemat Base Base 5% Cylinder, 1 00% Basemat Base 10% Cylinder, Base 1% Basemat Base 0.1% Cylinder, Base 0.01% Basemat Lower Bound Doubles every 10 0.1% Cylinder, 5% Cylinder, yrs 0.01% Basemat 1 00% Basemat Upper Bound Doubles every 2 1 0% Cylinder, 15% Cylinder, yrs 1% Basemat 1 00% Basemat BVPS-1 Upper Bound For Liner/Dome:

1% for 1 in 3 yrs 50% for 1 in 10 yrs 1 0% Cylinder, 15% Cylinder, 100% for 1 in 15 1% Basemat 100% Basemat yrs Basemat Doubles every 2 yrs PRA-BV1-13-028-ROO Page 50 of 62 Increase in Class 3b Frequency (LERF) for ILRT Extension 3 to 15 years (per yr) Increase Due to Total Increase Corrosion 2.1 OE-07 2.52E-09 2.32E-07 2.48E-08 2.09E-07 1.28E-09 2.11 E-07 3.52E-09 2.09E-07 1.51 E-09 2.33E-07 2.51 E-08 2.08E-07 2.51E-10 2.08E-07 7.67E-11 5.55E-07 3.48E-07 5.91 E-07 3.84E-07 PRA-BV1-13-028-ROO Page 51 of 62 6.2 EPRI EXPERT ELICITATION LEAKAGE SENSITIVITY An expert elicitation was performed to reduce excess conservatisms in the data associated with the probability of undetected leaks within containment

[27]. Since the risk impact assessment of the extensions to the ILRT interval is sensitive to both the probability of the leakage as well as the magnitude, it was decided to perform the expert elicitation in a manner to solicit the probability of leakage as a function of leakage magnitude.

In addition, the elicitation was performed for a range of failure modes which allowed experts to account for the range of failure mechanisms, the potential for undiscovered mechanisms, inaccessible areas of the containment, as well as the potential for detection by alternate means. The expert elicitation process has the advantage of considering the available data for small leakage events, which have occurred in the data, and extrapolate those events and probabilities of occurrence to the potential for large magnitude leakage events. The basic difference in the application of the ILRT interval methodology using the expert elicitation is a change in the probability of pre-existing leakage within containment.

The base case methodology uses the Jeffrey's non-informative prior for the large leak size and the expert elicitation sensitivity study uses the results from the expert elicitation.

In addition, given the relationship between leakage magnitude and probability, larger leakage that is more representative of large early release frequency can be reflected.

For the purposes of this sensitivity, the same leakage magnitudes that are used in the base case methodology (i.e., 10 La for small Class 3a and 100 La for large Class 3b) are used here. Table 6-2 illustrates the magnitudes and probabilities of a pre-existing leak in containment associated with the base case and the expert elicitation statistical treatments.

These values are used in the ILRT interval extension for the base methodology and in this sensitivity case. Details of the expert elicitation process, including the input to expert elicitation as well as the results of the expert elicitation, are available in the various appendices of EPRI TR-1 018243 [27]. Table D-1 from this reference presents the results of the analysis of the expert elicited input. The expert elicitation mean probability of occurrence results for the 10 La, 100 La, and 1000 La leakage sizes, are shown in Table 6-2, below. Table 6*2. EPRI Expert Elicitation Results Leakage Size (La) Base Case Expert Elicitation Mean Percent Reduction Probability of Occurrence 10 9.2E-03 3.88E-03 58% 100 2.3E-03 2.47E-04 89% 1000 N/A 4.50E-06 N/A PRA-BV1-13-028-ROO Page 52 of 62 The summary of results using the expert elicitation values for probability of containment leakage is provided in Table 6-3. As mentioned previously, probability values are those associated with the magnitude of the leakage used in the base case evaluation (1 0 La for small Class 3a, and 100 La for large Class 3b). The expert elicitation process produces a relationship between probability and leakage magnitude in which it is possible to assess higher leakage magnitudes that are more reflective of large early releases; however, these evaluations are not performed in this particular study. The net effect is that the reduction in the multipliers shown above has the same impact on the calculated increases in the LERF values. The increase in the overall value for LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years is 2.48E-08/yr.

Similarly, the increase due to increasing the interval from 10 to 15 years is 1.08E-08/yr.

As such, if the expert elicitation mean probabilities of occurrence are used instead of the non-informative prior estimates, the change in LERF for BVPS-1 is within the range of a "very small" change in risk when compared to the current 1-in-1 0, or baseline 3-in-1 0 year requirement.

The results of this sensitivity study are judged to be more indicative of the actual risk associated with the ILRT extension than the results from the assessment as dictated by the values from the EPRI methodology

[27], and yet are still conservative given the assumption that all of the Class 3b contribution is considered to be LERF.

Table 6-3. BVP$-1 Total Risk for ILRT Base Case, 10, and 15 Year Extensions (Based on EPRI Expert Elicitation Leakage Probabilities}

Base Case (3 per 10 years) Extended to 1 per 1 0 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population

!J.Dose tJ.Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) year) year> 1 8.0QE-+{)2 1.45E-06 1.16E-03 1.45E-06 1.16E-03 -1.60E-07 1.23E-06 9.87E-04 1.23E-06 9.86E-04 -9.32E-07 1.08E-06 8.63E-04 1.08E-06 8.61E-04 3a 8.00E-+{)3 8.74E-08 6.99E-04 8.74E-08 6.99E-04 N/A 2.91E-07 2.33E-03 2.91E-07 2.33E-03 N/A 4.37E-07 3.49E-03 4.37E-07 3.49E-03 3b 8.0QE-+{)4 5.56E-09 4.45E-04 5.76E-09 4.61E-04 1.60E-05 1.85E-08 1.48E-03 1.97E-08 1.58E-03 9.32E-05 2.78E-08 2.22E-03 3.05E-08 2.44E-03 6 3.6QE-+{)6 9.26E-08 3.33E-01 9.26E-08 3.33E-01 N/A 9.26E-08 3.33E-01 9.26E-08 3.33E-01 N/A 9.26E-08 3.33E-01 9.26E-08 3.33E-01 7 non-1.86E-+{)6 1.14E-05 2.13E-+{)1 1.14E-05 2.13E-+{)1 N/A 1.14E-05 2.13E-+{)1 1.14E-05 2.13E-+{)1 N/A 1.14E-05 2.13E-+{)1 1.14E-05 2.13E-+{)1 LERF 7 8.24E-+{)6 2.49E-09 2.06E-02 2.49E-09 2.06E-02 N/A 2.49E-09 2.06E-02 2.49E-09 2.06E-02 N/A 2.49E-09 2.06E-02 2.49E-09 2.06E-02 LERF 8 non-4.26E-+{)6 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 N/A 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 N/A 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 LERF 8 4.59E-+{)6 4.17E-08 1.91E-01 4.17E-08 1.91E-01 N/A 4.17E-08 1.91 E-01 4.17E-08 1.91E-01 N/A 4.17E-08 1.91E-01 4.17E-08 1.91 E-01 LERF Total 2.26E-05 6.21E-+{)1 2.26E-05 6.21E-+{)1 1.58E-05 2.26E-05 6.21E-+{)1 2.26E-05 6.21E-+{)1 9.22E-05 2.26E-05 6.21E-+{)1 2.26E-05 6.21 E-+{)1 IJ. Dose Rate 2.50E-03 2.57E-03 4.28E-03 4.48E-03 (o/o!J. Dose Rate) N/A N/A (0.00%) (0.00%) (0.01%) (0.01%) CCFP 93.18% 93.19% 93.24% 93.25% 93.28% 93.29% IJ.CCFP N/A N/A 0.06% 0.06% 0.10% 0.11% Total LERF 4.97E-08 4.99E-08 6.27E-08 6.39E-08 7.20E-08 7.47E-08 Class 3b LERF 5.76E-09 1.97E-08 3.05E-08 5.56E-09 1.85E-08 2.78E-08 (!J. w/Corrosion)

(2.00E-10)

(1.16E-09)

(2.72E-09)

Delta LERF from Base Case [3 per 10 years] 1.39E-08 2.48E-08 1.30E-08 2.22E-08 (!J. w/Corrosion)

(9.65E-10)

(2.52E-09)

Delta LERF from 1 per 10 years 1.08E-08 N/A 9.27E-09 (!J. w/Corrosion)

(1.56E-09)

-!J.Dose Rate from Corrosion (person-rem per year) -2.18E-06 N/A 2.18E-04 N/A N/A N/A N/A N/A 2.15E-04 I "1J :0 =!> OJ Ill ' <C_. coc.u (J16 c.uN o'P -:o 0)0 1\) 0 PRA-BV1-13-028-ROO Page 54 of 62 6.3 POTENTIAL IMPACT FROM LOSS OF CONTAINMENT OVERPRESSURE The EPRI guidance [27] states that for those plants that credit containment overpressure for the mitigation of design basis accidents, a brief description of whether overpressure is required should be included, as well as a discussion of the combined impacts from the ILRT extension on CDF and LERF, and comparison with the RG 1.174 acceptance guidelines.

At BVPS-1, mitigation of design basis accidents rely on containment overpressure in the calculation of available NPSH for both the recirculation spray (RS) pumps and low head safety injection (LHSI) pumps when taking suction from the containment sump. The EPRI guidance [27] suggests that as a first order estimate of the impact, it can be assumed that the EPRI Class 3b contribution would lead to loss of containment overpressure and the systems that require this contribution for available NPSH should be made unavailable when such an isolation failure exists. To model the impact of a loss of containment overpressure due to a large existing containment liner leak in the BV1 REVSA PRA, the EPRI Class 3b leakage probability for the various ILRT test intervals were added to the PRA model's baseline unavailability of the containment sump to provide an adequate source of water (i.e., available NPSH); thereby, failing the RS pumps and LHSI pumps during the safety injection recirculation phase. The Class 3b leakage probability for the various ILRT test intervals, including aging and corrosion effects, that were added to the containment sump unavailability are derived from Sections 4.3 and 4.4, and are summarized in Table 6-4. Table 6*4. Containment Overpressure Adjustment Factors ILRT Test Interval Class 3b Leakage Probability Class 3b Leakage Probability without Corrosion with Corrosion 3-in-1 0 years 2.30E-03 2.30E-03 + 8.88E-06 = (Baseline) 2.31 E-03 1-in-1 0 years 2.30E-03

• 3.33 = 2.30E-03

• 3.33 + 5.17E-05 = 7.68E-03 7.73E-03 1-in-15 years 2.30E-03

• 5.0 = 2.30E-03

• 5.0 + 1.21 E-04 = 1.15E-02 1.16E-02 The results of this loss of containment overpressure assessment on the total CDF and total LERF from all internal and external events (including aging and corrosion effects) are presented in Table 6-5.

PRA-BV1-13-028-ROO Page 55 of 62 As shown in Table 6-5, the total EPRI Class frequency (i.e., total CDF) goes from 2.26E-05/yr for the baseline 3-in-1 0 year ILRT case to 2.30E-05/yr for the 1-in-15 year extended ILRT case, even when including corrosion impacts. This represents a change in CDF of 3.58E-07/yr, which is well below the acceptance guidelines from RG 1.174 for very small changes in CDF and confirms that the impact on CDF from the ILRT extension is negligible.

The increase in LERF resulting from the increase in Class 3b leakage from a large liner breech (including corrosion effects) and subsequent loss of containment overpressure, due to the change in ILRT testing frequency from three in 10 years to one in 15 years is estimated as 2.15E-07/yr, with a corresponding total LERF of 3.11 E-07/yr. Based on RG 1.174, this meets the LERF threshold criteria for determining that the risk impact of extending the ILRT to one in 15 years is still small. It should also be noted in Table 6-5, that there are slight changes in the dose rates for more than just the Class 1 and Class 3b sequences due to the corrosion impacts.

The reasoning for this is that the corrosion also impacts the RS and LSHI pumps availability, as well as the CDF, which in turn alters the release bin frequencies of these other classes. This assessment is considered to be extremely conservative since the 100 La leakage rate from the EPRI Class 3b scenarios is not likely to be of sufficient size to actually result in the loss of containment overpressure required for the RS and LHSI pumps' NPSH, based on a BVPS-1 LAR evaluation that was performed in response to NRC additional questions relative to the containment overpressure credit [25]. This evaluation shows that there is an insignificant impact on the calculated NPSH margin for the limiting Outside RS pump by up to a 3-inch diameter hole in the containment building, which is greater than the 2-inch maximum containment hole size that will not result in LERF [17]. Since the minimum containment penetration size that can result in LERF is determined by the release of 100% of the containment volume per day at design pressure, it equates to about 1000 La or 10 times the assumed Class 3b leakage of 100 La. Therefore, the available NPSH for pumps taking suction from the containment sump should not be impacted unless the leakage exceeds 1000 La or 10 times the assumed Class 3b leakage. Based on the results of the EPRI expert elicitation

[27] provided in Table 6.2 of this analysis, the mean probability of occurrence of having a leakage size of 1000 La is about 55 times less likely to occur then having the assumed 3b leakage of 100 La.

Table 6-5. BVPS-1 Loss of Containment Overpressure Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 1 0 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population

/iDose 11 Dose 11 Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-year) year) rem per year) year) rem per year) year) rem per vearl vear) year) 1 8.00E-+{)2 1.28E-06 1.02E-03 1.28E-06 1.02E-03 -1.63E-07 6.55E-07 5.24E-04 6.54E-07 5.23E-04 -1.01E-06 2.03E-07 1.62E-04 2.00E-07 1.60E-04 -2.60E-06 3a 8.00E-+{)3 2.08E-07 1.67E-03 2.08E-07 1.67E-03 2.22E-08 7.01E-07 5.61E-03 7.01E-07 5.61E-03 5.17E-07 1.06E-06 8.46E-03 1.06E-06 8.47E-03 1.74E-06 3b 8.00E-+{)4 5.21E-08 4.17E-03 5.23E-08 4.18E-03 1.61E-05 1.75E-07 1.40E-02 1.76E-07 1.41E-02 9.57E-05 2.64E-07 2.12E-02 2.67E-07 2.14E-02 2.26E-04 6 3.60E-+{)6 9.28E-08 3.34E-01 9.28E-08 3.34E-01 4.32E-06 9.34E-08 3.36E-01 9.34E-08 3.36E-01 2.09E-05 9.38E-08 3.37E-01 9.38E-08 3.37E-01 4.43E-05 7 non-1.86E-+{)6 1.15E-05 2.15E-+{)1 1.15E-05 2.15E-+{)1 5.59E-04 1.17E-05 2.19E-+{)1 1.17E-05 2.19E-+{)1 3.91E-03 1.19E-05 2.22E-+{)1 1.19E-05 2.22E-+{)1 9.13E-03 LERF 7 8.24E-+{)6 2.49E-09 2.05E-02 2.49E-09 2.05E-02 0 2.49E-09 2.05E-02 2.49E-09 2.05E-02 -2.46E-07 2.49E-09 2.05E-02 2.49E-09 2.05E-02 -4.23E-07 . LERF 8 non-426E-+{)6 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 0 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 0 9.45E-06 4.03E-+{)1 9.45E-06 4.03E-+{)1 0 LERF 8 4.59E-+{)6 4.17E-08 1.91E-01 4.17E-08 1.91E-01 0 4.17E-08 1.91E-01 4.17E-08 1.91E-01 0 4.17E-08 1.91E-01 4.17E-08 1.91E-01 0 LERF Total 2.26E-05 6.23E-+{)1 2.26E-05 6.23E-+{)1 5.80E-04 2.29E-05 6.27E-+{)1 2.29E-05 6.27E-+{)1 4.03E-03 2.30E-05 6.30E-+{)1 2.30E-05 6.30E-+{)1 9.40E-03 tJ. Dose Rate 4.14E-01 4.17E-01 7.10E-01 7.19E-01 (%11 Dose Rate) N/A N/A (0.66%) (0.67%) (1.14%) (1.15%) CCFP 93.43% 93.43% 94.07% 94.07% 94.52% 94.53% I:J.CCFP N/A N/A 0.63% 0.64% 1.09% 1.10% Total LERF 9.62E-08 9.64E-08 2.19E-07 2.21E-07 3.09E-07 3.11E-07 Class 3b LERF 5.23E-08 1.76E-07 2.67E-07 5.21E-08 1.75E-07 2.64E-07 {11 w/Corrosion)

(2.01E-10)

(1.20E-09)

(2.83E-09)

Delta LERF from Base Case [3 per 10 years] 1.24E-07 2.15E-07 1.23E-07 2.12E-07 (11 w/Corrosion)

(9.95E-10)

(2.63E-09)

Delta CDF from Base Case (3 per 10 years] 2.08E-07 3.58E-07 2.06E-07 3.53E-07 {11 w/Corrosion)

(1.80E-09)

(4.41E-09)

---

*---------""0 JJ 1" IJJ -u:S: Ill ' (C_.. coW 016 m"' o'P -JJ mo 1\) 0

7. CONCLUSIONS PRA-BV1-13-028-ROO Page 57 of 62 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 fifteen years:

• RG 1.174 [4] provides guidance for determining the risk impact of 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 in Section 6.3 to have a very small impact on the total (internal plus external)

CDF for BVPS-1 resulting from the loss of containment overpressure, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval from three in ten years to one in fifteen years with corrosion included is 6. 72E-08/yr (see Table 5-6), which falls within the very small change region of the acceptance guidelines in RG 1.17 4.

• 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. When the external events contribution is also considered, the increase in total LERF including corrosion goes to 2.1 OE-07/yr, with an associated total LERF of 3.06E-07/yr (see Table 5-5). As such, the estimated change in total LERF is determined to be small using the acceptance guidelines of RG 1. 174, and is well below the RG 1.174 acceptance criteria for total LERF of 1 .OE-05. However, if the EPRI Expert Elicitation methodology is used, the change in total LERF is estimated as 2.48E-08/yr (see Table 6-3), which falls back within the very small change region.

• The change in the total 50-mile population dose risk from changing the Type A test frequency to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all accident sequences, is 2.26E-02 rem/yr using the EPRI guidance with the base case corrosion case (see Table 5-5). The change in dose risk increases to 7. 19E-01 person-rem/yr when including the impact from a loss of containment overpressure (see Table 6-5). EPRI Report No. 1009325, Revision 2-A [27] states that a very small population dose is defined as an increase of :s;; 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 probability from the three in ten year interval to one in fifteen year interval including corrosion is 0.93% (see Table 5-5), and increases to 1.10% when including the loss of containment overpressure impact (see Table 6-5). EPRI Report No.

PRA-BV1-13-028-ROO Page 58 of 62 1009325, Revision 2-A states that increases in CCFP of S1.5 percentage points are very small. Therefore this increase judged to be very small. Therefore, increasing the ILRT interval on a permanent basis to one in 15 years is not considered to be significant since it represents only a small change to the BVPS-1 risk profile when considering both internal and external events with corrosion and loss of containment overpressure impacts. Furthermore, the use of the EPRI Class 3b probability is judged to be very conservative because the BVPS containment buildings operate at a slightly sub-atmospheric pressure.

In plants without a sub-atmospheric containment, pre-existing leaks in lines connected to the containment atmosphere have been shown to be an important contributor to the loss of containment isolation and large, early release frequency.

These leaks are mostly associated with valves being inadvertently left open upon rise to power after shutdown, but could also be due to undetected large liner breeches (i.e., EPRI Class 3b). This condition is not likely to be important at Beaver Valley Units 1 and 2 for the following reasons:

• There is a technical specification limit on containment pressure during operation.

BVPS Technical Specification LCO 3.6.4 [18] states that containment pressure shall be 12.8 psia and :s; 14.2 psia.

• Technical Specification SR 3.6.4.1 [18] verifies that containment pressure is within the above limits every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

The EPRI methodologies

[27] to determine the increase in LERF and population dose for an ILRT interval extension are based on the assumption of increased undetected pre-existing leakage associated with an atmospheric containment, which is not assumed for a sub-atmospheric containment design since existing leakage would be detectable by changes in containment vacuum. Therefore, the use of the EPRI Class 3b probability in the BVPS-1 ILRT extension risk assessment results in conservatively overstating the increase in the LERF, and it is believed that the use of the EPRI Expert Elicitation methodology is more indicative of the true change in total LERF, which falls within the very small change region. Previous Assessments The NRC in NUREG-1493

[6] 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 PRA-BV1-13-028-ROO Page 59 of 62 potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

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

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

The findings for BVPS-1 confirm these general findings on a plant specific basis considering the severe accidents evaluated for BVPS-1, the BVPS-1 containment failure modes, and the local population surrounding BVPS.

8. REFERENCES PRA-BV1-13-028-ROO Page 60 of 62 [1] Nuclear Energy Institute, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," NEI 94-01, Revision 3-A, July 2012. [2] Electric Power Research Institute, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," EPRI TR-1 04285, August 1994. [3] "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals," Rev. 4, Developed for NEI by EPRI and Data Systems and Solutions, November 2001. [4] U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Regulatory Guide 1.174, Revision 2, May 2011. [5] "Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension," Letter from Mr. C. H. Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No. 50-317, March 27, 2002. [6] U.S. Nuclear Regulatory Commission, "Performance-Based Containment Leak-Test Program," NUREG-1493, September 1995. [7] U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Informed Activities," Regulatory Guide 1.200, Revision 1, January 2007. [8] Letter from R. J. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-007, January 18, 2001. [9] U.S. Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No. 3 -Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing (TAG No. MB0178), April 17, 2001. [1 0] Oak Ridge National Laboratory, "Impact of Containment Building Leakage on LWR Accident Risk," NUREG/CR-3539, ORNL/TM-8964, April 1984. [11] Pacific Northwest Laboratory, "Reliability Analysis of Containment Isolation Systems," NUREG/CR-4220, PNL-5432, June 1985. [12] U.S. Nuclear Regulatory Commission, "Technical Findings and Regulatory Analysis for Generic Safety Issue II.E.4.3 'Containment Integrity Check'," NUREG-1273, April 1988.

PRA-BV1-13-028-ROO Page 61 of 62 [13] Pacific Northwest Laboratory, "Review of Light Water Reactor Regulatory Requirements," NUREG/CR-4330, PNL-5809, Vol. 2, June 1986. [14] Electric Power Research Institute, "Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMŽ," TR-1 05189, Final Report, May 1995. [15] U.S. Nuclear Regulatory Commission, "Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants," NUREG-1150, December 1990. [16] U.S. Nuclear Regulatory Commission, "Reactor Safety Study, an Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," WASH-1400, October 1975. [17] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Unit 1, PRA Notebooks for PRA-BV1-AL-R05a, January 11, 2013. [18] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Units 1 and 2, Technical Specifications, Unit 1 Docket No. 50-334, License No. DPR-66, Unit 2 Docket No. 50-412, License No. NPF-73. [19] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Units 1 & 2, License Renewal Application, Appendix E -Environmental Report, Unit 1 Docket No. 50-334, Unit 2 Docket No. 50-412. [20] Anthony R. Pietrangelo, "One-time extensions of containment integrated leak rate test interval -additional information," NEI letter to Administrative Points of Contact, November 30, 2001. [21] Letter from J.A. Hutton (Exelon, Peach Bottom) to U.S. Nuclear Regulatory Commission, Docket No. 50-278, License No. DPR-56, LAR-01-00430, dated May 30, 2001. [22] Risk Assessment for Joseph M. Farley Nuclear Plant Regarding ILRT (Type A) Extension Request, prepared for Southern Nuclear Operating Co. by ERIN Engineering and Research, P029301 0002-1929-030602, March 2002. [23] Letter from D.E. Young (Florida Power, Crystal River) to U.S. Nuclear Regulatory Commission, 3F0401-11, dated April 25, 2001. [24] Risk Assessment for Vogtle Electric Generating Plant Regarding the ILRT (Type A) Extension Request, prepared for Southern Nuclear Operating Co. by ERIN Engineering and Research, February 2003.

PRA-BV1-13-028-ROO Page 62 of 62 [25] FENOC Letter No. L-06-003 from James H. Lash, Site Vice President, Beaver Valley Power Station, to USNRC, Beaver Valley Power Station, Unit Nos. 1 and 2, BV-1 Docket No. 50-334, License No. DPR-66, BV-2 Docket No. 50-412, License No. NPF-73, Additional Information in Support of License Amendment Request, Nos. 302 and 173 (Unit No. 1 TAG No. MC4645/Unit No. 2 TAG No. MC4646), dated January 25, 2006, (ADAMS Accession No. ML060330262).

[26] Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," EPRI Report 1009325, Revision 2, August 2007. [27] Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals:

Revision 2-A of 1 009325," EPRI Report 1018243, Final Report, October 2008. [28] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Unit 1, 1 BVT 1.47.2, Revision 5, "Containment Type A Leak Test," Test Results Report, Completed Test Date: April 15, 2006. [29] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Unit 1, i BVT 1.47.02, Issue 2, Revision 4, "Containment Type A Leak Test," Test Results Report, Completed Test Date: May 29, 1993. [30] Center for Nuclear Waste Regulatory Analyses, "Containment Building Liner Corrosion

-Corrosion and Leak Rate Models," Contract NRC-HQ-12-C-04-0069, July 2013, (ADAMS Accession No. ML 13204A004)

[31] U.S. Nuclear Regulatory Commission, "Risk-Informed Assessment of Degraded Containment Vessels," NUREG/CR-6920, November 2006.

Attachment 4 Plant Specific Confirmatory Analysis (PRA) BVPS-2 (63 pages follow)

PRA APPLICATIONS ANALYSIS/ASSESSMENT COVER SHEET Analysis/Assessment Sequence No.: PRA-BV2-13-002-ROO Rev.: QQ._ Ref. PRA Tracking#:

.:..:N:.:.../A_,__

_______________ (if applicable)

Subject:

BVPS-2 Risk Assessment for Extending ILRT lnteNal to One in 15 Years

Description:

The purpose of this analysis is to provide a risk assessment of extending the currently allowed containment Type A inte;:grated leak .rate test (ILRT) to a .permanent fifteen ea s. Documents Used by this Analysis/Assessment:

See Section 8 References.

Documents Supported by this Analysis/Assessment:

BVPS-2 ILRT LAR Documents Superseded by this Analysis/Assessment:

Preparer:*

F. William Etzel /: Reviewer.

S. T. Leung ifW&tjJ. pi' 5TL. fe/' t.e/eco"'

Additional Reviews (If required)

Performed by: R. J. Slremple Approved:

Date: 11/7/13 Date: u / e /r3 Date:

Date: II f 'i' /1:3

1. 1 .1 1.2 1.3 2. 3. 4. 4.1 4.2 4.3 4.4 5. 5.1 5.2 5.3 5.4 5.5 5.6 6. 6.1 6.2 6.3 PRA-BV2-13-002-ROO Page ii of iii PRA APPLICATIONS ANALYSIS/ASSESSMENT TABLE OF CONTENTS PURPOSE OF ANALYSIS .............................................................................

1 PURPOSE ......................................................................................................

1 BACKGROUND

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

1 ACCEPTANCE CRITERIA ............................................................................

3 METHODOLOGY

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

5 GROUND RULES ...........................................................................................

7 INPUTS ............................................................................................................

9 GENERAL RESOURCES AVAILABLE

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

9 PLANT-SPECIFIC INPUTS ........................................................................

13 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) ..............

24 IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE .............................................

25 RESULTS ......................................................................................................

31 STEP 1: QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR .......................................................

33 STEP 2: DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR ........................................

38 STEP 3: EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS .......................................................

.40 STEP 4: DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY (LERF) ..................................

.40 STEP 5: DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY (CCFP) ................................

.41

SUMMARY

OF RESULTS ..........................................................................

42 SENSITIVITIES

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

47 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS

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

.47 EPRI EXPERT ELICITATION LEAKAGE SENSITIVITY

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

.48 POTENTIAL IMPACT FROM LOSS OF CONTAINMENT OVERPRESSURE

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

52 PRA-BV2-13-002-ROO Page iii of iii 7. CONCLUSIONS

..................... , ......................................................................

55 8. REFERENCES

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

58 LIST OF TABLES Table 4-1. BVPS-2 Level 2 PRA Model Release Category Groups, Bins, and Frequencies

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

14 Table 4-2. Calculation of BVPS Population Dose at 50 Miles ..........................................

16 Table 4-3. Assignment of SAMA Release Category and BVPS Dose to Release Bin ..... 17 Table 4-4. EPRI Containment Failure Classification

[2] ...................................................

18 Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes ............

19 Table 4-6. BVPS-2 Level 2 Release Bin Frequency and Population Dose Risk ..............

21 Table 4-7. BVPS-2 50-Mile Population Dose Risk by EPRI Accident Class ....................

23 Table 4-8. Steel Liner Corrosion Base Case ....................................................................

28 Table 5-1. Accident Classes ............................................................................................

32 Table 5-2. BVPS-2 Categorized Accident Classes and Frequencies

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

33 Table 5-3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-2 Base Case) ......................................................................................

37 Table 5-4. BVPS-2 Population Dose Estimates for Population Within 50 Miles ...............

39 Table 5-5. Summary of BVPS-2 Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact.. ........................................................

44 Table 5-6. Summary of BVPS-2 Internal Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion lmpact.. ...............................................

.45 Table 5-7. Summary of BVPS-2 External Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion lmpact. ...........................................

.46 Table 6-1. Steel Liner Corrosion Sensitivity Cases .......................................................... 4 7 Table 6-2. EPRI Expert Elicitation Results ......................................................................

.49 Table 6-3. BVPS-2 Total Risk for ILRT Base Case, 10, and 15 Year Extensions (Based on EPRI Expert Elicitation Leakage Probabilities)

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

51 Table 6-4. Containment Overpressure Adjustment Factors .............................................

52 Table 6-5. BVPS-2 Loss of Containment Overpressure Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact .....................

54

1. PURPOSE OF ANALYSIS 1.1 PURPOSE PRA-BV2-13-002-ROO Page 1 of 60 The purpose of this analysis is to provide a risk assessment of extending the currently allowed containment Type A integrated leak rate test (ILRT) interval from ten years to a permanent fifteen years. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for the Beaver Valley Power Station Unit 2 (BVPS-2).

The risk assessment follows the guidelines from NEI 94-01, Revision 3-A [1], the methodology used in EPRI TR-1 04285 [2], the NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" from November 2001 [3], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide (RG) 1.200 [7] as applied to ILRT interval extensions and risk insights in support of a request for a plant's licensing basis as outlined in RG 1.174 [4], 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 [5], the methodology used in EPRI 1009325, Revision 2 [26], and the methodology used in EPRI 1018243 (Revision 2-A of 1 009325) [27]. 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 EPRI 1 01 8243 report.

1.2 BACKGROUND

Revisions to 1 OCFR50, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirement from three in ten years to at least once in 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 1 La. The basis for the current 1 0-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," September 1995 [6], 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 PRA-BV2-13-002-ROO Page 2 of 60 Research Institute (EPRI) Research Project Report TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals." To complement the EPRI report TR-1 04285, which only considered changes to the ILRT testing intervals based on population dose, EPRI report 1018243 was developed that considers population dose, large early release frequency (LERF) and containment conditional failure probability (CCFP). EPRI report 1018243 indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to fifteen years is small. However, a plant specific confirmatory analysis is required.

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

[6], 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 for a representative PWR plant (i.e., Surry) that containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.

Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for BVPS-2. The guidance provided in Appendix H of EPRI 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325, for performing risk impact assessments in support of ILRT extensions builds on the EPRI Risk Assessment methodology, EPRI TR-1 04285. This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment.

The associated change to NEI 94-01 will require that visual examinations be conducted during at least three other outages, and in the outage during which the ILRT is being conducted.

These requirements will not be changed as a result of the extended ILRT interval.

In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.

1.3 ACCEPTANCE

CRITERIA PRA-BV2-13-002-ROO Page 3 of 60 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) less than 1.0E-06 per reactor year and increases in large early release frequency (LERF) less than 1.0E-07 per reactor year. RG 1.174 also defines small changes in LERF as below 1.0E-06 per reactor year. When the calculated increase in LERF is in the range of 1.0E-07 per reactor year to 1.0E-06 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.0E-05 per reactor year. Since the Type A test does not impact CDF, with the exception of a loss of containment overpressure that is discussed in Section 6.4, the relevant criterion is the change in LERF. 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 depth philosophy, are met. Therefore, the increase in the CCFP that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.

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

In context, it is noted that a CCFP of 1/10 (1 0%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate the relative change in this parameter.

While no acceptance guidelines for these additional figures of merit are published, examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extension (summarized in Appendix G) indicate a range of incremental increases in population dose that have been accepted by the NRC 1. The range of incremental population dose increases is from :S.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

[6], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of :S1.0 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.

1 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 this document uses 1 OOLa. The dose rates are impacted by this change and will be larger than those in previous submittals.

PRA-BV2-13-002-ROO Page 4 of 60 In the current BVPS-2 design basis accident (DBA) loss-of-coolant accident (LOCA) analysis, containment overpressure is credited in calculating the available net positive suction head (NPSH) for the recirculation spray (RSS) pumps when taking suction from the containment sump. Therefore, an assessment of the impacts on CDF resulting from a loss of containment overpressure due to a large containment failure is provided in Section 6.3. The impact on CDF can then be accounted for in a similar fashion to the LERF contribution as the EPRI Class 3b contribution changes for various ILRT test intervals.

The combined impacts on CDF and LERF will then be considered in this ILRT evaluation and compared with the RG 1.174 acceptance guidelines.

2. METHODOLOGY PRA-BV2-13-002-ROO Page 5 of 60 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 fifteen years. The approach is consistent with that presented in Appendix H of EPRI 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325 [27], EPRI TR-1 04285 [2], NUREG-1493

[6], and the Calvert Cliffs liner corrosion analysis [5]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current PRA-BV2-AL-R05a (BV2REV5A)

PRA model and subsequent containment response resulting in various fission product release categories (including intact containment or negligible release).

This risk assessment is applicable to BVPS-2. 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 fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis, to the fractional contribution of increased large leakage failures (due to liner breach) to LERF, and to the loss of containment overpressure due to EPRI Class 3b liner breach on CDF and LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore,

• Consistent with the other industry containment leak risk assessments, the BVPS-2 assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and PRA-BV2-13-002-ROO Page 6 of 60 conditional containment failure probability are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.

• This evaluation for BVPS-2 uses ground rules and methods to calculate changes in risk metrics that are similar to those used in Appendix H of EPRI Report No. 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A of 1009325 [27].

3. GROUND RULES The following ground rules are used in the analysis:

PRA-BV2-13-002-ROO Page 7 of 60

• The technical adequacy of the PRA-BV2-AL-R05a (BV2REV5A)

PRA model is consistent with the requirements of RG 1.200, Revision 1 as is relevant to this ILRT interval extension.

• Although the BV2REV5A PRA model is only RG 1.200, Revision 1 compliant for internal events, it also includes fire and seismic external events. FirstEnergy Nuclear Operating Company (FENOC) considers these BVPS-2 external event PRA models of sufficient quality and detail to adequately assess the impact from the seismic and internal fire risk associated with this ILRT interval extension, using the methodology provided in EPRI 1018243. Since the risk acceptance guidelines in RG 1.174 are intended for comparison with a full-scope assessment of risk, the total impact from internal and external events will be evaluated for the extended ILRT intervals.

• The BVPS-2 Level 1 and Level 2 PRA models provide representative results that can be used to estimate the impact of an ILRT interval extension.

• Dose results for the containment failures modeled in the PRA can be characterized by information provided in the BVPS Environmental Report for License Renewal (Attachment C, Severe Accident Mitigation Alternatives)

[19].

• The use of the 50-mile lifetime dose commitment from all pathways (L-EFFECTIVE TOT LIF) using 2047 estimated population data from the License Renewal Application

[19] is appropriate for this analysis to estimate the 50-mile population dose.

• Accident classes describing radionuclide release end states are defined consistent with EPRI methodology

[2] and are summarized in Section 4.2.

• The representative containment leakage for Class 1 sequences is 1 La. Class 3 accounts for increased leakage due to Type A inspection failures.

• The representative containment leakage for Class 3a sequences is 10 La based on the previously approved methodology performed for Indian Point Unit 3 [8, 9].

• The representative containment leakage for Class 3b sequences is 100 La based on the guidance provided in EPRI Report No. 1009325, Revision 2.

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

[8, 9].

• 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 PRA-BV2-13-002-ROO Page 8 of 60 containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from this separate categorization.

• The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal.

• The EPRI guidance [27] will be used as a first order estimate of the impact from a loss of containment overpressure.

It will be assumed that the EPRI Class 3b contribution leads to a loss of containment overpressure, which will then lead to a loss of all systems that credit this containment overpressure in calculating the available NPSH when taking suction from the containment sump.

• An evaluation of the risk impact of the ILRT on shutdown risk is addressed using the generic results from EPRI TR-105189

[14].

4. INPUTS PRA-BV2-13-002-ROO Page 9 of 60 This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4. 1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539

[1 0] 2. NUREG/CR-4220

[11] 3. NUREG-1273

[12] 4. NUREG/CR-4330

[13] 5. EPRI TR-1 05189 [14] 6. NUREG-1493

[6] 7. EPRI TR-1 04285 [2] 8. NEI Interim Guidance [3][20] 9. Calvert Cliffs liner corrosion analysis [5] 10. EPRI Report 1018243 (Revision 2-A of 1 009325), Appendix H [27] 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 existing containment leakage at the time of a core damage accident.

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

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

The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study includes the NEI recommended methodology (promulgated in two letters) for evaluating the risk associated with obtaining a one-time extension of the ILRT interval.

The ninth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations.

Finally, the tenth 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

[1 Ol PRA-BV2-13-002-ROO Page 10 of 60 Oak Ridge National Laboratory documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.

This study uses information from WASH-1400

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

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

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

[121 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

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

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

[141 The EPRI study TR-1 05189 is useful to the ILRT test interval extension risk assessment because it provides insight regarding the impact of containment testing on shutdown risk. This study contains a quantitative evaluation (using the EPRI ORAM software) for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The conclusion from the study is that a small but measurable safety benefit is realized from extending the test intervals.

NUREG-1493

[6[ PRA-BV2-13-002-ROO Page 11 of 60 The first ILRT survey was performed in early 1994 [8] and represented the NEI (known as NUMARC at that time) input used in NUREG-1493.

NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies: Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-1 04285 [21 Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-1 05189 study), the EPRI TR-1 04285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150

[15] 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-1 04285 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 PRA-BV2-13-002-ROO Page 12 of 60 small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NEI Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals

[31[201 The guidance provided in this document builds on the EPRI risk impact assessment methodology

[2] and the NRC performance-based containment leakage test program [6], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER). Calvert Cliffs Response to Request for Additional Information Concerning the License Amendment for a One-Time Integrated Leakage Rate Test Extension

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

The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility.

The BVPS-2 containment structure is a steel-lined, reinforced concrete cylinder with a hemispherical dome and a flat reinforced concrete foundation mat, which is similar to the Calvert Cliffs type of containment.

EPRI Report 1018243 (Revision 2-A of 1009325).

Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals.

Appendix H [271 This report provides a generally applicable assessment of the risk involved in extension of ILRT test intervals to permanent 15-year intervals.

Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology

[2] and the NRC performance-based containment leakage test program [6], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER). The approach included in this guidance document is used in the BVPS-2 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 PRA-BV2-13-002-ROO Page 13 of 60 The plant-specific information used to perform the BVPS-2 ILRT Extension Risk Assessment includes the following:

• BVPS-2 PRA model results and release category definitions

[17]

• Population dose within a 50-mile radius [19]

• ILRT results to demonstrate adequacy of the administrative and hardware issues [28][29] 1 BVPS-2 PRA Model Results The BVPS-2 PRA model of record, PRA-BV2-AL-R05a (BV2REV5A), and supporting documentation

[17] have been maintained as a living program to reflect the as-built, operated plant. The latest update to the BVPS-2 PRA model occurred on August 31, 2012. The BV2REV5A PRA model includes both internal and external events (seismic and internal fire), and provides Level1 and Level 2 results. The BVPS-2 PRA model is highly detailed and includes a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA quantification process used is based on the large linked event tree methodology, which is a well-known and accepted methodology in the industry.

The BVPS-2 PRA model uses Binary Decision Diagram (BOD) methodology to quantify the faults trees, which computes the top event probability exactly and without requiring frequency or cutset order truncation.

The 1 E-14 truncation level used for the BVPS-2 PRA model sequence quantification is more than 9 orders of magnitude less than the baseline total (internal plus external)

CDF of 1 .67E-05 per year. This is more than sufficient to provide a converged value of CDF, since decreasing the truncation level by a decade from 1 E-14 to 1 E-15 only results in an increase in CDF of 0.03%. The BVPS-2 Level 2 PRA Model that is used was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. The Level 2 model is directly linked to the Level 1 PRA model, and was quantified with a total (internal plus external)

Large Early Release Frequency (LERF) = 1.79E-07/yr, Small Early Release Frequency (SERF) = 3.94E-06/yr, Late Containment Failure Frequency (LATE) = 1. 15E-05/yr, and Long-Term Containment Integrity Frequency (LONG) = 1.06E-06/yr.

Table 4-1 summarizes the BV2REV5A results in terms of release category group, release bin, and bin frequencies for both internal and external events together (Total), and separately.

1 The two most recent Type A tests at BVPS Unit 2 [28] [29] have been successful, so the current Type A test interval requirement is 10 years.

PRA-BV2-13-002-ROO Page14of60 Table 4-1 BVPS-2 Level 2 PRA Model Release Category Groups, Bins, and Frequencies . Total Bin Internal External Release Events Bin Events Bin Category Release Release Bin Definition Frequency Frequency Frequency Group Bin /yr /yr /yr BV01 Large, Early Release, Containment Sprays Unavailable,.

Containment Isolation Success, RCS Pressure > 600 ps1a 1.78E-09 4.75E-10 1.31 E-09 BV01S Large, Early Release, Containment Sprays Unavailable, 4.66E-12 2.54E-12 2.12E-12 Small Cnmt. Isolation Failure, RCS Pressure > 600 psla BV02 Large, Early Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure > 600 ps1a 1.16E-10 4.41 E-11 7.14E-11 BV02S Large, Early Release, Containment Sprays Available, Small 1.01E-13 O.OOE+OO 1.01E-13 Cnmt. Isolation Failure, RCS Pressure > 600 psia LEAF Large, Early Release, Containment Sprays Unavailable,.

BV03 Containment Isolation Success, RCS Pressure < 600 ps1a or 4.82E-12 1.22E-12 3.60E-12 Alpha Mode Containment Failure BV03S Large, Early Release, Containment Sprays Unavailable, O.OOE+OO O.OOE+OO O.OOE+OO Small Cnmt. Isolation Failure, RCS Pressure < 600 psia BV04 Large, Early Release, Containment Sprays Available, 2.26E-12 1.37E-12 8.94E-13 Containment Isolation Success, RCS Pressure < 600 psia BV04S Large, Early Release, Containment Sprays Available, Small 1.32E-11 7.38E-12 5.84E-12 Cnmt. Isolation Failure, RCS Pressure < 600 psia BV05 Small, Early Release, Containment Sprays Unavailable,.

Containment Isolation Success, RCS Pressure > 200 ps1a 3.23E-10 8.47E-11 2.38E-10 BVOSS Small, Early Release, Containment Sprays Unavailable, 5.79E-09 3.55E-09 2.24E-09 Small Cnmt. Isolation Failure, RCS Pressure > 200 psia BV06 Small, Early Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure > 200 ps1a 1.08E-11 9.97E-12 8.12E-13 BV06S Small, Early Release, Containment Sprays Available, Small 2.91 E-10 2.05E-10 8.61 E-11 Cnmt. Isolation Failure, RCS Pressure > 200 psia SERF BV07 Small, Early Release, Containment Sprays Unavailable,.

Containment Isolation Success, RCS Pressure < 200 ps1a 1.01 E-09 2.18E-10 7.89E-10 BV07S Small, Early Release, Containment Sprays Unavailable, 3.26E-08 1.89E-08 1.37E-08 Small Cnmt. Isolation Failure, RCS Pressure < 200 psia BV08 Small, Early Release, Containment Sprays Available, . Containment Isolation Success, RCS Pressure < 200 ps1a 1.66E-07 2.16E-08 1.45E-07 BV08S Small, Early Release, Containment Sprays Available, Small 1.27E-09 7.93E-10 4.80E-10 Cnmt. Isolation Failure, RCS Pressure < 200 psi a BV09 Large, Late Release, Containment Sprays Unavailable, . Containment Isolation Success, RCS Pressure > 200 ps1a O.OOE+OO O.OOE+OO O.OOE+OO BV09S Large, Late Release, Containment Sprays Unavailable, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure > 200 psia BV10 Large, Late Release, Containment Sprays Available, 4.72E-1 0 3.66E-10 1.06E-10 Containment isolation Success, RCS Pressure>

200 psla LATE Large, Late Release, Containment Sprays Available, Small BV10S O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure > 200 psia BV11 Large, Late Release, Containment Sprays Unavailable, . Containment Isolation Success, RCS Pressure < 200 ps1a O.OOE+OO O.OOE+OO O.OOE+OO BV11S Large, Late Release, Containment Sprays Unavailable, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia PRA-BV2-13-002-ROO Page 15 of 60 Table 4-1. BVPS-2 Level 2 PRA Model Release Category Groups, Bins, and Frequencies Release Total Bin Internal External Release Events Bin Events Bin Category Bin Release Bin Definition Frequency Frequency Frequency Group /yr /yr /yr BV12 Large, Late Release, Containment Sprays Available, 1.41 E-08 8.79E-09 5.29E-09 Containment Isolation Success, RCS Pressure < 200 psia BV12S Large, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV13 Small, Late Release, Containment Sprays Unavailable, 6.00E-06 1.59E-06 4.41 E-06 Containment Isolation Success, RCS Pressure > 200 psia BV13S Small, Late Release, Containment Sprays Unavailable, Small O.OOE+OO 0.00E+00 O.OOE+OO Cnmt. Isolation Failure, RCS Pressure > 200 psia BV14 Small, Late Release, Containment Sprays Available, O.OOE+OO 0.00E+00 O.OOE+OO Containment Isolation Success, RCS Pressure>

200 psia BV14S Small, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO LATE Cnmt. Isolation Failure, RCS Pressure > 200 psia (continued)

Small, Late Release, Containment Sprays Unavailable, BV15 Containment Isolation Success, RCS Pressure<

200 psia 5.34E-06 1.18E-06 4.16E-06 BV15S Small, Late Release, Containment Sprays Unavailable, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV16 Small, Late Release, Containment Sprays Available, O.OOE+OO O.OOE+OO O.OOE+OO Containment Isolation Success, RCS Pressure < 200 psia BV16S Small, Late Release, Containment Sprays Available, Small O.OOE+OO O.OOE+OO O.OOE+OO Cnmt. Isolation Failure, RCS Pressure < 200 psia BV17 Small, Late Release, Containment Isolation Success 1.84E-07 1.59E-07 2.50E-08 (Basemat Melt-through)

BV17S Small, Late Release, Small Cnmt. Isolation Failure (Basemat O.OOE+OO O.OOE+OO O.OOE+OO Melt-through)

BV18 Large, Containment Bypass (Unscrubbed Faulted SGTR, 1.73E-07 6.60E-08 1.07E-07 Pressure-Induced SGTR, or Temperature-Induced SGTR) LERF BV19 Large, Containment Bypass (Interlacing Systems LOCA) 3.89E-09 3.89E-09 O.OOE+OO SERF BV20 Small, Containment Bypass (Scrubbed Faulted SGTR) 3.73E-06 3.37E-07 3.39E-06 LONG BV21 Long-Term Containment Integrity (Intact Containment) 1.06E-06 7.47E-07 3.15E-07 TOTALS 1.67E-05 4.14E-06 1.26E-05 Population Dose Calculations The BVPS 50-mile baseline population dose (person-rem) used in this ILRT extension analysis is determined from the BVPS-2 Severe Accident Mitigation Alternative (SAMA) [19] results for the 50-mile lifetime (50-year) effective dose commitments.

The results presented in the BVPS-2 SAMA, Table 3.5-1 were developed for the BVPS License Renewal using the MELCOR Accident Consequence Code System (MACCS2) computer code, and are based on the average weather conditions at BVPS from 2001 through 2005, with the projected PRA-BV2-13-002-ROO Page 16 of 60 50-mile radius population of 3,607,001 in the year 2047. The plume data used in the MACCS2 analysis was based on a composite set of source term data for BVPS-1 and BVPS-2, and is appropriate for analyzing both units. Table 4-2 shows the results of applying the BVPS-2 SAMA, Table 3.5-1 population dose (Total L-EFFECTIVE LIFE Dose in Sieverts) to obtain the population dose in person-rem at 50 miles for BVPS-2. This table also provides the representative Level 2 release bins that were analyzed with MACCS2 for the BVPS SAMA Release Category.

Table 4-2. Calculation of BVPS Population Dose at 50 Miles BVPS Composite Weather Sensitivity Results for Total BVPS BVPS MACCS L-EFFECTIVE LIFE Dose in Sieverts Population Repre-SAMA 2 Run Dose at sentative Release 50 Miles Release Category Code 2001 2002 2003 2004 2005 Average (person-Bins rem) INTACT A 8 7 8 7 7 8 8.00E+02 BV21 ECF-8 50,400 47,200 51,000 53,600 40,800 48,600 4.86E+06 BV19 VSEQ ECF-c 44,500 41,400 43,800 46,500 37,000 42,640 4.26E+06 BV18 SGTR ECF-D 86,800 84,800 86,600 76,400 77,600 82,440 8.24E+06 BV01, DCH BV03 SECF-E 50,500 48,000 47,800 46,900 44,800 47,600 4.76E+06 N/A VSEQ SECF-F 35,200 35,500 33,200 34,000 36,400 34,860 3.49E+06 BV07S LOCI SECF-K 43,800 39,800 41,300 41,000 42,700 41,720 4.17E+06 BV05S BV5 LATE-G 1,530 1,440 1,780 1,600 1,450 1,560 1.56E+05 BV10, Large BV12 LATE-H 20,200 19,200 18,800 18,600 20,500 19,460 1.95E+06 BV13, Small BV15 LATE-H2 I 19,300 17,200 17,600 16,300 17,900 17,660 1.77E+06 BV09 Burn LATE-J 7,680 7,250 7,200 7,990 6,990 7,422 7.42E+05 BV17 BMMT Since not all of the BVPS Level 2 release bins were analyzed in the SAMA, a bounding SAMA release category must be assigned to the remaining release bins. Table 4-3, shows results of these conservatively assigned bounding SAMA release categories for each Level 2 release bin, along with the associated BVPS 50-mile population dose in person-rem.

PRA-BV2-13-002-ROO Page 17 of 60 Table 4-3. Assignment of SAMA Release Category and BVPS Dose to Release Bin Analyzed SAMA Assigned BVPS Release Release Category Release Bin Bounding Population Bin Category Sub-Grouping SAMA Release Dose at 50 Miles Description Category (person-rem)

BV01 ECF-DCH LERF ECF-DCH 8.24E+06 BV01S -LERF ECF-DCH 8.24E+06 BV02 -LERF ECF-DCH 8.24E+06 BV02S -LERF ECF-DCH 8.24E+06 BV03 ECF-DCH LERF ECF-DCH 8.24E+06 BV03S -LERF ECF-DCH 8.24E+06 BV04 -LERF ECF-DCH 8.24E+06 BV04S -LERF ECF-DCH 8.24E+06 BV05 -SERF-RCS > 200 psia SECF-BV5 4.17E+06 BV05S SECF-BV5 SERF -RCS > 200 psia SECF-BV5 4.17E+06 BV06 -SERF -RCS > 200 psia SECF-BV5 4.17E+06 BV06S -SERF-RCS > 200 psia SECF-BV5 4.17E+06 BV07 -SERF-RCS < 200 psia SECF-LOCI 3.49E+06 BV07S SECF-LOCI SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV08 -SERF-RCS < 200 psia SECF-LOCI 3.49E+06 BV08S -SERF -RCS < 200 psia SECF-LOCI 3.49E+06 BV09 LATE -H2 Burn LATE -Large, No Spray LATE-H2 Burn 1.77E+06 BV09S -LATE-Large, No Spray LATE -H2 Burn 1.77E+06 BV10 LATE-Large LATE-Large, Spray LATE-Large 1.56E+05 BV10S -LATE-Large, Spray LATE-Large 1.56E+05 BV11 -LATE-Large, No Spray LATE-H2 Burn 1.77E+06 BV11S -LATE-Large, No Spray LATE -H2 Burn 1.77E+06 BV12 LATE-Large LATE-Large, Spray LATE-Large 1.56E+05 BV12S -LATE-Large, Spray LATE-Large 1.56E+05 BV13 LATE-Small LATE-Small LATE-Small 1.95E+06 BV13S -LATE-Small LATE-Small 1.95E+06 BV14 -LATE-Small LATE-Small 1.95E+06 BV14S -LATE-Small LATE-Small 1.95E+06 BV15 LATE-Small LATE-Small LATE-Small 1.95E+06 BV15S -LATE-Small LATE-Small 1.95E+06 BV16 -LATE-Small LATE-Small 1.95E+06 BV16S -LATE-Small LATE-Small 1.95E+06 BV17 LATE-BMMT LATE-Basemat Melt-Through LATE-BMMT 7.42E+05 BV17S -LATE-Basemat Melt-Through LATE-BMMT 7.42E+05 BV18 ECF-SGTR LERF -Large Cnmt Bypass -SGTR ECF-SGTR 4.26E+06 BV19 ECF-VSEQ LEAF-Large Cnmt Bypass -VSEQ ECF-VSEQ 4.86E+06 BV20 -SERF-Small Cnmt Bypass -SGTR ECF-SGTR 4.26E+06 BV21 INTACT LONG -Intact Cnmt INTACT 8.00E+02 PRA-BV2-13-002-ROO Page18of60 Release Category Definitions Table 4-4 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology

[2]. 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 4-4. EPRI Containment Failure Classification

[2] Class Description Containment remains intact including accident sequences that do not lead to containment 1 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 pre-existing 3 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.

This class is similar to 4 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 pre-existing 5 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 and 6 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 induced by 8 phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.

PRA-BV2-13-002-ROO Page 19 of 60 Application of the BVPS-2 PRA Model Results to EPRI Accident Class A major factor related to this evaluation is that the results of the BVPS-2 Level 2 PRA model release bins defined in Table 4-1 do not directly correspond to the EPRI accident classes defined in Table 4-4. In order to use the EPRI Accident Classes presented in EPRI Report 1018243, it was necessary to match the BVPS-2 Level 2 release bins to the corresponding EPRI classes. Table 4-5 provides the relationship between the EPRI accident class and the BVPS-2 Level 2 release bins, including the delineation of LERF and non-LERF frequencies for Classes 7 and 8. It should be noted that in EPRI Report 1018243, the Class 2 group consists of all core damage accident progression bins for which a pre-existing leakage due to failure to isolate the containment occurs, and were dominated by failure to close of large (>2 inches in diameter) containment isolation valves. The Class 6 group also involved failures to isolate the containment, but were typically dominated by a failure to close smaller containment isolation valves. At BVPS all non-screened containment isolation valve failures are considered to be small (< 2 inches in diameter).

Therefore, these sequences with failures of the containment isolation valves to close will be binned into the EPRI Class 6 group, and are determined directly from the BVPS-2 PRA SERF bins BVOSS, BV06S, BV07S, and BV08S. Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes BVPS EPRI BVPS Release Corresponding Release Bin Grouping using EPRI Release Accident Category Group the EPRI Accident Class Description (bold Accident Category Sub-Level2 Bins Type) Class Group Class BV01, BV01S, BV02, Large, early containment failures due to LERF BV02S,BV03,BV03S, 7 7 LERF BV04, BV04S accident phenomenon, at any RCS pressure Small, early containment failures due to 7 non-SERF BV05, BV06 accident phenomenon, with RCS pressure > 7 LERF 200 psia SERF BV05S,BV06S Small, early containment failures due to failure to isolate, with RCS pressure > 200 psia 6 6 Small, early containment failures due to 7 non-SERF BV07,BV08 accident phenomenon, with RCS pressure < 7 LERF 200 psia SERF BV07S,BV08S Small, early containment failures due to 6 6 failure to isolate, with RCS pressure < 200 psia PRA-BV2-13-002-ROO Page 20 of 60 Table 4-5. BVPS Level 2 Release Bins to the Assigned EPRI Accident Classes BVPS EPRI BVPS Release Corresponding Release Bin Grouping using EPRI Release Accident Category Group the EPRI Accident Class Description (bold Accident Category Sub-Level2 Bins Type) Class Group Class LATE-BV09, BV09S, BV1 0, Large, late containment failures due to 7 non-BV1 OS, BV11, BV11 S, 7 LARGE accident phenomenon LERF BV12, BV12S BV13,BV13S, BV14, Small, late containment failures due to LATE-BV14S, BV15, BV15S, 7 non-accident phenomenon (including basemat melt-7 SMALL BV16, BV16S, BV17, LERF BV17S through) LERF-Large containment bypass (includes CNMT BV18, BV19 intertacing-systems LOCAs, induced SGTRs, 8 8 LERF BYPASS and unscrubbed faulted SGTRs) SERF-Small containment bypass (includes scrubbed 8 non-CNMT BV20 8 faulted SGTRs) LERF BYPASS LONG BV21 Long-Term Containment Integrity (Intact Containment) 1 1 Population Dose Risk Calculation for EPRI Accident Class The correlation between the BVPS Level 2 release bins to EPRI accident class in Table 4-5 was used along with the Level 2 release bin frequencies presented in Table 4-1 (columns 4, 5, & 6), and the bounding BVPS population dose at 50 miles assigned to the Level 2 release bins presented in Table 4-3 (column 5), to obtain a population dose risk for this ILRT analysis.

The population dose risk was calculated by multiplying the Level 2 release bin frequency by the associated release bin BVPS population dose at 50 miles. The results from these computations for the BVPS-2 total, internal, and external events are presented in Table 4-6. The bin frequencies from Table 4-1 and BVPS population dose at 50 miles from Table 4-3 are also reproduced for clarity.

PRA-BV2-13-002-ROO Page 21 of 60 Table 4-6. BVPS-2 Level 2 Release Bin Frequency and Population Dose Risk Total Internal External BVPS Total Internal Events External Release Release Release Release Release Population Population Population Events Category EPRI Sub-Class Population Group Bin Bin Freq. Bin Freq. Bin Freq. Dose at 50 Dose Risk Dose Risk Dose Risk (peryr} (peryr} (per yr} Miles (per.-rern} (person-rern/yr} (person-rem/yr} (person-rern/yr}

LERF BV01 1.78E-09 4.75E-10 1.31E-09 8.24E..06 CLASS 7 LERF 1.47E-02 3.92E-03 1.08E-02 LERF BV01S 4.66E-12 2.54E-12 2.12E-12 8.24E..06 CLASS 7 LERF 3.84E-05 2.09E-05 1.74E-05 LERF BV02 1.16E-10 4.41E-11 7.14E-11 8.24E..06 CLASS 7 LERF 9.52E-04 3.63E-04 5.89E-04 LERF BV02S 1.01E-13 O.OOE-+00 1.01E-13 8.24E..06 CLASS 7 LERF 8.35E-07 O.OOE-+00 8.35E-07 LERF BV03 4.82E-12 1.22E-12 3:60E-12 8.24E..06 CLASS 7 LERF 3.97E-05 1.01E-05 2.97E-05 LERF BV03S O.OOE-+00 O.OOE-+00 O.OOE-+00 8.24E..06 CLASS 7 LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LERF BV04 2.26E-12 1.37E-12 8.94E-13 8.24E..06 CLASS 7 LERF 1.86E-05 1.13E-05 7.37E-06 LERF BV04S 1.32E-11 7.38E-12 5.84E-12 8.24E..06 CLASS 7 LERF 1.09E-04 6.08E-05 4.82E-05 SERF BV05 3.23E-10 8.47E-11 2.38E-10 4.17E..06 CLASS 7 NON-LERF 1.35E-03 3.53E-04 9.95E-04 SERF BV05S 5.79E-09 3.55E-09 2.24E-09 4.17E..06 CLASS 6 2.41E-02 1.48E-02 9.35E-03 SERF BV06 1.08E-11 9.97E-12 8.12E-13 4.17E..06 CLASS 7 NON-LERF 4.50E-05 4.16E-05 3.39E-06 SERF BV06S 2.91E-10 2.05E-10 8.61E-11 4.17E..06 CLASS 6 1.21E-03 8.55E-04 3.59E-04 SERF BV07 1.01E-09 2.18E-10 7.89E-10 3.49E..06 CLASS 7 NON-LERF 3.51E-03 7.59E-04 2.75E-03 SERF BV07S 3.26E-08 1.89E-08 1.37E-08 3.49E..06 CLASS 6 1.14E-01 6.60E-02 4.77E-02 SERF BV08 1.66E-07 2.16E-08 1.45E-07 3.49E..06 CLASS 7 NON-LERF 5.80E-01 7.52E-02 5.05E-01 SERF BV08S 1.27E-09 7.93E-10 4.80E-10 3.49E..06 CLASS 6 4.44E-03 2.76E-03 1.67E-03 LATE BV09 O.OOE-+00 O.OOE-+00 O.OOE-+00 1.77E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV09S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.77E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV10 4.72E-10 3.66E-10 1.06E-10 1.56E..05 CLASS 7 NON-LERF 7.37E-05 5.71E-05 1.66E-05 LATE BV10S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.56E..05 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV11 O.OOE-+00 O.OOE-+00 O.OOE-+00 1.77E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV11S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.77E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV12 1.41 E-08 8.79E-09 5.29E-09 1.56E..05 CLASS 7 NON-LERF 2.20E-03 1.37E-03 8.26E-04 LATE BV12S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.56E..05 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV13 6.00E-06 1.59E-06 4.41 E-06 1.95E..06 CLASS 7 NON-LERF 1.17E..01 3.10E..OO 8.57E..OO LATE BV13S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV14 O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV14S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV15 5.34E-06 1.18E-06 4.16E-06 1.95E..06 CLASS 7 NON-LERF 1.04E..01 2.30E..OO 8.09E..OO LATE BV15S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV16 O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV16S O.OOE-+00 O.OOE-+00 O.OOE-+00 1.95E..06 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LATE BV17 1.84E-07 1.59E-07 2.50E-08 7.42E..05 CLASS 7 NON-LERF 1.37E-01 1.18E-01 1.86E-02 LATE BV17S O.OOE-+00 O.OOE-+00 O.OOE-+00 7.42E..05 CLASS 7 NON-LERF O.OOE-+00 O.OOE-+00 O.OOE-+00 LERF BV18 1.73E-07 6.60E-08 1.07E-07 4.26E..06 CLASS 8 LERF 7.38E-01 2.81E-01 4.57E-01 LERF BV19 3.89E-09 3.89E-09 O.OOE-+00 4.86E..06 CLASS 8 LERF 1.89E-02 1.89E-02 O.OOE-+00 SERF BV20 3.73E-06 3.37E-07 3.39E-06 4.26E..06 CLASS 8 NON-LERF 1.59E..01 1.44E..OO 1.45E..01 LONG BV21 1.06E-06 7.47E-07 3.15E-07 8.00E..02 CLASS 1 8.50E-04 5.97E-04 2.52E-04 TOTALS 1.67E-05 4.14E-06 1.26E-05 3.96E..01 7.42E..OO 3.22E..01 PRA-BV2-13-002-ROO Page 22 of 60 The EPRI accident sub-class release frequency for BVPS-2 was obtained by summing the assigned Level 2 release bin frequencies from Table 4-6. Likewise, the EPRI accident class population dose risk for BVPS-2 was obtained by summing the assigned BVPS population dose from Table 4-6. In the case of BVPS-2, a frequency-weighted dose is used to represent EPRI accident Class 6, Class 7 non-LERF, Class 7 LERF, and Class 8 LERF population dose since these classes are composed of multiple BVPS release category bins. Table 4-7 lists the release frequency, population dose risk, and weighted average population dose for BVPS-2 organized by EPRI release category, including the delineation of LERF and non-LERF frequencies for Classes 7 and 8. For the total (internal plus external events), the weighted average population dose (Column 5) was determined by dividing the associated population dose risk (Column 4) by the accident sub-class frequency (Column 3) for each of the EPRI accident sub-class.

An example of applying this frequency-weighted average population dose methodology to the total Class 8 LERF is calculated as follows: From Table 4-5, the Class 8 LERF is comprised of BVPS Release Category Group Level 2 Bins BV18 and BV19. From Table 4-6, the frequency for release bin BV18 is 1. 73E-07 /yr and the BVPS population dose at 50 miles is 4.26E+06 person-rem, for a BVPS-2 dose risk of 1.73E-07 /yr

• 4.26E+06 person-rem

= 7 .38E-01 person-rem/yr.

Also from Table 4-6, the frequency for release bin BV19 is 3.89E-09 /yr and the BVPS population dose at 50 miles is 4.86E+06 person-rem, for a BVPS-2 dose risk of 3.89E-09 /yr

• 4.86E+06 person-rem

= 1.89E-02 person-rem/yr.

The frequency-weighted average population dose for Class 8 LERF = (release bin BV18 population dose risk + release bin BV19 population dose risk) I (release bin BV18 frequency

+ release bin BV19 frequency)

= (7.38E-01

+ 1.89E-02) person-rem/yr I (1.73E-07

+ 3.89E-09) per yr = (7.57E-01 person-rem/yr)

I (1.77E-07

/yr) = 4.28E+06 person-rem The internal and external events weighted average population doses were similarly obtained for the EPRI accident sub-classes.

Table 4-7. BVPS-2 50-Mile Population Dose Risk by EPRI Accident Class I Total EPRI BVPS EPRI Weighted EPRI Accident Release Category Accident Population Average Accident Sub-Group Sub-Class Dose Risk Population Sub-Class Frequency (person-Dose Frequency Class Level2 Bins rem/yr) (person-(/yr} rem) (/yr} 1 BV21 1.06E-06 8.50E-04 8.00E+02 7.47E-07 6 BV05S,BV06S,BV07S, 4.00E-08 1.44E-01 3.59E+06 2.35E-08 BV08S BV05, BV06, BV07, BV08,BV09,BV09S, BV1 0, BV1 OS, BV11 , 7 non-BV11 S, BV12, BV12S, 1.17E-05 2.28E+01 1.95E+06 2.96E-06 LERF BV13,BV13S, BV14, BV14S,BV15,BV15S, BV16, BV16S, BV17, BV17S BV01, BV01S, BV02, 7 LERF BV02S, BV03, BV03S, 1.92E-09 1.58E-02 8.24E+06 5.32E-10 BV04, BV04S 8 non-BV20 3.73E-06 1.59E+01 4.26E+06 3.37E-07 LERF 8 LERF BV18, BV19 1.77E-07 7.57E-01 4.28E+06 6.99E-08 -Internal Events Weighted EPRI Population Average Accident Dose Risk Population Sub-Class (person-Dose Frequency rem/yr) (person-rem) (/yr) 5.97E-04 8.00E+02 3.15E-07 8.44E-02 3.60E+06 1.65E-08 5.59E+00 1.89E+06 8.74E-06 4.38E-03 8.24E+06 1.39E-09 1.44E+00 4.26E+06 3.39E-06 3.00E-01 4.30E+06 1.07E-07 External Events Population Dose Risk (person-rem/yr) 2.52E-04 5.91 E-02 1.72E+01 1.15E-02 1.45E+01 4.57E-01 Weighted I Average Population Dose (person-rem) 8.00E+02 3.58E+06 1.97E+06 8.24E+06 4.26E+06 4.26E+06 -u :D =!> lJJ Ill * (0 ..... <Dc.u 1\)6 c.uO 01}' -:D cno 00 PRA-BV2-13-002-ROO Page 24 of 60 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) 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 accident class, as defined in Table 4-4, 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 [27]. 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, Jeffery's non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5/(217+1)

= 0.0023). In a follow on letter [20] to their ILRT guidance document [3], NEI issued additional information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC RG 1.174. This additional NEI information includes a discussion of conservatisms in the quantitative guidance for delta LERF. NEI 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 LEAF or could never cause a LEAF, and are thus not associated with a postulated large Type A containment leakage path (LEAF). These contributors can be removed from Class 3b in the evaluation of LEAF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage. The application of this additional guidance to the analysis for BVPS-2, as detailed in Section 5, involves the following:

• The Class 7 LERF and Class 8 LERF sequences are subtracted from the CDF that is applied to Class 3b. Class 7 LERF and Class 8 LERF events refer to sequences with either large containment failures due to severe accident phenomena or large containment bypass events. These sequences PRA-BV2-13-002-ROO Page 25 of 60 are already considered to contribute to LERF in the BVPS-2 Level 2 PRA analysis.

To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Consistent with the NEI Guidance [3], 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 I 2), and the average time that a leak could exist without detection for a ten-year interval is 5 years (1 0 yr I 2). This change would lead to a non-detection probability that is a factor of 3.33 (5.011.5) higher for the probability of a leak that is detectable only by ILRT testing. Correspondingly, an extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 (7.511.5) increase in the 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 IP3 request for a time ILRT extension that was approved by the NRC [9]) because it does not factor in the possibility that the failures could be detected by other tests (e.g., the Type B local leak rate tests that will still occur.) Eliminating this possibility conservatively over-estimates the factor increases attributable to the ILRT extension.

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 [5]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. BVPS-2 can be considered to have a similar type of containment as Calvert Cliffs. 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 PRA-BV2-13-002-ROO Page 26 of 60

• Consistent with the Calvert Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures. (See Table 4-8, Step 1.)

• The two corrosion events that were initiated from the non-visible (backside) portion of the containment liner used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the BVPS-2 containment analysis.

These events, one at North Anna Unit 2 (September 1999) caused by a timber embedded in the concrete immediately behind the containment liner, and one at Brunswick Unit 2 (April 1999) caused by a cloth work glove embedded in the concrete next to the liner, were initiated from the nonvisible (backside) portion of the containment liner. A search of the NRC website LER database (https://lersearch.inl.gov/LERSearchCriteria.aspx) for ["containment liner" AND "defect" OR "hole"] through June 25, 2013 identified that two additional events have occurred since the Calvert Cliffs analysis was performed.

In January 2000, a 3/16-inch circular through-liner hole was found at Cook Nuclear Plant Unit 2 caused by a wooden brush handle embedded immediately behind the containment liner. The other event occurred in April 2009, where a through-liner hole approximately 3/8-inch by 1-inch in size was identified in the BVPS-1 containment liner caused by pitting originating from the concrete side due to a piece of wood that was left behind during the original construction that came in contact with the steel liner. Two other containment liner through wall hole events occurred at Turkey Point Units 3 and 4 in October 2010 and November 2006, respectively.

However, these events originated from the visible side caused by the failure of the coating system, which was not designed for periodic immersion service, and are not considered to be applicable to this analysis.

More recently, in October 2013, some through-wall containment liner holes were identified at BVPS-1, with a combined total area of approximately 0.395 square inches. One of these holes, found during the visual inspections of the internal containment liner and protective coatings, was located about 7 inches above the basemat floor. The others were identified during the follow-up lab analysis, and were located about 2 inches below the basemat concrete floor line. The cause of these through wall liner holes was attributed to corrosion originating from the outside concrete surface due to the presence of rayon fiber foreign material that was left behind during the original construction and was contacting the steel liner. For risk evaluation purposes, these five total corrosion events occurring in 66 operating plants with steel containment liners over a 17.1 year period from September 1996 to October 4, 2013 (i.e., 5/(66*17.1)

= 4.43E-03) are bounded by the estimated historical flaw probability based on the two events in the 5.5 year period of the Calvert Cliffs analysis (i.e., 2/(70*5.5)

= 5.19E-03) incorporated in the EPRI guidance. (See Table 4-8, Step 1.)

PRA-BV2-13-002-ROO Page 27 of 60

• 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 4-8, Steps 2 and 3.) Sensitivity studies are included in Section 6 that addresses 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% (1 0% 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 their ILRT target pressure of 64.7 psia. For BVPS-2, probabilities of 1% for the cylinder and dome, and 0.1% for the basemat are assumed in this analysis, which are consistent with the EPRI 1018243 guidance. (See Table 4-8, Step 4.) Sensitivity studies are included in Section 6 that increase and decrease the probabilities by an order of magnitude.

• 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 4-8, 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 4-8, Step 5.) Sensitivity studies are included in Section 6 that evaluate total detection failure likelihood of 5% and 15%, respectively.

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

This approach avoids a detailed analysis of containment failure timing and operator recovery actions. That is, the probability of all non-detectable failures from the corrosion sensitivity analysis are added to the EPRI Class 3b (and subtracted from EPRI Class 1 ).

Analysis Table 4-8. Steel Liner Corrosion Base Case Step Description Containment Cylinder and Dome Historical Steel Liner Flaw Events: 2 Likelihood 1 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis -2/(70

• 5.5) = 5.19E-03 70 steel lined containments and 5.5 years). Age Adjusted Steel Liner Year Failure Rate Flaw Likelihood 1 2.05E-03 During 15-year interval, avg 5-10 5.19E-03 assume failure rate doubles 2 every five years (14.9% 15 1.43E-02 increase per year). The average for 5th to 1 Oth year is set to the historical failure rate (consistent with Calvert 15 year average = 6.44E-03 Cliffs analysis).

Flaw Likelihood at 3, 1 0, 0. 71% (1 to 3 years) and 15 years 4.14% (1 to 10 years) Uses age adjusted liner flaw 9.67% (1 to 15 years) likelihood (Step 2), assuming (Note that the Calvert Cliffs failure rate doubles every five analysis presents the delta years (consistent with Calvert between 3 and 15 years of 3 Cliffs analysis-See Table 6 8.7% to utilize in the estimation of Reference

[5]). of the delta-LERF value. For this analysis, however, the values are calculated based on the 3, 1 0, and 15 year intervals consistent with the desired presentation of the results. PRA-BV2-13-002-ROO Page 28 of 60 Containment Basemat Events: 0 (assume half a failure) 0.5/(70

• 5.5) = 1.30E-03 Year Failure Rate 1 5.12E-04 avg 5-10 1.30E-03 15 3.58E-03 15 year average

= 1.61 E-03 0.18% (1 to 3 years) 1.03% (1 to 10 years) 2.42% (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 2.2% to utilize in the estimation of the delta-LERF value. For this analysis, however, the values are calculated based on the 3, 1 0, and 15 year intervals consistent with desired presentation of the results.

Table 4-8. Steel Liner Corrosion Base Case Step Description Containment Cylinder and Dome Likelihood of Breach in Containment Given Steel Liner Flaw The failure probability of the cylinder and dome is 4 assumed to be 1% 1.0% (compared to 1.1% in the Calvert Cliffs analysis).

The basemat failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis).

Visual Inspection Detection 10% Failure Likelihood 5% failure to identify visual Utilize assumptions flaws plus 5% likelihood that the consistent with Calvert Cliffs flaw is not visible (not through-5 analysis.

cylinder but could be detected by ILRT) All events have been detected through visual inspection.

5% visible failure detection is a conservative assumption.

Likelihood of Non-Detected 0.00071% (at 3 years) Containment Leakage 0.71%

• 1%

• 10% 6 (Steps 3

• 4

• 5) 0.00414% (at 10 years) 4.14%*1%*10%

0.00967% (at 15 years) 9.67%

• 1%

• 10% PRA-BV2-13-002-ROO Page 29 of 60 Containment Basemat 0.1% 100% Cannot be visually inspected.

0.00018% (at 3 years) 0.18%

• 0.1%

• 100% 0.00103% (at 10 years) 1.03%

• 0.1%

• 100% 0.00242% (at 15 years) 2.42%

• 0.1%

• 100%

PRA-BV2-13-002-ROO Page 30 of 60 The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 in Table 4-8 for the containment cylinder and dome, and the containment basemat as summarized below for BVPS-2: At 3 years: 0.00071% + 0.00018% = 0.00089% At 10 years:0.00414%

+ 0.00103% = 0.00517% At 15 years: 0.00967% + 0.00242% = 0.01208% The above factors are applied to those core damage accidents that are not already independently LERF or that could never result in LERF. For example, the 3-in-1 0 year case for the total risk is calculated as follows:

• Per Table 5-3, the EPRI Class 3b frequency is 3.81 E-08/yr.

• As discussed in Section 5.1, the BVPS-2 CDF associated with accidents that are not independently LERF is CDF -Class 7 LERF -Class 8 LERF, or 1.67E-05/yr-1.92E-09/yr-1.77E-07/yr

= 1.65E-05/yr.

• The increase in the base case Class 3b frequency due to the induced concealed flaw issue is calculated as 1.65E-05/yr

• 8.9E-06 = 1.47E-1 0/yr, where 8.9E-06 (0.00089%)

was previously shown above to be the cumulative likelihood of non-detected containment leakage due to corrosion at 3 years.

• The 3-in-1 0 year Class 3b frequency including the corrosion-induced concealed flaw issue is calculated as 3.81 E-08/yr + 1.47E-1 0/yr = 3.82E-08/yr.

5. RESULTS PRA-BV2-13-002-ROO Page 31 of 60 The application of the approach based on the guidance contained in EPRI Report No. 1009325, Revision 2-A, Appendix H, EPRI TR-1 04285 [2] and previous risk assessment submittals on this subject [5, 8, 21, 22, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5-1 lists these accident classes. The analysis performed examined the BV2REV5A specific accident sequences in which the containment remains intact or the containment is impaired.

Specifically, the break down of the severe accidents contributing to risk were considered in the following manner:

• Core damage sequences in which the containment remains intact initially and in the long term (EPRI 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 small containment isolation failures as a result of the accident sequence progression (EPRI Class 6 sequences).

For example, a 1-inch diameter containment isolation valve failing to close following a valid signal to close. These are accounted for in this evaluation as part of the baseline risk profile; however, they are not affected by the ILRT frequency change.

• Accident sequences involving failures induced by phenomena (EPRI Class 7 sequences), containment bypassed events (EPRI Class 8 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.

• All large (> 2-inch diameter) containment isolation failures (EPRI Class 2 sequences) were screened out during the BVPS-2 containment isolation analysis.

Therefore, this class is not specifically examined since it does not influence the results of this analysis.

• 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.

Table 5-1. Accident Classes Accident Classes (Containment Release Type) 1 2 3a 3b 4 5 6 7 8 CDF Description No Containment Failure Large Isolation Failures (Failure to Close) Small Isolation Failures (liner breach) Large Isolation Failures (liner breach) PRA-BV2-13-002-ROO Page 32 of 60 Small Isolation Failures (Failure to seal -Type B) Small Isolation Failures (Failure to seal-Type C) Other Isolation Failures (e.g., dependent failures)

Failures Induced by Phenomena (Early and Late) Bypass (Interfacing System LOCA) All CET End states (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 5-1. 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 3 to 15 and 1 0 to 15 years. Step 4) Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174. Step 5) Determine the impact on the Conditional Containment Failure Probability (CCFP)

PRA-BV2-13-002-ROO Page 33 of 60 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 existing leaks is included in the model. (These events are represented by the Class 3 sequences in EPRI TR-1 04285). The question on containment integrity was modified to include the probability of a liner breach or bellows failure (due to excessive leakage) at the time of core damage. 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 5-1 were developed for BVPS-2 by first determining the frequencies for Classes 1, 6, 7 and 8, as shown in Table 4-7, by using the categorized sequences and the identified correlations shown in Table 4-5. Next, the frequencies for Classes 3a and 3b were determined, which were then used to revise the Class 1 frequency in order to maintain the CDF. 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. The total frequency of the categorized sequences in the BVPS-2 Level 2 PRA is 1.67E-05/yr, which is also the total CDF in the BVPS-2 Level 1 PRA, so no scaling factor is necessary.

Table 5-2 contains the frequencies from the categorized sequences based on Table 4-7. The results are summarized below and in Table 5-3. Table 5-2. BVPS-2 Categorized Accident Classes and Frequencies EPRI Accident EPRI Accident EPRI Accident EPRI BVPS Sub-Class Sub-Class Sub-Class Accident Level 2 Release Bins Frequency for Frequency for Frequency for Sub-Class Total Risk Internal Events External Events (/yr) (/yr) (/yr) 1 BV21 1.06E-06 7.47E-07 3.15E-07 6 BV05S,BV06S, BV07S, 4.00E-08 2.35E-08 1.65E-08 BVOBS PRA-BV2-13-002-ROO Page 34 of 60 Table 5-2. BVPS-2 Categorized Accident Classes and Frequencies EPRI Accident EPRI Accident EPRI Accident EPRI BVPS Sub-Class Sub-Class Sub-Class Accident Level 2 Release Bins Frequency for Frequency for Frequency for Sub-Class Total Risk Internal Events External Events (/yr) (/yr) (/yr) BV05, BV06, BV07, BV08, BV09,8V09S,BV10,BV10S, 7 non-BV11, BV11 S, BV12, BV12S, 1.17E-05 2.96E-06 8.74E-06 LERF BV13,8V13S, BV14, BV14S, BV15, BV15S, BV16, BV16S, BV17, BV17S 7 LERF BV01,8V01S,BV02,8V02S, 1.92E-09 5.32E-10 1.39E-09 BV03,8V03S,BV04,8V04S 8 non-BV20 3.73E-06 3.37E-07 3.39E-06 LERF 8 LERF BV18, BV19 1.77E-07 6.99E-08 1.07E-07 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 <1 0 La) or large (>1 00 La). 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, additional consideration is made to not apply these failure probabilities on those cases that are already LERF scenarios (i.e., the Class 7 LERF and Class 8 LERF contributions).

For the total risk contribution the Class 3a and Class 3b frequencies are calculated as follows: Total Class 3a Frequency

= 0.0092 * (CDF-Class 7 LERF-Class 8 LERF) = 0.0092* (1.67E 1.92E-09-1.77E-07)

= 1.52E-07/yr PRA-BV2-13-002-ROO Page 35 of 60 Total Class 3b Frequency

= 0.0023 * (CDF-Class 7 LERF-Class 8 LERF) =0.0023 * (1.67E 1.92E-09-1. 77E-07) = 3.81 E-08/yr Similarly, the Class 3a and Class 3b frequencies for the internal and external events are: Internal Class 3a Frequency

= 0.0092 * (4.14E 5.32E-1 0-6.99E-08)

= 3. 75E-08/yr Internal Class 3b Frequency

= 0.0023 * (4.14E 5.32E-1 0 -6.99E-08)

= 9.38E-09/yr External Class 3a Frequency

= 0.0092 * (1.26E 1.39E-09-1.07E-07)

= 1.15E-07/yr External Class 3b Frequency

= 0.0023 * (1.26E 1.39E-09-1.07E-07)

= 2.87E-08/yr For this analysis, the associated containment leakage for Class 3a is 10 La and for Class 3b is 100 La. These assignments are consistent with the guidance provided in EPRI Report No. 1009325, Revision 2-A. Class 1 Sequences.

This group consists of all core damage accident progression bins for which the containment remains intact (modeled as Technical Specification Leakage).

The frequency per year is initially determined from the Level 2 Release Category BV21 listed in Table 5-2, minus the EPRI Class 3a and 3b frequency, calculated above. Subtracting Class 3a and Class 3b frequencies from the initial Class 1 frequency will preserve the total CDF. Therefore, the revised total Class 1 frequency is given as: Total Class 1 Frequency (revised)

= Initial Class 1 -Class 3a-Class 3b = (1.06E 1.52E-07-3.81 E-08) /yr = 8. 72E-07 per year Likewise, the internal and external events revised Class 1 frequencies are: Internal Class 1 Frequency (revised)

= (7.47E 3.75E-08-9.38E-09)

/yr = 7.00E-07 per year External Class 1 Frequency (revised)=

(3.15E 1.15E-07-2.87E-08)

/yr = 1.72E-07 per year PRA-BV2-13-002-ROO Page 36 of 60 Class 2 Sequences.

This group consists of all core damage accident progression bins for which a pre-existing leakage due to failure to isolate the containment occurs. These sequences are dominated by failure-to-close

(>2-inch diameter) containment isolation valves. Such sequences contribute to the plant LERF. For the BVPS-2 PRA model, a containment isolation analysis was performed to estimate the frequency of failure to isolate lines that could cause a significant risk of radioactive release. The results of this analysis screened-out all containment penetrations

> 2-inch diameter.

Furthermore, the Beaver Valley Power Station containments are operated at slightly sub-atmospheric pressures (BVPS Technical Specification LCO 3.6.4 [18] states that containment pressure shall be;;:: 12.8 psia and::::; 14.2 psia), thus the baseline PRA models do not consider a large pre-existing loss of containment isolation to be credible.

Therefore, the frequency per year for these Class 2 sequences is assumed to be zero. The containment isolation failures for the penetrations that did not screen-out (i.e., <= 2-inch diameter) are captured in the Class 6 Sequences.

The Class 2 group is not evaluated any further in this analysis.

Class 4 Sequences.

This group consists of all core damage accident progression bins for which containment isolation failure-to-seal of Type B test components occurs. Because these failures are detected by Type B tests which are unaffected by the Type A ILRT, this group is not evaluated any further in the analysis.

Class 5 Sequences.

This group consists of all core damage accident progression bins for which a containment isolation failure-to-seal of Type C test components.

Because the failures are detected by Type C tests which are unaffected by the Type A ILRT, this group is not evaluated any further in this analys*is.

Class 6 Sequences.

Similar to Class 2, the Class 6 group is comprised of isolation faults that occur as a result of the accident sequence progression, but are dominated by the failure of containment isolation valves (<=2-inch diameter) to close following an event. The leakage rate from <= 2-inch diameter holes are not considered large by the PRA LERF definition

[17]; therefore, sequences with containment isolation valve failures are placed into Class 6 to represent a small isolation failure. This value was taken directly from the BVPS-2 PRA. The frequency per year for these sequences is obtained from the Release Categories BV05S, BV06S, BVO?S, and BV08S, as listed in Table 5-2. Class 7 Sequences.

This group consists of all core damage accident progression bins that result in containment failure induced by severe accident phenomena (e.g., overpressure).

At BVPS, this group is broken into containment failures that result in LERF, and those that do not. The frequency PRA-BV2-13-002-ROO Page 37 of 60 per year for the Class 7 LERF sequences is obtained from Release Categories BV01, BV01 S, BV02, BV02S, BV03, BV03S, BV04, and BV04S, as listed in Table 5-2. The frequency per year for the Class 7 non-LERF sequences is obtained from Release Categories BV05, BV06, BV07, BV08, BV09, BV09S, BV10, BV10S, BV11, BV11S, BV12, BV12S, BV13, BV13S, BV14, BV14S, BV15, BV15S, BV16, BV16S, BV17, and BV17S, as listed in Table 5-2. Class 8 Sequences.

This group consists of all core damage accident progression bins in which the containment is bypassed.

At BVPS, this group is broken into containment failures that result in LERF, and those that do not. The frequency per year for the Class 8 LERF sequences is obtained from Release Categories BV18 and BV19, as listed in Table 5-2. The frequency per year for the Class 8 non-LERF sequences is obtained from Release Category BV20, as listed in Table 5-2. 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-1 04285 the NEI Interim Guidance, and guidance provided in EPRI Report No. 1009325, Revision 2-A. Table 5-3 summarizes these accident frequencies by accident class for BVPS-2. Table 5*3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-2 Base Case) Total Frequency (per yr) Internal Events Frequency External Events Frequency Accident (peryr) (per yr) Classes (Cnmt. Description EPRI EPRI EPRI Release EPRI Methodology EPRI Methodology EPRI Methodology Type) Methodology Plus Methodology Plus Methodology Plus Corrosion Corrosion Corrosion 1 No Containment Failure 8.72E-07 8.71E-07 7.00E-07 7.00E-07 1.72E-07 1.72E-07 2 Large Isolation Failures N/A N/A N/A N/A N/A N/A (Failure to Close) 3a Small Isolation Failures (liner 1.52E-07 1.52E-07 3.75E-08 3.75E-08 1.15E-07 1.15E-07 breach) 3b Large Isolation Failures (liner 3.81E-08 3.82E-08 9.38E-09 9.42E-09 2.87E-08 2.88E-08 breach) Small Isolation Failures N/A N/A N/A N/A N/A N/A 4 (Failure to seal-Type B) Small Isolation Failures N/A N/A N/A N/A N/A N/A 5 (Failure to seal-Type C)

PRA-BV2-13-002-ROO Page 38 of 60 Table 5-3. Radionuclide Release Frequencies as a Function of Accident Class (BVPS-2 Base Case) Total Frequency (per yr) Internal Events Frequency External Events Frequency Accident (peryr) (per yr) Classes (Cnmt. Description EPRI EPRI EPRI Release EPRI Methodology EPRI Methodology EPRI Methodology Type) Methodology Plus Methodology Plus Methodology Plus Corrosion Corrosion Corrosion 6 Other Isolation Failures (e.g., small isolation valve failures) 4.00E-08 4.00E-08 2.35E-08 2.35E-08 1.65E-08 1.65E-08 7 non-Failures Induced by Phenomena (Early and Late 1.17E-05 1.17E-05 2.96E-06 2.96E-06 8.74E-06 8.74E-06 LERF non-LERF)

Failures Induced by 7 LERF Phenomena (Early and Late 1.92E-09 1.92E-09 5.32E-10 5.32E-10 1.39E-09 1.39E-09 LERF) 8 non-Containment Bypass (non-3.73E-06 3.73E-06 3.37E-07 3.37E-07 3.39E-06 3.39E-06 LERF LERF) 8 LERF Containment Bypass (LERF) 1.77E-07 1.77E-07 6.99E-08 6.99E-08 1.07E-07 1.07E-07 CDF All CET End states 1.67E-05 1.67E-05 4.14E-06 4.14E-06 1.26E-05 1.26E-05 5.2 STEP 2: DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR Plant-specific release analyses were performed to estimate the weighted average person-rem doses to the population within a 50-mile radius from the plant. The releases are based on a combination of the information provided by the BVPS SAMA analysis [19] and the Level 2 containment failure release frequencies and BVPS population dose risk developed in Section 4.2 of this analysis (see Table 4-7). The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with the guidance provided in EPRI Report No. 1009325, Revision 2-A. To determine the dose rates for EPRI accident Classes 3a and 3b, the population dose for EPRI accident Class 1 (assumed to be 1 La) is multiplied by the factors of 10 La and 100 La, respectively.

The results of applying these releases to the EPRI containment failure classifications are provided in Table 5-4. The population dose estimates derived for use in this risk evaluation per the EPRI methodology

[2] containment failure PRA-BV2-13-002-ROO Page 39 of 60 classifications are consistent with the NEI guidance [3] as modified by EPRI Report No. 1009325, Revision 2-A. Table 5*4. BVPS-2 Population Dose Estimates for Population Within 50 Miles Accident Classes Weighted Average Population Dose at 50 Miles (person-rem) (Containment Description Release Type) Total Internal Events External Events 1 No Containment Failure 8.00E+02 8.00E+02 8.00E+02 2 Large Isolation Failures (Failure to Close) N/A N/A N/A 3a Small Isolation Failures (liner breach) 8.00E+03 8.00E+03 8.00E+03 3b Large Isolation Failures (liner breach) 8.00E+04 8.00E+04 8.00E+04 4 Small Isolation Failures (Failure to seal-N/A N/A N/A Type B) 5 Small Isolation Failures (Failure to seal-N/A N/A N/A Type C) 6 Other Isolation Failures (e.g., small isolation 3.59E+06 3.60E+06 3.58E+06 valve failures) 7 non-LERF Failures Induced by Phenomena (Early and 1.95E+06 1.89E+06 1.97E+06 Late non-LERF) 7 LERF Failures Induced by Phenomena (Early and 8.24E+06 8.24E+06 8.24E+06 Late LERF) 8 non-LERF Containment Bypass (non-LERF) 4.26E+06 4.26E+06 4.26E+06 8 LERF Containment Bypass (LERF) 4.28E+06 4.30E+06 4.26E+06 The above dose estimates, when combined with the results presented in Table 5-3, yield the BVPS-2 baseline mean consequence measures for each accident class. These results are presented in Table 5-5 for the total BVPS-2 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

PRA-BV2-13-002-ROO Page 40 of 60 5.3 STEP 3: EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS The next step is to evaluate the risk impact of extending the test interval from its current ten-year value to fifteen-years.

To do this, an evaluation must first be made of the risk associated with the ten-year interval since the base case applies to a 3-year interval (i.e., a simplified representation of a 3-in-1 0 interval).

Risk Impact Due to 1 0-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 frequencies of Class 3a and 3b sequences are 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 1 0-year interval are presented in Table 5-5 for the total BVPS-2 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

Risk Impact Due to 15-Year Test Interval The risk contribution for a 15-year interval is calculated in a manner similar to the 1 0-year interval.

The difference is in the increase in probability of leakage in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the 3-year interval value, as described in Section 4.3. The results for this 15-year interval calculation are presented in Table 5-5 for the total BVPS-2 risk. Table 5-6 and Table 5-7 present the results for the internal and external events, respectively.

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. 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 core damage frequency (CDF) below 1.0E-06/yr and increases in LERF below 1.0E-07/yr, and small changes in LERF as below 1.0E-06/yr.

Because the ILRT does not impact CDF, the relevant metric is LERF. However, a sensitivity assessment of the impacts on CDF resulting from PRA-BV2-13-002-ROO Page 41 of 60 a loss of containment overpressure due to a large containment failure is provided in Section 6.4. For BVPS-2 100% 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).

The change in (Delta) LERF is determined using the equation below, where the "frequency of Class 3b frequency x" is the frequency of the EPRI accident Class 3b for the ILRT interval of interest and the "frequency of Class 3b baseline" is defined as the EPRI accident Class 3b frequency for ILRTs performed on a three-per-1 0-years basis.

= (frequency of Class 3b new interval x) -(frequency of Class 3b baseline)

Based on the original 3-in-1 0 year test interval assessment from Table 5-5, the total Class 3b frequency from both internal and external events is 3.82E-08/yr, which includes the corrosion effect of the containment liner. Based on a year test interval from Table 5-5, the total Class 3b frequency is 1.28E-07/yr; and, based on a fifteen-year test interval from Table 5-5, the total Class 3b frequency is 1.92E-07/yr, both of which include corrosion effects. Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years (including corrosion effects) is 1.54E-07/yr.

Similarly, the increase due to increasing the interval from 10 to 15 years is 6.46E-08/yr.

Table 5-6 and Table 5-7 present the Delta LERF results for the internal and external events, respectively.

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 the current 1 0-year requirement, and just above that criteria when compared to the original 3-year requirement, placing it into Region II of Figure 4 of RG 1.174 [4] (small changes in LERF). Approximately 25% of this change in LERF by increasing the ILRT test interval from 3 to 15 years (including corrosion effects) is due to internal events, while 75% is associated with external events. 5.5 STEP 5: DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY (CCFP) Another parameter that the NRC guidance in RG 1.174 states can provide input into the decision-making process is the change in the conditional containment failure probability (CCFP). The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can be calculated from the results of this analysis.

One of the difficult aspects of this calculation is providing a definition of the "failed containment." In this assessment, the CCFP is defined such that containment failure includes all radionuclide release end PRA-BV2-13-002-ROO Page 42 of 60 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 guidance [27]. Based on this guidance, the frequency of those sequences which result in no containment failure is determined by summing the Class 1 and Class 3a results. The NRC has previously accepted similar calculations

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

The change in total CCFP (including corrosion effects) from both internal and external events is calculated as follows: CCFP = [1 -(Class 1 frequency

+ Class 3a frequency)

I CDF]

• 100% CCFP3 = 93.87% CCFP1o = 94.41% CCFP1s = 94.80% b.CCFP = CCFP1o-CCFP 3 = 0.54% b.CCFP = CCFP1s-CCFP3 = 0.92% b.CCFP = CCFP1s-CCFP1o = 0.39% The total change in CCFP of slightly less than 1% by extending the test interval to 15 years from the original 3-in-1 0 year requirement is judged to be insignificant.

Table 5-5, Table 5-6, and Table 5-7 present the Delta CCDP results for the total, internal, and external events, respectively.

5.6

SUMMARY

OF RESULTS The results from this ILRT extension risk assessment for BVPS-2 are summarized in Table 5-5, Table 5-6, and Table 5-7 for the total, internal, and external events, respectively.

These tables provide a summary of the BVPS-2 base case, as well as the impact caused by corrosion.

The tables are divided into three columns representing the frequency of the ILRT: Base Case (3 per 10 years), Extended to 1 per 10 years, and Extended to 1 per 15 years. Each of the three columns is sub-divided further into corrosion and corrosion cases. For both the corrosion and non-corrosion cases, the frequencies of the EPRI accident classes (i.e., CDF) are provided.

In the corrosion cases, an additional column titled Dose Rate from Corrosion (person-rem per yr)" is provided.

The Dose Rate from Corrosion (person-rem per yr)" column provides the change in person-rem per year between the case with corrosion and the case without corrosion.

Negative values in this column indicate a reduction in the person-rem per year for the selected accident class. This occurs only in EPRI accident Class 1 and is a result of the reduction in the frequency of the accident Class 1 and an increase in accident Class 3b.

PRA-BV2-13-002-ROO Page 43 of 60 Negative values for the EPRI accident Class 1 "Frequency (per year)" and "Dose Rate (person-rem per year)" columns are also shown in Table 5-7 for the external event extended ILRT cases. These occur due to the increase in the Class 3a frequencies exceeding the external events Class 1 base (prior to revising) frequency of 3.15E-07/yr. (See Table 4-6 External Release Bin Frequency (per yr) for release bin BV21 ). Having these negative Class 1 frequencies preserves the BVPS-2 external events total release frequency (i.e., CDF) of 1.26E-05/yr.

A row for the totals, both frequency and dose rate, are provided on the tables. Additional summary rows are also provided.

• The change in dose rate (person-rem/year) and change as % of base total dose rate is provided below the "Total" row.

• The Conditional Containment Failure Probability (CCFP) is provided in the next row.

• The percentage point change in CCFP from the base case (LlCCFP) is provided in the next row.

• The Total LERF is provided in the next row.

• Followed by the Class 3b LERF row that indicates the accident Class 3b frequency, as well as the change in the Class 3b frequency in parentheses.

This difference is calculated between the non-corrosion and corrosion cases.

• The next row, titled "Delta LERF from Base Case (3 per 10 years)," provides the change in LERF as a function of ILRT frequency from the base case. The difference between the non-corrosion and corrosion cases is provided in parentheses.

• The last row of the table, titled "Delta LERF from 1 per 10 years" provides the change in LERF as a result of changing the ILRT frequency from one in 10 years to one in 15 years. The difference between the non-corrosion and corrosion cases is provided in parentheses.

Section 4.4 presents an estimate of the likelihood and risk implications of corrosion-induced leakage of steel containment liners not being detected during the extended ILRT test intervals evaluated in this report. The analysis considers ILRT extension time, inspections, and concealed degradation in uninspectable areas. As can be seen from the total risk results provided in Table 5-5, the change from the base case of three tests per 10 years to one test per 15 years with corrosion in LERF is small, 1.54E-07 (the change in LERF for the same period without corrosion was 1.52E-07).

The change in delta-LERF between the 15-year corrosion and non-corrosion cases is correspondingly very small, 2.00E-09.

Table 5-5. Summary of BVPS-2 Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact I Base Case (3 per 10 years) Extended to 1 per 10 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population A Dose A Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per {per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) year) vearl 1 8.00E-+{)2 8.72E-07 6.97E-04 8.71E-07 6.97E-04 -1.17E-07 4.27E-07 3.42E-04 4.26E-07 3.41E-04 -6.84E-07 1.10E-07 8.76E-05 1.08E-07 8.60E-05 3a 8.00E-+{)3 1.52E-07 1.22E-03 1.52E-07 1.22E-03 N/A 5.08E-07 4.06E-03 5.08E-07 4.06E-03 N/A 7.62E-07 6.10E-03 7.62E-07 6.10E-03 3b 8.00E-+{)4 3.81E-08 3.05E-03 3.82E-08 3.06E-03 1.17E-05 1.27E-07 1.02E-02 1.28E-07 1.02E-02 6.84E-05 1.90E-07 1.52E-02 1.92E-07 1.54E-02 6 3.59E-+{)6 4.00E-08 1.44E-01 4.00E-08 1.44E-01 N/A 4.00E-08 1.44E-01 4.00E-08 1.44E-01 N/A 4.00E-08 1.44E-01 4.00E-08 1.44E-01 7 non-1.95E-+{)6 1.17E-05 2.28E-+{)1 1.17E-05 2.28E-+{)1 N/A 1.17E-05 2.28E-+{)1 1.17E-05 2.28E-+{)1 N/A 1.17E-05 2.28E-+{)1 1.17E-05 2.28E-+{)1 LERF 7 8.24E-+{)6 1.92E-09 1.58E-02 1.92E-09 1.58E-02 N/A 1.92E-09 1.58E-02 1.92E-09 1.58E-02 N/A 1.92E-09 1.58E-02 1.92E-09 1.58E-02 LERF 8 non-4.26E-+{)6 3.73E-06 1.59E-+{)1 3.73E-06 1.59E-+{)1 N/A 3.73E-06 1.59E-+{)1 3.73E-06 1.59E-+{)1 N/A 3.73E-06 1.59E-+{)1 3.73E-06 1.59E-+{)1 LERF 8 4.28E-+{)6 1.77E-07 7.57E-01 1.77E-07 7.57E-01 N/A 1.77E-07 7.57E-01 1.77E-07 7.57E-01 N/A 1.77E-07 7.57E-01 1.77E-07 7.57E-01 LERF Total 1.67E-05 3.96E-+{)1 1.67E-05 3.96E-+{)1 1.16E-05 1.67E-05 3.96E-+{)1 1.67E-05 3.96E-+{)1 6.77E-05 1.67E-05 3.96E-+{)1 1.67E-05 3.96E-+{)1

!J. Dose Rate 9.60E-03 9.66E-03 1.65E-02 1.66E-02 (%A Dose Rate) N/A N/A (0.02%) (0.02%) (0.04%) (0.04%) CCFP 93.87% 93.87% 94.41% 94.41% 94.79% 94.80% !J.CCFP N/A N/A 0.53% 0.54% 0.91% 0.92% Total LERF 2.17E-07 2.17E-07 3.06E-07 3.07E-07 3.69E-07 3.71E-07 Class 3b LERF 3.82E-08 1.28E-07 1.92E-07 (A w/Corrosion) 3.81E-08 1.27E-07 1.90E-07 (1.47E-10)

(8.55E-10)

(2.00E-09)

Delta LERF from Base Case [3 per 10 years] 8.96E-08 1.54E-07 8.89E-08 1.52E-07 (A w/Corrosion)

(7.08E-10)

(1.85E-09)

Delta LERF from 1 per 1 0 years 6.46E-08 N/A 6.35E-08 (A w/Corrosion)

(1.14E-09)

---

A Dose Rate from Corrosion (person-rem per year)_ -1.60E-06 N/A 1.60E-04 N/A N/A N/A N/A N/A 1.58E-04 --I -o JJ )> ' OJ Ill ' co ...... rot.U +>-6 .j:>-0 -o.JJ 0> 0 00 Table 5-6. Summary of BVPS-21nternal Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 10 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population

!!.Dose !!. Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) year) year) 1 8.00E-+{)2 7.00E.{)7 5.60E.{)4 7.00E.{)7 5.60E.{)4

-2.89E.{)8 5.90E.{)7 4.72E.{)4 5.90E.{)7 4.72E.{)4

-1.68E.{)7 5.12E.{)7 4.10E.{)4 5.12E.{)7 4.09E.{)4 3a 8.00E-+{)3 3.75E.{)8 3.00E.{)4 3.75E.{)8 3.00E.{)4 N/A 1.25E.{)7 1.00E.{)3 1.25E.{)7 1.0QE.{)3 N/A 1.88E.{)7 1.50E.{)3 1.88E.{)7 1.50E.{)3 3b 8.00E-+{)4 9.38E.{)9 7.50E.{)4 9.42E.{)9 7.53E.{)4 2.89E.{)6 3.13E.{)8 2.50E.{)3 3.15E.{)8 2.52E.{)3 1.68E.{)5 4.69E.{)8 3.75E.{)3 4.74E.{)8 3.79E.{)3 6 3.60E-+{)6 2.35E.{)8 8.44E.{)2 2.35E.{)8 8.44E.{)2 N/A 2.35E.{)8 8.44E.{)2 2.35E.{)8 8.44E.{)2 N/A 2.35E.{)8 8.44E.{)2 2.35E.{)8 8.44E.{)2 7 non-1.89E-+{)6 2.96E.{)6 5.59E-+{)0 2.96E.{)6 5.59E-+{)0 N/A 2.96E.{)6 5.59E-+{)0 2.96E.{)6 5.59E-+{)0 N/A 2.96E.{)6 5.59E-+{)0 2.96E.{)6 5.59E-+{)0 LERF 7 8.24E-+{)6 5.32E-10 4.38E.{)3 5.32E-10 4.38E.{)3 N/A 5.32E-10 4.38E.{)3 5.32E-10 4.38E.{)3 N/A 5.32E-10 4.38E.{)3 5.32E-10 4.38E.{)3 LERF 8 non-4.26E-+{)6 3.37E.{)7 1.44E-+{)0 3.37E.{)7 1.44E-+{)0 N/A 3.37E.{)7 1.44E-+{)0 3.37E.{)7 1.44E-+{)0 N/A 3.37E.{)7 1.44E-+{)0 3.37E.{)7 1.44E-+{)Q LERF 8 4.30E-+{)6 6.99E.{)8 3.00E.{)1 6.99E.{)8 3.00E.{)1 N/A 6.99E.{)8 3.00E.{)1 6.99E.{)8 3.00E.{)1 N/A 6.99E.{)8 3.00E.{)1 6.99E.{)8 3.00E.{)1 LERF Total 4.14E.{)6 7.42E-+{)0 4.14E.{)6 7.42E-+{)0 2.86E.{)6 4.14E.{)6 7.42E-+{)0 4.14E.{)6 7.42E-+{)0 1.67E.{)5 4.14E.{)6 7.42E-+{)0 4.14E.{)6 7.42E-+{)0 l:J.Dose Rate 2.36E.{)3 2.38E.{)3 4.05E.{)3 4.09E.{)3

(%!!.Dose Rate) N/A N/A (0.03%) (0.03%) (0.05%) (0.06%) CCFP 82.19% 82.19% 82.72% 82.73% 83.10% 83.11% l:J.CCFP N/A N/A 0.53% 0.53% 0.91% 0.92% Total LERF 7.98E.{)8 7.98E.{)8 1.02E.{)7 1.02E.{)7 1.17E.{)7 1.18E.{)7 Class 3b LERF 9.42E.{)9 3.15E.{)8 4.74E.{)8 9.38E.{)9 3.13E.{)8 4.69E.{)8

{!!. w/Corrosion)

(3.62E-11)

(2.11E-10)

(4.92E-10)

Delta LERF from Base Case [3 per 10 years] 2.21E.{)8 3.80E.{)8 2.19E.{)8 3.75E.{)8

(!!. w/Corrosion)

(1.74E-10)

(4.56E-10)

Delta LERF from 1 per 10 years 1.59E.{)8 N/A 1.56E.{)8

(!!. w/Corrosion)

(2.81E-10)

-!!.Dose Rate from Corrosion (person-rem per vearl -3.93E.{)7 N/A 3.93E.{)5 N/A N/A N/A N/A N/A 3.89E.{)5 "U :D 1> OJ Ill ' <C ...... coW .j:>.b 010 or:-' -::n CJ) 0 00 Table 5-7. Summary of BVPS-2 External Events Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 10 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion Wrth Corrosion EPRI Population ll Dose ll Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) {per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per {person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) vear) year) 1 8.00E-+{)2 1.72E-07 1.37E-04 1.72E-07 1.37E-04 -8.86E-08

-1.63E-07

-1.31E-04

-1.64E-07

-1.31E-04

-5.16E-07

-4.03E-07

-3.22E-04

-4.04E-07

-3.23E-04 3a 8.00E-+{)3 1.15E-07 9.19E-04 1.15E-07 9.19E-04 N/A 3.83E-07 3.06E-03 3.83E-07 3.06E-03 N/A 5.74E-07 4.60E-03 5.74E-07 4.60E-03 3b 8.00E-+{)4 2.87E-08 2.30E-03 2.88E-08 2.31E-03 8.86E-06 9.57E-08 7.66E-03 9.64E-08 7.71E-03 5.16E-05 1.44E-07 1.15E-02 1.45E-07 1.16E-02 6 3.58E-+{)6 1.65E-08 5.91E-02 1.65E-08 5.91E-02 N/A 1.65E-08 5.91E-02 1.65E-08 5.91E-02 N/A 1.65E-08 5.91E-02 1.65E-08 5.91E-02 7 non-1.97E-+{)6 8.74E-06 1.72E-+{)1 8.74E-06 1.72E-+{)1 N/A 8.74E-06 1.72E-+{)1 8.74E-06 1.72E-+{)1 N/A 8.74E-06 1.72E-+{)1 8.74E-06 1.72E-+{)1 LERF 7 8.24E-+{)6 1.39E-09 1.15E-02 1.39E-09 1.15E-02 N/A 1.39E-09 1.15E-02 1.39E-09 1.15E-02 N/A 1.39E-09 1.15E-02 1.39E-09 1.15E-02 LERF 8 non-4.26E-+{)6 3.39E-06 1.45E-+{)1 3.39E-06 1.45E-+{)1 N/A 3.39E-06 1.45E-+{)1 3.39E-06 1.45E-+{)1 N/A 3.39E-06 1.45E-+{)1 3.39E-06 1.45E-+{)1 LERF 8 4.26E-+{)6 1.07E-07 4.57E-01 1.07E-07 4.57E-01 N/A 1.07E-07 4.57E-01 1.07E-07 4.57E-01 N/A 1.07E-07 4.57E-01 1.07E-07 4.57E-01 LERF Total 1.26E-05 3.22E-+{)1 1.26E-05 3.22E-+{)1 8.77E-06 1.26E-05 3.22E-+{)1 1.26E-05 3.22E-+{)1 5.11E-05 1.26E-05 3.22E-+{)1 1.26E-05 3.22E-+{)1 1!. Dose Rate 7.24E-03 7.28E-03 1.24E-02 1.25E-02 (%/l Dose Rate) N/A N/A (0.02%) (0.02%) (0.04%) (0.04%) CCFP 97.72% 97.72% 98.25% 98.26% 98.63% 98.65% l!.CCFP N/A N/A 0.53% 0.54% 0.91% 0.92% Total LERF 1.37E-07 1.37E-07 2.04E-07 2.05E-07 2.52E-07 2.54E-07 Class 3b LERF 2.88E-08 9.64E-08 1.45E-07 2.87E-08 9.57E-08 1.44E-07 (ll w/Corrosion)

(1.11E-10)

(6.45E-10)

(1.51E-09)

Delta LERF from Base Case [3 per 10 years] 6.75E-08 1.16E-07 6.70E-08 1.15E-07 (ll w/Corrosion)

(5.34E-10)

(1.40E-09)

Delta LERF from 1 per 10 years 4.87E-08 N/A 4.79E-08 (ll w/Corrosion)

(8.61E-10) ll Dose Rate from Corrosion (person-rem per year) -1.20E-06 N/A 1.20E-04 N/A N/A N/A N/A N/A 1.19E-04 ' -u :D 1> OJ < "'UI\J Ill ' co ...... m'f """0 cno -:n CJ) 0 00

6. SENSITIVITIES PRA-BV2-13-002-ROO Page 47 of 60 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS The results in Tables 5-5, 5-6 and 5-7 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, assuming that the first year failure rates for the cylinder and dome start out as the baseline value presented in Section 4.4 as 2.5E-03/yr and the basemat starts out as the baseline value of 5.12E-04/yr.

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% for the cylinder and dome, while keeping the basemat at the baseline 100% value. Additionally, both a lower and upper bound sensitivity were performed by biasing all sensitivity parameters to their lower or upper values. The results of the increase in total Class 3b frequency from both internal and external events are presented in Table 6-1. In every case the impact from including the corrosion effects is very minimal. Even the upper bound estimates with very conservative assumptions for all of the key parameters yield increases in LERF due to corrosion of only 2.55E-07/yr.

The results indicate that even with very conservative assumptions, the conclusions from the base analysis would not change. Table 6*1. Steel Liner Corrosion Sensitivity Cases Containment Increase in Class 3b Frequency Age Breach Visual Inspection

& (LERF) for ILRT Extension 3 to 15 (Step 3 in the Non-Visual Flaws years (per yr) (Step 4 in the corrosion (Step 5 in the analysis) corrosion corrosion analysis)

Increase Due to analysis)

Total Increase Corrosion Base Case Base Case Base Case Doubles every 5 {1% Cylinder, {1 0% Cylinder, 1.54E-07 1.85E-09 yrs 0.1% Basemat) 1 00% Basemat) Doubles every 2 yrs Base Base 1.71 E-07 1.82E-08 Doubles every 10 yrs Base Base 1.53E-07 9.38E-1 0 Table 6-1. Steel Liner Corrosion Sensitivity Cases Containment Age Breach Visual Inspection

& (Step 3 in the Non-Visual Flaws (Step 4 in the corrosion (Step 5 in the analysis) corrosion corrosion analysis) analysis)

Base Base 15% Cylinder, 100% Basemat Base Base 5% Cylinder, 1 00% Basemat Base 1 0% Cylinder, Base 1% Basemat Base 0.1% Cylinder, Base 0.01% Basemat Lower Bound Doubles every 10 0.1% Cylinder, 5% Cylinder, yrs 0.01% Basemat 1 00% Basemat Upper Bound Doubles every 2 1 0% Cylinder, 15% Cylinder, yrs 1% Basemat 1 00% Basemat PRA-BV2-13-002-ROO Page 48 of 60 Increase in Class 3b Frequency (LERF) for ILRT Extension 3 to 15 years (per yr) Increase Due to Total Increase Corrosion 1.55E-07 2.58E-09 1.54E-07 1.11 E-09 1.71 E-07 1.85E-08 1.53E-07 1.85E-10 1.52E-07 5.63E-11 4.08E-07 2.55E-07 6.2 EPRI EXPERT ELICITATION LEAKAGE SENSITIVITY An expert elicitation was performed to reduce excess conservatisms in the data associated with the probability of undetected leaks within containment

[27]. Since the risk impact assessment of the extensions to the ILRT interval is sensitive to both the probability of the leakage as well as the magnitude, it was decided to perform the expert elicitation in a manner to solicit the probability of leakage as a function of leakage magnitude.

In addition, the elicitation was performed for a range of failure modes which allowed experts to account for the range of failure mechanisms, the potential for undiscovered mechanisms, inaccessible areas of the containment, as well as the potential for detection by alternate means. The expert elicitation process has the advantage of considering the available data for small leakage events, which have occurred in the data, and extrapolate those events and probabilities of occurrence to the potential for large magnitude leakage events.

PRA-BV2-13-002-ROO Page 49 of 60 The basic difference in the application of the ILRT interval methodology using the expert elicitation is a change in the probability of pre-existing leakage within containment.

The base case methodology uses the Jeffrey's non-informative prior for the large leak size and the expert elicitation sensitivity study uses the results from the expert elicitation.

In addition, given the relationship between leakage magnitude and probability, larger leakage that is more representative of large early release frequency can be reflected.

For the purposes of this sensitivity, the same leakage magnitudes that are used in the base case methodology (i.e., 10 La for small Class 3a and 100 La for large Class 3b) are used here. Table 6-2 illustrates the magnitudes and probabilities of a pre-existing leak in containment associated with the base case and the expert elicitation statistical treatments.

These values are used in the ILRT interval extension for the base methodology and in this sensitivity case. Details of the expert elicitation process, including the input to expert elicitation as well as the results of the expert elicitation, are available in the various appendices of EPRI TR-1 018243 [27]. Table D-1 from this reference presents the results of the analysis of the expert elicited input. The expert elicitation mean probability of occurrence results for the 1 0 La, 1 00 La, and 1000 La leakage sizes, are shown in Table 6-2, below. Table 6*2. EPRI Expert Elicitation Results Leakage Size (La) Base Case Expert Elicitation Mean Percent Reduction Probability of Occurrence 10 9.2E-03 3.88E-03 58% 100 2.3E-03 2.47E-04 89% 1000 N/A 4.50E-06 N/A The summary of results using the expert elicitation values for probability of containment leakage is provided in Table 6-3. As mentioned previously, probability values are those associated with the magnitude of the leakage used in the base case evaluation (1 0 La for small Class 3a, and 100 La for large Class 3b). The expert elicitation process produces a relationship between probability and leakage magnitude in which it is possible to assess higher leakage magnitudes that are more reflective of large early releases; however, these evaluations are not performed in this particular study. The net effect is that the reduction in the multipliers shown above has the same impact on the calculated increases in the LEAF values. The increase in the overall value for LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years is 1.82E-08/yr.

Similarly, the increase due to increasing the interval from 10 to 15 years is 7.95E-09/yr.

As such, if the expert elicitation mean probabilities of occurrence are used instead of the non-informative prior estimates, the change in LERF for BVPS-2 is within the range of a "very small" PRA-BV2-13-002-ROO Page 50 of 60 change in risk when compared to the current 1-in-1 0, or baseline 3-in-1 0 year requirement.

The results of this sensitivity study are judged to be more indicative of the actual risk associated with the ILRT extension than the results from the assessment as dictated by the values from the EPRI methodology

[27], and yet are still conservative given the assumption that all of the Class 3b contribution is considered to be LERF.

Table 6-3. BVPS-2 Total Risk for ILRT Base Case, 10, and 15 Year Extensions (Based on EPRI Expert Elicitation Leakage Probabilities)

Base Case (3 per 10 years) Extended to 1 per 1 0 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population tJ.Dose tJ.Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per year) year) rem per year) year) rem per year) year) vearl vearl 1 8.0QE-+{J2 9.94E-07 7.95E-04 9.94E-07 7.95E-04 -1.17E-07 8.35E-07 6.68E-04 8.34E-07 6.67E-04 -6.84E-07 7.21E-07 5.77E-04 7.19E-07 5.75E-04 3a 8.00E-+{J3 6.42E-08 5.13E-04 6.42E-08 5.13E-04 N/A 2.14E-07 1.71E-03 2.14E-07 1.71E-03 N/A 3.21E-07 2.57E-03 3.21E-07 2.57E-03 3b 8.00E-+{J4 4.08E-09 3.27E-04 4.23E-09 3.38E-04 1.17E-05 1.36E-08 1.09E-03 1.45E-08 1.16E-03 6.84E-05 2.04E-08 1.63E-03 2.24E-08 1.79E-03 6 3.59E-+{J6 4.00E-08 1.44E-01 4.00E-08 1.44E-01 N/A 4.00E-08 1.44E-01 4.00E-08 1.44E-01 N/A 4.00E-08 1.44E-01 4.00E-08 1.44E-01 7 non-1.95E-+{J6 1.17E-05 2.28E-+{J1 1.17E-05 2.28E-+{J1 N/A 1.17E-05 228E-+{J1 1.17E-05 228E-+{J1 N/A 1.17E-05 228E-+{J1 1.17E-05 2.28E-+{J1 LERF 7 8.24E-+{J6 1.92E-09 1.58E-02 1.92E-09 1.58E-02 N/A 1.92E-09 1.58E-02 1.92E-09 1.58E-02 N/A 1.92E-09 1.58E-02 1.92E-09 1.58E-02 LERF 8 non-4.26E-+{J6 3.73E-06 1.59E-+{J1 3.73E-06 1.59E-+{J1 N/A 3.73E-06 1.59E-+{J1 3.73E-06 1.59E-+{J1 N/A 3.73E-06 1.59E-+{J1 3.73E-06 1.59E-+{J1 LERF 8 4.28E-+{J6 1.77E-07 7.57E-01 1.77E-07 7.57E-01 N/A 1.77E-07 7.57E-01 1.77E-07 7.57E-01 N/A 1.77E-07 7.57E-01 1.77E-07 7.57E-01 LERF Total 1.67E-05 3.96E-+{J1 1.67E-05 3.96E-+{J1 1.16E-05 1.67E-05 3.96E-+{J1 1.67E-05 3.96E-+{J1 6.77E-05 1.67E-05 3.96E-+{J1 1.67E-05 3.96E-+{J1 D. Dose Rate 1.83E-03 1.89E-03 3.14E-03 3.29E-03 Rate) N/A N/A (0.00%) (0.00%) (0.01%) (0.01%) CCFP 93.67% 93.67% 93.73% 93.73% 93.77% 93.78% D. CCFP N/A N/A 0.06% 0.06% 0.10% 0.11% Total LERF 1.83E-07 1.83E-07 1.93E-07 1.93E-07 1.99E-07 2.01E-07 Class 3b LERF 4.23E-09 1.45E-08 2.24E-08 4.08E-09 1.36E-08 2.04E-08 w/Corrosion)

(1.47E-10)

(8.55E-10)

(2.00E-09)

Delta LERF from Base Case [3 per 10 years] 1.02E-08 1.82E-08 9.53E-09 1.63E-08 (tJ. w/Corrosion)

(7.08E-10)

(1.85E-09)

Delta LERF from 1 per 10 years 7.95E-09 N/A 6.81E-09 w/Corrosion)

(1.14E-09)

---

tJ. Dose Rate from Corrosion (person-rem per vearl -1.60E-06 N/A 1.60E-04 N/A N/A N/A N/A N/A 1.58E-04 "U :D =!> OJ < "UN Ill ' (() ...... co'f (]10 ...... o I\) 0 ' -:c en o 00 PRA-BV2-13-002-ROO Page 52 of 60 6.3 POTENTIAL IMPACT FROM LOSS OF CONTAINMENT OVERPRESSURE The EPRI guidance [27] states that for those plants that credit containment overpressure for the mitigation of design basis accidents, a brief description of whether overpressure is required should be included, as well as a discussion of the combined impacts from the ILRT extension on CDF and LERF, and comparison with the RG 1.174 acceptance guidelines.

At BVPS-2, mitigation of design basis accidents rely on containment overpressure in the calculation of available NPSH for the recirculation spray (RSS) pumps when taking suction from the containment sump. The EPRI guidance [27] suggests that as a first order estimate of the impact, it can be assumed that the EPRI Class 3b contribution would lead to loss of containment overpressure and the systems that require this contribution for available NPSH should be made unavailable when such an isolation failure exists. To model the impact of a loss of containment overpressure due to a large existing containment liner leak in the BV2REV5A PRA, the EPRI Class 3b leakage probability for the various ILRT test intervals were added to the PRA model's baseline unavailability of the containment sump to provide an adequate source of water (i.e., available NPSH); thereby, failing the RSS pumps. The Class 3b leakage probability for the various ILRT test intervals, including aging and corrosion effects, that were added to the containment sump unavailability are derived from Sections 4.3 and 4.4, and are summarized in Table 6-4. Table 6-4. Containment Overpressure Adjustment Factors ILRT Test Interval Class 3b Leakage Probability Class 3b Leakage Probability without Corrosion with Corrosion 3-in-1 0 years 2.30E-03 2.30E-03 + 8.88E-06 = (Baseline) 2.31 E-03 1-in-1 0 years 2.30E-03

• 3.33 = 2.30E-03

• 3.33 + 5.17E-05 = 7.68E-03 7.73E-03 1-in-15 years 2.30E-03

• 5.0 = 2.30E-03

• 5.0 + 1.21 E-04 = 1.15E-02 1.16E-02 The results of this loss of containment overpressure assessment on the total CDF and total LERF from all internal and external events (including aging and corrosion effects) are presented in Table 6-5. As shown in Table 6-5, the total EPRI Class frequency (i.e., total CDF) goes from 1.69E-05/yr for the baseline 3-in-1 0 year ILRT case to 1.750E-05/yr for the 1-in-15 year extended ILRT case, even when including corrosion impacts. This PRA-BV2-13-002-ROO Page 53 of 60 represents a change in CDF of 6.02E-07/yr, which is well below the acceptance guidelines from RG 1.174 for very small changes in CDF and confirms that the impact on CDF from the ILRT extension is negligible.

The increase in LERF resulting from the increase in Class 3b leakage from a large liner breech (including corrosion effects) and subsequent loss of containment overpressure, due to the change in ILRT testing frequency from three in 10 years to one in 15 years is estimated as 1.63E-07/yr, with a corresponding total LERF of 3.80E-07/yr.

Based on RG 1.174, this meets the LERF threshold criteria for determining that the risk impact of extending the ILRT to one in 15 years is still small. It should also be noted in Table 6-5, that there are slight changes in the dose rates for more than just the Class 1 and Class 3b sequences due to the corrosion impacts. The reasoning for this is that the corrosion also impacts the RSS pumps availability, as well as the CDF, which in turn alters the release bin frequencies of these other classes. This assessment is considered to be extremely conservative since the 100 La leakage rate from the EPRI Class 3b scenarios is not likely to be of sufficient size to actually result in the loss of containment overpressure required for the RSS pumps' NPSH, based on an evaluation that was performed as part of the BVPS-2 LAR to credit containment overpressure

[25]. This evaluation shows that there is no significant impact on the RSS pumps' available NPSH by up to a 2-inch diameter hole in the containment building, which is considered to be the maximum containment hole size that will not result in LERF [17]. Since the minimum containment penetration size that can result in LERF is determined by the release of 100% of the containment volume per day at design pressure, it equates to about 1000 La or 10 times the assumed Class 3b leakage of 100 La. Therefore, the available NPSH for pumps taking suction from the containment sump should not be impacted unless the leakage exceeds 1000 La or 10 times the assumed Class 3b leakage. Based on the results of the EPRI expert elicitation

[27] provided in Table 6.2 of this analysis, the mean probability of occurrence of having a leakage size of 1000 La is about 55 times less likely to occur then having the assumed 3b leakage of 100 La.

Table 6-5. BVPS-2 Loss of Containment Overpressure Total Risk for ILRT Base Case, 10, and 15 Year Extensions, Including Corrosion Impact Base Case (3 per 10 years) Extended to 1 per 10 years Extended to 1 per 15 years Weighted Average Without Corrosion With Corrosion Without Corrosion With Corrosion Without Corrosion With Corrosion EPRI Population

!!.Dose !!.Dose !!.Dose Dose at Class 50 Miles Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from Dose Rate Dose Rate Rate from (person-Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion Frequency (person-Frequency (person-Corrosion rem) (per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-(per year) rem per (per year) rem per (person-year) year) rem per year) year) rem per year) year) rem per yearl year) year) 1 8.00E-+02 8.67E.{)7 6.94E.{)4 8.67E.{)7 6.94E.{)4

-2.03E.{)7 4.00E.{)7 3.20E.{)4 3.99E.{)7 3.19E.{)4

-8.86E-07 5.45E.{)8 4.36E.{)5 5.18E.{)8 4.14E.{)5

-2.19E.{)6 3a 8.00E-+03 1.54E.{)7 1.23E.{)3 1.54E.{)7 1.23E.{)3 3.69E.{)8 5.23E.{)7 4.19E.{)3 5.23E.{)7 4.19E.{)3 8.07E.{)7 7.96E.{)7 6.37E.{)3 7.97E.{)7 6.37E.{)3 2.86E.{)6 3b 8.00E-+04 3.84E.{)8 3.08E.{)3 3.86E.{)8 3.09E.{)3 1.19E.{)5 1.31E.{)7 1.05E.{)2 1.32E.{)7 1.05E.{)2 7.25E.{)5 1.99E.{)7 1.59E.{)2 2.01E.{)7 1.61E.{)2 1.74E.{)4 6 3.59E-+06 4.02E.{)8 1.44E.{)1 4.02E.{)8 1.44E.{)1 4.63E.{)6 4.06E.{)8 1.46E.{)1 4.06E.{)8 1.46E.{)1 1.54E.{)5 4.10E.{)8 1.47E.{)1 4.10E.{)8 1.47E.{)1 4.01E.{)5 7 non-1.95E-+06 1.19E.{)5 2.31E-+01 1.19E.{)5 2.31E-+01 1.17E.{)3 1.22E.{)5 2.38E-+01 1.22E.{)5 2.38E-+01 6.58E.{)3 1.25E.{)5 2.43E-+01 1.25E.{)5 2.43E-+01 1.55E.{)2 LERF 7 8.24E-+06 1.92E.{)9 1.58E.{)2 1.92E.{)9 1.58E.{)2 1.65E.{)9 1.92E.{)9 1.58E.{)2 1.92E.{)9 1.58E.{)2 4.86E.{)9 1.92E.{)9 1.59E.{)2 1.92E.{)9 1.59E.{)2 1.48E.{)8 LERF 8 non-4.26E-+06 3.73E.{)6 1.59E-+01 3.73E.{)6 1.59E-+01 0 3.73E.{)6 1.59E-+01 3.73E.{)6 1.59E-+01 0 3.73E.{)6 1.59E-+01 3.73E.{)6 1.59E-+01 0 LERF 8 4.28E-+06 1.77E.{)7 7.57E.{)1 1.77E.{)7 7.57E.{)1 0 1.77E.{)7 7.57E.{)1 1.77E.{)7 7.57E.{)1 0 1.77E.{)7 7.57E.{)1 1.77E.{)7 7.57E.{)1 0 LERF Total 1.69E.{)5 3.99E-+01 1.69E.{)5 3.99E-+01 1.18E.{)3 1.72E.{)5 4.06E-+01 1.72E.{)5 4.06E-+01 6.67E.{)3 1.75E.{)5 4.11E-+01 1.75E.{)5 4.11E-+01 1.57E.{)2 11 Dose Rate 6.96E.{)1 7.02E.{)1 1.20E-+OO 1.21E-+OO N/A N/A (%!!.Dose Rate) (1.75%) (1.76%) (3.00%) (3.03%) CCFP 93.94% 93.95% 94.64% 94.64% 95.13% 95.14% 11 CCFP N/A N/A 0.69% 0.70% 1.18% 1.20% Total LERF 2.17E.{)7 2.18E.{)7 3.10E.{)7 3.11E.{)7 3.78E.{)7 3.80E.{)7 Class 3b LERF 3.86E.{)8 1.32E.{)7 2.01E.{)7 3.84E.{)8 1.31E.{)7 1.99E.{)7

(!!. w/Corrosion)

(1.49E-10)

(9.06E-10)

(2.18E-09)

Delta LERF from Base Case [3 per 10 years) 9.31E.{)8 1.63E.{)7 9.24E.{)8 1.61E.{)7

(!!. w/Corrosion)

(7.57E-10)

(2.03E-09)

Delta CDF from Base Case [3 per 10 years] 3.49E.{)7 6.02E.{)7 3.46E.{)7 5.95E.{)7

(!!. w/Corrosion)

(2.78E.{)9)

(7.27E-09)

---

"U :IJ :t> 0 OJ Ill 0 !C ...... coc:.u 016 -1>-0 -:IJ 0)0 00

7. CONCLUSIONS PRA-BV2-13-002-ROO Page 55 of 60 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 fifteen years:

• RG 1.174 [4] provides guidance for determining the risk impact of specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF below 1.0E-06/yr and increases in LERF below 1.0E-07/yr.

Since the ILRT extension was demonstrated in Section 6.3 to have a very small impact on the total (internal plus external)

CDF for BVPS-2 resulting from the loss of containment overpressure, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval from three in ten years to one in fifteen years with corrosion included is 3.80E-08/yr (see Table 5-6), which falls within the very small change region of the acceptance guidelines in RG 1.174.

• RG 1.174 also states that when the calculated increase in LERF is in the range of 1.0E-06 per reactor year to 1.0E-07 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than 1.0E-05 per reactor year. When the external events contribution is also considered, the increase in total LERF including corrosion goes to 1.54E-07/yr, with an associated total LERF of 3.71 E-07/yr (see Table 5-5). As such, the estimated change in total LERF is determined to be small using the acceptance guidelines of RG 1.174, and is well below the RG 1.174 acceptance criteria for total LERF of 1.0E-05. However, if the EPRI Expert Elicitation methodology is used, the change in total LERF is estimated as 1.82E-08/yr (see Table 6-3), which falls back within the very small change region.

• The change in the total 50-mile population dose risk from changing the Type A test frequency to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all accident sequences, is 1.66E-02 rem/yr using the EPRI guidance with the base case corrosion case (see Table 5-5). The change in dose risk increases to 1.21 E+OO person-rem/yr when including the impact from a loss of containment overpressure (see Table 6-5). However, only 1.30E-02 person-rem/yr is attributed to the increase in the Class 3b population dose, while 1.19 person-rem/yr (2.43E+01 minus 2.31 E+01) is due to the increase in the Class 7 non-LERF frequency.

EPRI Report No. 1009325, Revision 2-A [27] states that a very small population dose is defined as an increase of s; 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.

PRA-BV2-13-002-ROO Page 56 of 60

• The increase in the conditional containment failure probability from the three in ten year interval to one in fifteen year interval including corrosion is 0.92% (see Table 5-5), and increases to 1.20% when including the loss of containment overpressure impact (see Table 6-5). EPRI Report No. 1009325, Revision 2-A states that increases in CCFP of $1.5 percentage points are very small. Therefore this increase judged to be very small. Therefore, increasing the ILRT interval on a permanent basis to one in 15 years is not considered to be significant since it represents only a small change to the BVPS-2 risk profile when considering both internal and external events with corrosion and loss of containment overpressure impacts. Furthermore, the use of the EPRI Class 3b probability is judged to be very conservative because the BVPS containment buildings operate at a slightly sub-atmospheric pressure.

In plants without a sub-atmospheric containment, pre-existing leaks in lines connected to the containment atmosphere have been shown to be an important contributor to the loss of containment isolation and large, early release frequency.

These leaks are mostly associated with valves being inadvertently left open upon rise to power after shutdown, but could also be due to undetected large liner breeches (i.e., EPRI Class 3b). This condition is not likely to be important at Beaver Valley Units 1 and 2 for the following reasons:

• There is a technical specification limit on containment pressure during operation.

BVPS Technical Specification LCO 3.6.4 [18] states that containment pressure shall be 2: 12.8 psia and $ 14.2 psia.

• Technical Specification SR 3.6.4.1 [18] verifies that containment pressure is within the above limits every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

The EPRI methodologies

[27] to determine the increase in LEAF and population dose for an ILRT interval extension are based on the assumption of increased undetected pre-existing leakage associated with an atmospheric containment, which is not assumed for a sub-atmospheric containment design since existing leakage would be detectable by changes in containment vacuum. Therefore, the use of the EPRI Class 3b probability in the BVPS-2 ILRT extension risk assessment results in conservatively overstating the increase in the LEAF, and it is believed that the use of the EPRI Expert Elicitation methodology is more indicative of the true change in total LEAF, which falls within the very small change region. Previous Assessments The NRC in NUREG-1493

[6] has previously concluded that:

PRA-BV2-13-002-ROO Page 57 of 60

• Reducing the frequency of Type A tests (ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type 8 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 BVPS-2 confirm these general findings on a plant specific basis considering the severe accidents evaluated for BVPS-2, the BVPS-2 containment failure modes, and the local population surrounding BVPS.

8. REFERENCES PRA-BV2-13-002-ROO Page 58 of 60 [1] Nuclear Energy Institute, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," NEI 94-01, Revision 3-A, July 2012. [2] Electric Power Research Institute, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," EPRI TR-1 04285, August 1994. [3] "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals," Rev. 4, Developed for NEI by EPRI and Data Systems and Solutions, November 2001. [4] U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Regulatory Guide 1.174, Revision 2, May 2011. [5] "Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension," Letter from Mr. C. H. Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No. 50-317, March 27, 2002. [6] U.S. Nuclear Regulatory Commission, "Performance-Based Containment Leak-Test Program," NUREG-1493, September 1995. [7] U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Informed Activities," Regulatory Guide 1.200, Revision 1, January 2007. [8] Letter from R. J. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-007, January 18, 2001. [9] U.S. Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No. 3 -Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing (TAC No. MB0178), April 17, 2001. [1 0] Oak Ridge National Laboratory, "Impact of Containment Building Leakage on LWR Accident Risk," NUREG/CR-3539, ORNL/TM-8964, April 1984. [11] Pacific Northwest Laboratory, "Reliability Analysis of Containment Isolation Systems," NUREG/CR-4220, PNL-5432, June 1985. [12] U.S. Nuclear Regulatory Commission, "Technical Findings and Regulatory Analysis for Generic Safety Issue II.E.4.3 'Containment Integrity Check'," NUREG-1273, April 1988.

PRA-BV2-13-002-ROO Page 59 of 60 [13] Pacific Northwest Laboratory, "Review of Light Water Reactor Regulatory Requirements," NUREG/CR-4330, PNL-5809, Vol. 2, June 1986. [14] Electric Power Research Institute, "Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMŽ," TR-1 05189, Final Report, May 1995. [15] U.S. Nuclear Regulatory Commission, "Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants," NUREG-1150, December 1990. [16] U.S. Nuclear Regulatory Commission, "Reactor Safety Study, an Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," WASH-1400, October 1975. [17] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Unit 2, PRA Notebooks for PRA-BV2-AL-R05a, August 31, 2012. [18] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Units 1 and 2, Technical Specifications, Unit 1 Docket No. 50-334, License No. DPR-66, Unit 2 Docket No. 50-412, License No. NPF-73. [19] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station Units 1 & 2, License Renewal Application, Appendix E -Environmental Report, Unit 1 Docket No. 50-334, Unit 2 Docket No. 50-412. [20] Anthony R. Pietrangelo, "One-time extensions of containment integrated leak rate test interval -additional information," NEI letter to Administrative Points of Contact, November 30, 2001. [21] Letter from J.A. Hutton (Exelon, Peach Bottom) to U.S. Nuclear Regulatory Commission, Docket No. 50-278, License No. DPR-56, LAR-01-00430, dated May 30, 2001. [22] Risk Assessment for Joseph M. Farley Nuclear Plant Regarding ILRT (Type A) Extension Request, prepared for Southern Nuclear Operating Co. by ERIN Engineering and Research, P029301 0002-1929-030602, March 2002. [23] Letter from D.E. Young (Florida Power, Crystal River) to U.S. Nuclear Regulatory Commission, 3F0401-11, dated April 25, 2001. [24] Risk Assessment for Vogtle Electric Generating Plant Regarding the ILRT (Type A) Extension Request, prepared for Southern Nuclear Operating Co. by ERIN Engineering and Research, February 2003.

PRA-BV2-13-002-ROO Page 60 of 60 [25] FENOC Letter No. L-08-293 from Peter P. Sena Ill, Site Vice President, Beaver Valley Power Station, to USNRC, Beaver Valley Power Station, Unit No.2, License Amendment Request No.08-029, Credit for Containment Overpressure, November 7,2008, (ADAMS Accession No. ML083170522).

[26] Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," EPRI Report 1009325, Revision 2, August 2007. [27] Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals:

Revision 2-A of 1 009325," EPRI Report 1018243, Final Report, October 2008. [28] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Unit 2, 2BVT 1.47.2, Revision 2, "Containment Type A Leak Test," Test Results Report, Completed Test Date: May 11, 2008. [29] FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Unit 2, 2BVT 1.47.02, Issue 2, Revision 1, "Containment Type A Leak Test," Test Results Report, Completed Test Date: November 10, 1993.

Attachment 5 Documentation of BVPS-1 Probabilistic Risk Assessment (PRA) Technical Adequacy (21 pages follow)

DOCUMENTATION OF BVPS-1 PROBABILISTIC RISK ASSESSMENT (PRA) TECHNICAL ADEQUACY Page i ofi DOCUMENTATION OF BVPS-1 PRA TECHNICAL ADEQUACY TABLE OF CONTENTS 1.0 OVERVIEW ..........................................................................................................

1 2.0 TECHNICAL ADEQUACY OF THE PRA MODEL. ...............................................

3 2.1 PRA Maintenance and Update ..........................................................................

4 2.2 Plant Changes Not Yet Incorporated into the PRA Model. ................................

5 2.3 Applicability of Peer Review Findings and Observations (F&Os) ......................

5 2.3.1 2002 BVPS PRA Peer Review ...................................................................

6 2.3.2 2007 BVPS PRA Self-Assessment

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

8 2.3.3 2007 BVPS HRA Focused Peer Review ....................................................

9 2.3.4 2011 BVPS Internal Flood PRA Focused Peer Review ...........................

10 2.4 Consistency with Applicable PRA Standards

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

1 0 2.5 Identification of Key Assumptions

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

11 3.0 EXTERNAL EVENTS CONSIDERATIONS

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

12 4.0 SHUTDOWN EVENTS CONSIDERATIONS

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

13 5.0

SUMMARY

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

14

6.0 REFERENCES

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

14 Table 1: Summary of BVPS Peer Reviews and Self-Assessment..

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

11 Table 2: Summary of BVPS-1 F&O Resolutions Requiring a PRA Model Change ....... 16 Page 1 of 19 DOCUMENTATION OF BVPS-1 PRA TECHNICAL ADEQUACY 1.0 OVERVIEW The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specifications Initiative 5b) at Beaver Valley Power Station, Unit No. 1 (BVPS-1) will follow the guidance provided by Nuclear Energy Institute (NEI) in NEI 04-10, Revision 1 [Ref. 1] in evaluating proposed surveillance test interval (STI; also referred to as "surveillance frequency")

changes. The following steps of the risk-informed STI revision process are common to proposed changes to all STis within the proposed licensee-controlled program.

• Each proposed STI revision is reviewed to determine whether there are any commitments made to the NRC that may prohibit changing the interval.

If there are no related commitments, or the commitments may be changed using a commitment change process based on NRC endorsed guidance, then evaluation of the STI revision would proceed. If a commitment exists and the commitment change process does not permit the change without NRC approval, then the proposed STI revision cannot be implemented.

Only after receiving NRC approval to change the commitment could the proposed STI revision proceed.

• A qualitative analysis is performed for each proposed STI revision that involves several considerations as explained in N El 04-1 0, Revision 1.

• Each proposed STI revision is reviewed by an expert panel, referred to as the Integrated Oecisionmaking Panel (lOP), which is normally the same panel as is used for Maintenance Rule implementation, but with the addition of specialists with experience in surveillance tests and system or component reliability.

If the lOP approves the STI revision, the change is documented, implemented, and available for future audits by the NRC. If the lOP does not approve the STI revision, the STI value is left unchanged.

• Performance monitoring is conducted as recommended by the lOP. In some cases, no additional monitoring may be necessary beyond that already conducted under the Maintenance Rule. The performance monitoring helps to confirm that no failure mechanisms related to the revised test interval become important enough to alter the information provided for the justification of the interval changes.

• The lOP is responsible for periodic review of performance monitoring results. If it is determined that the time interval between successive performances of a surveillance test is a factor in the unsatisfactory performances of the surveillance, the lOP will adjust the STI as needed to provide reasonable assurance of continued satisfactory performance.

• In addition to the above steps, the Probabilistic Risk Assessment (PRA) is used, when possible, to quantify the effect of a proposed individual STI revision Page 2 of 19 compared to acceptance criteria in NEI 04-10, Revision 1. Neither the current BVPS PRA models nor the industry generic failure data, for which they are based upon, distinguish between the time-related failure contribution (the standby time-related failure rate) and the cyclic demand-related failure contribution (the demand stress failure probability) for standby component failure modes (for example, NUREG/CR-6928

[Ref. 2] assumes these failures are on a demand basis). Since this distinction is not made, FENOC, in accordance with NEI 04-10, Revision 1, will assume that all failures are related in calculating the risk impact of a proposed STI adjustment, to obtain the maximum test-limited risk contribution.

If a further breakdown of failure probability is required to remove conservatism from the risk impact calculation of a proposed surveillance frequency change, it shall be justified through data and/or engineering analyses.

Furthermore, FENOC will abide by the cautionary sentence in NEI 04-10, Revision 1, Step 8, third paragraph, which states, " ... caution should be taken in dividing the failure probability into time-related and cyclic demand-related contributions because the test-limited risk can be underestimated when only part of the failure rate is considered as being related while this may not be the case." Also, the cumulative impact of all informed STI revisions on all applicable PRA evaluations (internal events, external events and shutdown) is compared to the risk acceptance criteria as delineated in NEI 04-10, Revision 1. For those cases where the STI can not be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change. The NEI 04-10, Revision 1 methodology endorses the guidance provided in Regulatory Guide (RG) 1.200, Revision 1 [Ref. 3], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Informed Activities." The guidance in RG 1.200, Revision 1 indicates that the following steps should be followed when performing PRA assessments:

1. Identify the parts of the PRA used to support the application.

• Identify structures, systems, and components (SSCs), operational characteristics affected by the application and how these are implemented in the PRA model.

• A definition of the acceptance criteria used for the application.

2. Identify the scope of risk contributors addressed by the PRA model.

• If not full scope (internal events, external events, all modes), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the PRA model. 3. Summarize the risk assessment methodology used to assess the risk of the application.

• Include how the PRA model was modified to appropriately model the risk impact of the change request.

Page 3 of 19 4. Demonstrate the Technical Adequacy of the PRA.

• Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

• Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

• Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, RG 1.200, Revision 1, which includes only the internal events PRA standard).

Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.

• Identify key assumptions and approximations relevant to the results used in the decision-making process. Item 1 satisfies the requirements of RG 1.200, Revision 1, Section 3.1 Identification of Parts of a PRA Used to Support the Application.

Item 2 satisfies the requirements of RG 1.200, Revision 1, Section 3.2 Scope of Risk Contributors Addressed by the PRA Model. Item 3 satisfies one of the requirements of RG 1.200, Revision 1, Section 4.2 Licensee Submittal Documentation.

Item 4 satisfies the requirements of RG 1.200, Revision 1, Section 3.3 Demonstration of Technical Adequacy of the PRA, and the remaining requirements of RG 1.200, Revision 1, Section 4.2. Because of the broad scope of potential Technical Specifications Initiative 5b applications and the fact that the risk assessment details will differ from application to application, each of the issues encompassed in Items 1 through 3 above will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests.

The purpose of the remaining portion of this attachment is to address the requirements identified in Item 4 above. 2.0 TECHNICAL ADEQUACY OF THE PRA MODEL The BVPS-1 PRA model of record, PRA-BV1-AL-R05a, and supporting documentation have been maintained as a living program, with updates directed every other refueling cycle (approximately every three years) to reflect the as-built, as-operated plant. Interim updates may be prepared and issued in between regularly scheduled model updates on an as needed basis. Typically, an interim revision would be used for an update that would cause a change in Core Damage Frequency (CDF) of greater than 10 percent, a change in Large Early Release Frequency (LERF) of greater than 20 percent, or the changes that could critically impact a risk informed application.

Interim models may also be released following focused peer reviews of upgraded PRA models once the associated findings and suggestions have been addressed.

Page 4 of 19 The BVPS-1 PRA model is highly detailed and includes a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA quantification process used is based on the large linked event tree methodology, which is a well-known and accepted methodology in the industry.

The BVPS-1 PRA model uses Binary Decision Diagram (BOD) methodology to quantify the faults trees, which computes the top event probability exactly and without requiring frequency or cutset order truncation.

The 1 E-14 truncation level used for the BVPS-1 PRA model sequence quantification is more than 9 orders of magnitude less than the baseline CDF. This is more than sufficient to provide a converged value of CDF, since decreasing the truncation level by a decade from 1E-14 to 1 E-15 only results in an increase in CDF of 0.01%. FirstEnergy Nuclear Operating Company (FENOC) makes use of a multi-faceted, structured approach in establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all FENOC nuclear generation sites. This approach includes a proceduralized PRA maintenance and update process, as well as the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the BVPS-1 PRA. 2.1 PRA Maintenance and Update The BVPS-1 PRA model and supporting documentation have been maintained as a living program, which is routinely updated in order to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component data. The latest update to the BVPS-1 PRA model occurred in January 11, 2013 with the effective reference model, PRA-BV1-AL-R05a, being released at that time. This PRA model is an interim revision to the R05 PRA model to update the internal flooding PRA so that it conforms to the technical requirements of RG 1.200, Revision 1, and the ASME/ANS PRA Standard [Ref. 4], and is capable of being used to support current and future informed licensing applications and risk management activities.

The R05a PRA model includes both internal and external events, and provides Level 1 and Level 2 results. The FENOC risk management process ensures that the applicable PRA model is an accurate reflection of the as-built, and as-operated BVPS-1 plant. This process is defined in the FENOC PRA Program, which consists of a governing procedure (NOPM-CC-6000, "Probabilistic Risk Assessment Program")

and subordinate implementation procedures.

Procedure NOPM-CC-6000, serves as the higher tier procedure and establishes the FENOC PRA Program and provides administrative requirements for the maintenance and upgrade of the FENOC PRA models and risk-informed applications.

The overall objective of the PRA Program is to provide technically adequate PRA models such that the requirements set forth in RG 1.200 are satisfied for use in risk-informed applications.

Working in conjunction with the above procedure, NOBP-CC-6001, "Probabilistic Risk Assessment Model Page 5 of 19 Management," establishes the administrative and technical requirements for the maintenance and upgrade of the FENOC PRA models. 2.2 Plant Changes Not Yet Incorporated into the PRA Model A procedurally controlled process is used to maintain configuration control of the BVPS-1 PRA model, data, and software.

In addition to model control, administrative mechanisms are in place to assure that plant modifications, procedure changes relevant to the PRA, changes to calculations, and industry operating experiences (OEs) are appropriately screened, dispositioned, and tracked for incorporation into the PRA model if that change would impact the model. As part of this process, if any proposed changes are identified, which are perceived to significantly increase or decrease risk, they are incorporated into a working model (given their known level of detail at the time), and the results are compared to the effective model of record to identify if the proposed change should be pursued. These processes help to assure that the BVPS-1 PRA reflects the built, as-operated plant within the limitations of the PRA methodology, and that the significance of future expected changes or enhancements are understood and managed. The interfacing process involves an ongoing solicitation of review of any changes that may have an impact upon the PRA model. Any changes to the PRA model or its supporting documentation are captured within a tracking database for PRA implementation tracking and future disposition.

Additionally, the PRA staff provides the top risk significant operator actions to the Operations Training staff, for simulator validation to ensure that the current human reliability modeling reflects actual expected response and timing. As part of the PRA evaluation for each STI change request, a review of open items in the tracking database will be performed for applicability and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a nontrivial impact is expected, then performance of additional sensitivity studies or PRA model changes to confirm the impact on the risk analysis will be included.

2.3 Applicability

of Peer Review Findings and Observations (F&Os) The Level 1 and Level 2 BVPS-1 PRA analyses were originally developed in support of Generic Letter 88-20 [Ref. 5 and Ref. 6]. The BVPS-1 Individual Plant Examination (IPE) and the Individual Plant Examination of External Events (IPEEE) were submitted to the NRC under separate letters in October 1992 and June 1995, respectively.

Since the inception of these studies, the BVPS-1 PRA model has evolved and has been updated many times. The following list summarizes the BVPS-1 PRA model revision history:

Date 10/1992 06/1995 06/1998 09/2003 06/2006 12/2010 01/2013 Revision 0 1 2 3 4 5 5a Page 6 of 19 BVPS-1 PRA Model Change Individual Plant Examination (IPE) NRC submittal Individual Plant Examination-External Events (IPEEE) NRC submittal Integrated Level1 and Level 2 models WOG NEI 00-02 Peer Review with Category NB F&Os addressed HRA [Human Reliability Analysis]

Calculator, replacement steam generators, atmospheric containment conversion, and extended power uprate model RG 1.200, R1 (excluding Floods) CCII Compliant Model Interim model update to include Internal Flooding, RG 1.200, R1 (including Floods) CCII Compliant Model The BVPS-1 PRA model has been the subject of several assessments to establish the technical adequacy of the PRA. These assessments are identified and discussed in the paragraphs below.

• 2002 -An independent PRA peer review of the BVPS PRA models [Ref. 7] was conducted under the auspices of the Westinghouse Owners Group (WOG) in July 2002, following the NEI 00-02 Industry PRA Peer Review process [Ref. 8]. This peer review included an assessment of the PRA model maintenance and update process.

• 2007-Following the BVPS-1 PRA model revision in 2006, a self-assessment of the BVPS PRA models [Ref. 9] against the ASME PRA Standard was performed using RG 1.200, Revision 1.

• 2007 -As part of the resolution to several F&Os from the 2002 PRA peer review, a change in the Human Reliability Analysis (HRA) methodology was incorporated into the 2006 BVPS-1 PRA model revision, so a focused scope peer review of the HRA Technical Elements [Ref. 1 0] against the ASME PRA Standard was performed using RG 1.200, Revision 1.

• 2011 -Due to an upgrade of the internal flooding model following the BVPS-1 PRA model revision in 2010, a focused scope peer review of the Internal Flood PRA Technical Elements [Ref. 11] was performed against the applicable requirements of Part 3 of the ASME/ANS PRA standard (along with the NRC clarifications provided in RG 1.200, Revision 2). 2.3.1 2002 BVPS PRA Peer Review The WOG conducted the Beaver Valley PRA model peer review following the NEI 00-02 process, during the week of July 15, 2002. This peer review primarily focused on the Unit 2 PRA model, since its model and documentation had been Page 7 of 19 more recently updated, but also provided a cursory review of the Unit 1 PRA model and methodology.

It was noted by the Peer Review Team that, since Unit 1 uses the same PRA modeling techniques as Unit 2, when the Unit 1 PRA revision is performed in the future with the same modeling assumptions as Unit 2 (including addressing applicable peer review comments), the Unit 1 PRA model and results should have the same level of confidence and applicability as those of Unit 2. Westinghouse, who was the lead in performing the peer review, prepared the final BVPS PRA peer review report in December 2002. The final BVPS PRA peer review report identified 5 Category A Level of Significance Fact & Observations and 31 Category B Level of Significance Fact & Observations.

However, 2 of the Category A F&Os, and 2 of the Category B F&Os were determined to be only applicable to the BVPS-2 PRA model. This report also identified 33 Category C Level of Significance Fact & Observations and 5 Category D Level of Significance Fact & Observations.

One of the Category C F&Os, and one of the Category D F&Os were determined to be only applicable to the BVPS-2 PRA model. The PRA Peer Review Team did not identify any F&Os that were only unique to Unit 1. All of the PRA peer review Category A and B F&Os have been entered into the BVPS Corrective Action Program and resolved by using one or more of the following methods: 1. Correcting the finding and incorporating it into the updated PRA model and/or documentation;

2. Disposition of the finding by providing additional information, technical bases, or evaluations to demonstrate that it is acceptably modeled and/or documented as is; or by 3. Justifying the finding with an interim solution, which includes cross comparisons with industry methods/values to ensure that it is not an outlier, demonstrating that the impact is insignificant on the quantified results, and developing a long term resolution.

Condition Report 02-09041 and its associated Corrective Actions document the 3 Category A F&Os applicable to BVPS-1 and their responses.

Condition Report 02-09045 and its associated Corrective Actions document 27 of the BVPS-1 Category B F&Os and their responses.

The remaining two BVPS-1 Category B F&Os (HR-09 and QU-03) are documented in Corrective Actions 02-09046-19, and 02-09046-24, since they were originally classified as Category C F&Os in the draft peer review report but were subsequently reclassified as a Category B in the final report. In the response to a BVPS-2 Slave Relay Surveillance Test Interval Extension Request for Additional Information (RAI) [Ref. 12], FENOC provided the BVPS-2 Corrective Action summaries and resolutions for all 5 of the F&Os that were classified as Category A observations, and all 19 of the Category B observations that could potentially impact the PRA model. The remainder of the Category B F&Os were documentation issues and did not impact the PRA models. The Page 8 of 19 majority of these observations that were provided to the NRC were also applicable to Unit 1, with the exception of those instances where the F&O applied strictly to Unit2. The significant findings (Category A and B F&Os) from the BVPS PRA peer review were incorporated into the BVPS-1 Revision 3 (2003) PRA model. A long term solution to one of PRA peer review findings, was to revise the methodology used in the human reliability analysis from the success likelihood index methodology (SLIM) used in the previous PRA models to the EPRI HRA Calculator.

The BVPS-1 HRA was revised using the EPRI HRA Calculator and the results were incorporated into the BVPS-1 Revision 4 (2006) PRA model. This Revision 4 PRA model also included the replacement steam generators, atmospheric containment conversion, and extended power uprate to 2900 MWt. All of the WOG PRA peer review Category A, B, C, and D F&Os captured in the corrective action program against the BVPS-1 PRA model have since been resolved in the 2003, 2006, 2010, and 2013 PRA model revisions.

2.3.2 2007 BVPS PRA Self-Assessment Following the BVPS-1 PRA Model Revision 4 in 2006, a self-assessment of the BVPS PRA models was conducted in 2007 with the assistance of Westinghouse.

Once again this review focused on the BVPS-2 PRA model, but to the extent that the PRA modeling methodologies are equivalent, this self-assessment was also applicable to the Unit 1 PRA. This self-assessment was performed to determine if there were any gaps present between the BVPS PRA models and meeting the Capability Category II Supporting Requirements (SR) in the 2005 version of the ASME PRA Standard Addendum B, as amplified by RG 1.200, Revision 1. This self-assessment covered 304 of the 316 SRs in the ASME PRA Standard.

However, only 291 SRs were reviewed (there were 13 SRs that are determined to be not applicable because they address specific methodologies that the BVPS PRA models did not use, or were deleted in RA-Sb-2005 of the ASME PRA Standard).

The other 12 SRs (post-initiator Human Reliability Analysis SRs HR-G1 through HR-H3) were not reviewed in this self-assessment since they were to be addressed in a focused scope HRA peer review due to the model upgrade in this area. The status of the "A" and "B" level F&Os from the original BVPS peer review were also checked, and all were found to be resolved when considering the change in methodology to the EPRI HRA Calculator, and associated reports that document the HRA inputs and considerations.

Of the 291 SRs reviewed, 224 met the Capability Category II, Ill, or "Meets" requirements, which span all three Capability Categories.

An additional 21 SRs met Capability Category I, while 46 of the SRs were determined not to be met. Of these 46 SRs not met, 19 were associated with the internal flooding element due to the BVPS flooding analysis not following the ASME PRA Standard internal flooding methodology, resulting in 27 F&Os. Following the completion of the reviews by both the lead and supporting reviewer, a consensus session was conducted wherein all of the reviewers were responsible for reviewing the reasonableness of Page 9 of 19 the findings of the lead and supporting reviewers.

A total of 73 F&Os were prepared to document any issues that were identified during this review, which were reviewed by the entire team and a consensus was reached regarding the level of the F&O. However, 1 of the F&Os for SR SY-B13 was determined to be only applicable to the BVPS-2 PRA model. In January 2008, Westinghouse provided the final summary report of the BVPS PRA model self-assessment to demonstrate compliance with the ASME PRA Standard and RG 1.200, Revision 1. For those SRs that did not meet Capability Category II requirements, this assessment provided a starting point for determining where, for a given application of the PRA, enhancements to the model, sensitivity analyses or evaluations outside the PRA may be needed to adequately support the integrated decision-making process. 2.3.3 2007 BVPS HRA Focused Peer Review In order to address one of the WOG PRA peer review findings, a long term solution was to revise the methodology used in the human reliability analysis from the success likelihood index methodology (SLIM) used in the previous PRA models to the EPRI HRA Calculator.

Both the ASME PRA Standard and RG 1.200, Revision 1 require that any upgrade to a PRA involving a methodology change needs to have a peer review of those portions of the PRA affected by the change. This change in HRA methodology was incorporated into the BVPS-1 Revision 4 (2006) PRA Model. Since there was a change in the HRA methodology following the WOG PRA peer review in July 2002, a focused scope peer review was conducted by Westinghouse the week of October 29, 2007 on the BVPS HRA to determine compliance with Addendum B of the ASME PRA Standard and RG 1.200, Revision 1. Because the methodology is the same and the basic analyses differ only in minor details, the review focused on the Unit 2 HRA Report for the post-initiator Human Error Probabilities (HEPs}, but is also applicable to Unit 1. The Human Reliability element of the ASME PRA Standard contains a total of 35 SRs under 9 High Level Requirements (HLRs). BVPS met Capability Category CC-II or better for 25 of the 35 SRs and met CC-I for an additional 3 SRs. The BVPS PRA did not meet requirements for 7 of the SRs, primarily due to documentation issues. Seven new F&Os were prepared to document the specific issues that were identified.

All seven of these HRA F&Os were rated as Findings.

Westinghouse provided a summary report of this HRA focused peer review in March 2008. The BVPS-1 Revision 5 (2010) PRA model resolved all identified PRA assessment F&Os and focused HRA peer review F&Os, with the exception of the 27 F&Os associated with internal flood, which required an upgrade of the internal flooding model to comply with the ASME PRA Standard internal flooding methodology.

Page 10 of 19 2.3.4 2011 BVPS Internal Flood PRA Focused Peer Review The BVPS-1 Revision 5 internal flooding PRA model was upgraded for the purpose of complying with the combined ASME/ANS PRA standard (RA-Sa-2009), along with the NRC clarifications and qualifications provided in RG 1.200, Revision 2, for meeting the Capability Category II Supporting Requirements.

Both the ASME PRA Standard and RG 1.200 require that any upgrade to a PRA involving a methodology change needs to have a peer review of those portions of the PRA affected by the change. Therefore, in June 2012, the BVPS PRA models underwent a focused PRA peer review on the Internal Flooding portion of the model. This focused peer review was performed using the process defined in NEI 05-04 [Ref. 13]. For this focused peer review, only the five technical elements, comprising ten HLRs, for internal flooding (Part 3 of the ASME/ANS Combined PRA Standard) were reviewed.

These five technical elements contain 62 SRs supporting requirements; of which three were determined to not be applicable to BVPS Units 1 and 2. Of the 59 remaining SRs, 48 were rated as Capability Category II or greater. None of the SRs were rated as just meeting Capability Category I. Only 11 of the SRs were rated as not met. This review resulted in 17 new F&Os; 3 Suggestions and 14 Findings.

All 17 of these new internal flooding PRA F&Os pertain to BVPS-1, while only 16 pertain to BVPS-2. Westinghouse provided a summary report of this internal flooding focused peer review in September 2011. All 17 of the IFPRA F&Os were appropriately resolved in an interim BVPS-1 Revision 5a (2013) PRA model. This BVPS-1 Revision 5a PRA model (PRA-BV1-AL-R5a) became effective in January 2013, and is currently the effective reference model. 2.4 Consistency with Applicable PRA Standards The BVPS-1 Revision 5a (2013) PRA model (PRA-BV1-AL-R05a) has resolved all of the applicable F&Os identified in the 2002 BVPS PRA Peer Review, 2007 BVPS PRA Self-Assessment, 2007 BVPS HRA Focused Peer Review, and the 2011 BVPS Internal Flood PRA Focused Peer Review. This PRA model is considered to be fundamentally compliant with RG 1.200, Revision 1 for the scope of this application, and meets Capability Category II or above in the ASME PRA Standard (RA-Sb-2005).

The PRA-BV1-AL-R05a PRA model is capable of supporting all risk-informed applications requiring Capability Category I or II. Table 1 summarizes the results of the BVPS PRA Peer Reviews and Self-Assessment.

Page 11 of 19 Table 1: Summary of BVPS Peer Reviews and Self-Assessment Peer Review I Self-Total Identified Total F&Os Resolved to Meet Assessment Applicable Capability Category II F&Os 68 (including 2 F&Os resolved 2002 BVPS PRA Peer 68 by the updated Internal Flooding Review PRA model and 3 resolved by the updated HRA model) 72 (including 27 internal flood 2007 BVPS PRA Self-72 F&Os resolved by the updated Assessment Internal Flooding PRA model and focused Peer Review) 2007 BVPS HRA Focused 7 7 Peer Review 2011 BVPS Internal Flood 17 17 PRA Focused Peer Review A brief summary of the BVPS-1 final resolutions to all of the 2007 BVPS PRA Assessment, 2007 BVPS HRA Focused Peer Review, and the 2011 BVPS Internal Flood PRA Focused Peer Review F&Os, which resulted in a change to the PRA model, are provided in Table 2. All other F&Os from these assessment/reviews were considered to be documentation issues, and did not impact the PRA models. As noted in Section 2. 3.1, a summary of the 2002 BVPS PRA Peer Review Category A observations and the Category B observations that potentially impacted the model, and their resolutions were previously provided to the NRC in response to a 2003 RAI [Ref. 12]. 2.5 Identification of Key Assumptions The overall Technical Specifications Initiative 5b process is a risk-informed process with the PRA model results providing one of the inputs to the lOP to determine if an STI change is warranted.

The NEI 04-10 methodology recognizes that a key area of uncertainty for this application is the standby failure rate utilized in the determination of the STI extension impact. Therefore, the methodology requires the performance of selected sensitivity studies on the standby failure rate of the component(s) of interest for the STI assessment.

The results of the standby failure rate sensitivity study plus the results of any additional sensitivity studies identified during the performance of the reviews as outlined in Section 2.2 above, including a review of the identified key sources of uncertainty and insights that were developed for the BVPS-1 Revision Sa (2013)

Page 12 of 19 PRA model for their potential impacts, for each STI change assessment will be documented and included in the results of the risk analysis that goes to the IDP. 3.0 EXTERNAL EVENTS CONSIDERATIONS The NEI 04-10, Revision 1, methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group). A qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed STI change. External hazards were evaluated in the BVPS-1 Individual Plant Examination of External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20, Supplement

4) [Ref. 6]. The IPEEE Program was a time review of external hazard risk and was limited in its purpose for the identification of potential plant vulnerabilities and the understanding of associated severe accident risks. The results of the BVPS-1 IPEEE study are documented in the BVPS-1 IPEEE Summary Report [Ref. 14]. Each of the BVPS-1 external event evaluations were reviewed by the NRC and compared to the requirements of NUREG-1407

[Ref. 15]. The NRC transmitted to FENOC (formerly Duquesne Light Company) in December 2000 their Staff Evaluation Report of the BVPS Units 1 and 2 IPEEE Submittals

[Ref. 16]. Consistent with Generic Letter 88-20, the BVPS-1 IPEEE submittal does not screen out seismic or internal fire hazards, but provides quantitative analyses for these. The seismic and internal fire risk analyses provided in the BVPS-1 IPEEE used detailed full-scope Level 2 PRA models, which met the requirements of Generic Letter 88-20 and NUREG-1407, to systematically and successively evaluate the seismic and fire hazards, and their associated risks. The overall methodology used for the seismic and internal fire PRA models was an extension of the PRA methodology used for the IPE. As such, the BVPS-1 IPEEE PRA model was fully integrated into the IPE PRA model to provide quantified CDF and LERF values for at-power internal events, internal fires, and seismic events. During the subsequent BVPS-1 PRA model revisions following the IPEEE, the seismic and internal fire PRA models have been kept fully integrated with the internal events and internal flooding PRA models. As a result, the plant response modeling (fault trees and event trees) following these external initiating events have been updated as part of the PRA model update process. The BVPS-1 seismic and internal fire PRA models have not undergone a PRA Peer Review; however, to the extent that their accident sequence logic is incorporated into the internal events PRA system event tree logic, they have had some limited peer checks. Furthermore, the BVPS-1 IPEEE seismic and internal fire PRA models were reviewed internally by both the utility personnel and the Page 13 of 19 IPEEE contractors (PLG and Stevenson

& Associates).

Additionally, as documented in Reference 15, the NRC and their contractors (Brookhaven National Laboratory and Sandia National Laboratory) also reviewed these PRA models during the BVPS IPEEE submittal evaluation, and found the results to be reasonable and capable of identifying the most likely severe accidents and vulnerabilities from external events. FENOC considers these BVPS-1 external event PRA models of sufficient scope to adequately address the seismic and internal fire risk associated with this informed application.

Therefore, these quantifiable PRA models will be used to determine the internal fire and seismic external hazard risk metric inputs (CDF and LERF) associated with the STI change. However, if it is determined that the SSC undergoing the STI change is only implicitly modeled in the seismic or internal fire PRA, and cannot be adequately addressed in these PRA models with some revisions, then there is a choice of performing a bounding analysis.

The BVPS-1 IPEEE also included an analysis of high winds and tornados, external floods, and other external hazards (HFO) by using the NUREG-1407 recommended progressive screening approach to review the plant and vicinity against the regulatory requirements regarding these hazards. The BVPS-1 IPEEE concluded that no potential vulnerabilities were identified with respect to the postulated HFO events. Furthermore, all BVPS-1 HFO events were found to be in conformance with the guidance of NUREG-1407, and were screened out as being significant contributors to total CDF and LERF. Insights from this HFO evaluation will be used to qualitatively analyze these hazards, whenever possible.

If the HFO qualitative information is not deemed sufficient to provide confidence that the net impact of the STI change would be negligible (or zero) from a CDF and LERF perspective, then a bounding analysis will be performed, as required.

As previously stated, the NEI 04-10, Revision 1 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. Therefore, in performing the assessments for the HFO hazard groups, a qualitative or a bounding approach will be utilized.

The existing BVPS-1 seismic and internal fire PRA models will be .used to obtain quantitative seismic and internal fire risk metric insights for most cases, but may need refinements on a case-by-case basis. If these external events PRA models prove to be inadequate to address the STI change, a bounding analysis will be performed.

This approach is consistent with the accepted NEI 04-10, Revision 1 methodology.

4.0 SHUTDOWN

EVENTS CONSIDERATIONS BVPS-1 has a defense-in-depth shutdown safety program based on the principles contained in NUMARC 91-06 [Ref. 17]. Since a PRA model has not yet been developed for shutdown conditions at BVPS-1, STI change evaluations involving SSCs required to function while shutdown will include qualitative information using the NUMARC 91-06 principles.

This approach is consistent with the accepted NEI 04-10, Revision 1 methodology.

Page 14 of 19 5.0

SUMMARY

The BVPS-1 PRA model of record (PRA-BV1-AL-R05a) fully meets all the Capability Category II requirements of Part 2 "Internal Events" and Part 3 "Internal Flood" of the ASME/ANS PRA Standard.

All applicable F&Os from peer reviews and self-assessments have been resolved.

The current BVPS-1 seismic and internal fire PRA models have not been assessed against the requirements of the ASME/ANS PRA Standard, but have been subject to independent review by external events experts, and maintained in the current PRA model of record. Therefore, the BVPS-1 seismic and internal fire PRA models are believed to be of sufficient scope to adequately address the seismic and internal fire risk associated with this risk-informed application.

These PRA models, in combination with the maintenance and update processes described above, provide a robust basis for concluding that the full power internal events, seismic, and internal fire PRA models are suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. In performing the assessments for the HFO hazard groups and shutdown events, the qualitative or bounding approach will be utilized.

Also, in addition to the standard set of sensitivity studies required per the NEI 04-10, Revision 1, methodology, open items for changes at the site will be reviewed to determine which, if any, would merit application specific sensitivity studies in the presentation of the application results.

6.0 REFERENCES

1. NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance Document," Nuclear Energy Institute, Revision 1, April 2007. 2. NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, February 2007. 3. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 1, US Nuclear Regulatory Commission, January 2007. 4. ASME/ANS RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," American Society of Mechanical Engineers and American Nuclear Society, February 2009. 5. U.S. Nuclear Regulatory Commission, Generic Letter 88-20, "Individual Plant Examination for Severe Accident Vulnerabilities

-10 CFR 50.54(f)," December 1988. 6. U.S. Nuclear Regulatory Commission, Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities

-10 CFR 50.54(f)," Supplement 4, June 28, 1991.

Page 15 of 19 7. "Beaver Valley Power Station, Probabilistic Risk Assessment Peer Review Report," Westinghouse Electric Company, Final Report, December 2002. 8. NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance," Nuclear Energy Institute, Revision A3, March 2000. 9. Westinghouse Letter No. FENOC-08-11, "FirstEnergy Nuclear Operating Company, Beaver Valley Unit 2, PRA Regulatory Guide 1.200 Gap Assessment," January 30, 2008. 10. Westinghouse Letter No. FENOC-08-22, "FirstEnergy Nuclear Operating Company, Beaver Valley Units 1 and 2, Transmittal of Human Reliability Analysis (HRA) Update Peer Review," March 4, 2008. 11. Westinghouse Letter No. FENOC-11-104, "FirstEnergy Nuclear Operating Company, Beaver Valley Nuclear Power Station Unit 1, Transmittal of Reg. Guide 1.200 PRA Peer Review Results -Internal Flooding PRA," September 12, 2011. 12. Pearce, L. W./USNRC, Beaver Valley Power Station, Unit No. 2, BV-2 Docket No. 50-412, License No. NPF-73, Response to a Request for Additional Information in Support of License Amendment Requests No. 180, dated October 24, 2003, Serial L-03-160. 13. NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard (Internal Events)," Nuclear Energy Institute, Revision 2, November 2008. 14. Duquesne Light Company, "Beaver Valley Power Station Unit 1, Probabilistic Risk Assessment, Individual Plant Examination of External Events, Summary Report," June 30, 1995. 15. NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," June 1991. 16. Letter from Lawrence J. Burkhart (USNRC) to L. W. Myers, FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Units 1 and 2, Staff Evaluation of Licensee's Response to Generic Letter 88-20 (TAC Nos. M83590 and M83591 ), December 11, 2000 (Docket Nos. 50-334 an 50-412). 17. NUMARC 91-06, "Guidelines for Industry Actions to Address Shutdown Management," December 1991.

Table 2: Summary of BVPS-1 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. HR-81-01 HR-81, B 9 This F&O is a carry-over from the peer review (F&O HR-02 HR-2). A generic error of omission term from the PLG database (ZHE01A) was used for all misalignment HEPs without regard for procedural or operational failure barriers such as independent verification, peer checks, walkdowns, etc. However, plant specific data was used for test and maintenance frequencies.

Therefore, the overall misalignment errors were a hybrid of generic and plant specific data. This was used for systems which are important to COF (e.g., Auxiliary Feedwater, Safety Injection).

HR-PR-003 HR-02, Finding 10 The method for quantifying pre-initiator misalignment HR-03, errors as described on page 8 of the "Beaver Valley HR-04, Power Station Unit 2 PRA Notebook-Human HR-11, Reliability Analysis," Revision 2, dated 10/01/07, relies HR-12 on the use of a generic Error of Omission rate that does not reflect any detailed assessment of the HEPs. The process also does not consider the quality of plant-specific written procedures, administrative controls or the man-machine interface and does not include an explicit assessment of the potential for recovery that specifically delineates which procedures and processes influence the potential for identification and recovery.

Furthermore, the method for quantifying post-maintenance miscalibrations relies on a single generic error of omission rate. A complication in reviewing the pre-initiator Human Failure Events (HFEs) was that the HRA notebook does not include a list of the pre-initiator HFEs or their probabilities.

The system notebooks provide evidence of the search for and identification of misalignments but they do not present a list of such events or their -------probabilities.

-BVPS-1 Final Resolution As outlined in HRA Notebook Section 2.2, testing and maintenance procedures were evaluated to identify potential misalignments.

These potential misalignments were evaluated using the EPRI HRA Calculator 4.1.1 to develop specific HEPs for each potential misalignment as documented in HRA Notebook Table 3.5. Pre-initiators are now quantified using the THERP methodology as presented in the EPRI HRA Calculator.

This is documented in Sections 2.2 & 3.4 and Table 3-5 of the HRA Notebook.

The pre-initiator human error probabilities were determined using BVPS operator input and BVPS specific procedures and processes.

The process now considers the plant specific written procedures, administration controls, and man-machine interface.

A list of the pre-initiator HFEs and their probabilities was added to Section 3 in Table 3 5. I -a Ill (C CD .... 0> a .... <0 Table 2: Summary of BVPS-1 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. IF-05-01 IF-05, B 9 The IF pipe and tank break frequencies used in the IF IF-D5a assessment are based on 1988 and 1990 data. The prior pipe break frequencies should be updated to reflect more recent experience and should include plant specific experience.

In estimating pipe break frequencies, it is recommended that experience with safety related vs. BOP piping be considered along with active pipe degradation mechanisms.

Credit for condition monitoring programs should also be applied where applicable.

IF-05-02 IF-05 c 9 The IEF for pipe breaks is based on a generic 80% capacity factor. There are two issues with this method: a) current capacity factors are typically greater than 80% so that the IEFs are slightly lower, and b) the method is inconsistent with the method used to calculate other IEFs. It is recommended that the calculation for IF IEF be revised to be consistent with the method used for other IEFs. LE-C2a-01 LE-C2a, B 9 SR LE-C2a is assigned a capability category I LE-C2b, because BVPS 2 does not use operator actions post LE-C3, core damage. This is considered conservative LE-C6 treatment of operator actions following the onset of core damage. To meet capability category Ill for this SR, BVPS 2 level 2 analysis must contain realistic operator actions, based on SAMGs, EOPs, etc. such as WCAP-16657 -P. BVPS-1 Final Resolution This F&O was superseded by the updated Internal Flooding PRA model and focused Peer Review conducted during June 6-9, 2011, by the PWR Owners Group. The PRA-BV1-AL-R05a Internal Flooding Analysis Notebook, Section 13 documents the focused Peer Review F&Os as well as their resolution.

This F&O was superseded by the updated Internal Flooding PRA model and focused Peer Review conducted during June 6-9, 2011, by the PWR Owners Group. The PRA-BV1-AL-R05a Internal Flooding Analysis Notebook, Section 13 documents the focused Peer Review F&Os as well as their resolution.

The Level 2 LERF Analysis Notebook Section 2.5 "General Discussion of Level 2 Operator Actions" discusses operator actions considered for this model. WCAP-16657 -P suggests seven potential operator actions (OA) for inclusion in a Level 2 PRA model. Each of these actions along with two others were reviewed specifically for Beaver Valley Unit 1. The Level 2 OA to restore feedwater to a dry steam generator was added to the PRA model. I -c Dl co (l) ....... -....1 Q, ....... co Table 2: Summary of BVPS-1 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. LE-C10-01 LE-C10 B 9 SGTR and containment bypass did not take credit for scrubbing.

WCAP-16657 suggests that scrubbing for tube rupture events can be credited by an operator action restart auxiliary feedwater to the ruptured steam generator.

LE-05-01 LE-05 B 9 Beaver Valley Thermal Induced SGTR is based on a 1995 F auske and Associates report and Westinghouse Calculation CN-RRA-02-38.

Recent investigations suggest that these results may be too optimistic.

A more reasonable approach may be implementing WCAP 16341, "Simplified LERF Model,

• and characterizing the uncertainties based on that latest EPRI, PWROG, and NRC interactions.

LE-E4-01 LE-E4 B 9 The BV2 LERF model is quantified using RISKMAN. Only point-estimates for each top event are used and there are no uncertainty estimates or uncertainty propagation.

--BVPS-1 Final Resolution A discussion has been added to Section 3.3 "Containment Event Tree," Top Event OL to credit SGTR scrubbing and the basis for the decontamination factor. The PI-SGTR and TI-SGTR methods are included in Appendix F of the Level 2 LERF Analysis Notebook.

The Level 2 phenomena split fraction distributions are included in Table 3-26 of the Level 2 LERF Analysis Notebook.

This table contains Beaver Valley Unit 1 plant specific Level 2 phenomena distributions along with the mean, median, 5th%ile, and the 95th%ile.

A discussion on how these distributions were developed is provided in Section 3.4 of this notebook.

iJ Ill co CD ...... 00 Q, ...... co Table 2: Summary of BVPS-1 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. SY-81-01 SY-81 c 9 At the time of the BVPS Unit 2 common cause MGL data update during Revision 3, the NRC update to NUREG/CR-5497 was still not available.

As such, a decision was made during the update process to keep the existing generic MGL data, which is almost exclusively based on the PLG generic database dated circa 1989. There is no documentation to illustrate that the Beaver Valley considered NUREG/CR-5497 during the Revision 4 PRA update. ----BVPS-1 Final Resolution Up-to-date generic MGL CCF data has been updated in PRA-BV1-AL-R05 using WCAP-16672-P (Section 3.6 and Table C-5 in the Data Analysis Notebook).

In June 2008, Westinghouse issued WCAP-16672-P which covers 1980 -2003 in order to provide guidance to address the concerns that were raised regarding the consistency and correctness of the CCF events included in the NRC CCF database.

The WCAP data source contains CCF parameter estimates for the majority of risk-significant components whose performance are potentially applicable to PWROG utilities only in the U.S. designed by either Westinghouse or Combustion Engineering.

The parameter estimates for failure modes of significant components that are generally included in the PRA are provided for the Alpha factors that are converted to the Multiple Greek Letter approach (MGL) by the method in NUREG/CR-5485 and to allow for quantifying CCF probabilities.

'"0 Dl (0 (1) ....>. co a ....>. co Attachment 6 Documentation of BVPS-2 Probabilistic Risk Assessment (PRA) Technical Adequacy (21 pages follow)

DOCUMENTATION OF BVPS-2 PROBABILISTIC RISK ASSESSMENT (PRA) TECHNICAL ADEQUACY Page i of i DOCUMENTATION OF BVPS-2 PRA TECHNICAL ADEQUACY TABLE OF CONTENTS 1.0 OVERVIEW ..........................................................................................................

1 2.0 TECHNICAL ADEQUACY OF THE PRA MODEL. ...............................................

3 2.1 PRA Maintenance and Update ..........................................................................

4 2.2 Plant Changes Not Yet Incorporated into the PRA Model. ................................

5 2.3 Applicability of Peer Review Findings and Observations (F&Os) ......................

5 2.3.1 2002 BVPS PRA Peer Review ...................................................................

7 2.3.2 2007 BVPS PRA Self-Assessment

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

8 2.3.3 2007 BVPS HRA Focused Peer Review ....................................................

9 2.3.4 2011 BVPS Internal Flood PRA Focused Peer Review .............................

9 2.4 Consistency with Applicable PRA Standards

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

10 2.5 Identification of Key Assumptions

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

11 3.0 EXTERNAL EVENTS CONSIDERATIONS

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

12 4.0 SHUTDOWN EVENTS CONSIDERATIONS

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

13 5.0

SUMMARY

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

14

6.0 REFERENCES

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

14 Table 1: Summary of BVPS Peer Reviews and Self-Assessment..

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

11 Table 2: Summary of BVPS-2 F&O Resolutions Requiring a PRA Model Change ....... 16 Page 1 of 19 DOCUMENTATION OF BVPS-2 PRA TECHNICAL ADEQUACY 1.0 OVERVIEW The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specifications Initiative Sb) at Beaver Valley Power Station, Unit No. 2 (BVPS-2) will follow the guidance provided by Nuclear Energy Institute (NEI) in NEI 04-10, Revision 1 [Ref. 1] in evaluating proposed surveillance test interval (STI; also referred to as "surveillance frequency")

changes. The following steps of the risk-informed STI revision process are common to proposed changes to all STis within the proposed licensee-controlled program.

• Each proposed STI revision is reviewed to determine whether there are any commitments made to the NRC that may prohibit changing the interval.

If there are no related commitments, or the commitments may be changed using a commitment change process based on NRC endorsed guidance, then evaluation of the STI revision would proceed. If a commitment exists and the commitment change process does not permit the change without NRC approval, then the proposed STI revision cannot be implemented.

Only after receiving NRC approval to change the commitment could the proposed STI revision proceed.

• A qualitative analysis is performed for each proposed STI revision that involves several considerations as explained in NEI 04-10, Revision 1.

• Each proposed STI revision is reviewed by an expert panel, referred to as the Integrated Decisionmaking Panel (IDP), which is normally the same panel as is used for Maintenance Rule implementation, but with the addition of specialists with experience in surveillance tests and system or component reliability.

If the IDP approves the STI revision, the change is documented, implemented, and available for future audits by the NRC. If the IDP does not approve the STI revision, the STI value is left unchanged.

• Performance monitoring is conducted as recommended by the IDP. In some cases, no additional monitoring may be necessary beyond that already conducted under the Maintenance Rule. The performance monitoring helps to confirm that no failure mechanisms related to the revised test interval become important enough to alter the information provided for the justification of the interval changes.

• The IDP is responsible for periodic review of performance monitoring results. If it is determined that the time interval between successive performances of a surveillance test is a factor in the unsatisfactory performances of the surveillance, the IDP will adjust the STI as needed to provide reasonable assurance of continued satisfactory performance.

• In addition to the above steps, the Probabilistic Risk Assessment (PRA) is used, when possible, to quantify the effect of a proposed individual STI revision Page 2 of 19 compared to acceptance criteria in NEI 04-10, Revision 1. Neither the current BVPS PRA models nor the industry generic failure data, for which they are based upon, distinguish between the time-related failure contribution (i.e.; the standby time-related failure rate) and the cyclic demand-related failure contribution (the demand stress failure probability) for standby component failure modes (for example, NUREG/CR-6928

[Ref. 2] assumes these failures are on a demand basis). Since this distinction is not made, FENOC, in accordance with NEI 04-10, Revision 1, will assume that all failures are related in calculating the risk impact of a proposed STI adjustment, to obtain the maximum test-limited risk contribution.

If a further breakdown of failure probability is required to remove conservatism from the risk impact calculation of a proposed surveillance frequency change, it shall be justified through data and/or engineering analyses.

Furthermore, FENOC will abide by the cautionary sentence in NEI 04-10, Revision 1, Step 8, third paragraph, which states, " ... caution should be taken in dividing the failure probability into time-related and cyclic demand-related contributions because the test-limited risk can be underestimated when only part of the failure rate is considered as being related while this may not be the case." Also, the cumulative impact of all informed STI revisions on all applicable PRA evaluations (i.e., internal events, external events and shutdown) is compared to the risk acceptance criteria as delineated in NEI 04-10, Revision 1. For those cases where the STI can not be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change. The NEI 04-10, Revision 1 methodology endorses the guidance provided in Regulatory Guide (RG) 1.200, Revision 1 [Ref. 3], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Informed Activities." The guidance in RG 1.200, Revision 1 indicates that the following steps should be followed when performing PRA assessments:

1. Identify the parts of the PRA used to support the application.

• Identify structures, systems, and components (SSCs), operational characteristics affected by the application and how these are implemented in the PRA model.

• A definition of the acceptance criteria used for the application.

2. Identify the scope of risk contributors addressed by the PRA model.

• If not full scope (i.e., internal events, external events, all modes), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the PRA model. 3. Summarize the risk assessment methodology used to assess the risk of the application.

• Include how the PRA model was modified to appropriately model the risk impact of the change request.

Page 3 of 19 4. Demonstrate the Technical Adequacy of the PRA.

• Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

• Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

• Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, RG 1.200, Revision 1, which includes only the internal events PRA standard).

Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.

• Identify key assumptions and approximations relevant to the results used in the decision-making process. Item 1 satisfies the requirements of RG 1.200, Revision 1, Section 3.1 Identification of Parts of a PRA Used to Support the Application.

Item 2 satisfies the requirements of RG 1.200, Revision 1, Section 3.2 Scope of Risk Contributors Addressed by the PRA Model. Item 3 satisfies one of the requirements of RG 1.200, Revision 1, Section 4.2 Licensee Submittal Documentation.

Item 4 satisfies the requirements of RG 1.200, Revision 1, Section 3.3 Demonstration of Technical Adequacy of the PRA, and the remaining requirements of RG 1.200, Revision 1, Section 4.2. Because of the broad scope of potential Technical Specifications Initiative 5b applications and the fact that the risk assessment details will differ from application to application, each of the issues encompassed in Items 1 through 3 above will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests.

The purpose of the remaining portion of this attachment is to address the requirements identified in Item 4 above. 2.0 TECHNICAL ADEQUACY OF THE PRA MODEL The BVPS-2 PRA model of record, PRA-BV2-AL-R05a, and supporting documentation have been maintained as a living program, with updates directed every other refueling cycle (approximately every three years) to reflect the as-built, as-operated plant. Interim updates may be prepared and issued in between regularly scheduled model updates on an as needed basis. Typically, an interim revision would be used for an update that would cause a change in Core Damage Frequency (CDF) of greater than 10 percent, a change in Large Early Release Frequency (LERF) of greater than 20 percent, or the changes that could critically impact a risk informed application.

Interim models may also be released following focused peer reviews of upgraded PRA models once the associated findings and suggestions have been addressed.

Page 4 of 19 The BVPS-2 PRA model is highly detailed and includes a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA quantification process used is based on the large linked event tree methodology, which is a well-known and accepted methodology in the industry.

The BVPS-2 PRA model uses Binary Decision Diagram (BOD) methodology to quantify the faults trees, which computes the top event probability exactly and without requiring frequency or cutset order truncation.

The 1 E-14 truncation level used for the BVPS-2 PRA model sequence quantification is more than 9 orders of magnitude less than the baseline CDF. This is more than sufficient to provide a converged value of CDF, since decreasing the truncation level by a decade from 1 E-14 to 1E-15 only results in an increase in CDF of0.03%. FirstEnergy Nuclear Operating Company (FENOC) makes use of a multi-faceted, structured approach in establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all FENOC nuclear generation sites. This approach includes a proceduralized PRA maintenance and update process, as well as the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the BVPS-2 PRA. 2.1 PRA Maintenance and Update The BVPS-2 PRA model and supporting documentation have been maintained as a living program, which is routinely updated in order to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component data. The latest update to the BVPS-2 PRA model occurred in August 31, 2012 with the effective reference model, PRA-BV2-AL-R05a, being released at that time. This PRA model is an interim revision to the R05 PRA model to update the internal flooding PRA so that it conforms to the technical requirements of RG 1.200, Revision 1, and the ASME/ANS PRA Standard [Ref. 4], and is capable of being used to support current and future informed licensing applications and risk management activities.

The R05a PRA model includes both internal and external events, and provides Level 1 and Level 2 results. The FENOC risk management process ensures that the applicable PRA model is an accurate reflection of the as-built, and as-operated BVPS-2 plant. This process is defined in the FENOC PRA Program, which consists of a governing procedure (NOPM-CC-6000, "Probabilistic Risk Assessment Program")

and subordinate implementation procedures.

Procedure NOPM-CC-6000, serves as the higher tier procedure and establishes the FENOC PRA Program and provides administrative requirements for the maintenance and upgrade of the FENOC PRA models and risk-informed applications.

The overall objective of the PRA Program is to provide technically adequate PRA models such that the requirements set forth in RG 1.200 are satisfied for use in risk-informed applications.

Working in conjunction with the Page 5 of 19 above procedure, NOBP-CC-6001, "Probabilistic Risk Assessment Model Management," establishes the administrative and technical requirements for the maintenance and upgrade of the FENOC PRA models. 2.2 Plant Changes Not Yet Incorporated into the PRA Model A procedurally controlled process is used to maintain configuration control of the BVPS-2 PRA model, data, and software.

In addition to model control, administrative mechanisms are in place to assure that plant modifications, procedure changes relevant to the PRA, changes to calculations, and industry operating experiences (OEs) are appropriately screened, dispositioned, and tracked for incorporation into the PRA model if that change would impact the model. As part of this process, if any proposed changes are identified, which are perceived to significantly increase or decrease risk, they are incorporated into a working model (given their known level of detail at the time), and the results are compared to the effective model of record to identify if the proposed change should be pursued. These processes help to assure that the BVPS-2 PRA reflects the built, as-operated plant within the limitations of the PRA methodology, and that the significance of future expected changes or enhancements are understood and managed. The interfacing process involves an ongoing solicitation of review of any changes that may have an impact upon the PRA model. Any changes to the PRA model or its supporting documentation are captured within a tracking database for PRA implementation tracking and future disposition.

Additionally, the PRA staff provides the top risk significant operator actions to the Operations Training staff, for simulator validation to ensure that the current human reliability modeling reflects actual expected response and timing. As part of the PRA evaluation for each STI change request, a review of open items in the tracking database will be performed for applicability and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a nontrivial impact is expected, then performance of additional sensitivity studies or PRA model changes to confirm the impact on the risk analysis will be included.

2.3 Applicability

of Peer Review Findings and Observations (F&Os) The Level 1 and Level 2 BVPS-2 PRA analyses were originally developed in support of Generic Letter 88-20 [Ref. 5 and Ref. 6]. The BVPS-2 Individual Plant Examination (IPE) and the Individual Plant Examination of External Events (IPEEE) were submitted to the NRC under separate letters in March 1992 and September 1997, respectively.

Since the inception of these studies, the BVPS-2 PRA model has evolved and has been updated many times. The following list summarizes the BVPS-2 PRA model revision history:

Date Revision 03/1992 0 09/1997 1 10/1997 2 01/2002 3A 05/2003 38 04/2007 4 12/2010 5 08/2012 Sa Page 6 of 19 BVPS-2 PRA Model Change Individual Plant Examination (IPE) NRC submittal Individual Plant Examination-External Events (IPEEE) NRC submittal Integrated Level 1 and Level 2 models WOG NEI 00-02 Peer Reviewed WOG NEI 00-02 Peer Review with Category AlB F&Os addressed HRA [Human Reliability Analysis]

Calculator, atmospheric containment conversion, and extended power uprate model RG 1.200, R1 (excluding Floods) CCII Compliant Model Interim model update to include Internal Flooding, RG 1.200, R1 (including Floods) CCII Compliant Model The BVPS-2 PRA model has been the subject of several assessments to establish the technical adequacy of the PRA. These assessments are identified and discussed in the paragraphs below.

• 2002 -An independent PRA peer review of the BVPS PRA models [Ref. 7] was conducted under the auspices of the Westinghouse Owners Group (WOG) in July 2002, following the NEI 00-02 Industry PRA Peer Review process [Ref. 8]. This peer review included an assessment of the PRA model maintenance and update process.

• 2007 -Following the BVPS-2 PRA model revision in 2007, a self-assessment of the BVPS PRA models [Ref. 9] against the ASME PRA Standard was performed using RG 1.200, Revision 1.

• 2007 -As part of the resolution to several F&Os from the 2002 PRA peer review, a change in the Human Reliability Analysis (HRA) methodology was incorporated into the 2007 BVPS-2 PRA model revision, so a focused scope peer review of the HRA Technical Elements [Ref. 10] against the ASME PRA Standard was performed using RG 1.200, Revision 1.

• 2011 -Due to an upgrade of the internal flooding model following the BVPS-2 PRA model revision in 2010, a focused scope peer review of the Internal Flood PRA Technical Elements [Ref. 11] was performed against the applicable requirements of Part 3 of the ASME/ANS PRA standard (along with the NRC clarifications provided in RG 1.200, Revision 2).

Page 7 of 19 2. 3. 1 2002 BVPS PRA Peer Review The WOG conducted the Beaver Valley PRA model peer review following the NEI 00-02 process, during the week of July 15, 2002. This peer review primarily focused on the Unit 2 PRA model, since its model and documentation had been more recently updated, but also provided a cursory review of the Unit 1 PRA model and methodology.

Westinghouse, who was the lead in performing the peer review, prepared the final BVPS PRA peer review report in December 2002. The final BVPS PRA peer review report identified 5 Category A Level of Significance Fact & Observations and 31 Category B Level of Significance Fact & Observations.

This report also identified 33 Category C Level of Significance Fact & Observations and 5 Category D Level of Significance Fact & Observations.

All of the PRA peer review Category A and B F&Os have been entered into the BVPS Corrective Action Program and resolved by using one or more of the following methods: 1. Correcting the finding and incorporating it into the updated PRA model and/or documentation;

2. Disposition of the finding by providing additional information, technical bases, or evaluations to demonstrate that it is acceptably modeled and/or documented as is; or by 3. Justifying the finding with an interim solution, which includes cross comparisons with industry methods/values to ensure that it is not an outlier, demonstrating that the impact is insignificant on the quantified results, and developing a long term resolution.

Condition Report 02-09037 and its associated Corrective Actions document the 5 Category A F&Os applicable to BVPS-2 and their responses.

Condition Report 02-09042 and its associated Corrective Actions document 29 of the BVPS-2 Category B F&Os and their responses.

The remaining two BVPS-2 Category B F&Os (HR-09 and QU-03) are documented in Corrective Actions 02-09043-19 and 02-09043-25, since they were originally classified as Category C F&Os in the draft peer review report but were subsequently reclassified as a Category B in the final report. In the response to a BVPS-2 Slave Relay Surveillance Test Interval Extension Request for Additional Information (RAI) [Ref. 12], FENOC provided the BVPS-2 Corrective Action summaries and resolutions for all 5 of the F&Os that were classified as Category A observations, and all 19 of the Category B observations that could potentially impact the PRA model. The remainder of the Category B F&Os were documentation issues and did not impact the PRA models. The significant findings (Category A and B F&Os) from the BVPS PRA peer review were incorporated into the BVPS-2 Revision 38 (2003) PRA model. A long term solution to one of PRA peer review findings, was to revise the methodology used in the human reliability analysis from the success likelihood index methodology Page 8 of 19 (SLIM) used in the previous PRA models to the EPRI HRA Calculator.

The BVPS-2 HRA was revised using the EPRI HRA Calculator and the results were incorporated into the BVPS-2 Revision 4 (2007) PRA model. This Revision 4 PRA model also included the atmospheric containment conversion, and extended power uprate to 2900 MWt. All of the WOG PRA peer review Category A, B, C, and D F&Os captured in the corrective action program against the BVPS-2 PRA model have since been resolved in the 2003, 2007, 2010, and 2012 PRA model revisions.

2.3.2 2007 BVPS PRA Self-Assessment Following the BVPS-2 PRA Model Revision 4 in 2007, a self-assessment of the BVPS PRA models was conducted in 2007 with the assistance of Westinghouse.

Once again this review focused on the BVPS-2 PRA model, but to the extent that the PRA modeling methodologies are equivalent, this self-assessment was also applicable to the Unit 1 PRA. This self-assessment was performed to determine if there were any gaps present between the BVPS PRA models and meeting the Capability Category II Supporting Requirements (SR) in the 2005 version of the ASME PRA Standard Addendum B, as amplified by RG 1.200, Revision 1. This self-assessment covered 304 of the 316 SRs in the ASME PRA Standard.

However, only 291 SRs were reviewed (there were 13 SRs that are determined to be not applicable because they address specific methodologies that the BVPS PRA models did not use, or were deleted in RA-Sb-2005 of the ASME PRA Standard).

The other 12 SRs (post-initiator Human Reliability Analysis SRs HR-G1 through HR-H3) were not reviewed in this self-assessment since they were to be addressed in a focused scope HRA peer review due to the model upgrade in this area. The status of the "A" and "B" level F&Os from the original BVPS peer review were also checked, and all were found to be resolved when considering the change in methodology to the EPRI HRA Calculator, and associated reports that document the HRA inputs and considerations.

Of the 291 SRs reviewed, 224 met the Capability Category II, Ill, or "Meets" requirements, which span all three Capability Categories.

An additional 21 SRs met Capability Category I, while 46 of the SRs were determined not to be met. Of these 46 SRs not met, 19 were associated with the internal flooding element due to the BVPS flooding analysis not following the ASME PRA Standard internal flooding methodology, resulting in 27 F&Os. Following the completion of the reviews by both the lead and supporting reviewer, a consensus session was conducted wherein all of the reviewers were responsible for reviewing the reasonableness of the findings of the lead and supporting reviewers.

A total of 73 F&Os were prepared to document any issues that were identified during this review, which were reviewed by the entire team and a consensus was reached regarding the level of the F&O. In January 2008, Westinghouse provided the final summary report of the BVPS PRA model self-assessment to demonstrate compliance with the ASME PRA Standard and RG 1.200, Revision 1. For those SRs that did not meet Capability Page 9 of 19 Category II requirements, this assessment provided a starting point for determining where, for a given application of the PRA, enhancements to the model, sensitivity analyses or evaluations outside the PRA may be needed to adequately support the integrated decision-making process. 2.3.3 2007 BVPS HRA Focused Peer Review In order to address one of the WOG PRA peer review findings, a long term solution was to revise the methodology used in the human reliability analysis from the success likelihood index methodology (SLIM) used in the previous PRA models to the EPRI HRA Calculator.

Both the ASME PRA Standard and RG 1.200, Revision 1 require that any upgrade to a PRA involving a methodology change needs to have a peer review of those portions of the PRA affected by the change. This change in HRA methodology was incorporated into the BVPS-2 Revision 4 (2007) PRA Model. Since there was a change in the HRA methodology following the WOG PRA peer review in July 2002, a focused scope peer review was conducted by Westinghouse the week of October 29, 2007 on the BVPS HRA to determine compliance with Addendum B of the ASME PRA Standard and RG 1.200, Revision 1. Because the methodology is the same and the basic analyses differ only in minor details, the review focused on the Unit 2 HRA Report for the post-initiator Human Error Probabilities (HEPs), but is also applicable to Unit 1. The Human Reliability element of the ASME PRA Standard contains a total of 35 SRs under 9 High Level Requirements (HLRs). BVPS met Capability Category CC-II or better for 25 of the 35 SRs and met CC-I for an additional 3 SRs. The BVPS PRA did not meet requirements for 7 of the SRs, primarily due to documentation issues. Seven new F&Os were prepared to document the specific issues that were identified.

All seven of these HRA F&Os were rated as Findings.

Westinghouse provided a summary report of this HRA focused peer review in March 2008. The BVPS-2 Revision 5 (201 0) PRA model resolved all identified PRA assessment F&Os and focused HRA peer review F&Os, with the exception of the 27 F&Os associated with internal flood, which required an upgrade of the internal flooding model to comply with the ASME PRA Standard internal flooding methodology.

2.3.4 2011 BVPS Internal Flood PRA Focused Peer Review The BVPS-2 Revision 5 internal flooding PRA model was upgraded for the purpose of complying with the combined ASME/ANS PRA standard (RA-Sa-2009}, along with the NRC clarifications and qualifications provided in RG 1.200, Revision 2, for meeting the Capability Category II Supporting Requirements.

Both the ASME PRA Standard and RG 1.200 require that any upgrade to a PRA involving a methodology change needs to have a peer review of those portions of the PRA affected by the change. Therefore, in June 2012, the BVPS PRA models Page 10 of 19 underwent a focused PRA peer review on the Internal Flooding portion of the model. This focused peer review was performed using the process defined in NEI 05-04 [Ref. 13]. For this focused peer review, only the five technical elements, comprising ten HLRs, for internal flooding (Part 3 of the ASME/ANS Combined PRA Standard) were reviewed.

These five technical elements contain 62 SRs supporting requirements; of which three were determined to not be applicable to BVPS Units 1 and 2. Of the 59 remaining SRs, 48 were rated as Capability Category II or greater. None of the SRs were rated as just meeting Capability Category I. Only 11 of the SRs were rated as not met. This review resulted in 17 new F&Os; 3 Suggestions and 14 Findings.

All 17 of these new internal flooding PRA F&Os pertain to BVPS-1, while only 16 pertain to BVPS-2. Westinghouse provided a summary report of this internal flooding focused peer review in September 2011. All 16 of the IFPRA F&Os were appropriately resolved in an interim BVPS-2 Revision Sa (2012) PRA model. This BVPS-2 Revision Sa PRA model (PRA-BV2-AL-R5a) became effective in August 2012, and is currently the effective reference model. 2.4 Consistency with Applicable PRA Standards The BVPS-2 Revision Sa (2012) PRA model (PRA-BV2-AL-R05a) has resolved all of the applicable F&Os identified in the 2002 BVPS PRA Peer Review, 2007 BVPS PRA Self-Assessment, 2007 BVPS HRA Focused Peer Review, and the 2011 BVPS Internal Flood PRA Focused Peer Review. This PRA model is considered to be fundamentally compliant with RG 1.200, Revision 1 for the scope of this application, and meets Capability Category II or above in the ASME PRA Standard (RA-Sb-2005).

The PRA-BV2-AL-R05a PRA model is capable of supporting all risk-informed applications requiring Capability Category I or II. Table 1 summarizes the results of the BVPS PRA Peer Reviews and Self-Assessment.

Page 11 of 19 Table 1: Summary of BVPS Peer Reviews and Self-Assessment Peer Review I Self-Total Identified Assessment Applicable Total F&Os Resolved F&Os 74 (including 2 F&Os resolved 2002 BVPS PRA Peer 74 by the updated Internal Flooding Review PRA model and 3 resolved by the updated HRA model) 73 (including 27 internal flood 2007 BVPS PRA Self-73 F&Os resolved by the updated Assessment Internal Flooding PRA model and focused Peer Review) 2007 BVPS HRA Focused 7 7 Peer Review 2011 BVPS Internal Flood 16 16 PRA Focused Peer Review A brief summary of the BVPS-2 final resolutions to all of the 2007 BVPS PRA Assessment, 2007 BVPS HRA Focused Peer Review, and the 2011 BVPS Internal Flood PRA Focused Peer Review F&Os, which resulted in a change to the PRA model, are provided in Table 2. All other F&Os from these assessment/reviews were considered to be documentation issues, and did not impact the PRA models. As noted in Section 2.3.1, a summary of the 2002 BVPS PRA Peer Review Category A observations and the Category B observations that potentially impacted the model, and their resolutions were previously provided to the NRC in response to a 2003 RAI [Ref. 12]. 2.5 Identification of Key Assumptions The overall Technical Specifications Initiative Sb process is a risk-informed process with the PRA model results providing one of the inputs to the IDP to determine if an STI change is warranted.

The NEI 04-10 methodology recognizes that a key area of uncertainty for this application is the standby failure rate utilized in the determination of the STI extension impact. Therefore, the methodology requires the performance of selected sensitivity studies on the standby failure rate of the component(s) of interest for the STI assessment.

The results of the standby failure rate sensitivity study plus the results of any additional sensitivity studies identified during the performance of the reviews as outlined in Section 2.2 above, including a review of the identified key sources of Page 12 of 19 uncertainty and insights that were developed for the BVPS-2 Revision Sa (2012) PRA model for their potential impacts, for each STI change assessment will be documented and included in the results of the risk analysis that goes to the IDP. 3.0 EXTERNAL EVENTS CONSIDERATIONS The NEI 04-10, Revision 1, methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group). A qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed STI change. External hazards were evaluated in the BVPS-2 Individual Plant Examination of External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20, Supplement

4) [Ref. 6]. The IPEEE Program was a time review of external hazard risk and was limited in its purpose for the identification of potential plant vulnerabilities and the understanding of associated severe accident risks. The results of the BVPS-2 IPEEE study are documented in the BVPS-2 IPEEE Summary Report [Ref. 14]. Each of the BVPS-2 external event evaluations were reviewed by the NRC and compared to the requirements of NUREG-1407

[Ref. 15]. The NRC transmitted to FENOC (formerly Duquesne Light Company) in December 2000 their Staff Evaluation Report of the BVPS Units 1 and 2 IPEEE Submittals

[Ref. 16]. Consistent with Generic Letter 88-20, the BVPS-2 IPEEE submittal does not screen out seismic or internal fire hazards, but provides quantitative analyses for these. The seismic and internal fire risk analyses provided in the BVPS-2 IPEEE used detailed full-scope Level 2 PRA models, which met the requirements of Generic Letter 88-20 and NUREG-1407, to systematically and successively evaluate the seismic and fire hazards and their associated risks. The overall methodology used for the seismic and internal fire PRA models was an extension of the PRA methodology used for the IPE. As such, the BVPS-2 IPEEE PRA model was fully integrated into the IPE PRA model to provide quantified CDF and LERF values for at-power internal events, internal fires, and seismic events. During the subsequent BVPS-2 PRA model revisions following the IPEEE, the seismic and internal fire PRA models have been kept fully integrated with the internal events and internal flooding PRA models. As a result, the plant response modeling (fault trees and event trees) following these external initiating events have been updated as part of the PRA model update process. The BVPS-2 seismic and internal fire PRA models have not undergone a PRA Peer Review; however, to the extent that their accident sequence logic is incorporated into the internal events PRA system event tree logic, they have had some limited peer checks. Furthermore, the BVPS-2 IPEEE seismic and internal Page 13 of 19 fire PRA models were reviewed internally by both the utility personnel and the IPEEE contractors (PLG and Stevenson

& Associates).

Additionally, as documented in Reference 15, the NRC and their contractors (Brookhaven National Laboratory and Sandia National Laboratory) also reviewed these PRA models during the BVPS IPEEE submittal evaluation, and found the results to be reasonable and capable of identifying the most likely severe accidents and vulnerabilities from external events. FENOC considers these BVPS-2 external event PRA models of sufficient scope to adequately address the seismic and internal fire risk associated with this informed application.

Therefore, these quantifiable PRA models will be used to determine the internal fire and seismic external hazard risk metric inputs (CDF and LERF) associated with the STI change. However, if it is determined that the SSC undergoing the STI change is only implicitly modeled in the seismic or internal fire PRA, and cannot be adequately addressed in these PRA models with some revisions, then there is a choice of performing a bounding analysis.

The BVPS-2 IPEEE also included an analysis of high winds and tornados, external floods, and other external hazards (HFO) by using the NUREG-1407 recommended progressive screening approach to review the plant and vicinity against the regulatory requirements regarding these hazards. The BVPS-2 IPEEE concluded that no potential vulnerabilities were identified with respect to the postulated HFO events. Furthermore, all BVPS-2 HFO events were found to be in conformance with the guidance of NUREG-1407, and were screened out as being significant contributors to total CDF and LERF. Insights from this HFO evaluation will be used to qualitatively analyze these hazards, whenever possible.

If the HFO qualitative information is not deemed sufficient to provide confidence that the net impact of the STI change would be negligible (or zero) from a CDF and LERF perspective, then a bounding analysis will be performed, as required.

As previously stated, the NEI 04-10, Revision 1 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. Therefore, in performing the assessments for the HFO hazard groups, a qualitative or a bounding approach will be utilized.

The existing BVPS-2 seismic and internal fire PRA models will be used to obtain quantitative seismic and internal fire risk metric insights for most cases, but may need refinements on a case-by-case basis. If these external events PRA models prove to be inadequate to address the STI change, a bounding analysis will be performed.

This approach is consistent with the accepted NEI 04-10, Revision 1 methodology.

4.0 SHUTDOWN

EVENTS CONSIDERATIONS BVPS-2 has a defense-in-depth shutdown safety program based on the principles contained in NUMARC 91-06 [Ref. 17]. Since a PRA model has not yet been developed for shutdown conditions at BVPS-2, STI change evaluations involving SSCs required to function while shutdown will include qualitative information using the NUMARC 91-06 principles.

This approach is consistent with the accepted NEI 04-10, Revision 1 methodology.

Page 14 of 19 5.0

SUMMARY

The BVPS-2 PRA model of record (PRA-BV2-AL-R05a) fully meets all the Capability Category II requirements of Part 2 "Internal Events" and Part 3 "Internal Flood" of the ASME/ANS PRA Standard.

All applicable F&Os from peer reviews and self-assessments have been resolved.

The current BVPS-2 seismic and internal fire PRA models have not been assessed against the requirements of the ASME/ANS PRA Standard, but have been subject to independent review by external events experts, and maintained in the current PRA model of record. Therefore, the BVPS-2 seismic and internal fire PRA models are believed to be of sufficient scope to adequately address the seismic and internal fire risk associated with this risk-informed application.

These PRA models, in combination with the maintenance and update processes described above, provide a robust basis for concluding that the full power internal events, seismic, and internal fire PRA models are suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. In performing the assessments for the HFO hazard groups and shutdown events, the qualitative or bounding approach will be utilized.

Also, in addition to the standard set of sensitivity studies required per the NEI 04-10, Revision 1, methodology, open items for changes at the site will be reviewed to determine which, if any, would merit application specific sensitivity studies in the presentation of the application results.

6.0 REFERENCES

1. NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance Document," Nuclear Energy Institute, Revision 1, April 2007. 2. NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, February 2007. 3. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 1, US Nuclear Regulatory Commission, January 2007. 4. ASME/ANS RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," American Society of Mechanical Engineers and American Nuclear Society, February 2009. 5. U.S. Nuclear Regulatory Commission, Generic Letter 88-20, "Individual Plant Examination for Severe Accident Vulnerabilities

-10 CFR 50.54(f)," December 1988. 6. U.S. Nuclear Regulatory Commission, Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities

-10 CFR 50.54(f)," Supplement 4, June 28, 1991.

Page 15 of 19 7. "Beaver Valley Power Station, Probabilistic Risk Assessment Peer Review Report," Westinghouse Electric Company, Final Report, December 2002. 8. NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance," Nuclear Energy Institute, Revision A3, March 2000. 9. Westinghouse Letter No. FENOC-08-11, "FirstEnergy Nuclear Operating Company, Beaver Valley Unit 2, PRA Regulatory Guide 1.200 Gap Assessment," January 30, 2008. 10. Westinghouse Letter No. FENOC-08-22, "FirstEnergy Nuclear Operating Company, Beaver Valley Units 1 and 2, Transmittal of Human Reliability Analysis (HRA) Update Peer Review," March 4, 2008. 11. Westinghouse Letter No. FENOC-11-1 04, "FirstEnergy Nuclear Operating Company, Beaver Valley Nuclear Power Station Unit 1, Transmittal of Reg. Guide 1.200 PRA Peer Review Results-Internal Flooding PRA," September 12,2011. 12. Pearce, L. W./USNRC, Beaver Valley Power Station, Unit No. 2, BV-2 Docket No. 50-412, License No. NPF-73, Response to a Request for Additional Information in Support of License Amendment Requests No. 180, dated October 24, 2003, Serial L-03-160. 13. NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard (Internal Events)," Nuclear Energy Institute, Revision 2, November 2008. 14. Duquesne Light Company, "Beaver Valley Power Station Unit 2, Probabilistic Risk Assessment, Individual Plant Examination of External Events, Summary Report," September 30, 1997. 15. NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," June 1991. 16. Letter from Lawrence J. Burkhart (USNRC) to L. W. Myers, FirstEnergy Nuclear Operating Company, Beaver Valley Power Station, Units 1 and 2, Staff Evaluation of Licensee's Response to Generic Letter 88-20 (TAC Nos. M83590 and M83591), December 11, 2000 (Docket Nos. 50-334 an 50-412). 17. NUMARC 91-06, "Guidelines for Industry Actions to Address Shutdown Management," December 1991.

Table 2: Summary of BVPS-2 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. HR-81-01 HR-81, 8 9 This F&O is a carry-over from the peer review (F&O HR-02 HR-2). A generic error of omission term from the PLG database (ZHE01A) was used for all misalignment HEPs without regard for procedural or operational failure barriers such as independent verification, peer checks, walkdowns, etc. However, plant specific data was used for test and maintenance frequencies.

Therefore, the overall misalignment errors were a hybrid of generic and plant specific data. This was used for systems which are important to COF (e.g., Auxiliary Feedwater, Safety Injection).

HR-PR-003 HR-02, Finding 10 The method for quantifying pre-initiator misalignment HR-03, errors as described on page 8 of the "Beaver Valley HR-04, Power Station Unit 2 PRA Notebook -Human HR-11, Reliability Analysis," Revision 2, dated 10/01/07, relies HR-12 on the use of a generic Error of Omission rate that does not reflect any detailed assessment of the HEPs. The process also does not consider the quality of plant-specific written procedures, administrative controls or the man-machine interface and does not include an explicit assessment of the potential for recovery that specifically delineates which procedures and processes influence the potential for identification and recovery.

Furthermore, the method for quantifying post-maintenance miscalibrations relies on a single generic error of omission rate. A complication in reviewing the pre-initiator Human Failure Events (HFEs) was that the HRA notebook does not include a list of the pre-initiator HFEs or their probabilities.

The system notebooks provide evidence of the search for and identification of misalignments but they do not present a list of such events or their probabilities.

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BVPS-2 Final Resolution As outlined in HRA Notebook Section 2.2, testing and maintenance procedures were evaluated to identify potential misalignments.

These potential misalignments were evaluated using the EPRI HRA Calculator 4.1.1 to develop specific HEPs for each potential misalignment as documented in HRA Notebook Table 3.5. Pre-initiators are now quantified using the THERP methodology as presented in the EPRI HRA Calculator.

This is documented in Sections 2.2 & 3.4 and Table 3-5 of the HRA Notebook.

The pre-initiator human error probabilities were determined using BVPS operator input and BVPS specific procedures and processes.

The process now considers the plant specific written procedures, administration controls, and man-machine interface.

A list of the pre-initiator HFEs and their probabilities was added to Section 3 in Table 3 5. ----. I I ""C Ql <C CD ...... en a ...... (0 Table 2: Summary of BVPS-2 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. IF-05-01 IF-05, B 9 The IF pipe and tank break frequencies used in the IF IF-D5a assessment are based on 1988 and 1990 data. The prior pipe break frequencies should be updated to reflect more recent experience and should include plant specific experience.

In estimating pipe break frequencies, it is recommended that experience with safety related vs. BOP piping be considered along with active pipe degradation mechanisms.

Credit for condition monitoring programs should also be applied where applicable.

IF-05-02 IF-05 c 9 The IEF for pipe breaks is based on a generic 80-% capacity factor. There are two issues with this method: a) current capacity factors are typically greater than 80% so that the IEFs are slightly lower, and b) the method is inconsistent with the method used to calculate other IEFs. It is recommended that the calculation for IF IEF be revised to be consistent with the method used for other IEFs. LE-C2a-01 LE-C2a, B 9 SR LE-C2a is assigned a capability category I LE-C2b, because BVPS 2 does not use operator actions post LE-C3, core damage. This is considered conservative LE-C6 treatment of operator actions following the onset of core damage. To meet capability category Ill for this SR, BVPS 2 level 2 analysis must contain realistic operator actions, based on SAMGs, EOPs, etc. such as WCAP-16657-P.

BVPS-2 Final Resolution This F&O was superseded by the updated Internal Flooding PRA model and focused Peer Review conducted during June 6-9, 2011, by the PWR Owners Group. The PRA-BV2-AL-R05a Internal Flooding Analysis Notebook, Section 13 documents the focused Peer Review F&Os as well as their resolution.

This F&O was superseded by the updated Internal Flooding PRA model and focused Peer Review conducted during June 6-9, 2011, by the PWR Owners Group. The PRA-BV2-AL-R05a Internal Flooding Analysis Notebook, Section 13 documents the focused Peer Review F&Os as well as their resolution.

The Level 2 LERF Analysis Notebook Section 2.5 "General Discussion of Level 2 Operator Actions" discusses operator actions considered for this model. WCAP-16657-P suggests seven potential operator actions (OA) for inclusion in a Level 2 PRA model. Each of these actions along with two others were reviewed specifically for Beaver Valley Unit 2. The Level 2 OA to restore feedwater to a dry steam generator was added to the PRA model. ""C Ill (C CD ...... -...j Q. ...... co Table 2: Summary of BVPS-2 F&O Resolutions Requiring a PRA Model Change I F&OID Supt. Sign. Review Fact & Observation BVPS-2 Final Resolution Req. Level Ref. LE-C10-01 LE-C10 B 9 SGTR and containment bypass did not take credit for A discussion has been added to Section 3.3 I scrubbing.

WCAP-16657 suggests that scrubbing for "Containment Event Tree," Top Event OL to tube rupture events can be credited by an operator credit SGTR scrubbing and the basis for the action restart auxiliary feedwater to the ruptured decontamination factor. steam generator.

LE-05-01 LE-05 B 9 Beaver Valley Thermal Induced SGTR is based on a The PI-SGTR and TI-SGTR methods are 1995 Fauske and Associates report and included in Appendix F of the Level 2 LERF Westinghouse Calculation CN-RRA-02-38.

Recent Analysis Notebook.

investigations suggest that these results may be too optimistic.

A more reasonable approach may be implementing WCAP 16341, "Simplified LERF Model," and characterizing the uncertainties based on that latest EPRI, PWROG, and NRC interactions.

LE-E4-01 LE-E4 B 9 The BV2 LERF model is quantified using RISKMAN. The Level 2 phenomena split fraction Only point-estimates for each top event are used and distributions are included in Table 3-26 of there are no uncertainty estimates or uncertainty the Level 2 LERF Analysis Notebook.

This propagation.

table contains Beaver Valley Unit 2 plant specific Level 2 phenomena distributions along with the mean, median, 5th%ile, and the 95th%ile.

A discussion on how these distributions were developed is provided in Section 3.4 of this notebook.

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"lJ Dl IC CD -" CXl a -" co Table 2: Summary of BVPS-2 F&O Resolutions Requiring a PRA Model Change F&OID Supt. Sign. Review Fact & Observation Req. Level Ref. SY-81-01 SY-81 c 9 At the time of the BVPS Unit 2 common cause MGL data update during Revision 3, the NRC update to NUREG/CR-5497 was still not available.

As such, a decision was made during the update process to keep the existing generic MGL data, which is almost exclusively based on the PLG generic database dated circa 1989. There is no documentation to illustrate that the Beaver Valley considered NUREG/CR-5497 during the Revision 4 PRA update. BVPS-2 Final Resolution Up-to-date generic MGL CCF data has been updated in PRA-BV2-AL-R05 using WCAP-16672-P (Section 3.6 and Table C-5 in the Data Analysis Notebook).

In June 2008, Westinghouse issued WCAP-16672-P which covers 1980 -2003 in order to provide guidance to address the concerns that were raised regarding the consistency and correctness of the CCF events included in the NRC CCF database.

The WCAP data source contains CCF parameter estimates for the majority of risk-significant components whose performance are potentially applicable to PWROG utilities only in the U.S. designed by either Westinghouse or Combustion Engineering.

The parameter estimates for failure modes of significant components that are generally included in the PRA are provided for the Alpha factors that are converted to the Multiple Greek Letter approach (MGL) by the method in NUREG/CR-5485 and to allow for quantifying CCF probabilities.

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