NRC 2018-0018, License Amendment Request 288, Request to Extend Containment Leakage Rate Test Frequency

License Amendment Request 288, Request to Extend Containment Leakage Rate Test Frequency

ML18092A239
Person / Time
Site:	Point Beach
Issue date:	03/30/2018
From:	Craven R Point Beach
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC 2018-0018
Download: ML18092A239 (138)

Text

March 30, 2018 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555 Point Beach Nuclear Plant, Units 1 and 2 Dockets 50-266 and 50-301 NRC 2018-0018 10 CFR 50.90

Subject:

License Amendment Request 288, Request to Extend Containment Leakage Rate Test Frequency Pursuant to 10 CFR 50.90, NextEra Energy Point Beach, LLC (NextEra) is requesting an amendment to revise the technical specifications (TS) for Point Beach Nuclear Plant (PBNP),

Units 1 and 2. The proposed change would revise TS 5.5.15, "Containment Leakage Rate Testing Program," to require a program 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." to this letter provides NextEra's evaluation of the proposed change. Enclosure 2 provides a markup of the current TS showing the proposed change, and Enclosure 3 contains the revised (clean) TS page. Enclosure 4 provides the plant-specific risk impact assessment and Appendix A 1 to the enclosure provides documentation related to the technical adequacy of the PBNP probabilistic risk assessment (PRA).

The U.S. Nuclear Regulatory Commission (NRC) has previously reviewed the technical adequacy of the PBNP, Units 1 and 2 PRA model identified in the application for transition of the PBNP fire protection program to a risk-informed, performance-based program based on National Fire Protection Association Standard 805 (NFPA 805), "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 2001 Edition, in accordance with 10 CFR 50.48(c) in License Amendment Request 271 (NRC Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML13182A353 and ML13182A350). The PRA model technical adequacy was reviewed by the NRC, as discussed in its Safety Evaluation, dated September 8, 2016 (ADAMS Accession No. ML16196A093). The NRC has also previously reviewed the technical adequacy of the PBNP PRA models identified in "Application for Technical Specification Change Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program," Licen~e Amendment Request i73, dated July 3, 2014 (ADAMS Accession No. ML14190A267), as discussed in the Safety Evaluation, dated July 28, 2015 (ADAMS Accession No. ML15195A201 ). NextEra requests that the NRC utilize the reviews of the PRA technical adequacy for these applications when performing the review for this application.

NextEra Energy Point Beach, LLC 6610 Nuclear Road, Two Rivers, WI 54214

Document Control Desk Page 2 As discussed in the enclosed evaluation, the proposed change does not involve a significant hazards consideration pursuant to 10 CFR 50.92, and there are no significant environmental impacts associated with the change. This submittal has been reviewed by the PBNP Onsite Review Group.

This letter contains no new commitments or revisions to existing commitments.

NextEra requests approval of the proposed license amendment by April 1, 2019. The amendment will be implemented within 90 days of approval by the NRC.

In accordance with 10 CFR 50.91 (b)(1 ), a copy of this application, with enclosures, is being provided to the designated Wisconsin Official.

If you should have any questions regarding this submittal, please contact Eric Schultz, Licensing Manager, at 920-755-7854.

I declare under penalty of perjury that the foregoing is true and correct. Executed on March 30, 2018.

Sincerely, Robert Craven Plant General Manager NextEra Energy Point Beach, LLC

Enclosures:

As stated cc:

Regional Administrator, USNRC, Region Ill Project Manager, USNRC, Point Beach Nuclear Plant Resident Inspector, USNRC, Point Beach Nuclear Plant Public Service Commission of Wisconsin

1.0.

2.0 3.0 4.0 NextEra Energy Point Beach, LLC Point Beach Nuclear Plant, Units 1 and 2 License Amendment Request 288 Request to Extend Containment Leakage Rate Test Frequency Evaluation of the Proposed Changes

SUMMARY

DESCRIPTION DETAILED DESCRIPTION TECHNICAL EVALUATION 3.1 Leakage Test History 3.2 Containment Inspections 3.3 NRC Information Notices 3.4 NRC Limitations and Conditions 3.5 Plant-Specific Confirmatory Analysis 3.6 Conclusion REGULATORY SAFETY ANALYSIS 4.1 No Significant Hazards Consideration Determination 4.2 Precedent 4.3 Applicable Regulatory Requirements/Criteria 4.4 Conclusions

6.0 REFERENCES

38 Pages Follow

1.0

SUMMARY

DESCRIPTION NextEra Energy Point Beach, LLC (NextEra) requests a license amendment to revise the Point Beach Nuclear Plant (PBNP) Units 1 and 2 Technical Specifications (TS). Specifically, the proposed change would revise TS 5.5.15.a, "Containment Leakage Rate Testing Program," to require a program that is 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" (Reference 6.1 ). The NRC determined that NEI 94-01, Revision 3-A, describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations in its Safety Evaluation (Reference 6.2). This proposed change 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.

2.0 DETAILED DESCRIPTION

2.1 PROPOSED CHANGE

The proposed license amendments would revise TS 5.5.15.a as shown below.

5.5.15 Containment Leakage Rate Testing Program

a.

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) 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 exception to Nuclear Energy Institute (NEI) 94-01, Rev.-0 Revision 3-A, "Industry Guidance for Implementing Performance Based Option of 10 CFR 50, Appendix J", and the conditions and limitations specified in NE/ 94-01, Revision 2-A.Section 9.2.3, to allm.v the following:.

(i)

The first Unit 1 Type A test performed after October 7, 1997, shall be performed by October 7, 2012.

(ii)

The first Unit 2 Type A test performed after March 31, 1997, shall be performed by March 31, 2012.

A markup of the TS showing the proposed changes is provided in Enclosure 2. Enclosure 3 provides a revised (clean) TS page.

The purpose of NEI 94-01, Revision 3-A 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 (Reference 6.3) 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 60 months. NEI 94-01, Revision 3-A incorporates, by reference, the provisions of ANSl/ANS-56.8-2002 (Reference 6.17).

Page 1of38

The technical basis for the proposed license amendment utilizes risk-informed analysis augmented with non-risk related considerations. A risk impact evaluation performed by Sargent

& Lundy, LLC (S&L) concluded that the increases in large early release frequency (LERF) are within the limits set forth by the applicable guidance contained in Regulatory Guide (RG) 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" (Reference 6.6), NUREG-1493, "Performance Based Containment Leak-Test Program," and EPRI Report No. 1009325 (Reference 6.5).

In accordance with the guidance of NEI 94-01, Revision 3-A, NextEra proposes to extend the maximum surveillance interval for the ILRT to no longer than 15 years from the last ILRT based on satisfactory performance history. The current interval is no longer than ten years and would require that the next ILRT for PBNP Unit 1 be performed during the Fall 2020 refueling outage and the next ILRT for PBNP Unit 2 be performed during the Spring 2020 refueling outage. The proposed change would allow the next PBNP Unit 1 ILRT to be performed by November 2026 and the next PBNP Unit 2 ILRT to be performed by April 2026. This will reduce the number of ILRTs performed over the licensed period of operation resulting in significant savings in radiation exposure to personnel and critical path time during refueling outages.

2.2 DESCRIPTION

OF POINT BEACH REACTOR CONTAINMENT The PBNP Unit 1 and 2 primary containment structures are Seismic Class I structures. The containment ambient temperature during operation is between 50 and 120°F with a maximum operable containment average air temperature of 116.3°F per TS 3.6.5, "Containment Air Temperature". The reactor containment structure for PBNP Unit 2 is essentially identical in design and construction to that of Unit 1 except that it is oriented differently. Minor differences for Unit 2 include increased drainage from the containment floor to the sump, a slight difference in fan cooler locations, slightly smaller cavity floor area, and different penetration locations with a small number of spare penetrations.

The PBNP reactor containment system is a right cylinder with a flat base slab and a shallow domed roof. A % inch thick welded ASTM A-442 steel liner is attached to the inside face of the concrete shell to insure a high degree of leak tightness. The base liner is installed on top of the structural slab and is covered with concrete. The structure provides biological shielding for both normal and accident situations. The containment structures of Units 1 and 2 are designed to maintain leakage no greater than the maximum allowable containment leakage rate (La) of 0.2%

of containment air weight per day at a peak design containment internal accident pressure (Pa) of 60 pounds per square inch gauge (psig). The entire containment structure is housed in an unheated enclosure (facade) that provides protection from the weather.

The internal containment net free volume is approximately 1,000,000 cubic feet, and its associated engineered safety features systems are capable of withstanding a design internal pressure of 60 psig and a temperature of 286°F. The engineered safety features for containment include containment spray and the air recirculation cooling systems, which are used to ensure that containment does not exceed its design pressure. The containment systems and engineered safety features are described in detail in Chapters 5 and 6, respectively, of the PBNP Final Safety Analysis Report (FSAR).

The nominal 3 ft. 6 in. thick cylindrical wall and 3 ft. thick dome are prestressed and post tensioned. The nominal 9 ft. thick concrete base slab is reinforced with high strength reinforcing steel. The slab is supported on H piles driven to refusal in the underlying bedrock.

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Numerous mechanical and electrical systems penetrate the containment wall through welded steel penetrations.

The PBNP containment is a post-tensioned containment, whereby internal pressure load is balanced by an external load on the structure. Sufficient post-tensioning is used on the cylinder and dome to balance the internal pressure so that a margin of external pressure exists beyond that required to resist the design accident pressure. Nominal, bonded reinforcing steel is also provided to distribute strains due to shrinkage and temperature. Additional bonded reinforcing steel is used at penetrations and discontinuities to resist local moments and shears.

The internal pressure loads on the base slab are resisted by both the piles and the strength of the reinforced concrete slab. Thus, post tensioning is not required to exert an external pressure for this portion of the structure.

The post tensioning system design consists of:

Three groups of 49 dome tendons oriented at 120° to each other, for a total of 147 tendons anchored at the vertical face of the dome ring girder; 168 vertical tendons anchored at the top surface of the ring girder and at the bottom of the base slab; A total of 367 hoop tendons anchored at the six vertical buttresses.

ASTM A-432 reinforcement steel is used throughout the base slab and around the large penetrations. A-15 steel is used for the bonded reinforcement throughout the cylinder and dome as crack control reinforcement. At areas of discontinuities where additional steel is used, such steel is generally A-432 to provide an additional margin of elastic strain capability.

The 1/4 in. thick liner plate is attached to the concrete by means of an angle grid system stitch welded to the liner plate and embedded in the concrete. The frequent anchoring is designed to prevent significant distortion of the liner plate during accident conditions and to ensure that the liner maintains its leak tight integrity. The design of the liner anchoring system also considers the various erection tolerances and their effect on its performance. The liner plate is coated on the inside with 1-1/2 mil (nominal thickness) zinc silicate primer. The top coat is an epoxy finish with thickness as required by location.

The liner plate serves as a leak tight barrier and is also used to transmit loads to the concrete structure. There are no design conditions under which the liner plate is relied upon to assist the concrete in maintaining the integrity of the structure. Loads are transmitted to the liner plate through the anchorage system and direct contact with the concrete and vice versa. Loads may be transmitted by bond and/or friction with the concrete. These loads cause or are caused by liner strain. The liner is designed to withstand the predicted strains without leaking.

The liner plate is fabricated with a leak chase channel (LCC) system which covers all welded seams in the liner plate. In addition, some penetrations have leak chase channels installed over penetration assembly welds. The LCCs are welded on the inside of the liner plate, except for the dome LCCs, which are welded to the outside of the liner plate. The original purpose of the LCCs was to have the ability to pressure test the liner plate or penetration welds for leaks without pressurizing the full containment structure.

The LCCs are considered an integral part of the liner plate and therefore a part of the leak tight containment pressure boundary. These channels were not intended to be vented to the containment and were not vented during the early containment integrated leakage rate tests.

Page 3 of 38

Additional analyses, tests and comparison to more recent ASME design codes were performed to demonstrate both structural and leak-tight integrity of the LCC system. This additional information formed the basis for the NRC's approval to continue Type A testing with the LCCs not vented (Reference 6.12).

While acknowledging that PBNP was constructed prior to the implementation of the ASME Section Ill, Division 1, Subsection MC, the NRC staff required that the LCCs, as built, meet the intent of the Code. A comparison of the ASME code to the original design and construction codes was included in a summary report provided to the NRC (Reference 6.14). The summary report supports the conclusions that: 1) the channel welds are qualitatively equivalent to those for the primary containment liner welds as demonstrated by construction records, quality control measures, leak tests and inspection reports, and 2) the analyses and tests demonstrate that the leak chase channels, external or internal, are rugged components which will function as integral parts of the liner plate system, are capable of withstanding the loading conditions of both normal operation and design basis accidents, and will maintain their structural integrity at all times.

The accessible LCCs that provide the containment pressure boundary are visually examined as part of the liner plate. The entire LCC is included with each liner plate such that the weld of the LCC on an adjacent plate is included with the examination boundary for a liner plate ID. LCCs in the containment dome and in the concrete floor are considered inaccessible and will not be visually examined. Containment liner plate areas that are inaccessible include areas behind the containment ventilation ducting, containment accident fan coolers, and around the refueling penetration where the refueling cavity concrete does not afford accessibility.

Containment penetrations are double-barrier assemblies consisting of a closed sleeve, in most cases, or a double gasketed closure for the fuel transfer tube. The mechanical penetrations are welded to the containment shell. Likewise, the electrical penetration assemblies are constructed to provide a leak-tight barrier. These penetrations are described further below.

Equipment up to and including the size of the reactor vessel 0 ring seal can be transferred into or out of containment through a 15 ft. diameter equipment hatch. The hatch is fabricated from steel and furnished with a double gasketed flange and bolted dished door. Provision is made to allow test pressurization of the spaces between the double gaskets of the dished door flanges and the weld seam channels at the liner joint, hatch flanges, and dished door.

Personnel access to the containment structure is provided by two personnel air locks. One of these air locks penetrates the dished door of the equipment. The other personnel air lock is located at a higher elevation of the containment structure. Each personnel air lock is a double door, welded steel assembly, designed to withstand all containment design conditions with either or both doors closed and locked. Doors open toward the center of the containment structure and are thus sealed under containment pressure. Each personnel air lock door is provided with double gaskets to permit pressurization between the gaskets for leakage testing.

A fuel transfer penetration is provided in each containment structure for fuel movement between the refueling transfer canal and the spent fuel pool. The penetration consists of a 20 in. stainless steel pipe installed inside a 24 in. pipe. The inner pipe acts as the transfer tube and is fitted with a double gasketed transfer tube closure assembly in the refueling canal and a standard gate valve in the spent fuel pool. This arrangement prevents leakage through the transfer tube in the event of an accident. The outer pipe is welded to the containment liner and provision is made by use of continuous leak chase channels for test pressurizing all welds essential to the integrity of the penetration during plant operation.

Page 4 of 38

The piping and ventilation penetrations are of the rigid welded type and are solidly anchored to the containment wall, thus eliminating the need to use expansion bellows for containment barriers inside containment. Electrical penetrations consist of carbon steel pipe canisters with stainless steel header plates welded to each end. Identical hermetically ceramic sealed multi-pin connectors are welded into both headers for conductors rated less than 600 volts. High voltage conductors utilize single conductor hermetically sealed ceramic bushings welded to both header plates. Thus, each canister affords a double barrier against leakage.

Principal containment building dimensions (approximate size) and design pressure and temperature are summarized below:

Design Pressure (psig)

Design Temperature (°F)

Inner Diameter (ft)

Interior Height (ft)

Cylinder Shell Thickness (ft)

Dome Thickness (ft)

Internal Free Volume (ft3)

Cavity Floor Thickness (ft)

Cavity Floor Area (ft2)

Total Containment Surface Area (ft2)

3.0 TECHNICAL EVALUATION

3.1 LEAK TEST HISTORY 3.1.1 Type A Testing 60.0 286 105 150.25 3.5 3.0 Approximately 1,000,000 9.0 362(Unit1) and 355 (Unit 2) 54,272 ft2 (conservative estimate)

PBNP TS 5.5.15.a requires the measurement of the containment leakage rate. TS 5.5.15.d limits as-left Type A leakage to s; 0.75 La. The results of past Type A tests for PBNP are provided below. The more conservative as-left acceptance criteria is listed with the worst case as-found leakage. The current method for leakage determination is the mass point 95 percent upper confidence level (UCL) estimate of leakage rate. The pre-operational tests reported the tests results as a calculated point-to-point leak rate. The results of Type A tests performed at PBNP have met as-found acceptance criteria except for the Unit 1 April 1987 test. The as-found results were 0.241 percent of containment air weight per day and the as-left results were 0.086 percent of containment air weight per day. Corrections were made during this test for packing leakage. These results demonstrate a history of satisfactory performance for both leak tightness and structural integrity of the containment vessel.

The pre-operational tests and the most recent test for each unit were conducted at the design pressure of 60 psig. The remainder of the tests were performed at a reduced pressure of 30 psig (half the design pressure) with acceptance criteria established for the reduced pressure test based upon the full pressure acceptance criteria. Performance of a reduced pressure test was allowable per the original 10 CFR 50, Appendix J. In 1995, Appendix J was revised to provide Option 8, which does not allow reduced pressure testing. PBNP implemented the amended regulation via License Amendments 169 and 173 for Units 1 and 2 (Reference 6.15),

respectively, dated October 9, 1996, as corrected via NRC letter dated November 13, 1996.

These license amendments removed the performance of reduced pressure ILRT testing from the PBNP TS and required testing under design basis loss-of-coolant accident (LOCA) containment peak pressure only.

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The containment system was originally designed to maintain a leakage rate no greater than 0.4% of containment air weight per day (wt%/day) when subject to design pressure and temperature (60 psig, 286°F), humidity, chemicals, missiles and other severe environmental conditions predicted in the event of a design basis LOCA. License Amendments 240 and 244 (Reference 6.16) changed this limit to 0.2 wt%/day.

As-left acceptance criteria is listed in the tables below relative to the test leakage limit. This is the acceptance criteria for entering a mode where containment integrity is required. This acceptance criteria is based on the following parameters:

La= Design Basis Accident Leakage Rate (60 psig, 286 °F) = 199,800 seem Lr= Maximum Allowable Test Leakage Rate at Reduced Test Pressure (30 psig, 80 °F)

(historical value no longer in use to determine the acceptance criteria).

Unit 1 Test Test Design As Found As Found As Left As Left Date Pressure Pressure Leak Rate Acceptance Leak Rate Acceptance (psia)

(psid)

(Wt.%/day)

Criteria (Wt.%/day)

Criteria (Wt.% I day)

(Wt.%/day)

April 1990 44.62 60 0.067 (Note 1) 0.067 0.212 (0.75Lr)

April 1993 44.05 60 0.072 (Note 1) 0.072 0.212 (0. 75L r)

Oct. 1997 75.10 60 0.0465 0.400 0.0465 0.300 (0.75La)

Nov. 2011 73.26 60 0.1141 0.200 0.1136 0.150 (0.75La)

Test Test Test As Found As Found As Left As Left Date Pressure Pressure Leak Rate Acceptance Leak Rate Acceptance (psia)

(psid)

(Wt.%/day)

Criteria (Wt.%/day)

Criteria (Wt.% I day)

(Wt.%/day)

Sept.1989 44.68 60 0.060 Note 1 0.060 0.201 (0.75Lr)

Oct. 1992 45.09 60 0.101 Note 1 0.101 0.201 (0.75Lr)

March 1997 75.01 60 0.1087 0.400 0.1009 0.300 (0.75La)

April 2011 73.40 60 0.0859 0.200 0.0859 0.150 (0.75La)

Note 1: As-found Acceptance Criteria was not specifically identified in the testing documents for the pre-1997 tests.

Repair or replacement activities (including any unplanned activities) performed on the pressure retaining boundary df the primary containment 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.

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As required by NEI 94-01, Revision 3-A, Section 9.1.2, further extensions in test intervals are based upon two consecutive, periodic, successful Type A tests and requirements stated in Section 9.2.3 of this guideline. The results in the table show that there has been margin to the maximum allowable leakage rate of 0.15 wt%/day in the last two consecutive successful Type A tests for each unit.

3.1.2 Type B and C Testing As discussed in NUREG-1493 and NEI 94-01, Revision 3-A, Type Band Type C tests can identify the vast majority of all containment leakage paths. This amendment request adopts the guidance in NEI 94-01, Revision 3-A in place of NEI 94-01, Revision 0, but otherwise does not affect the scope, performance or scheduling of Type B or Type C tests. Type B and Type C testing will continue to provide a high degree of assurance that containment leakage rates are maintained well within limits.

Summary of Recent Type Band C Testing A review of the Type B and Type C test results from the spring of 2005 through the fall of 2015 has shown a large amount of margin between the actual as-found and as-left outage summations and the TS leakage rate acceptance criteria (that is, less than 0.6 La).

The as-found minimum pathway leak rate for PBNP Unit 1 shows an average of 7.8 percent of 0.6 La.

The as-left maximum pathway leak rate for PBNP Unit 1 shows an average of 8.5 percent of 0.6 La with a high of 12.0 percent or 0.072 La.

The as-found minimum pathway leak rate for PBNP Unit 2 shows an average of 7.8 percent of 0.6 La.

The as-left maximum pathway leak rate for PBNP Unit 2 shows an average of 7.9 percent of 0.6 La with a high of 13.1 percent or 0.0785 La.

Point Beach Unit 1 Type Band C Leakage Rate Summation History Refueling As-Found Min.

Percentage of As-Left Max.

Percentage of Outaqe Path 0.6La Path 0.6La U1R31 27,651 seem 23.1%

7,041 seem 5.9%

(Fall 2008)

U1R32 13,484 seem 11.2%

10,937 seem 9.1%

(Sprinq 2010)

U1R33 4,353 seem 3.6%

7,974 seem 6.6%

(Fall 2011)

U1R34 2,499 seem 2.1%

7,977 seem 6.7%

(Spring 2013)

. U1R35 4,772 seem 4.0%

10,070 seem 8.4%

(Fall 2014)

U1R36 4,574 seem 3.8%

13,367 seem 11.2%

(Sprinq 2016)

U1R37 8,160 seem 6.8%

14,382 seem 12.0%

(Fall 2017)

Page 7 of 38

Point Beach Unit 2 Type 8 and C Leakage Rate Summation History Refueling As-Found Min.

Percentage of As-Left Max.

Percentage of Outaqe Path 0.6La Path 0.6La U2R29 15,101 seem 12.6%

8,224 seem 6.9%

(Sprinq 2008)

U2R30 10,930 seem 9.1%

15,689 seem 13.1%

(Fall 2009)

U2R31 4,453 seem 3.7%

6,770 seem 5.6%

(Sprinq 2011)

U2R32 3,258 seem 2.7%

11,235 seem 9.4%

(Fall 2012)

U2R33 12,865 seem 10.7%

9,290 seem 7.7%

(Sprinq 2014)

U2R34 5,504 seem 4.6%

9,588 seem 8.0%

(Fall 2015)

U2R35 13,691 seem 11.4%

5,628 seem 4.7%

(Spring 2017) seem = standard cubic centimeters per minute For Unit 1, there has been one local leak rate test failure in the past 36 months. During U1 R37, diaphragm valve 1WL-1721 failed the local leak rate test. 1WL-1721 had been overhauled in U1 R36. As part of the overhaul, the valve was disassembled, inspected, cleaned, and reassembled with new elastomers. Subsequent to the leakage test in U1 R37, it was determined that the body to bonnet bolts had been torqued to the incorrect value in U1 R36, resulting in an under-torqued as-left body to bonnet connection.

For Unit 2, there have been four local leak rate test failures in the past 36 months. During U2R35, air-operated globe valve 2CV-0313A, gate valve 2SA-17, diaphragm valve 2WL-1721, and Penetrations P-17 and P-15 failed their local leak rate tests.

Valve 2CV-0313A had debris preventing the valve from fully closing. The valve was disassembled, cleaned, adjusted and retested with an as-left leakage rate of 4.2 seem.

The leakage associated with valve 2SA-17 was determined to be related to packing leakage at valves 2SA-27 and 2SA-28. The packing was tightened and retested with an as-left leakage of 21 seem.

Valve 2WL-1721 experienced body to bonnet leakage which impacted the test results for valves 2SF-816, 2WL-1003A, 2WL-1003B, and 2WL-1698. The bonnet bolts on valve 2WL-1721 were torqued and retested with an as-left leakage of 29 seem.

Valves 2CC-754A and 2CC-759A-The leakage associated with Penetrations P-17 and P-15 was determined to be leakage at the flanges at the inlet and outlet of a Reactor Coolant Pump oil cooler. The upper oil cooler piping was re-aligned, flanges re-torqued and retested with an as-left leakage of 79.8 seem.

Extension of Type B and C Testing There are performance factors that need to be considered before applying an extended testing interval. For purposes of determining an extended test interval, an assessment of the containment penetration and valve performance has been performed and documented. The Page 8 of 38

following items have been considered in establishing and implementing extended test intervals for Type B and C components:

Past Component Performance - Specific component performance of two successful consecutive as-found Type B or C tests are performed.

Service - The environment and use of components in determining their likelihood of failure based on their performance history.

Design - Valve type and penetration design may contribute to their leakage characteristics.

Safety Impact - The relative importance of penetrations due to the potential impact of failure in limiting releases from containment under accident conditions.

Cause Determination - For failures identified during an extended test interval, a cause determination should be conducted and appropriate corrective actions identified to address common-mode failure mechanisms.

For Type B testing, 5 penetrations for Unit 1 and 6 penetrations for Unit 2 are currently on extended frequency. For both Units 1 and 2, two penetrations (each) are tested when the penetrations are opened. If these penetrations are not opened for multiple outages, the penetrations are eligible for extended frequency testing. Measured leakage for these penetrations has not changed significantly over 120 months.

For Type C testing, there are 42 penetrations at Unit 1, and 42 penetrations at Unit 2. The percentage of eligible penetrations currently on extended frequency supports an extended test interval up to 75 months for Type C tested containment isolation valves (CIVs), in accordance with the guidance of NEI 94-01, Revision 3-A. There are no Type C tested CIVs in a restricted category. The Vent and Purge valves have been modified to include blind flanges inside containment. The number of penetrations on extended frequency is adjusted periodically based on valve performance and other plant testing requirements.

Table 1 - Extended Frequency Percentages Group Number of Number of

% Extended Comment Penetrations Penetrations on Extended Frequency Unit 1 Type B 13 5

38.5%

5 Electrical Pens on 3R Penetrations TypeC 42 31 73.8%

Max Extended frequency is Penetrations 60 months.

Unit2 Type B 14 6

42.9%

1 on 10 Y, 5 Electrical Penetrations penetrations on 3R TypeC 42 29 69.0%

Max Extended frequency is Penetrations 60 months.

Page 9 of 38

Table 2 - Type B Penetrations On Extended Frequency (Most Recent Two Tests)

Penetration Limit Most Recent Leakage Previous 1PQ-58 1PQ-21 1PQ-22 1PQ-28 1PQ-54 2P-67-2 2PQ-58 2PQ-20 2PQ-22 2PQ-1 2PQ-54 Penetration 1P-32b 1P-9 1P-10 1 P-11 1P-12a 1 P-12c 1P-14a 1P-14c (seem)

Test (seem)

Test Unit 1 20 seem U1R37 0 seem U1R35 20 seem U1R37 0 seem U1R35 20 seem U1R37 0 seem U1R35 20 seem U1R37 4 seem U1R35 20 seem U1R37 2 seem U1R35 Unit2 1000 seem U2R31 235 seem U2R30 20 seem U2R35 1 seem U2R34 20 seem U2R35 13 seem U2R33 20 seem U2R35 3 seem U2R33 20 seem U2R35 17 seem U2R34 20 seem U2R35 2 seem U2R33 Table 3 -Type C Penetrations Most Recent Two Tests (Max Path As-Found Leakage)

Valves Limit Most Leakage Previous (seem)

Recent (seem)

Test Test Unit 1 1Sl-879A 1000 seem U1R37 680 seem U1R34 1Sl-879B 1SF-816 1000 seem U1R37 17,600 seem U1R36 1WL-1003A Note 1 1WL-1003B 1WL-1698 1WL-1721 1CV-0369A 1000 seem U1R37 113 seem U1R36 1CV-0371 1CV-0371A 1CV-0294 1000 seem U1R37 1 seem U1R36 1CV-0313A 1CV-0313 1 Dl-09 1000 seem U1R36 0 seem U1R34 101-11

'1WG-1786 1000 seem U1R37 0 seem U1R36 1WG-1787 1RC-528 1000 seem U1R37 95 seem U1R36 1RC-595 1Sl-8340 1000 seem U1R37 17 seem U1R36 1 Sl-846 Page 10 of 38 Leakage (seem) 3 seem 1 seem 1 seem 4 seem 1 seem 226 seem 5 seem 5 seem 13 seem 3 seem 0 seem Leakage (seem) 134 seem 9 seem 133 seem Note2 15 seem Note 2 10 seem 10'SCCm 122 seem Note2 16 seem Note 2

Penetration Valves Limit Most Leakage Previous Leakage (seem)

Recent (seem)

Test (seem)

Test 1P-25c-1 1 H2-V-12 1000 seem U1R37 0 seem U1R35 411 seem 1H2-V-22 1H2-V-13 1H2-V-23 1P-26 1CV-0370 1000 seem U1R36 3 seem U1R33 19 seem 1P-28a 18C-955 1000 seem U1R37 80 U1R34 1 seem 18C-966C 1 P-28b 18C-953 1000 seem U1R37 2 seem U1R36 16 seem 18C-991 Note 2 18C-9668 1 P-28c 18C-951 1000 seem U1R37 145 seem U1R36 14 seem 18C-966A Note 2 1P-29a 1CV-0304C 1000 seem U1R36 1 seem U1R33 3 seem 1 P-29b 1CV-0304D 1000 seem U1R36 2 seem U1R33 4sccm 1 P-30c 1RC-508 1000 seem U1R37 50 seem U1R36 37 seem 1RC-529 Note 2 1P-31b 1H2-V-08 1000 seem U1R36 6sccm U1R33 6 seem 1H2-V-09 1 P-31c 1H2-V-04 1000 seem U1R37 o seem U1R34 0 seem 1H2-V-06 1 H2-V-19 1H2-V-05 1H2-V-07 1H2-V-20 1 P-32c 1CV-1296 1000 seem U1R37 892 seem U1R35 117 seem 1P-33a-1 11A-3047 1000 seem U1R37 90 seem U1R36 325 seem IA-1182 1 P-33b-1 11A-3048 1000 seem U1R35 19 seem U1R34 214 seem IA-1192 1 P-33c 18A-17 1000 seem U1R37 186 seem U1R35 30 seem 18A-27 1 P-34a 1RC-538 1000 seem U1R37 5sccm U1R36 9 seem 1RC-539 1 P-34b 1M8-2083 2000 seem U1R36 142 seem U1R33 3 seem 1 P-34c 1M8-2084 2000 seem U1R36 7 seem U1R33 9 seem 1 P-34d 1WG-1788 1000 seem U1R35 2 seem U1R33 3 seem 1WG-1789 1P-50 1M8-5959 2000 seem U1R37 50 seem U1R36 209 seem 1P-51 1M8-5958 2000 seem U1R37 3 seem U1R36 10 seem 1P-54 181-862A 1000 seem U1R37 69 seem U1R36 15 seem 181-862G Note 2 181-864A 1P-55 181-8628 1000 seem U1R37 20 seem U1R36 265 seem 181-862H Note 2 181-8648 1 P-71 1WL-1723 1000 seem U1R37 89 seem U1R34 2 seem 1WL-1728 Page 11 of 38

Penetration Valves Limit Most Leakage Previous Leakage (seem)

Recent (seem)

Test (seem)

Test 1PX-1 1RM-3200B 500 seem U1R36 29 seem U1R34 52 seem 1RM-3200C 1PX-2 1RM-3200A 500 seem U1R37 186 seem U1R36 83 seem 1RM-3200AA Note 2 1 P-14b None 1000 seem U1R37 3 seem U1R36 3 seem 1 P-31a None 1000 seem U1R~7 4 seem U1R36 3 seem 1 P-32a None 1000 seem U1R37 3 seem U1R36 4 seem 1 P-19 1CC-766 1000 seem U1R36 9 seem U1R33 7 seem 1P-20 1CC-769 1000 seem U1R36 8 seem U1R33 1 seem 1 P-15 1CC-754A 1000 seem U1R36 47 seem U1R33 20 seem 1 P-17 1CC-759A 1000 seem U1R36 40 seem U1R33 20 seem 1P-16 1CC-754B 1000 seem U1R35 800 seem U1R33 20 seem 1 P-18 1CC-759B 1000 seem U1R35 128 seem U1R33 20 seem Unit 2 2P-32b 2Sl-879A 1000 seem U2R35 12 seem U2R32 49 seem 2Sl-879B 2P-9 2SF-816 1000 seem U2R35 2700 seem U2R34 2 seem 2WL-1003A Nole 1 2WL-1003B 2WL-1698 2WL-1721 2P-10 2CV-0369A 1000 seem U2R35 82 seem U2R34 133 seem 2CV-0371 Note 2 2CV-0371A 2P-11 2CV-0294 1000 seem U2R35 11483 seem U2R34 215 seem 2CV-0313A Note 1 Note2 2CV-0313 2P-12a 2Dl-11 1000 seem U2R35 O seem U2R34 2 seem 201-9 2P-12c 2WG-1786 1000 seem U2R35 0 seem U2R33 0 seem 2WG-1787 2P-14a 2RC-528 1000 seem U2R35 0 seem U2R34 4 seem 2RC-595 Note 2 2P-14c 2Sl-834D 1000 seem U2R35 24 seem U2R34 199 seem 251-846 2P-42c-2 2H2-V-12 1000 seem U2R35 20 seem U2R32 42 seem 2H2-V-22 2H2-V-13 2H2-V-23 2P-26 2CV-0370 1000 seem U2R35 572 seem U2R34 6 seem 2P-28a 2SC-955 1000 seem U2R35 37 seem U2R33 7 seem 2SC-966C 2P-28b 2SC-953 1000 seem U2R35 0 seem U2R34 2 seem 2SC-991 Note2 2SC-966B Page 12 of 38

Penetration Valves Limit Most Leakage Previous Leakage (seem)

Recent (seem)

Test (seem)

Test 2P-28c 28C-951 1000 seem U2R35 464 seem U2R32 213 seem 28C-966A 2P-29a 2CV-0304C 1000 seem U2R35 0 seem U2R32 2 seem 2P-29b 2CV-0304D 1000 seem U2R35 0 seem U2R32 2 seem 2P-30c 2RC-529 1000 seem U2R35 25 seem U2R34 0 seem 2RC-508 Note 2 2P-31b 2H2-V-08 1000 seem U2R35 2 seem U2R34 4 seem 2H2-V-09 2P-31c 2H2-V-04 1000 seem U2R35 20 seem U2R32 30 seem 2H2-V-06 2H2-V-19 2H2-V-05 2H2-V-07 2H2-V-20 2P-32c 2CV-1296 1000 seem U2R33 0 seem U2R32 5 seem 2P-33a-2 IA-1314 1000 seem U2R35 42 seem U2R32 188 seem 21A-3047 2P-33b-2 21A-3048 1000 seem U2R33 74 seem U2R32 48 seem IA-1324 2P-33c 28A-17 1000 seem U2R35 1005 seem U2R34 390 seem 28A-27 Note 1 Note 2 2P-34a 2RC-538 1000 seem U2R35 45 seem U2R32 37 seem 2RC-539 2P-34b 2M8-2083 2000 seem U2R35 1 seem U2R34 124 seem 2P-34c 2M8-2084 2000 seem U2R33 23 seem U2R31 0 seem 2P-34d 2WG-1788 1000 seem U2R35 30 seem U2R34 2 seem 2WG-1789 2P-50 2M8-5958 2000 seem U2R35 296 seem U2R32 168 seem 2P-51 2M8-5959 2000 seem U2R35 103 seem U2R32 190 seem 2P-54 281-862A 1000 seem U2R35 200 seem U2R34 202 seem 281-862G Note 2 281-864A 2P-55 281-8628 1000 seem U2R35 70 seem U2R34 56 seem 281-862H Note2 281-8648 2P-71 2WL-1723 1000 seem U2R35 30 seem U2R32 20 seem 2WL-1728 2PX-1 2RM-32008 500 seem U2R34 122 seem U2R33 113 seem 2RM-3200C 2PX-2 2RM-3200A 500 seem U2R35 9 seem U2R34 112 seem 2RM-3200AA Note 2 2P-148 None 1000 seem U2R35 1 seem U2R32 2 seem 2P-31A None 1000 seem U2R35 480 seem U2R32 4 seem 2P-32A None 1000 seem U2R35 1 seem U2R32 2 seem 2P-19 2CC-766 1000 seem U2R35 443 seem U2R32 536 seem 2P-20 2CC-769 1000 seem U2R35 648 seem U2R32 370 seem 2P-15 2CC-754A 1000 seem U2R35 6401 seem U2R32 74 seem Page 13 of 38

Penetration Valves Limit Most Leakage Previous Leakage (seem)

Recent (seem)

Test (seem)

Test Note 1 2P-17 2CC-759A 1000 seem U2R35 6401 seem U2R32 72 seem Note 1 2P-16 2CC-754B 1000 seem U2R33 101 seem U2R32 172 seem 2P-18 2CC-7598 1000 seem U2R33 520 seem U2R32 232 seem Note 1: For Penetrations 1 P-9, 2P-9, 2P-33C, 2P-11, 2P-15 and 2P-17, the as-found leakage exceeded the administrative limit. These penetrations are currently tested every refueling outage, and may be returned to extended test frequency after meeting the performance criteria.

Note 2: The penetrations listed above are eligible for extended testing frequency under the rules of NEI 94-01, Revision 3A. Valves associated with some penetrations are leak tested on a more frequent basis to meet the needs of other programmatic activities such as lnservice Testing Program (IST), Air Operated Valve (AOV) Program, Motor Operated Valve (MOV) program or Post Maintenance Testing Requirements.

Specific testing frequencies for the Appendix J local leak rate tests are reviewed prior to every refueling outage (18-month cycle). An outage scope document is issued to document local leak rate test periodicity and to ensure pre-maintenance and post-maintenance testing is complete.

The post-outage report provides a written record of extended testing interval changes and reasons for the changes based upon testing results, trending and maintenance history.

Based on the above measures, the LLRT program will provide continuing assurance that the most likely sources of leakage will be identified and repaired.

3.2 CONTAINMENT INSPECTIONS General visual examinations of the accessible surfaces of the primary containment are performed in accordance with the 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 IWE and IWL. These examinations are performed in sufficient detail to identify areas of the metal containment liner or concrete structure deterioration and distress.

Detailed visual examinations are performed to determine the magnitude and extent of deterioration of suspect surfaces initially detected by general visual examinations in the containment structure. 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 Containment lnservice Inspection Program discussed in Section 3.2.1. This program includes provisions to satisfy the visual examination requirements of ASME Code Section XI, Subsection IWE and 10 CFR 50, Appendix J, Option 8. 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 Page 14 of 38

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 3.2.4. 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 every refueling outage. This program is implemented to ensure that the integrity of the coatings is maintained in accordance with the PBNP 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 significant signs of paint blistering, peeling, or corrosion.

3.2.1 Containment lnservice Inspection Program PBNP has established a containment lnservice Inspection Program in accordance with 10 CFR 50.55a for Class MC components. The third IWE inspection interval has been developed in accordance with the requirements of the 2007 Edition with the 2008 Addenda of the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE, as modified by 10 CFR 50.55a. The scope of the program includes the accessible pressure retaining containment surface areas including: Containment vessel liner surfaces and integral attachments, surfaces requiring augmented examination, mechanical/electrical penetrations, moisture barriers, pressure retaining bolting and Appendix J tested IWE components. The first 10-year inspection interval was conducted in accordance with the ASME IWE 1992 Edition with the 1992 Addenda. The second 10-year inspection interval, from September 2007 through September 2016, applied Subsection IWE, 2001 Edition with the 2003 Addenda. The third 10-year inspection interval, from September 2016 to September 2026, will apply Subsection IWE, 2007 Edition with the 2008 Addenda.

Each 10-year inspection interval consists of three examination periods. A visual examination of interior and exterior containment vessel surface areas is required each period by ASME Section XI and is implemented by the PBNP IWE Containment Inspection Program.

The IWL Inspection Program identifies the ASME Section XI Subsection IWL component or items that are required to be examined in accordance with the 2007 Edition with the 2008 Addenda of the ASME Boiler and Pressure Vessel Code within the limitations as well as modifications required by Title 10 of the Code of Federal Regulation, Part 50.55a, Codes and Standards. The scope of the IWL portion of the program includes surveillance of accessible concrete surface areas and the unbonded post-tensioning system, including tendons, tendon wires or strands, anchorage hardware and surrounding concrete, corrosion protection medium and testing for evidence of free water. The first interval program was developed and implemented in accordance with the 1992 Edition 1992 Addenda of the Code. The first 10-year inspection interval was established from September 9, 1996, to September 9, 2006, and was extended to September 9, 2007, as permitted by IWA-2430(d), 1992 Edition 1992 Addenda. The second inspection interval was established from September 9, 2007 to September 9, 2016 and implemented in accordance with the 2001 Edition 2003 Addenda of the code. The third 10-year inspection interval, from September 10, 2016 to September 2026, will apply Subsection IWL, 2007 Edition with the 2008 Addenda.

Page 15 of 38

The containment lnservice inspection program is not affected by the proposed amendment for Appendix J testing. Tendon surveillances will continue to be performed on a 5-year frequency as required by IWL-2400. Therefore, even though the proposed amendment will extend the ILRT testing frequency for 5 additional years, the IWE and IWL examinations, tendon surveillances and associated requirements will continue to provide assurance that degradation of the containment will be detected and corrected before it can result in a leakage path.

Approved Alternatives to Subsection IWE Requirements For the third IWE lnservice inspection interval, there are no relief requests or other NRC approved alternatives being implemented.

For the third IWL lnservice inspection interval, there are no relief requests or other NRC approved alternatives being implemented.

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 PBNP are summarized in the tables below:

Page 16 of 38

Table 4 - Current IWE/IWL Interval System Examination Item Examination Period Schedules Identification Description Number Method Examination Category E-A 1

2 3

Containment Accessible Surface E1.11 GV x

x x

Liner Areas Pressure Retaining E1.11 GV x

x x

Bolting Moisture Barrier E1.30 GV x

x x

Examination Category E-C 1

2 3

Containment Visible Surfaces E4.11 VT-1 (Note 2) x x

x Liner Surface Area Grid E4.12 UTT x

x x

Minimum Wall Thickness Location Examination Category E-G Containment Pressure Retaining E8.10 VT-3 (Note 1) x Liner BoltinQ Examination Category L-A 38 yr 43 yr 48 yr Concrete Concrete Surface -

L 1.11 GV U1/U2 U1/U2 U1/U2 Surfaces All Accessible Surface Area Concrete Surface -

L 1.12 GV U1/U2 U1/U2 U1/U2 Suspect Areas Examination Category L-B Tendon Tendon L.2.10 Per IWL-2522 U1 U2 U1 Wire or strand L.2.20 Per IWL-U1 U2 U1 2523.2 Anchorage hardware L.2.30 Detailed U1/U2 U1/U2 U1/U2 and surrounding Visual concrete Corrosion protection L.2.40 Per IWL-2525 U1/U2 U1/U2 U1/U2 medium Free water L.2.50 Per IWL-2525 U1/U2 U1/U2 U1/U2 Item Number Refers to item numbers listed in ASME Code Section XI, 2007 Edition with the 2008 Addenda Table IWE-2500-1 or Table IWL-2500-1.

Exam Method:

GV - General Visual UTT-Ultrasonic Thickness Test VT examination method defined in ASME Code Section XI, Paragraph IWA-2213, "VT -3 Examination" VT examination method defined in ASME Code Section XI, Paragraph IWA 2211, "VT-1 Examination" Notes:

1. An examination of the pressure-retaining bolted connections in Item E1.1 of Table IWE-2500-1 using the VT-3 examination method must be conducted Page 17of38

Schedule:

once each interval per 10 CFR 50.55a(b)(2))(ix)(G). Per 10 CFR 50.55a(b)(2))(ix)(H), containment bolting that is disassembled during scheduled performance of the examinations in Item E1.11 of Table IWE-2500-1 must be examined using the VT-3 method.

2. Required per 10 CFR 50.55a(b)(2)(ix)(G).

3. The Unit 1 and Unit 2 38 year surveillances were completed in 2009 and 43 year surveillances were completed in 2014. The 48 year surveillances are scheduled for Units 1 and 2 in 2019.

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.

IWE Examination Category E-C, Item No. E4.11 and E4.12 - Containment Surfaces Requiring Augmented Examination This category includes IWE component areas selected for augmented examination because of known existing degraded conditions. Surface areas likely to experience accelerated degradation and aging require augmented examination. In addition, interior containment surfaces that are subject to excessive wear causing a loss of protective coatings, deformation or material loss are also examined. Examination methods are detailed visual examinations (VT-1) and ultrasonic testing (UT). PBNP specific cases are:

Units 1 and 2 Containment Horizontal Liner Plate at El. 6'-6":

Access to the El. 6'-6" horizontal liner plate is achieved through seven core drilled holes through the El. 8' floor in Unit 1, and four core drilled holes through the El. 8' floor in Unit 2.

These core drilled holes were installed in 1988 as a result of standing water discovered on the El. 8' of containment. They provided access to monitor the corrosion rate of the horizontal liner plate. Corrosion probes were originally installed in two core drilled holes for each unit and conductivity was measured to monitor corrosion rate. Caulking was installed as a moisture barrier at the same time to prevent water from accessing the horizontal liner plate at El. 6' 6". The moisture barriers and liners are examined in accordance with the IWE program.

Containment IWE Inspections Recent Liner Plate Surface Examinations:

Unit 1 - Visual Examination of Containment Liner Plates was performed during U1 R37 2017.

Chipping, discoloration and rust spots were noted in the liner coating at a number of locations on the floor and wall liner plates. The examination results of the individual panels were reviewed versus the results of previous examinations. While there are some new chips/scratches in the liner coating, they are similar to those previously identified and reviewed. The VT-1 examinations on the areas found no evidence of on-going degradation.

Small areas of missing coatings (some with, and some without signs of corrosion) were identified. The VT-1 examinations on the areas found no evidence of on-going degradation.

The areas with rust indications were reviewed, and those indications are considered to be very light surface corrosion, with no sign of actual wall loss. As such, these indications would not affect the function of the liner, nor any of the structural steel where they were identified.

Page 18 of 38

VT-1 examinations were performed for areas of previously identified indications. These inspections identified no evidence of on-going degradation.

Unit 2 - Visual Examination of Containment Liner Plates was performed in U2R35 in the spring of 2017. Chipping, discoloration and rust spots were noted in the liner coating at a number of locations on the floor and wall liner plates. The examination results of the individual panels were reviewed versus the results of previous examinations. While there are some new chips/scratches in the liner coating, they are similar to those previously identified and reviewed. The VT-1 examinations on the areas of recordable indications found no evidence of on-going degradation.

Discoloration of the coating was determined to be an acceptable condition. In most cases, the discoloration is due to leakage of some substance onto the coating. In the identified conditions, there was no evidence that the coating is degrading (blistering, cracking, or peeling) that would be indicative of substance adversely affecting the coating, and therefore, the underlying liner/structural steel is considered to be not affected also.

The areas with rust indications were reviewed, and those indications are considered to be very light surface corrosion, with no sign of actual wall loss. As such, these indications would not affect the function of the liner nor any of the structural steel where they were identified.

The rusted areas identified in the vicinity of Sump A showed little change over the last 6 years. These areas were prepped and underwent UT, with the resulting thickness readings showing that none of the readings are less than nominal liner plate thickness; therefore, the intended function of the liner is not affected. UT results from previous outages were also compared to the results obtained this outage. Previous UT locations were in the vicinity of the readings from this outage, but they were coated, and thus showed thicknesses a bit above those from this outage. The areas that were prepped for UT this outage, were subsequently re-coated prior to startup.

The VT-1 inspections of the recordable indications confirmed that these areas are not experiencing any appreciable degradation/wall loss, and therefore would not have any effect on the function of the liner.

==

Conclusion:==

With no damage or degradation to the liner evident, and no apparent changes at previously identified locations, the recorded conditions are considered acceptable.

Moisture Barrier Examinations:

Unit 1 - The Unit 1 containment moisture barriers were examined during U1 R35. This exam identified no areas of damaged or improperly adhered moisture barrier.

Condusion:

Since the entire moisture barrier was inspected, and no recordable indications were identified that required repair, no additional, successive, or supplemental exams are required.

Unit 2 - The Unit 2 containment moisture barriers were examined during U2R35. This exam identified six areas of the moisture barrier that were damaged or not adhered to the mating surface. Since the moisture barrier's primary purpose is to prevent moisture from seeping Page 19 of 38

down joints onto inaccessible portions of the carbon steel liner, it was recommended that these locations be repaired. These repairs were performed prior to startup from U2R35.

==

Conclusion:==

Since the entire moisture barrier was inspected, and recordable areas were repaired by corrective action, no additional, successive, or supplemental exams are required.

Containment IWL Inspections lnservice examinations of containment concrete Class CC components of PBNP Unit 1, performed in conjunction with tendon surveillance on a five year interval, have found:

• Grease leakage observed at tendon grease cans

• Exposed corroded reinforcing steel with pop outs

• Exposed reinforcing steel with corrosion

• Minor concrete cracking observed consistent with previous recorded indications The findings noted above for Unit 1 were evaluated and determined to not be detrimental to either the structural integrity or leak tight integrity of the containment structure.

lnservice examinations of containment concrete Class CC components of PBNP Unit 2, performed in conjunction with tendon surveillance on a five year interval, have found:

• Grease leakage at tendon grease cans

• Exposed corroded reinforcing steel with pop outs

• Concrete cracking showing no change from previously recorded indications

• Grease on Containment Dome parapet The findings noted above for Unit 2 were evaluated and determined to not be detrimental to either the structural integrity or leak tight integrity of the containment structure.

3.2.2 Containment Visual Inspection Containment and containment enclosure surface inspection procedure, NOE 762, for PBNP is 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 5.5.15 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 ten years, in order to allow for early uncovering of evidence of structural deterioration.)

The PBNP Containment Leak Rate Testing Program requires that these examinations be conducted prior to initiating a Type A test and during two other refueling outages before the next Type A test.

Page 20 of 38

With the implementation of the proposed change, Technical Specification 5.5.15 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.

The PBNP Containment Leak Rate Testing Program credits the detailed method and schedule for inspecting the accessible interior and exterior surfaces of the containment structure for structural deterioration in accordance with the ASME Section XI, Subsection IWE/IWL Containment Inspection Programs for these visual examinations. Additionally, the tests will continue to be performed to meet the requirements of Technical Specification 5.5.15 with the incorporation of NEI 94-01, Revision 3-A guidelines.

3.2.3 Inaccessible Areas For Class CC and MC applications, PBNP 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, PBNP shall provide the following in the ISi 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.

A description of the corrective action.

NextEra has not needed to implement new technologies to perform inspections of inaccessible areas at this time. However, NextEra 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 PBNP. 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.

3.2.4 Containment Coatings Inspections The PBNP Containment Coatings Program, ER-AA-109, 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 building. These inspections assure compliance with the PBNP response to NRC Generic Letter 2004-02, "Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors."

Results of Recent Coatings Inspections Unit 1 - Inspections of the coatings in the Unit 1 reactor containment building were completed in U 1 R37 in the fall of 2017 and assessed by Engineering. The assessment was compared with the previous containment coating assessment from U1 R36 in accordance with license basis requirements and coating program procedures. The polar crane coatings also were inspected and results were consistent with the existing unqualified coatings log with no changes required.

Overall, no significant findings were identified. The condition of the containment coatings was Page 21of38

acceptable and no immediate corrective actions were required to meet design and license basis requirements. Some minor repairs were initiated to improve the material condition and margin with respect to the amount of unqualified coatings. The total quantity of unqualified coatings remains within the bounds required by design basis, with considerable margin remaining.

Unit 2 - Inspections of the coatings in the Unit 2 reactor containment building were completed in U2R35 in the spring of 2017 and assessed by Engineering. The assessment was compared with the previous containment coating assessment from U2R34 in accordance with license basis requirements and coating program procedures. Overall, no significant findings were identified. The condition of the containment coatings was acceptable and no immediate corrective actions were required to meet design and license basis requirements. Some desired minor repairs were initiated to improve the material condition and margin with respect to the amount of unqualified coatings in containment. The total quantity of unqualified coatings remains within the bounds required by design basis, with considerable margin remaining.

3.2.5 Maintenance Rule The containment isolation function of limiting the release of radioactive fission products following an accident has been classified as high risk significant and its condition is monitored pursuant to 10 CFR 50.65 in accordance with the PBNP Maintenance Rule program. Operability of the containment isolation equipment is ensured by compliance with TS Sections 3.6 and 5.5. The proposed amendment affects only the ILRT and LLRT test intervals and does not impact the PBNP Maintenance Rule program.

3.3 NRC Information Notices The NRG has issued several information notices concerning containment corrosion.

NextEra reviewed these notices to determine the impact on the PBNP containment.

Information Notice 92-20, "Inadequate Local Leak Rate Testing," dated March 3, 1992 Information Notice (IN) 92-20, "Inadequate Local Leak Rate Testing," dated March 3, 1992 (Reference 6.8), stated that problems exist with testing of stainless steel containment penetration bellows. Specifically, in-leakage through such bellows may not be readily detectable by LLRTs. The testing deficiency can occur if the test tap pressurizes between the two sheets of bellows materials. The PBNP mechanical penetrations sealed with a bellows arrangement are located outside of containment and are not subjected to containment pressure. The portion of the mechanical penetrations inside containment that provide the containment pressure boundary is tested during the Type A test by removing the mechanical penetration plug outside containment to ensure full differential test pressure across the mechanical penetration weld to the liner plate (e.g., single passive barrier).

Information Notice 2011-15, "Steel Containment Degradation and Associated License Renewal Aging Management Issues," dated August 1, 2011 IN 2011-15, "Steel Containment Degradation and Associated License Renewal Aging Management Issues," dated August 1, 2011 (Reference 6.13) describes mechanisms that can lead to degradation of coatings and pitting of containment liner plates due to long term exposure to water and moisture. Similar degradation mechanisms were described in IN 2004-09, "Corrosion of Steel Containment and Containment Liner," dated April 27, 2004 (Reference 6.9), which stated that over time, the existing floor-to-containment seal can degrade, allowing moisture into the crevice between the containment liner plate and floor and that small amounts of stagnant water behind the floor seal area promote pitting corrosion.

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Although not referenced in IN 2011-15, IN 2010-12, "Containment Liner Corrosion," dated June 18, 2010 (Reference 6.10), provided additional examples of containment liner degradation caused by corrosion. The operating experience described in IN 2011-15 relates to containment liner corrosion that results from the liner plates being in contact with objects and materials that are lodged between or embedded in the containment concrete. Liner locations that are in contact with objects made of an organic material are susceptible to accelerated corrosion because organic materials can trap water that combined with oxygen will promote carbon steel corrosion.

At PBNP, water intrusion into inaccessible areas has been experienced in the past. Water was found to have seeped through expansion joints in the concrete floor of the 8-foot elevation. As a result, holes have been bored into the concrete floors on the 8-foot elevation and in the keyways in both containments to allow examination of small portions of containment liner under the concrete floor in these locations. PBNP has continued to periodically examine the liner plates through these holes. Under the IWE program, areas of missing paint are VT, and sometimes UT, examined and where susceptible to the deleterious effects of moisture are typically recoated to inhibit corrosion.

Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner," dated May 5, 2014 Information Notice 2014-07, "Degradation Of Leak-Chase Channel Systems For Floor Welds of Metal Containment Shell And Concrete Containment Metallic Liner," dated May 5, 2014 (Reference 6.11 ), provided examples of operating experience at some plants of water accumulation and corrosion degradation in the leak-chase channel system that has the potential to affect the leak-tight integrity of the containment shell or liner plate. PBNP does not have a configuration of leak chase channel vents as described in IN 2014-07. Activities were completed in response to IN 2014-07 to identify the locations of the leak chase channel vents for future reference. These walkdowns confirmed the LCC vents are not as described in IN 2014-07.

While PBNP does not have the LCC vent configuration described in IN 2014-07, core holes were drilled through the floor down to the liner plate, as discussed in Section 3.3. These core holes were made to allow monitoring of the liner for degradation due to moisture intrusion. In U1, nine core holes were made, and in U2, six core holes were made.

UT thickness data from the liner in these core holes was monitored over ten years on both units, with no signs of significant wall thinning. One core hole from each unit is monitored each period and the remaining core holes are monitored once per interval.

3.4 NRC Limitations and Conditions for NEI 94-01 3.4.1 June 25, 2008 NRC Safety Evaluation The limitations and conditions from the June 25, 2008 safety evaluation (Reference 6.18) for NEI 94-01, Revision 2 are presented in the table below with the NextEra response.

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June 25, 2008 NRC Safety Evaluation (SE) Limitations and Conditions Limitation/Condition (From Section 4.1 of Safety Evaluation)

1. For calculating the Type A leakage rate, the licensee should use the definition in NEI TR 94-01, Revision 2, in lieu of that in ANSl/ANS-56.8-2002. (Refer to SE Section 3.1.1.1 ).

2. The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3)

3. The licensee addresses the areas of containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3).

4. The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4).

5. The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provisions of section 9.1 or NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to SE Section 3.1.1.2).

Response for PBNP PBNP will utilize the definition in NEI 94-01, Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

Reference Section 3.2.1 and 3.2.2.

General visual observations of the accessible interior and external surfaces of the containment structure shall continue to be performed in accordance with containment structural integrity test procedures to meet the requirements of the proposed revision to TS 5.5.15, the inspection requirements of ASME Code Section XI, subsection IWE and NEI 94- 01, Revision 3-A, Sections 9.2.1 and 9.2.3.2.

Reference Section 3.2.1 through 3.2.4.

General visual observations of the accessible interior and external surfaces of the containment structure shall continue to be performed in accordance with containment structural integrity test procedures to meet the requirements of the proposed revision to TS 5.5.15, the inspection requirements of ASME Code Section XI, subsection IWE and NEI 94- 01, Revision 3-A, Sections 9.2.1 and 9.2.3.2.

In general, the NRC staff considers the cutting of a large hole in the containment for replacement of steam generators or reactor vessel heads, replacement of large penetrations, as major repairs or modifications to the containment structure.

PBNP has performed no major repairs or modifications to the containment structure.

No major repairs or modifications are planned.

PBNP will follow the requirements of NEI 94-01, Revision 3-A, Section 9.1. This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

In accordance with Section 3.1.1.2 of the NRC safety evaluation dated June 25, 2008 (Reference 6.18), NextEra will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15 year interval is required. Justification for such an extension request will be in accordance with Page 24of38

Limitation/Condition Response for PBNP (From Section 4.1 of Safety Evaluation) the staff position in Regulatory Issue Summary (RIS) 2008-27.

6. For plants licensed under 10 CFR Part 52, Not applicable. PBNP was not licensed under applications requesting a permanent 10 CFR Part 52.

extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design has been completed and applicants have confirmed the applicability of NEI TR 94-01, Revision 2, and [Electric Power Research Institute] EPRI No. 1009325, 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 (Reference 6.2) for NEI 94-01, Revision 3 are stated below with the NextEra response.

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 non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs to be increased to 75 months with the requirement that a licensee's post-outage report include the margin between 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 [Main Steam Isolation Valves]), 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 T apical Report Condition 1.

Response to Condition 1 Condition 1 presents three (3) separate issues that are addressed as follows:

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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.

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 PBNP administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.60 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the PBNP 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:

PBNP 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 LLRTs 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.

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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.

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 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, PBNP 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 greater than 60 month (up to 75 month) extended test interval. This will result in a combined conservative Type C total for all 60-75 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 greater than 60 month (up to 75 month) extended interval is summed with the non-adjusted total of those Type C components being tested at less than the 60-75 month interval and the total of the Type B tested components, if the minimum pathway leak rate is greater than the PBNP administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.60 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.

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 Page 27 of 38

and 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 B 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 B, and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSl/ANS-56.8-2002 and shall be available on-site for NRG 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 B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B 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 Band 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.

An adverse trend is defined as three consecutive increases in the 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 PBNP Type A test interval from the current ten 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 15 years. The approach is consistent with that presented in:

Appendix Hof Electric Power Research Institute, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325," EPRI Topical Report TR-1018243, dated October 2008 (Reference 6.5);

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, Calvert Cliffs liner corrosion analysis described in a letter to the NRG dated March 27, 2002 (Reference 6.19).

The analysis uses results from PBNP's analysis of core damage scenarios (Level 1) and subsequent containment responses (Level 2) resulting in various fission product release categories (including intact containment or negligible release).

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In the safety evaluation issued by NRC letter dated June 25, 2008 (Reference 6.18), the NRC concluded that the methodology in EPRI Report No. 1009325, Revision 2 (Reference 6.4 ), is acceptable for referencing by licensees proposing to amend their TS 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 Report No. 1009325, Revision 2.

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EPRI Report No. 1009325, Revision 2, Limitations and Conditions Conditions Response for PBNP (From Section 4.2 of NRC Safety Evaluation dated June 25, 2008)

1. The licensee submits documentation that The PBNP technical adequacy is addressed the technical adequacy of their (probabilistic in Section 3.5.2.

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 Report No. 1009325, Revision 2-A, indicating that the estimated risk increase incorporates these population dose and associated with permanently extending the conditional containment failure probability ILRT surveillance interval to 15 years is small, acceptance guidelines, and these guidelines.

and consistent with the clarification provided in have been used for the PBNP plant-specific Section 3.2.4.51 of this [safety evaluation] SE.

risk assessment.

Specifically, a small increase in population The increase in population dose is discussed dose should be defined as an increase in in Section 3.5.3.

population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive.

In addition, a small increase in [conditional The increase in conditional containment containment failure probability] CCFP should failure probability is discussed in Section be defined as a value marginally greater than 3.5.3.

that accepted in 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 points.

3. The methodology in EPRI Report No.

EPRI Report No. 1009325, Revision 2-A, 1009325, Revision 2, is acceptable except for incorporates the use of 100 La as the the calculation in the increase in expected average leak rate for the pre-existing population dose (per year of reactor containment large leakage rate accident operation). In order to make the methodology case (accident class 3b), and this value has acceptable, the average leak rate for the pre-been used in the PBNP plant-specific risk existing containment large leak rate accident assessment.

case (accident case 3b) used by the licensees shall be 100 La instead of 35 La.

4. A [license amendment request] LAR is PBNP does not rely on containment required in instances where containment overpressure for ECCS performance.

overpressure is relied upon for [emergency core coolinq system] ECCS performance.

1 The SE for EPRI Report No. 1009325, Revision 2, indicates that the clarification regarding small increases in risk is provided in Section 3.2.4.5; however, the clarification is actually provided in Section 3.2.4.6.

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3.5.2 Probabilistic Risk Assessment (PRA) Acceptability The PBNP Internal Events, Internal Flood, and Fire PRA models have been peer reviewed and there are no PRA upgrades that have not been peer reviewed. The PRA models credited in this request are the PRA models used in the NFPA 805 application (References 8.44 and 8.45 of ) and the Surveillance Frequency Control Program (SFCP) application (Reference 8.46 of Enclosure 4), with routine maintenance updates applied. Capability Category (CC) II of the NRG-endorsed AS ME/ANS PRA Standard is the target capability level for both of these applications. The acceptability (previously referred to as technical adequacy or quality) of the PRA models was reviewed by the NRG for these respective applications and determined to be acceptable, as discussed in the Safety Evaluations, dated September 8, 2016 and July 28, 2015 (References 8.36 and 8.38 of Enclosure 4).

As stated in the NRG Final Safety Evaluation for NEI 94-01, Revision 2 and EPRI Report No. 1009325, Revision 2 (Reference 8.29 of Enclosure 4), CC I of the ASME PRA Standard shall be applied as the standard for assessing PRA quality for ILRT extension applications, as approximate values of core damage frequency (GDF) and LERF and their distribution among release categories, are sufficient to support the evaluation of changes to ILRT frequencies. The NRG Safety Evaluation also states the assessment of external events can be taken from existing, previously submitted and approved analyses or other alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval. Therefore, the ILRT interval extension risk assessment is allowed to use the existing Internal Flooding and Fire PRA models and other existing seismic and external hazard evaluations.

Appendix A 1 of Enclosure 4 provides a more detailed discussion of the external hazard evaluations and the PRA acceptability for the ILRT interval extension risk impact assessment.

The information in Appendix A 1 of Enclosure 4 demonstrates that the PRA is of sufficient quality and level of detail to support this submittal, and has been subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRG.

3.5.3 Conclusions of the Plant-Specific Risk Assessment Results The findings of the PBNP 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 PBNP plant-specific results for extending the Type A test interval from three in ten years to one in 15 years is summarized below.

Core Damage Frequency (GDF) is not impacted by the proposed change. PBNP does not 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 (Reference 6.6) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Regulatory Guide 1.17 4 defines very small changes in risk as resulting in increases of GDF less than 1 E-06 per reactor year and increases in Large Early Release Frequency (LERF) less than 1 E-07 per reactor year.

There is no quantifiable change in GDF as a result of the proposed ILRT Type A test interval extension. Therefore, the Regulatory Guide 1.17 4 acceptance guideline for a "very small" change in GDF is considered to be met as the impact on GDF for the Type A test interval extension is negligible. Thus, the relevant acceptance criterion is LERF.

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With consideration of liner corrosion included, the increase in LERF resulting from a change in the Type A ILRT test interval from three in ten years to one in 15 years is conservatively estimated for Unit 1 as 4.68E-08/yr due to internal events contribution; and, 6.11 E-07/yr due to internal flood and external events. The total combined impact for Unit 1 is 6.58E-07/yr. For Unit 2, the impact is conservatively estimated as 4.67E-08/yr due to internal events contribution; and, 7.01 E-7/yr due to internal flood and external events. The total combined impact for Unit 2 is 7.48E-7 /yr.

The impact due to an increase in the Type A ILRT interval to one in 15 years is "very small" when considering only internal events. Regulatory Guide 1.17 4 (Reference 6.6) also states that when the calculated increase in LERF is in the "small" 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. When including the impact from internal flood and external events, the change to LERF is in the "small" range for both PBNP Unit 1 and Unit 2. Therefore, the total LERF is evaluated. The resulting total LERF for Unit 1 is approximately 3.0E-06/yr. The resulting total LERF for Unit 2 is approximately 3.2E-06/yr. The total LERF for both Unit 1 and Unit 2 are below the RG 1.17 4 acceptance criteria for total LERF of 1.0E-05/yr and therefore this change satisfies both the incremental and absolute criteria with regard to the RG 1.17 4 LERF metric.

The calculated increase in the total 50-mile population dose risk for the proposed ILRT Type A interval change from three per ten 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.SSE-02 person-rem/yr for Unit 1 and 2.88E-02 person-rem/yr for Unit 2 when considering internal events only. Including the effect of internal flood and external events, the total change in plant risk is 0.405 person-rem/yr for Unit 1 and 0.461 person-rem/yr for Unit 2. EPRI Report No. 1009325, 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 one percent of the total population dose, whichever is less restrictive. Thus, the estimated 50-mile population dose increase at PBNP is very small using the guidelines of EPRI Report No. 1009325, Revision 2-A.

The increase in the conditional containment failure probability from the three per ten years to once in 15 years Type A test interval including corrosion effects is 0.92% for both Unit 1 and Unit 2. EPRI Report No. 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 PBNP.

In summary, based on the above results, the proposed 15-year Type A test interval represents a very small change in risk and is acceptable as a permanent change.

Details of the PBNP risk assessments are contained in Enclosure 4 of the LAR.

3.6 Conclusion NEI 94-01, Revision 3-A, describes an NRG accepted approach for implementing the performance-based requirements of Appendix J, Option B. It incorporates the 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.

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Based on the previous Type A tests conducted at PBNP, extension of the containment Type A test interval from ten to 15 years represents minimal risk to increased leakage. The risk is further 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 PBNP inspection programs:

Primary Containment lnservice Inspection Program Containment Coatings Inspection and Assessment Program This experience is supplemented by risk analysis studies, including the PBNP risk analysis provided in Enclosure 4. The findings of the risk assessment confirm the general findings of previous industry studies, on a plant-specific basis, that extending the Type A test interval from ten to 15 years results in a very small and acceptable change to the PBNP baseline risk.

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4.0 REGULATORY SAFETY ANALYSIS 4.1 Significant Hazards Consideration NextEra Energy Point Beach, LLC (NextEra) requests a license amendment to revise Point Beach Technical Specifications (TS) 5.5.15.a, "Containment Leakage Rate Testing Program," to require a program that is 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." This change 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.

Next Era has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment," as discussed below:

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

Response: No The proposed amendment adopts the NRG-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 PBNP 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 PBNP 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, an extension of the leak test interval in accordance with NEI 94-01, Revision 3-A 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 containment 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 change does. not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No Page 34 of 38

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.

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

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

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

Response: No Margin of safety is related to confidence in the ability of the fission product barriers (fuel cladding, reactor coolant system, and primary containment) to perform their design functions during and following postulated accidents. The proposed change to implement a performance-based containment testing program, associated with integrated leakage rate test and local leak rate testing 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 TS Containment Leakage 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 TS 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 change does not involve a significant reduction in a margin of safety.

4.2 Precedent This license amendment request is similar to Amendment No. 153 which was approved for Seabrook Station on March 15, 2017 (Reference 6.7). The amendment approved a containment leakage rate testing program for Seabrook in accordance with the guidelines contained in NEI 94-01, Revision 3-A, and conditions and limitations specified in NEI 94-01, Revision 2-A.

4.3 Applicable Regulatory Requirements/Criteria The proposed amendment has been evaluated to determine whether applicable regulations and requirements continue to be met.

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10 CFR 50.54(0) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Primary Reactor Containment Leakage Testing for Water-Cooled Nuclear Power Reactors." 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 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 (Reference 6.18) and June 8, 2012 (Reference 6.2) are incorporated in 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 PBNP TS 5.5.15, "Containment Leakage Rate Testing Program," by changing the wording to indicate that the program shall be in accordance with NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," and the conditions and limitations specified in NEI 94-01, Revision 2-A, instead of Regulatory Guide 1.163, "Performance Based Containment Leak Test Program," and the listed Type A test exception. 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 TS in regards to containment leakage rate testing.

NextEra has evaluated the proposed changes against the applicable regulatory requirements and acceptance criteria. Based on the foregoing, the proposed amendment will continue to ensure compliance with 10 CFR 50.54(0), and Option B of 10 CFR Part 50, Appendix J.

4.4 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.

Page 36 of 38

5.0 EVIRONMENTAL CONSIDERATION NextEra has evaluated the proposed amendment for environmental considerations. The review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, 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 needs to be prepared in connection with the proposed amendment.

6.0 REFERENCES

1.

Nuclear Energy Institute (NEI) Topical Report, 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated July 2012 (ADAMS Accession No. ML12221A202).

2.

Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear Energy institute (NEI) Report, 94-01, Revision 3, 'Industry Guideline for Implementing Performance-based Option of 10 CFR Part 50, Appendix J,' (TAC No. ME2164)," dated June 8, 2012 (ADAMS Accession No. ML121030286).

3.

Nuclear Energy Institute (NEI) Topical Report, 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," dated October 2008 (ADAMS Accession No. ML100620847).

4.

Electric Power Research Institute, Report No. 1009325, Revision 2, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," dated August 2007 (ADAMS Accession No. ML072970208).

5.

Electric Power Research Institute, Report No. 1009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," dated October 2008 (also identified as EPRI TR-1018243, which is publicly available and can be found at www.epri.com by typing "1018243" in the search field box).

6.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.174, Revision 3, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated January 2018 (ADAMS Accession No. ML17317A256).

7.

U.S. Nuclear Regulatory Commission, "Seabrook Station, Unit No. 1-Issuance of Amendment Re: Extension of Containment Leakage Rate Test Frequency (CAC No. MF7565)," dated March 15, 2017 (ADAMS Accession No. ML17046A443).

8.

U.S. Nuclear Regulatory Commission, Information Notice 92-20, "Inadequate Local Leak Rate Testing," dated March 3, 1992 (https://www.nrc.gov/reading-rm/doc-collections/gen-comm/info-notices/1992/in92020.html).

Page 37 of 38

9.

U.S. Nuclear Regulatory Commission, Information Notice 2004-09, "Corrosion of Steel Containment and Containment Liner," dated April 27, 2004 (ADAMS Accession No. ML041170030).

10.

U.S. Nuclear Regulatory Commission, Information Notice 2010-12, "Containment Liner Corrosion," dated June 18, 2010 (ADAMS Accession No. ML100640449).

11.

U.S. Nuclear Regulatory Commission, Information Notice 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner," dated May 5, 2014 (ADAMS Accession No. ML14070A114).

12.

U.S. Nuclear Regulatory Commission, Safety Evaluation, AC Nos. 63152 and 63153, "Containment Liner Leak Chase Channel Venting," September 18, 1989 (ADAMS Legacy Library Accession Nos. 8909270236 and 8910020122).

13.

U.S. Nuclear Regulatory Commission, Information Notice 2011-15, "Steel Containment Degradation and Associated License Renewal Aging Management Issues," dated August 1, 2011 (ADAMS Accession No. ML111460369).

14.

WE Letter to NRC, VPNPD-89-278, Transmittal of "Containment Leak Chase Channel Summary Report," Point Beach Nuclear Plant Units 1 and 2, dated May 9, 1989 (ADAMS Legacy Library Accession No. 8905240521).

15.

NRC Safety Evaluation, "Amendment Nos. 169 and 173 to Facility Operating License Nos. DPR-24 and DPR Point Beach Nuclear Plant, Unit Nos. 1 and 2 (TAC Nos. M95668 and M95669)," dated October 9, 1996 and November 13, 1996 (ADAMS Legacy Library Accession Nos. 9610170271, 9610170267, 9610170254, 9611180088 and 9611180082).

16.

NRC Safety Evaluation, "Point Beach Nuclear Plant (PBNP), Units 1 and 2 - Issuance of License Amendments Regarding Use of Alternate Source Term (TAC Nos. ME0219 and ME0220)," dated April 14, 2011 and May 4, 2011 (ADAMS Accession Nos. ML110240054 and ML111220078).

17.

ANSl/ANS-56.8-2002, "Containment System Leakage Testing Requirements."

18.

Letter from M. Maxin (NRC) to J. Butler (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J' and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals' (TAC No. MC9663)," dated June 25, 2008 (ADAMS Accession No. ML081140105).

19.

Calvert Cliffs Nuclear Power Plant, "Response to Request for Additional Information Concerning the License Amendment Request for One-Time Integrated Leakage Rate Test Extension," dated March 27, 2002 (ADAMS Accession No. ML020920100).

Page 38 of 38 NextEra Energy Point Beach, LLC Point Beach Nuclear Plant, Units 1 and 2 License Amendment Request 288 Request to Extend Containment Leakage Rate Test Frequency Proposed Technical Specifications Change Markup 1 Page Follows

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 5.5.15 Point Beach Safety Function Determination Program (SFDP) (continued)

A loss of safety function exists when, assuming no concurrent single failure, and assuming no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

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

When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

Containment Leakage Rate Testing Program

a.

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) 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 follo1Ning exception to Nuclear Energy Institute (NEI) 94-01, Rev,...-0 Revision 3-A, "Industry Guidance for Implementing Performance Based Option of 10 CFR 50, Appendix J," and the conditions and limitations specified in NE/

Revision 2-A.Section 9.2.3, to allow the follo*.ving:.

(i)

The first Unit 1 Type A test performed after October 7, 1997, shall be performed by October 7, 2012.

(ii)

The first Unit 2 Type A test performed after March 31; 1997, shall be performed by March 31, 2012.

5.5-15 Unit 1 - Amendment No. 2'W Unit 2 - Amendment No. ~

NextEra Energy Point Beach, LLC Point Beach Nuclear Plant, Units 1 and 2 License Amendment Request 288 Request to Extend Containment Leakage Rate Test Frequency Revised (Clean) Technical Specifications Page 1 Page Follows

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 5.5.15 Point Beach Safety Function Determination Program (SFDP) (continued)

A loss of safety function exists when, assuming no concurrent single failure, and assuming no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

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

When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

Containment Leakage Rate Testing Program

a.

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with Nuclear Energy Institute (NEI) 94-01, Revision 3-A, "Industry Guidance for Implementing Performance Based Option of 10 CFR 50, Appendix J, "and the conditions and limitations specified in NEI 94-01, Revision 2-A.

5.5-15 Unit 1 - Amendment No. XX Unit 2 - Amendment No. XX

ENCLOSURE4 LICENSE AMENDMENT REQUEST 288 POINT BEACH NUCLEAR PLANT EXTENSION OF CONTAINMENT INTEGRATED LEAKAGE RATE TEST INTERVAL RISK ASSESSMENT 92 Pages Follow

POINT BEACH NUCLEAR PLANT PERMANENT ILRT INTERVAL EXTENSION RISK ASSESSMENT (APPENDIX A TO S&L 2017-10630)

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Table of Contents Section Page 1.0 Purpose of Analysis............................................................................................................... 3 1.1 Purpose................................................................................................................................. 3 1.2 Background.......................................................................................................................... 3 1.3 Criteria................................................................................................................................. 4 2.0 Methodology......................................................................................................................... 5 3.0 Ground Rules......................................................................................................................... 6 4.0 Inputs..................................................................................................................................... 7 4.1 General Resources Available............................................................................................... 7 4.2 Plant Specific Inputs.......................................................................................................... 11 4.3 Impact of Extension on Detection of Component Failures That Lead to Leakage (Small and Large)....................................................................................................................... 16 4.4 Impact of Extension on Detection of Steel Liner Corrosion that Leads to Leakage......... 17 5.0 Results................................................................................................................................. 20 5.1 Step 1 - Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year.............. 22 0

Step 2 - Develop Plant Specific Person-Rem Dose (Population Dose) Per Reactor Year 26 5.3 Step 3 - Evaluate Risk Impact of Extending Type A Test Interval From 10 to 15 Years.30 5.4 Step 4 - Determine the Change in Risk in Terms of Large Early Release Frequency (LERF)............................................................................................................................ 35 5.5 Step 5 - Determine the Impact on the Conditional Containment Failure Probability (CCFP)............................................................................................................................ 35 5.6 Summary ofResults........................................................................................................... 37 6.0 Sensitivities......................................................................................................................... 38 6.1 Sensitivity to Corrosion Impact Assumptions................................................................... 38 6.2 Sensitivity to Class 3B Contribution to LERF...................................................................40 6.3 Potential Impact from External Events Contribution......................................................... 40 7.0 Conclusions......................................................................................................................... 40 8.0 References........................................................................................................................... 57 Appendix Al.................................................................................................................................. 62 Page I 2

1.0 Purpose of Analysis 1.1 Purpose The purpose of this analysis is to provide a risk assessment for extending the currently allowed containment Type A Integrated Leak Rate Test (ILRT) 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 Point Beach Nuclear Plant (PBNP). The risk assessment follows the guidelines from Nuclear Energy Institute (NEI) 94-01, Revision 3-A1 (Reference 8.1), the methodology used in Electric Power Research Institute (EPRI) TR-104285 (Reference 8.2), 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 (Reference 8.3), the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide (RG) 1.200 (Reference 8.35) 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 (Reference 8.4), 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 (Reference 8.5), and the methodology used in EPRI Report No. 1009325, Revision 2-A2 (Reference 8.26).

1.2 Background

Revisions to 10 CFR 50, Appendix J (Option B) allow individual plants to extend the ILRT surveillance testing frequency requirement from three in ten years to at least once in ten years.

The revised ILRT frequency is based on an acceptable performance history defined as two consecutive periodic ILRTs at least 24 months apart in which the calculated performance leakage rate was less than the limiting containment leakage rate of 1La3*

The basis for the current 10-year test interval for PBNP is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995. Section 11.0 of NEI 94-01 states that NUREG-1493, "Performance-Based Containment Leak Test Program," September 1995 (Reference 8.6), 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 EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals."

The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leak(J.ge on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR 1 Note that there are no differences in the risk assessment criteria between Revisions 2-A and 3-A.

2 EPRI Report No. 1009325, Revision 2-A, is also identified as EPRI TR-1018243.

3 La (percent/24 hours) is the maximum allowable leakage rate at the calculated peak design containment internal accident pressure, P., as specified in the Technical Specifications.

Page I 3

plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for PBNP.

The guidance provided in Appendix Hof EPRI Report No. 1009325, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals," (Reference 8.26) for performing risk impact assessments in support of ILR T extensions builds on the EPRI Risk Assessment methodology, EPRI TR-104285. 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 and C local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets and containment isolation valves are also not affected by the change to the ILR T frequency.

1.3 Criteria The acceptance guidelines in RG 1.17 4 are used to assess the acceptability of this permanent extension of the ILRT 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 10-6 per reactor year and increases in Large Early Release Frequency (LERF) less than 10-7 per reactor year. Since the ILRT does not impact CDF, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 10-6 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the Conditional Containment Failure Probability (CCFP) that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.

The criteria described below are taken from Section 3.2.4.6 of the NRC Final Safety Evaluation for NEI 94-01, Revision 2 and EPRI Report No. 1009325, Revision 2 (Reference 8.29).

Regarding CCFP, the NRC concluded that a small increase in CCFP should be defined as a value marginally greater than that accepted in previous one time fifteen year ILRT extension requests.

To this end the NRC has endorsed a small increase in CCFP as an increase in CCFP less than or equal to 1.5% (Reference 8.29).

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In addition, the total annual risk (person-rem/yr population dose) is examined to demonstrate the relative change in this parameter. For purposes of assessing the risk impacts of the Type A ILRT extension in accordance with the EPRI methodology, the NRC concluded that a small increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 % of the total population dose, whichever is less restrictive.

2.0 Methodology A simplified bounding analysis approach consistent with the EPRI approach is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in Appendix H of EPRI Report No. 1009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals" (Reference 8.26), EPRI TR-104285 (Reference 8.2), NUREG-1493 (Reference 8.6) and the Calvert Cliffs liner corrosion analysis (Reference 8.5). The analysis uses results from the Level 2 PRA model of core damage scenarios from the current PBNP PRA model to establish the containment fission product release categories and associated release frequencies.

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 EPRI Report No. 1009325, Revision 2-A (Reference 8.26).

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 ofLERF in accordance with RG 1.174 (Reference 8.4) and compare with the acceptance guidelines ofRG 1.174.

5. Determine the impact of the ILRT interval extension on the CCFP and the population dose and compare with the acceptance guidance of Reference 8.29.

6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis, external events and to the fractional contribution of increased large isolation failures (due to liner breach) to LERF.

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 PBNP assessment uses LERF and delta LERF in accordance with the risk acceptance guidance ofRG 1.174. Changes in population dose and conditional containment failure probability are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.

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Containment overpressure is not necessary to satisfy emergency core cooling system (ECCS) pump net positive suction head (NPSH) requirements at PBNP, thus CDP is not affected by a change in containment leakage and LERF remains the relevant risk metric for the analysis ofILRT frequency extension.

The evaluation for PBNP uses ground rules and methods to calculate changes in risk metrics that are similar to those used in Appendix Hof EPRl Report No. 1009325, Revision 2-A, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals."

3.0 Ground Rules The following ground rules are used in the analysis:

The PBNP Level 1 and Level 2 PRA models are used to conservatively estimate the impact of the proposed ILRT extension on population dose and LERF risk metrics.

As discussed in Appendix Al, the acceptability of the PBNP Internal Events and Internal Flooding PRA and Fire PRA are consistent with the requirements of RG 1.200, Revision 2 (Reference 8.35), as is relevant to this ILRT interval extension. The results from the Individual Plant Examination-External Events (IEEEE) Seismic Margin Analysis (SMA) and screenings for other external hazards are also used.

The analysis includes a quantitative assessment of the contribution of external events (e.g., fire and seismic) in the risk impact assessment for extended ILRT intervals. The external event results used herein are consistent with those used in the PBNP license amendment request (LAR) to adopt 10 CPR 50.69 (Reference 8.17). The ILRT risk impacts associated with seismic events are supplemented with sensitivity assessments to further support the conclusion that the potential risk associated with ILRT frequency extension is acceptable.

It is assumed that the distribution of releases for each hazard (internal flood, fire, seismic, other external events) are consistent with the distribution calculated for the internal events PRA results. This approach is consistent with that used in the one-time ILRT interval extension (Reference 8.31 ). Additionally, it is noted that the impact from the ILRT extension on the percent increase in population dose would not be expected to change when accounting for the population dose contribution from external events.

Per EPRl Report No. 1009325, Revision 2-A, Section 4.2.2 (Reference 8.26), the order of preference for population dose information shall be plant-specific best estimate, Severe Accident Mitigation Alternative (SAMA) for license renewal, and scaling of a reference plant population dose. Therefore, PBNP plant specific dose results from the Level 3 PRA results in Table F.1-4 of the environmental rep01i for license extension (Reference 8.30) are used for this risk assessment.

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Accident classes describing radionuclide release end states are defined consistent with EPRI methodology (Reference 8.2) 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 (References 8.8, 8.9). Class 3a represents intact containments with leakages somewhat larger than La as discussed in EPRI Report No. 1009325, Revision 2-A.

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

Class 3b can be very conservatively categorized as LERF based on the previously approved methodology (References 8.8, 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 ent1y for comparison purposes. Since the containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from this separate categorization.

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

4.0 Inputs This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2).

4.1 General Resources Available Various industry studies on containment leakage risk assessment are briefly summarized here:

I. NUREG/CR-3539 (Reference 8.10)

2. NUREG/CR-4220 (Reference 8.11)

3. NUREG-1273 (Reference 8.12)

4. NUREG/CR-4330 (Reference 8.13)

5. EPRI TR-105189 (Reference 8.14)

6. NUREG-1493 (Reference 8.6)

7. EPRI TR-104285 (Reference 8.2)

8. NUREG-1150 (Reference 8.15) and NUREG/CR-4551(Reference8.7)

9. NEI Interim Guidance (Reference 8.3, Reference 8.20)

10. Calvert Cliffs Liner Corrosion Analysis (Reference 8.5)

11. EPRI Report No. 1009325, Revision 2-A, Appendix H (Reference 8.26)

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The first study is applicable because it provides one basis for the threshold that could be used in the Level 2 PRA for the size of containment leakage that is considered significant and is to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database. The fourth study provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension. The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRJ study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study provides an ex-plant consequence analysis for a 50-mile radius surrounding a plant that can be used as the bases for the consequence analysis of the ILRT interval extension for PBNP when plant-specific information is not available. The ninth 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 tenth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations. Finally, the eleventh 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.

4.1.1 NUREG/CR-3539 (Reference 8.10)

Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. This study uses information from WASH-1400 (Reference 8.16) as the basis for its risk sensitivity calculations. ORNL concluded that the impact of leakage rates on L WR accident risks is relatively small.

4.1.2 NUREG/CR-4220 (Reference 8.11)

NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.

The study reviewed over two thousand LERs, ILRT repmis and other related records to calculate the unavailability of containment due to leakage.

4.1.3 NUREG-1273 (Reference 8.12)

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.

4.1.4 NUREG/CR-4330 (Reference 8.13)

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.

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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."

4.1.5 EPRI TR-105189 (Reference 8.14)

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

The conclusion from the study is that a small but measurable safety benefit is realized from extending the test intervals.

4.1.6 NUREG-1493 (Reference 8.6)

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 three per ten years to one per twenty 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.

4.1.7 EPRI TR-104285 (Reference 8.2)

Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150 Level 3 population dose models to perform the analysis. The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals.

EPRI TR-104285 uses a simplified Containment Event Tree to subdivide representative core damage frequencies into eight classes of containment response to a core damage accident:

1. Containment intact and isolated

2. Containment isolation failures dependent upon the core damage accident

3. Type A (ILRT) related containment isolation failures

4. Type B (LLRT) related containment isolation failures

5. Type C (LLRT) related containment isolation failures

6. Other penetration related containment isolation failures

7. Containment failures due to core damage accident phenomena

8. Containment bypass Page I 9

Consistent with the other containment leakage risk assessment studies, this study concluded:

[T]he proposed CLR T (containment leak rate tests) frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.04 person-rem per year...

4.1.8 NUREG-1150 (Reference 8.15) and NUREG/CR 4551(Reference8.7)

NUREG-1150 and the technical basis, NUREG/CR-4551, provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage). This ex-plant consequence analysis is calculated for the 50-mile radial area surrounding Surry. The ex-plant calculation can be delineated to total person-rem for each identified Accident Progression Bin (APB) from NUREG/CR-4551. However, these references were not used in this analysis. PBNP plant-specific dose results from the Level 3 PRA results in the environmental report for license extension (Reference 8.30) are used for this risk assessment.

4.1.9 NEI Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals (Reference 8.3, Reference 8.20)

The guidance provided in this document builds on the EPRI risk impact assessment methodology (Reference 8.2) and the NRC performance-based containment leakage test program (Reference 8.6), and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) and Crystal River.

4.1.10 Calvert Cliffs Response to Request for Additional Information Concerning the License Amendment for a One-Time Integrated Leakage Rate Test Extension (Reference 8.5)

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, 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 PBNP assessment has addressed the plant-specific differences from the Calvert Cliffs design, and how the Calvert Cliffs methodology was adapted to address the specific design features.

4.1.11 EPRI Report No. 1009325, Revision 2-A, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (Reference 8.26)

This report provides a generally applicable assessment of the risk involved in extension of ILRT test intervals to permanent 15-year intervals. Appendix Hof this document provides guidance for performing plant specific supplemental risk impact assessments and builds on the previous EPRI Page I 10

risk impact assessment methodology (Reference 8.2) and the NRC performance-based containment leakage test program (Reference 8.6), and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) and Crystal River.

The approach included in this guidance document is used in the PBNP assessments 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 Classes 3a and 3b scenarios in this analysis as described in Section 5.

4.2 Plant Specific ln:puts The plant specific information used to perform the PBNP ILRT Extension Risk Assessments include the following:

Level 1 Model results Level 2 Model results Release category definitions used in the Level 2 Model ILRT results to demonstrate adequacy of the administrative and hardware issues Containment design and fragility data 4.2.1 Level 1 Model The Level 1 PRA model that is used for PBNP is characteristic of the as-built plant. The cunent Level 1 model is a linked fault tree model, and was quantified for internal and external initiating events (Internal Events, Internal Fire, Internal Flood, Seismic Events, and Other External Events) with the total Core Damage Frequency (CDF) = 7.2E-05/yr for Unit 1 and 8.2E-05/yr for Unit 2 (Reference 8.17).

a e esu s >Y azar T bl 4 2 1 PBNP CDF R It b H d

Model Unit 1 CDF Unit2 CDF Source Internal Events 5.lE-06 5.lE-06 Peer reviewed plant-specific PRA model Internal Flood 3.0E-07 3.0E-07 Peer reviewed plant-specific PRA model Internal Fire 5.9E-05 6.9E-05 Peer reviewed plant-specific PRA model Seismic 6.24E-06 6.24E-06 SMA performed for IPEEE-Other External

<l.OE-06

<l.OE-06 Screening results from IPEEE Hazards Total 7.2E-05 8.2E-05 Page 111

4.2.2 Level 2 Model The Level 2 Model that is used for PBNP was developed to calculate LERF. The following table summarizes the pertinent PBNP results for LERF in terms of the initiating hazard (Reference 8.17).

T bl 4 2 2 PBNP LERF R It b H d

a e. - :

esu s 1y azar Model Unit 1 LERF Unit2 LERF Source Internal Events 3.7E-08 3.6E-08 Peer reviewed plant-specific PRA model Internal Flood 2.0E-08 2.0E-08 Peer reviewed plant-specific PRA model Internal Fire 9.0E-07 l.lE-06 Peer reviewed plant-specific PRA model Seismic 1.21E-06 l.21E-06 SMA performed for IPEEE Other External

<l.OE-07

<l.OE-07 Screening results from IPEEE Hazards Total 2.3E-06 2.5E-06 To define the frequency of the EPRI release classes, each containment event tree (CET) sequence is assigned to one of the EPRI release classes in the PBNP model. The model is then quantified to define the frequency for the release classes. These additional release class quantifications are used to define the distribution of CDF between the EPRI release categories as shown in Table 4.2-3 (Reference 8.18).

Table 4.2-3: EPRI Release Class Distributions EPRI Release Class Percent of CDF Unit 1 Unit2 1

73.149%

71.515%

2 0.008%

0.008%

7 25.472%

26.923%

8 1.371%

1.554%

Applying the release class distributions of Table 4.2-3 to the CDF results from Table 4.2-1 yields the hazard specific release class distributions shown in Tables 4.2-4 and 4.2-5.

Page J 12

T bl 4 2 4 U 't 1 EPRI R I a e Ill e ease CI F

ass b H requenc1es 1v azar d EPRI Release Class Frequency by Hazard Type (per year)

Distribution Internal Internal Internal

(%of CDF)

Events Flood Fire Seismic Other CDF 5.10E-06 3.00E-07 5.90E-05 6.24E-06 1.00E-06 1

73.149%

3.73E-06 2.19E-07 4.32E-05 4.56E-06 7.31E-07 2

0.008%

4.07E-10 2.40E-11 4.71E-09 4.98E-10 7.99E-11 7

25.472%

1.30E-06 7.64E-08 1.50E-05 1.59E-06 2.55E-07 8

1.371%

6.99E-08 4.11E-09 8.09E-07 8.56E-08 1.37E-08 T bl 4 2 5 U 't 2 EPRIR I CI F

b H d

a e. - :

Ill e ease ass requenc1es 1v azar EPRI Release Class Frequency by Hazard Type (per year)

Distribution Internal Internal Internal

(%of CDF)

Events Flood Fire Seismic Other CDF 5.10E-06 3.00E-07 6.90E-05 6.24E-06 1.00E-06 1

71.515%

3.65E-06 2.15E-07 4.93E-05 4.46E-06 7.15E-07 2

0.008%

4.20E-10 2.47E-11 5.68E-09 5.13E-10 8.23E-11 7

26.923%

1.37E-06 8.08E-08 1.86E-05 1.68E-06 2.69E-07 8

1.554%

7.92E-08 4.66E-09 1.07E-06 9.69E-08 1.55E-08 4.2.3 Population Dose Calculations The baseline population dose for PBNP is given in Table 4.2-6a. As discussed in EPRI 1009325, Revision 2-A, Section 4.2.2 (Reference 8.26), the order of preference for population dose information shall be plant-specific best estimate, Severe Accident Mitigation Alternative (SAMA) for license renewal, and scaling of a reference plant population dose. Therefore, PBNP plant specific dose results based on the Level 3 PRA results in Table F.1-4 of the environmental report for license extension (Reference 8.30) are used for this risk assessment. This data is consistent with that submitted in the one-time extension for PBNP ILRT (Reference 8.31).

a e. - a:

opu a ion T bl 4 2 6 PBNP P I f D ose PB Release Category Person-SV Dose (REM)

Applicable EPRI Release Category Late SGTR l.39E+03 l.39E+05 7 and 8 Early SGTR l.88E+03 l.88E+05 8

Isolation Failure l.13E+03 1.13E+05 2

IS LO CA l.13E+04 1.13E+06 8

Internal Other Core 3.86E+Ol 3.86E+03 1

Melt (CM) Sequences Page I 13

An updated evacuation study was performed for PBNP in 2012 (Reference 8.52). The updated study provided a bounding evacuation time of approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> for a radius of 10 miles around the PBNP site. This updated evacuation time is consistent with that used in the SAMA analysis to establish the evacuation speed, thus the 2012 evacuation study does not affect the SAMA dose rate estimates.

Additionally, the 2012 evacuation study (Reference 8.52) shows a reduction in permanent resident population in the emergency planning zone between 2000 and 2010. The SAMA analysis was based on conservative population growth estimates, therefore, no adjustments to the SAMA doses are required for population growth.

The SAMA population dose data provided in Table 4.2-6a is based on a rated power level of 1518.5 MWt (Reference 8.30, Section F.1.2.1). The cunent licensed power for PBNP Units 1 and 2 is 1800 MWt (Reference 8.32). EPRI Report No. 1009325 (Reference 8.26) provides a method for approximating population dose based a reference plant if it is conected for allowable containment leak rate (La), reactor power level, and population density. Using this method, the SAMA population dose data in Table 4.2-6a is adjusted to account for power uprate at PBNP.

Note that at the time of the SAMA analysis, La at PBNP was 0.4 wt%/ day, while currently La at PBNP is 0.2 wt%/ day (References 8.53 and 8.54). If the EPRI report scaling methodology was applied, this reduction in La would reduce the PBNP intact containment dose rates by a factor of 2. Conservatively, this adjustment due to reduced La at PBNP is not credited.

Power level adjustment:

Current rated power level of PBNP (MWt)

FPower = ---------------

SAMA rated power level for PBNP (MWt)

FPower = 1800 MWt I 1518.5 MWt FPower = 1.185 Each of the PBNP population doses in Table 4.2-6a are adjusted by the power level adjustment above as shown in Table 4.2-6b.

Table 4.2-6b: PBNP Adjusted Population Dose PB Release Category Dose from Power Level Dose (person-rem)

Applicable Table 4.2-6a Adjustment EPRI (person-rem)

Release Category Late SGTR l.39E+05 1.185 1.65E+05 7 and&

Early SGTR l.88E+05 1.185 2.23E+05 8

Isolation Failure l.13E+05 1.185 l.34E+05 2

ISLOCA l.13E+06 1.185 l.34E+06 8

Internal Other Core 3.86E+03 1.185 4.57E+03 1

Melt (CM) Sequences Page I 14

4.2.4 Type A Tests The two most recent Type A ILRTs at PBNP Unit 1 and Unit 2 have been successful, so the current ILRT interval requirement is 10 years (Reference 8.42). A one-time extension of the ILRT interval to 15 years was previously approved (Reference 8.43), so the interval between the prior two tests for Unit 1 (October 1997 - November 2011) and Unit 2 (March 1997 -April 2011) demonstrate prior successful performance at an extended test interval.

4.2.5 Release Category Definitions Table 4.2-7 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology (Reference 8.2). 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 6 of this report.

Table 4.2-7: EPRI Containment Failure Classification (Reference 8.2)

Class Description 1

Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2

Containment isolation failures (as reported in the IP Es) include those accidents in which there is a failure to isolate the containment.

3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e., provide a leak-tight containment) is not dependent on the sequence in progress.

4 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 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.

5 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 Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.

6 Containment isolation failures include those leak paths covered in the plant test and maintenance requirements or verified per inservice 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.

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

Page I 15

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 bellow 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 4.2-7, it is divided into two sub-classes, Class 3a and Class 3b, representing small and large leakage failures, respectively.

The probability of the EPRI Class 3a and 3b failures is determined consistent with the EPRI Guidance. For Class 3a, the probability is based on the maximum likelihood estimate of failure (arithmetic average) from the available data (i.e., 2 "small" failures in 217 tests leads to 2/217=0.0092). For Class 3b, Jefferys non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5I(217+1) = 0.0023).

In a follow on letter (Reference 8.20) to their ILRT guidance document (Reference 8.3), 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 PBNP, as detailed in Section 5, involves the following:

The Class 2 and Class 8 sequences are subtracted from the CDF that is applied to Class 3b.

To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Class 2 and Class 8 events refer to sequences with either large preexisting containment isolation failures or containment bypass events. These sequences are already considered to contribute to LERF in the PBNP Level 2 PRA analyses.

Page j 16

Class I accident sequences may involve availability and or successful operation of containment sprays.

It could be assumed that, for calculation of the Class 3b and 3a frequencies, the fraction of the Class I CDF associated with successful operation of containment sprays can also be subtracted. However, containment sprays are not credited for any of the release classes in this PBNP analysis.

Consistent with the NEI Guidance (Reference 8.3), 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/2), and the average time that a leak could exist without detection for a ten year interval is five years (10 yr/2). This change would lead to a non-detection probability that is a factor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing. An extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 (7.5/1.5) increase in the non-detection probability of a leak compared to a three year interval.

It should be noted that using the methodology discussed above is very conservative compared to previous submittals (e.g., the IP3 request for a one-time ILRT extension that was approved by the NRC (Reference 8.9)) 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 (Reference 8.5). The Calvert Cliffs analysis was performed for a concrete cylinder, dome and a concrete basemat, each with a steel liner. PBNP has a similar type of containment (Reference 8.32).

The following approach is used to determine the change in likelihood, due to extending the ILRT, of detecting corrosion of a containment steel liner. It should be noted that this computation is being applied to provide an upper bound approach to quantify corrosion induced risk. The Calvert Cliffs corrosion likelihood methodology 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 upper containment (cylinder and dome regions in Calvert Cliffs evaluation)

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 Page I 17

4.4.1 Assumptions Consistent with the Calve1i Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures. (See Table 4.4-1, Step I.)

The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to this PBNP containment analysis. These events, one at Nmih Anna Unit 2 and one at Brunswick Unit 2, were initiated from the nonvisible (backside) pmiion of the containment liner.

The Calvert Cliffs analysis used the estimated historical liner flaw probability of 5.5 years to reflect the years since September 1996 when 10 CFR 50.55a started requiring visual inspection. Additional success data was not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date. Since the time of the Calvert Cliffs submittal, two additional relevant liner corrosion events involving concealed corrosion (corrosion initiated on the inaccessible liner surface) were observed and are considered in the corrosion risk assessment. These events occurred at Beaver Valley Unit 1 and D.C. Cook Unit 2 (Reference 8.27 and Reference 8.28, respectively). Consistent with the addition of the two observed events, the historical liner flaw probability was established by incrementing the flaw observation time by 7.75 years.

This re-evaluation resulted in a reduction of the historical liner flaw likelihood to 4.3E-03/year ((2+2) I [70 * (5.5 + 7.75)] = 4.3E-03/year). This value is smaller than the value of 5.2E-03 which is used in the Calvert Cliffs analysis. The conservative value of 5.2E-03 will be used in this PBNP report to remain consistent with the Calvert Cliffs analysis.

In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated as 1.1 % for the cylinder and dome and 0.11 % (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure, and the selected values are consistent with a pressure that corresponds to the ILRT target pressure of 37 psig. For PBNP, the containment failure probabilities are less than these values at the PBNP ILRT target pressure of 60 psig (Reference 8.18).

Conservative probabilities of 1 % for the cylinder and dome and 0.1 % for the basemat are used in this analysis, and sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4.)

Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crack formation) in the basemat region is considered to be less likely than the containment cylinder and dome region. (See Table 4.4-1, Step 4.)

Consistent with the Calve1i Cliffs analysis, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used.

To date, all liner corrosion events have been detected through visual inspection. (See Table 4.4-1, Step 5.) Sensitivity studies are included that evaluate total detection failure likelihood of5% and 15%, respectively.

Page I 18

Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases. This approach avoids a detailed analysis of containment failure timing and operator recovery actions.

4.4.2 Analysis Table 4.4-1: Steel Liner Corrosion Analysis Step Description Containment Walls Containment Basemat Historical Steel Liner Flaw 1

Likelihood Events: 2 Events 0 (assume 0.5 failure)

Failure Data:

2/(70*5.5) = 5.2E-3 0.51(70

• 5.5) = l.3E-3 Year Failure Rate Year Failure Rate 2

Age-Adjusted Steel Liner 1

2.lE-3 1

5.0E-4 Flaw Likelihood avg. 5-10 5.2E-3 avg.5-10 l.3E-3 15 1.4E-2 15 3.5E-3 15 year average= 6.27E-3 15-year average= l.57E-3 Flaw Likelihood at 3, IO, and 0.71% (1to3 years) 0.18% (I to 3 years) 3 4.06% (I to IO years) 1.02% (I to IO years) 15 years 9.40% (1to15 years) 2.35% (1 to 15 years)

Likelihood of Breach in 4

Containment Given Steel 1%

0.1%

Liner Flaw 5

Visual Inspection Detection IO%

100%

Failure Likelihood 0.00071%

0.00018%

0.71%*1%* 10%

0.18%

• 0.1%

• 100%

Likelihood of Non-Detected 0.0041%

O.OOIO%

6 Containment Leakage 4.1%

• 1%

• 10%

1.0%

• 0.1 %

• IOO%

(Steps 3*4*5) 0.0094%

0.0024%

9.4%

• 1% *IO%

2.4%

• 0.1 %

• IOO%

The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 for the leakages for the upper containment and the containment basemat as summarized below for PBNP.

Page I 19

Total Likelihood of Non-Detected Containment Leakage Due To Corrosion for PBNP:

At 3 years: 0.00071 % + 0.00018% = 0.00089%

At 10 years: 0.0041% + 0.0010% = 0.0051%

At 15 years: 0.0094% + 0.0024% = 0.012%

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 Unit 1 three in ten year case is calculated as follows:

Per Table 5-2a, the EPRI Unit 1 Class 3b frequency is l.16E-08/yr.

As discussed in Section 5.1, the PBNP Unit 1 CDP associated with accidents that are not independently LERF or could never result in LERF is 5.lOE 4.07E 6.99E-08 =

5.03E-06.

The increase in the base case Class 3b frequency due to the corrosion-induced concealed flaw issue is calculated as 5.03E-06/yr

• 0.00089% = 4.48E-11/yr, where 0.00089% was previously shown above to be the cumulative likelihood of non-detected containment leakage due to corrosion at three years.

The three in ten year Class 3b frequency including the corrosion-induced concealed flaw issue is then calculated as l.16E-08/yr + 4.48E-11/yr = l.16E-08/yr.

5.0 Results The application of the approach based on the guidance contained in EPRI Report No. 1009325, Revision 2-A, Appendix H, EPRI-TR-104285 (Reference 8.2) and previous risk assessment submittals on this subject (References 8.5, 8.8, 8.21, 8.22) 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 PBNP specific accident sequences in which the containment remains intact or the containment is impaired. Specifically, the breakdown of the severe accidents contributing to risk is considered in the following manner:

Core damage sequences in which the containment remains intact initially and in the long term (EPRI TR-104285 Class 1 sequences).

Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components. For example, liner breach or bellows leakage. (EPRI TR-104285 Class 3 sequences).

Page I 20

Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left "opened" following a plant post-maintenance test. For example, a valve failing to close following a valve stroke test. (EPRI TR-104285 Class 6 sequences). Consistent with the NEI Guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.

Accident sequences involving containment bypassed (EPRI TR-104285 Class 8 sequences),

large containment isolation failures (EPRI TR-104285 Class 2 sequences), and small containment isolation "failure-to-seal" events (EPRI TR-104285 Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change.

Class 4 and 5 sequences are impacted by changes in Type B and C test intervals; therefore, changes in the Type A test interval do not impact these sequences.

Table 5-1: Accident Classes Accident Classes (Containment Description Release Type) 1 No Containment Failure 2

Large Isolation Failures (Failure to Close) 3a Small Isolation Failures (Liner Breach) 3b Large Isolation Failures (Liner Breach) 4 Small Isolation Failures (Failure to Seal-Type B) 5 Small Isolation Failures (Failure to Seal-Type C) 6 Other Isolation Failures (e.g., Dependent Failures) 7 Failures Induced by Phenomena (Early and Late) 8 Bypass (Interfacing System LOCA)

CDF 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 three to fifteen. and ten to fifteen years.

Step 4 - Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174.

Step 5 - Determine the impact on the Conditional Containment Failure Probability (CCFP).

Page j 21

5.1 Step 1-Quantify the Base-Line Risk in Terms of Frequency Per Reactor Year As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena.

For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks is included in the model. (These events are represented by the Class 3 sequences in EPRI TR-104285). 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 PBNP by first determining the frequencies for Classes 1, 2, 7 and 8 using the categorized sequences and the identified correlations shown in Table 4.2-3, scaling these frequencies to account for the uncategorized sequences, determining the frequencies for Classes 3a and 3b, and then determining the remaining frequency for Class 1. Furthermore, adjustments were made to the Class 3b and hence Class 1 frequencies to account for the impact of undetected corrosion per the methodology described in Section 4.4.

The Unit 1 total frequency of the categorized sequences is 5.IOE-06/yr, the total CDF is 5.lOE-06/yr (Table 4.2-4), and the scale factor is 1.0. The scaling factor is determined by dividing CDF by the total categorized release category frequency (5.lOE-06/yr I 5.lOE-06/yr =

1.0).

The Unit 2 total frequency of the categorized sequences is 5.IOE-06/yr, the total CDF is 5.IOE-06/yr (Table 4.2-5), and the scale factor is 1.0. The scaling factor is determined by dividing CDF by the total categorized release category frequency (5.IOE-06/yr I 5.lOE-06/yr =

1.0).

Tables 5-2a and 5-2b contain the frequencies from the scaling factor. The results are summarized below and in Tables 5-3a and 5-3b.

T bl 5 2 PBNP U. 1 C a e - a:

mt

. dA "d Cl ate1wnze CCI ent asses an dF requenc1es Adjusted Frequency EPRI Class Class Frequency (-/yr)

Using Scale Factor of 1.0 (per yr) 1 3.73E-06 3.73E-06 2

4.07E-10 4.07E-10 7,

l.30E~06 l.30E-06 8

6.99E-08 6.99E-08 Total 5.lOE-06 5.IOE-06 Frequency 3a

=0.0092* CDF-Class2-Class8 4.63E-08 3b

=0.0023* CDF-Class2-Class8 l.16E-08 Pagel22

T bl 5 2b PBNP U 't 2 C t

' d A 'd t Cl a e -

Ill a egorize CCI en asses an dF requencies Adjusted Frequency EPRI Class Class Frequency (-/yr)

Using Scale Factor of 1.0 (per yr) 1 3.65E-06 3.65E-06 2

4.20E-10 4.20E-10 7

l.37E-06 l.37E-06 8

7.92E-08 7.92E-08 Total 5.lOE-06 5.IOE-06 Frequency 3a

=0.0092* CDF-Class2-Class8 4.62E-08 3b

=0.0023* CDF-Class2-Class8 1.15E-08 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 PRA model.

Class 2 Sequences. This group consists of all core damage accident progression bins for which a failure to isolate the containment occurs. The frequency per year for these sequences is obtained from the Level 2 PRA model.

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

< 10 La) or large (> 100 La)*

The respective frequencies per year are determined as follows:

PROBc1ass_3a

= probability of small pre-existing containment liner leakage

= 0.0092 [see Section 4.3]

PROBctass_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., Class 2 and Class 8 contributions).

Class 3a Frequency= 0.0092 * (CDF - CLASS2 - CLASS8)

= 0.0092 * (5.1 OE-06/yr - 4.07E 6.99E-08) = 4.63E-08/yr Class 3b Frequency= 0.0023 * (CDF - CLASS2 - CLASS8)

=0.0023 * (5.IOE-06/yr-4.07E 6.99E-08) = 1.16E-08/yr Page I 23

Class 3a Frequency= 0.0092 * (CDF - CLASS2-CLASS8)

= 0.0092 * (5.1 OE-06/yr - 4.20E 7.92E-08) = 4.62E-08/yr Class 3b Frequency= 0.0023 * (CDF-CLASS2-CLASS8)

=0.0023 * (5.10E-06/yr-4.20E 7.92E-08) = l.15E-08/yr For this analysis, the associated contaimnent 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 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 containment isolation failure-to-seal of Type C test components occurs. Because the failures are detected by Type C tests which are unaffected by the Type A ILRT, this group is not evaluated any further in this analysis.

Class 6 Sequences. This group is similar to Class 2. These are sequences that involve core damage accident progression bins for which a failure-to-seal containment leakage due to failure to isolate the containment occurs. These sequences are dominated by misalignment of containment isolation valves following a test/maintenance evolution, typically resulting in a failure to close smaller containment isolation valves. All other failure modes are bounded by the Class 2 assumptions. Consistent with guidance provided in EPRI Report No. 1009325, Revision 2-A, this accident class is not explicitly considered since it has a negligible impact on the results.

Class 7 Sequences. This group consists of all core damage accident progression bins in which containment failure induced by severe accident phenomena occurs (e.g., overpressure). For this analysis, the frequency is determined from the Level 2 PRA model.

Class 8 Sequences. This group consists of all core damage accident progression bins in which containment bypass occurs. For this analysis, the frequency is determined from the Level 2 PRA model.

Page I 24

5.1.1 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-104285 the NEI Interim Guidance, and guidance provided in EPRI Report No. 1009325, Revision 2-A.

Tables 5-3a and 5-3b summarize these accident frequencies by accident class for PBNP and provide the changes in frequency associated with the corrosion analysis.

Table 5-3a: Unit 1 Radionuclide Release Frequencies as a Function of Accident Class Accident Frequency (per Rx-yr)

Classes Description (Containment EPRI Corrosion Corrosion Corrosion Release Type)

Methodology (3 in 10 yr) 1 (1in10yr) 1 (1in15yr) 1 1

No Containment Failure 3.67E-06

-4.48E-ll

-2.57E-10

-5.94E-10 2

Large Isolation Failures 4.07E-10 O.OOE+OO O.OOE+OO 0.00E+OO (Failure to Close)

Small Isolation Failures 3a (liner breach) 4.63E-08 0.00E+OO 0.00E+OO O.OOE+OO 3b Large Isolation Failures l.16E-08 4.48E-11 2.57E-10 5.94E-10 (liner breach)

Small Isolation Failures 4

(Failure to seal-Type B)

NIA NIA NIA NIA Small Isolation Failures NIA NIA NIA NIA 5

(Failure to seal-Type C)

Other Isolation Failures NIA NIA NIA NIA 6

(e.g., dependent failures)

Failures Induced by 7

Phenomena (Early and 1.30E-06 0.00E+OO O.OOE+OO O.OOE+OO Late) 8 Bypass (Interfacing 6.99E-08 O.OOE+OO 0.00E+OO O.OOE+OO System LOCA)

CDF All CET end states 5.lOE-06 0.00E+OO 0.00E+OO O.OOE+OO 1 Based on data developed in Section 4.4. Only Classes 1 and 3b are impacted by the corrosion analysis.

The increase in Class 3b frequency leads to a reduction in Class 1 frequency to preserve overall CDF.

Page j 25

T bl 5 3b U. 2 R d" l"d R 1 a

e -

mt a IOllUC I e e ease F requencies as a F unctwn o fA "d Cl CCI ent ass Accident Classes Frequency (per Rx-yr)

(Containment Description EPRI Corrosion Corrosion Corrosion Release Type)

Methodology (3in10 yr) 1 (1in10yr) 1 (1in15 yr) 1 1

No Containment Failure 3.59E-06

-4.47E-ll

-2.56E-10

-5.92E-10 2

Large Isolation Failures 4.20E-10 O.OOE+OO 0.00E+OO O.OOE+OO (Failure to Close)

Small Isolation Failures 3a (liner breach) 4.62E-08 O.OOE+OO O.OOE+OO O.OOE+OO 3b Large Isolation Failures l.15E-08 4.47E-ll 2.56E-10 5.92E-10 (liner breach)

Small Isolation Failures 4

(Failure to seal -Type B)

NIA NIA NIA NIA Small Isolation Failures 5

(Failure to seal-Type C)

NIA NIA NIA NIA Other Isolation Failures 6

(e.g., dependent failures)

NIA NIA NIA NIA Failures Induced by 7

Phenomena (Early and l.37E-06 O.OOE+OO O.OOE+OO O.OOE+OO Late) 8 Bypass (Interfacing 7.92E-08 0.00E+OO 0.00E+OO 0.00E+OO System LOCA)

CDF All CET end states 5.lOE-06 0.00E+OO O.OOE+OO O.OOE+OO 1 Based on data developed in Section 4.4. Only Classes 1 and 3b are impacted by the corrosion analysis.

The increase in Class 3b frequency leads to a reduction in Class 1 frequency to preserve overall CDF.

5.2 Step 2 - Develop Plant Specific Person-Rem Dose (Population Dose) Per Reactor Year Plant specific release analyses were performed to estimate the person-rem doses to the population within a 50 mile radius from the plant, and summarized in Table 4.2-6b. The results of applying these releases to the EPRl containment failure classification are as follows:

Class 1=4.57E+03 person-rem (Note 1)

Class 2 = l.34E+05 person-rem (Note 2)

Class 3a =Class 1Frequencyx10 La= 4.57E+04 person-rem (Note 3)

Class 3b =Class 1 Frequency x 100 La= 4.57E+05 person-rem (Note 3)

Class 4 =Not analyzed Class 5 =Not analyzed Class 6 =Not analyzed Class 7 = l.65E+05 person-rem (Note 4)

Class 8 = l.34E+06 person-rem (Note 5)

Page J 26

(1) Class 1 is assigned the dose from "Internal Other CM Sequences" category from Table 4.2-6b.

(2) The Class 2, containment isolation failures is assigned the dose from the "Isolation Failure" category from Table 4.2-6b.

(3) The Class 3a and 3b doses are related to the leakage rate as shown. This is consistent with the guidance provided in EPRI Report No. 1009325, Revision 2-A.

( 4) The Class 7 dose is assigned the dose from the "Late SGTR" category from Table 4.2-6b.

(5) Class 8 sequences involve containment bypass failures; as a result, the person-rem dose is not based on normal containment leakage. The releases for this class would include some fraction of Early SGTR, Late SGTR, and ISLOCA contributions. However, Class 8 is conservatively assigned the dose based entirely on the "ISLOCA" category from Table 4.2-6b because this bounds all the categories.

In summary, the population dose estimates derived for use in the risk evaluation per the EPRI methodology (Reference 8.2) containment failure classifications, and consistent with the NEI guidance (Reference 8.3) as modified by EPRI Report No. 1009325, Revision 2-A are provided in Table 5-4.

Table 5-4:

PBNP Ponulation Dose Estimates for Population Within 50 Miles Accident Classes Person-Rem (50 (Containment Release Description Type) miles) 1 No Containment Failure 4.57E+03 2

Large Isolation Failures (Failure to Close) l.34E+05 3a Small Isolation Failures (liner breach) 4.57E+04 3b Large Isolation Failures (liner breach) 4.57E+05 4

Small Isolation Failures (Failure to seal-Type B)

NIA 5

Small Isolation Failures (Failure to seal-Type C)

NIA 6

Other Isolation Failures (e.g., dependent failures)

NIA 7

Failures Induced by Phenomena (Early and Late) 1.65E+05 8

Bypass (Interfacing System LOCA) l.34E+06 The above dose estimates, when combined with the results presented in Tables 5-3a and 5-3b, yield the PBNP baseline mean consequence measures for each accident class. These results are presented in Tables 5-5a and 5-5b.

Pagej27

Table 5-5a: PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 3110 Years Accident EPRI Methodology EPRI Methodology Plus Change Due Corrosion Classes Description Person-Rem Person-Person-to Corrosion (Containment (50 miles)

Frequency Frequency Person-Rem/yr Rem/yr Rem/yrC1l Release Type)

(per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure l-J 4.57E+03 3.67E-06 1.68E-02 3.67E-06 1.68E-02

-2.05E-07 2

Large Isolation Failures 1.34E+05 4.07E-10 5.45E-05 4.07E-10 5.45E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 4.63E-08 2.12E-03 4.63E-08 2.12E-03 O.OOE+OO (liner breach) 3b

• Large Isolation Failures 4.57E+05 l.16E-08 5.29E-03 l.16E-08 5.31E-03 2.05E-05 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal -Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 1.30E-06 2.14E-01 1.30E-06 2.14E-01 O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System 1.34E+06 6.99E-08 9.36E-02 6.99E-08 9.36E-02 O.OOE+OO LOCA)

CDF All CET end states NIA 5.lOE-06 3.32E-Ol 5.lOE-06 3.32E-Ol 2.03E-05

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDF, thus the Person-Rem change for Classl is negative.

2) Characterized as IL.release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs.

Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page j 28

Table 5-5b: PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 3110 Years Accident EPRI Methodology EPRI Methodology Plus Corrosion Change Due Classes Description Person-Rem Person-Person-to Corrosion (Containment (50 miles)

Frequency Frequency Person-Release Type)

(per Rx-yr)

Rem/yr (per Rx-yr)

Rem/yr Rem/y..C1l (50 miles)

(50 miles)

I No Containment Failure <2>

4.57E+03 3.59E-06 l.64E-02 3.59E-06 l.64E-02

-2.04E-07 2

Large Isolation Failures l.34E+05 4.20E-10 5.62E-05 4.20E-10 5.62E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 4.62E-08 2.l IE-03 4.62E-08 2.llE-03 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 l.15E-08 5.28E-03 l.16E-08 5.30E-03 2.04E-05 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by 1.65E+05 l.37E-06 2.26E-Ol l.37E-06 2.26E-Ol O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 7.92E-08 1.06E-Ol 7.92E-08 l.06E-Ol O.OOE+OO LOCA)

CDP All CET end states NIA 5.IOE-06 3.56E-Ol 5.IOE-06 3.56E-Ol 2.02E-05 I) Only release Classes I and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Class I frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as I La release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs.

Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 29

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

5.3.1 Risk Impact Due to 10-year Test Interval As previously stated, Type A tests impact only Class 3 sequences. For Class 3 sequences, the release magnitude is not impacted by the change in test interval (a small or large breach remains the same, even though the probability of not detecting the breach increases). Thus, only the frequency of Class 3a and 3b sequences is directly impacted.

As it is assumed that the new Class 3 end states arise from previously intact containment states, the intact state frequency is reduced accordingly. 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 ten year interval are presented in Tables 5-6a and 5-6b.

5.3.2 Risk Impact Due to 15-Year Test Interval The risk contribution for a fifteen year interval is calculated in a manner similar to the ten year interval. The difference is in the increase in probability of leakage in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the three year interval value, as described in Section 4.3. The results for this calculation are presented in Tables 5-7a and 5-7b.

Page I 30

Table 5-6a: PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1110 Years Accident Classes EPRI Methodology EPRI Methodology Plus Corrosion Change Due to (Containment Description Person-Rem Person-Corrosion (50 miles)

Frequency Frequency Person-Rem/yr Person-Release Type)

Rem/yr(SO Rem/yr<1l (per Rx-yr) miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure t2l 4.57E+03 3.54E-06 l.62E-02 3.54E-06 l.62E-02

-l.17E-06 2

Large Isolation Failures l.34E+05 4.07E-10 5.45E-05 4.07E-10 5.45E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 l.54E-07 7.05E-03 l.54E-07 7.05E-03 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 3.85E-08 l.76E-02 3.88E-08 l.77E-02 l.17E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 l.30E-06 2.14E-Ol l.30E-06 2.14E-Ol O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 6.99E-08 9.36E-02 6.99E-08 9.36E-02 0.00E+OO LOCA)

CDP All CET end states NIA 5.lOE-06 3.49E-Ol 5.lOE-06 3.49E-Ol l.16E-04

1) Only release Classes 1and3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as IL.release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 31

Table 5-6b: PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/10 Years Accident Classes EPRI Methodology EPRI Methodology Plus Corrosion Change Due to (Containment Description Person-Rem Corrosion (50 miles)

Frequency Person-Rem/yr Frequency Person-Rem/yr Person-Release Type)

(per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles)

Rem/yr<1l 1

No Containment Failure PJ 4.57E+03 3.46E-06 l.58E-02 3.45E-06 l.58E-02

-l.17E-06 2

Large Isolation Failures 1.34E+05 4.20E-10 5.62E-05 4.20E-10 5.62E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 l.54E-07 7.04E-03 l.54E-07 7.04E-03 0.00E+OO (liner breach) 3b Large Isolation Failures 4.57E+05 3.85E-08 l.76E-02 3.87E-08 l.77E-02 l.17E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 1.37E-06 2.26E-01 1.37E-06 2.26E-Ol O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System 1.34E+06 7.92E-08 l.06E-Ol 7.92E-08 l.06E-01 O.OOE+OO LOCA)

CDF All CET end states NIA 5.lOE-06 3.73E-01 5.lOE-06 3.73E-Ol l.16E-04

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDF, thus the Person-Rem change for Classl is negative.

2) Characterized as IL.release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Pagel32

Table 5-7a: PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/15 Years Accident Classes EPRI Methodology EPRI Methodology Plus Person-Rem Corrosion Change Due to (Containment 0

Description (50 miles)

Corrosion Person-Release Type)

Frequency Person-Rem/yr Frequency Person-Rem/yr Rem/yr(l)

(per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles)

I No Containment Failure 4.57E+03 3.44E-06 l.57E-02 3.44E-06 l.57E-02

-2.71E-06 (2) 2 Large Isolation Failures l.34E+05 4.07E-10 5.45E-05 4.07E-10 5.45E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 2.31E-07 l.06E-02 2.31E-07 l.06E-02 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 5.78E-08 2.65E-02 5.84E-08 2.67E-02 2.71E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal -Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 l.30E-06 2.14E-Ol l.30E-06 2.14E-01 O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing l.34E+06 6.99E-08 9.36E-02 6.99E-08 9.36E-02 O.OOE+OO System LOCA)

CDP All CET end states NIA 5.IOE-06 3.60E-01 5.IOE-06 3.61E-01 2.69E-04

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as IL.release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 33

Table 5-7b: PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/15 Years Accident Classes EPRI Methodology EPRI Methodology Plus Change Due to Person-Rem Corrosion (Containment Description (50 miles)

Corrosion Person-Release Type)

Frequency (per Person-Rem/yr Frequency Person-Rem/yr Rem/yr(l)

Rx-yr)

(50 miles)

(per Rx-yr)

(SO miles) 1 No Containment Failure 4.57E+03 3.36E-06 l.54E-02 3.36E-06 1.54E-02

-2.71E-06 (2) 2 Large Isolation Failures l.34E+05 4.20E-10 5.62E-05 4.20E-10 5.62E-05 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 2.31E-07 l.06E-02 2.31E-07 1.06E-02 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 5.77E-08 2.64E-02 5.83E-08 2.67E-02 2.71E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by 1.65E+05 l.37E-06 2.26E-01 l.37E-06 2.26E-01 O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing l.34E+06 7.92E-08 l.06E-01 7.92E-08 l.06E-01 O.OOE+OO System LOCA)

CDP All CET end states NIA 5.lOE-06 3.85E-01 5.lOE-06 3.85E-01 2.68E-04

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as IL.release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page\\ 34

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 (CDP) below 10-6/yr and increases in LERF below 10-7/yr, and small changes in LERF as below 10-6/yr. Because the ILRT does not impact CDP, the relevant metric is LERF.

For PBNP, 100% of the frequency of Class 3b sequences can be used as a very conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI guidance methodology). Based on a ten year test interval from Tables 5-6a and 5-6b, the Class 3b large early release frequency contribution (conservatively including corrosion) is 3.88E-08/yr for Unit 1 and 3.87E-08/yr for Unit 2; and, based on a fifteen year test interval from Tables 5-7a and 5-7b, this LERF contribution increases to 5.84E-08/yr for Unit 1 and 5.83E-08/yr for Unit 2. Thus, the increase in the overall LERF due to Class 3b sequences that is due to increasing the ILRT test interval from three to fifteen years is 4.68E-08/yr for Unit 1 and 4.67E-08/yr for Unit 2 as shown in Tables 5-8a and 5-8b. Similarly, the increase in LERF due to increasing the ILRT interval from ten years to fifteen years is 1.97E-08/yr for Unit 1 and 1.96E-08/yr for Unit 2 as shown in Tables 5-8a and 5-8b.

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

5.5 Step 5 - Determine the Impact on the Conditional Containment Failure Probability (CCFP)

Another parameter that the NRC guidance in RG 1.17 4 states can provide input into the decision-making process is the change in the conditional containment failure probability (CCFP).

The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. The CCFP can be calculated from the results of this analysis. One of the difficult aspects of this calculation is providing a definition of the "failed containment." In this assessment, the CCFP is defined such that containment failure includes all radionuclide release end states other than the intact state. The conditional part of the definition is conditional given a severe accident (i.e., core damage).

The change in CCFP can be calculated by using the method specified in the EPRI Report No. 1009325, Revision 2-A. The NRC has previously accepted similar calculations (Reference 8.9) as the basis for showing that the proposed change is consistent with the Page j 35

defense-in-depth philosophy.

The list below shows the CCFP values that result from the assessment for the various testing intervals including corrosion effects.

Unit 1 CCFP = [1 - (Class 1 :frequency+ Class 3a :frequency) I CDF]

• 100%

CCFP3= [1 - (3.67E-06/yr + 4.63E-08/yr) I 5.lOE-06/yr]

• 100% = 27.08%

CCFP3 = 27.08%

CCFP10 = [1 - (3.54E-06/yr + 1.54E-07/yr) I 5.lOE-06/yr]

• 100% = 27.61 %

CCFP10= 27.61 %

CCFP15 = [1 - (3.44E-06/yr + 2.3 lE-07/yr) I 5.lOE-06/yr]

• 100% = 28.00%

CCFP15 = 28.00%

ilCCFP3 to 15 = CCFP15 - CCFP3 = 0.92%

ilCCFP10 to 1s = CCFP15 - CCFP10 = 0.39%

ilCCFP3 to 10 = CCFP10 - CCFP3 = 0.53%

Unit2 CCFP = [1 - (Class 1 frequency+ Class 3a :frequency) I CDF]

• 100%

CCFP3 = [1 - (3.59E-06/yr + 4.62E-08/yr) I 5.lOE-06/yr]

• 100% = 28.71 %

CCFP10 = [1 - (3.45E-06/yr + 1.54E-07/yr) I 5.lOE-06/yr]

• 100% = 29.24%

CCFP10= 29.24%

CCFP15 = [1 - (3.36E-06/yr + 2.31E-07/yr) I 5.lOE-06/yr]

• 100% = 29.63%

CCFP15 = 29.63%

ilCCFP3 to 15 = CCFP15 - CCFP3 = 0.92%

ilCCFP10 to 15 = CCFP15 - CCFP10 = 0.38%

ilCCFP3 to lo= CCFP10 - CCFP3 = 0.53%

The change in CCFP of approximately 0.92% :from extending the test interval to fifteen years from the original three in ten year requirement is judged to be very small.

Page I 36

5.6 Summary of Results The results from this ILRT extension risk assessment for PBNP are summarized in Tables 5-8a and 5-8b.

Table 5-8a:

PBNP Unit 1 ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions (Including Age Adjusted Steel Liner Corrosion Likelihood EPRI DOSE Per-Base Case 3 in 10 Years Extend to 1in10 Years Extend to 1 in 15 Class Rem Years CDF/Yr Per-CDF/Yr Per-CDF/Yr Per-Rem/Yr Rem/Yr Rem/Yr 1

4.57E+03 3.67E-06 l.68E-02 3.54E-06 l.62E-02 3.44E-06 l.57E-02 2

l.34E+05 4.07E-10 5.45E-05 4.07E-10 5.45E-05 4.07E-10 5.45E-05 3a 4.57E+04 4.63E-08 2.12E-03 l.54E-07 7.05E-03 2.31E-07 1.06E-02 3b 4.57E+05 1.16E-08 5.3 lE-03 3.88E-08 1.77E-02 5.84E-08 2.67E-02 7

1.65E+05 l.30E-06 2.14E-01 l.30E-06 2.14E-Ol l.30E-06 2.14E-01 8

l.34E+06 6.99E-08 9.36E-02 6.99E-08 9.36E-02 6.99E-08 9.36E-02 Total NIA 5.lOE-06 3.32E-01 5.lOE-06 3.49E-01 5.lOE-06 3.61E-01 ILRT Dose Rate from 3a and 3b 7.43E-03 2.48E-02 3.73E-02 Delta Total From 3 yr NIA l.67E-02 2.88E-02 Dose Rate From 10 yr NIA NIA 1.21E-02 change From 3 yr in dose NIA 5.04%

8.68%

rate from base From lOyr NIA NIA 3.47%

3b Frequency (LERF) 1.16E-08 3.88E-08 5.84E-08 Delta From3 yr NIA 2.72E-08 4.68E-08 LERF From 10 yr NIA NIA 1.97E-08 I

CCFP%

27.08%

27.61%

28.00%

Delta From 3 yr NIA 0.53%

0.92%

CCFP%

From lOyr NIA NIA 0.39%

Page I 37

Table 5-8b:

PBNP Unit 2 ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions (Including Age Adjusted Steel Liner Corrosion Likelihood EPRI DOSE Base Case 3 in 10 Extend to 1 in 10 Years Extend to 1in15 Years Class Per-Rem Years CDF/Yr Per-CDF/Yr Per-CDF/Yr Per-Rem/Yr Rem/Yr Rem/Yr 1

4.57E+03 3.59E-06 1.64E-02 3.45E-06 l.58E-02 3.36E-06 l.54E-02 2

l.34E+05 4.20E-10 5.62E-05 4.20E-10 5.62E-05 4.20E-10 5.62E-05 3a 4.57E+04 4.62E-08 2.l IE-03 1.54E-07 7.04E-03 2.3IE-07 1.06E-02 3b 4.57E+05 l.16E-08 5.30E-03 3.87E-08 l.77E-02 5.83E-08 2.67E-02 7

1.65E+05 l.37E-06 2.26E-Ol l.37E-06 2.26E-Ol l.37E-06 2.26E-Ol 8

l.34E+06 7.92E-08 l.06E-01 7.92E-08 l.06E-01 7.92E-08 l.06E-Ol Total NIA 5.lOE-06 3.56E-Ol 5.lOE-06 3.73E-Ol 5.IOE-06 3.85E-01 ILRT Dose Rate from 3a and 3b 7.4IE-03 2.47E-02 3.72E-02 Delta Total From 3 yr NIA l.67E-02 2.88E-02 Dose Rate From 10 yr NIA NIA 1.2IE-02 change From 3 yr NIA in dose 4.69%

8.08%

rate from base From 10 yr NIA NIA 3.23%

3b Frequency (LERF) l.16E-08 3.87E-08 5.83E-08 Delta From3 yr NIA 2.7IE-08 4.67E-08 LERF From lOyr NIA NIA 1.96E-08 CCFP%

28.71%

29.24%

29.63%

Delta From 3 yr NIA 0.53%

0.92%

CCFP%

From 10 yr NIA NIA 0.38%

6.0 Sensitivities 6.1 Sensitivity to Corrosion Impact Assumptions The PBNP results in Tables 5-Sa through 5-7b 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.

Page I 38

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 eve1y two and every ten years. The failure probabilities for the upper containment and the basemat were increased and decreased by an order of magnitude. The total detection failure likelihood was adjusted from 10% to 15% and 5%. The results are presented in Table 6-1 based on Unit 1 results. Due to the similarity of the Unit I and Unit 2 results this sensitivity is documented only for Unit 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 I.64E-08/yr. The results indicate that even with very conservative assumptions, the conclusions from the base analysis would not change.

Table 6-1:

Unit 1 Steel Plate Corrosion Sensitivity Cases Visual Increase in Class 3b Frequency Age (Step 3 in the Containment Inspection &

(LERF) for ILRT Extension corrosion Breach (Step 4 Non-Visual from 3 to 15 years (per Rx-yr) analysis) in the corrosion Flaws (Step 5 in analysis) the corrosion Increase Due analysis)

Total Increase to Corrosion Base Case Base Case Base Case Doubles every (1% Upper (10% Upper 4.69E-08 5.91E-10 Containment, Containment, 5 yrs 0.1 % Basemat) 100% Basemat)

Doubles every Base Base 4.74E-08 1.l&E-09 2 vrs Doubles every Base Base 4.68E-08 5.28E-10 JO yrs Base Base 15%

4.71E-08 8.27E-10 Base Base 5%

4.66E-08 3.55E-10 10% Upper Base Containment, 1 %

Base 5.22E-08 5.91E-09 Basemat 0.1% Upper Base Containment, Base 4.63E-08 5.91E-11 0.01 % Basemat Lower Bound Doubles every 0.1% Upper 5% Upper Containment, Containment; 4.63E-08

~2.l lE-11 10 yrs 0.01 % Basemat 1% Basemat Upper Bound Doubles every 2 10% Upper 15% Upper Containment, 1 %

Containment, 6.27E-08 1.64E-08 yrs Basemat 100% Basemat Page J 39

6.2 Sensitivity to Class 3B Contribution to LERF The Class 3b frequency for the base case of a three in ten year ILRT interval including corrosion is l.16E-08/yr for Unit 1 and 1.16E-08/yr for Unit 2 (Tables 5-5a and 5-5b). Extending the interval to one in ten years results in a frequency of 3.88E-08/yr for Unit 1 and 3.87E-08/yr for Unit 2 (Tables 5-6a and 5-6b). Extending it to one in fifteen years results in a frequency of 5.84E-08/yr for Unit 1 and 5.83E-08/yr for Unit 2 (Tables 5-7a and 5-7b ), which is an increase of approximately 4.68E-08/yr from three in ten years to once in fifteen years.

Even when 100% of the Class 3b sequences are assumed to have potential releases large enough for LERF, then the increase in LERF due to extending the interval from three in ten to one in fifteen is below the RG 1.174 threshold for very small changes in LERF of 1.0E-07 /yr.

6.3 Potential Impact from External Events and Internal Flooding Contribution As described in Section 4.2.1 above, the ILRT risk assessment quantitative results are based on PBNP's Internal Events Level 1 and Level 2 PRA model. This model is used to define the distribution of releases amongst the different EPRI release class bins. This section summarizes the impact on the ILRT risk assessment of including external events (fire, seismic, other external events) and internal flooding core damage frequency.

The purpose of the external events evaluation is to determine. whether there are any unique insights or important quantitative information that explicitly impact the risk assessment results obtained when considering only internal events.

The detailed external events and internal flooding risk assessment is shown in Tables 6-3a to 6-9b. As described in Section 4.2.1, the PBNP PRA includes fire and internal flooding models that are peer reviewed against the requirements of the PRA Standard and RG-1.200, Rev. 2. The PBNP PRA quantitative results for fire and internal flooding are used directly without further qualitative evaluation or sensitivity study. The seismic and other external events results are based on IPEEE evaluations rather than formally peer reviewed models. Accordingly, seismic and external events risks are qualitatively assessed below to further demonstrate that the proposed ILRT Type A test extension has a minimal risk impact from external events.

6.3.1 External Events and Internal Flooding Contribution - Qualitative Insights Internal Fire Events - Qualitative Risk Impacts on ILRT Extension The PBNP Fire PRA includes an integrated quantitative assessment of at-power internal fire risk.

In the base case plant risk model, internal fire events contribute significantly to the total Unit 1 and Unit 2 at-power CDF and LERF. The base case quantitative CDF/LERF risk results for internal fire events are as provided in Tables 4.2-1 and 4.2-2 and are used in the quantitative external event assessment in Tables 6-3a to 6-9b.

Pagel40

The proposed extension of the ILRT interval does not impact the frequency of any fire initiating events nor does the ILRT extension impact the reliability of active equipment credited in fire initiating event sequences. PBNP addressed critical fire vulnerabilities as part of the transition to a performance-based, risk-informed fire protection program in accordance with 10 CFR 50.48(c) and NFPA 805 (References 8.36 and 8.37).

The ILRT test is focused on performing a periodic validation of the containment liner leak tightness, which is a condition that is independent of fire events risk. Therefore the ILRT extension has no direct effect on the core damage from fire events.

Internal Flooding Events - Qualitative Risk Impacts on ILRT Extension The PBNP PRA includes an integrated quantitative assessment of at-power internal flooding risk. In the base case plant risk model, internal flooding events contribute less than 1 % of the total Unit 1 and Unit 2 at-power CDF and LERF. The base case quantitative CDF/LERF results for internal flooding events are as provided in Tables 4.2-1 and 4.2-2 and are used in the quantitative external event assessment in Tables 6-3a to 6-9b.

The proposed extension of the ILRT interval does not impact the frequency of any flooding initiating events nor does the ILRT extension impact the reliability of active equipment credited in flooding initiating event sequences. The ILRT test is focused on performing a periodic validation of the containment liner leak tightness, which is a condition that is independent of flooding events risk. Therefore the ILR T extension has no direct effect on the core damage from flooding events.

Seismic Events - Qualitative Risk Impacts on ILRT Extension The PBNP Seismic risk is derived from the SMA performed for the IPEEE (Reference 8.24). In the base case plant risk model, seismic events contribute approximately 9% to Unit 1 and 8% to Unit 2 total at-power CDF. Seismic events contribute approximately 53% to Unit 1 and 49% to Unit 2 total at-power LERF. The base case quantitative CDF/LERF results for seismic events are as provided in Tables 4.2-1 and 4.2-2 and are used in the quantitative external event assessment in Tables 6-3a to 6-9b. As shown in Table 4.2-2, seismic events contribute approximately l.2E-06/yr to LERF based on the conservative SMA estimates.

The proposed extension of the ILRT interval does not impact the frequency of any seismic initiating event nor does the ILRT extension impact the reliability of active equipment credited in seismic initiating event sequences. The ILRT test is focused on performing a periodic validation of the containment liner leak tightness, which is a condition independent of the risk of seismic events.

Therefore the ILRT extension has no direct effect on the core damage or release mitigation capability from seismic events.

Page I 41

As noted above the PBNP seismic risk is from a SMA rather than a formally peer reviewed seismic PRA. If a seismic PRA were developed using the latest industry seismic risk hazard and methods, it is recognized that the actual PBNP seismic-induced CDF/LERF could increase above the current values. The seismic CDF stated in Table D-1 of Appendix D to the NRC Safety/Risk Assessment for Generic Issue 199 (GI-199), "Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants" (Reference 8.33), is 7.3E-6/yr for the "simple average" and is 1.lE-05/yr for the bounding "weakest link model." The seismic CDF of 1.lE-05/yr is approximately 76% higher than the PBNP seismic CDF used in the base risk assessment. Therefore, a seismic risk sensitivity evaluation was performed by assuming that the current seismic-induced CDF is equivalent to 1. lE-05/yr. This sensitivity updates the external event core damage frequency input by increasing the release category frequencies in Tables 4.2-4 and 4.2-5 by the ratio of the GI-199 seismic CDF to PBNP's model-of-record CDF in Table 4.2-1. All other calculations in the assessment are unchanged. The results of this evaluation for Unit 1 are shown in Table 6-2. Due to the similarity of the results for Unit 1 and Unit 2, this sensitivity is documented only for Unit 1. This evaluation shows that the 3b LERF due to external events for a 15 year ILRT interval would become 8.l 7E-07/yr resulting in a delta-LERF of 6.55E-07/yr. This represents an increase in the delta-LERF of approximately 4.36E-08/yr above the baseline Unit 1 external event delta-LERF of 6.1 lE-07 /yr (Table 6-9a).

This shows that the baseline delta-LERF is relatively insensitive to the assumed increase in seismic risk.

Based on this seismic risk sensitivity, the baseline quantitative seismic CDF and LERF contributions are judged appropriate for use in the delta LERF impact of the ILRT Type A test interval extension.

Page I 42

Table 6-2: Sensitivity to GI-199 Seismic CDF for PBNP EPRI DOSE Base Case 3 in 10 Years Extend to 1 in 10 Years Extend to 1in15 Years Class Per-Rem CDF/Yr Per-CDF/Yr Per-CDF/Yr Per-Rem/Yr Rem/Yr Rem/Yr 1

4.57E+03 5.13E-05 2.35E-Ol 4.95E-05 2.26E-01 4.81E-05 2.20E-01 2

1.34E+05 5.70E-09 7.63E-04 5.70E-09 7.63E-04 5.70E-09 7.63E-04 3a 4.57E+04 6.47E-07 2.96E-02 2.15E-06 9.85E-02 3.23E-06 l.48E-Ol 3b 4.57E+05 1.62E-07 7.43E-02 5.42E-07 2.48E-OI 8.l 7E-07 3.74E-Ol 7

l.65E+05 l.82E-05 2.99E+OO 1.82E-05 2.99E+OO l.82E-05 2.99E+OO 8

1.34E+06 9.78E-07 1.3 IE+OO 9.78E-07 l.31E+OO 9.78E-07 l.31E+OO Total NIA 7.13E-05 4.64E+OO 7.13E-05 4.87E+OO 7.13E-05 5.04E+OO ILRT Dose Rate from 3aand3b l.04E-01 3.47E-OI 5.22E-01 Delta From 3 yr NIA 2.34E-01 4.03E-01 Total Dose Rate From 10 yr NIA NIA l.69E-01 change From 3 yr NIA 5.04%

8.68%

in dose rate from base From 10 yr NIA NIA 3.47%

3b Frequency (LERF) l.62E-07 5.42E-07 8.17E-07 From 3 yr NIA Delta 3.80E-07 6.55E-07 LERF From 10 yr NIA NIA 2.75E-07 CCFP%

27.08%

27.61%

28.00%

From 3 yr NIA 0.53%

0.92%

Delta CCFP%

From 10 yr NIA NIA 0.39%

Other External Events - Qualitative Risk Impacts on ILRT Extension Other external events include external flooding, high winds, tornado, transportation and near-by industrial facility hazards, turbine missile, aircraft crash, heavy load drop, etc. These other external events are screened out based on the low probability of occurrence and rigorous plant design features as described in the PRA notebook for external events PRA 9.2 (Reference 8.19).

These other external events are judged to have a very small contribution to CDF/LERF, however, for the purposes of the quantitative evaluation in Tables 6-3a to 6-9b, the CDP and LERF values cited in Table 4.2-1 are used.

Page J 43

The proposed extension of the ILRT test interval does not impact the initiating event frequencies of other external events nor does the ILRT extension impact the reliability of active equipment needed to mitigate these events. The ILRT test is focused on performing a periodic validation of the containment liner leak tightness, which is a condition that is independent of external event risk.

Therefore the ILRT extension has no direct effect on the core damage and release mitigation capability from external events.

6.3.2 External Events and Internal Flooding Contribution - Quantitative Evaluation It is assumed that the distribution of the internal flooding and external events (IF IEE) contributions to core damage frequency will be similar to that of internal events (Section 3.0).

The percent contribution of the total CDP to each accident class is provided in Table 4.2-3.

The total contribution to CDP from IF IEE is:

Ul: 3.0E-07/yr (IF)+ 6.24E-06/yr (seismic)+ 5.9E-05/yr (fire)+ 1.0E-06/yr (other)= 6.65E-05/yr U2: 3.0E-07/yr (IF)+ 6.24E-06/yr (seismic)+ 6.9E-05/yr (fire)+ 1.0E-06/yr (other)= 7.65E-05/yr Tables 4.2-4 and 4.2-5 provide the results of distributing the internal flooding and external events CDP contributions to the EPRI accident classes. Utilizing the combined external event input, the impact ofILRT interval extension due to external events is evaluated in Tables 6-3a to 6-9b.

Table 6-3a:

PBNP Unit 1 Categorized Accident Classes and Frequencies (EE Sensitivity)

Adjusted Frequency EPRI Class Class Frequency (-/yr)

Using Scale Factor of 1.0 (per vr) 1 4.87E-05 4.87E-05 2

5.31E-09 5.31E-09 7

l.69E-05 l.69E-05 8

9.12E-07 9.12E-07 Total 6.65E-05 6.65E-05 Frequency 3a

=0.0092* CDF-Class2-Class8 6.04E-07 3b

=O.0023 *( CDF-Class2-Class8 l.51E-07 Page I 44

Table 6-3b:

PBNP Unit 2 Catee:orized Accident Classes and Frequencies (EE Sensitivity)

Adjusted Frequency EPRI Class Class Frequency (-/yr)

Using Scale Factor of 1.0 (per yr) 1 5.47E-05 5.47E-05 2

6.30E-09 6.30E-09 7

2.06E-05 2.06E-05 8

l.19E-06 l.19E-06 Total 7.65E-05 7.65E-05 Frequency 3a

=0.0092* CDF-Class2-Class8 6.93E-07 3b

=0.0023* CDF-Class2-Class8 l.73E-07 Table 6-4a:

PBNP Unit 1 Radionuclide Release Frequencies as a Function of Accident Class (EE Sensitivity)

Accident Frequency (per Rx-yr)

Classes Description (Containment EPRI Corrosion Corrosion Corrosion Release Type)

Methodology (3 in 10yr) 1 (1in10yr) 1 (1in15 yr) 1 1

No Containment Failure 4.79E-05

-5.84E-10

-3.35E-09

-7.74E-09 2

Large Isolation Failures 5.31E-09 O.OOE+OO O.OOE+OO O.OOE+OO (Failure to Close)

Small Isolation Failures 3a (liner breach) 6.04E-07 0.00E+OO 0.00E+OO 0.00E+OO 3b Large Isolation Failures l.51E-07 5.84E-10 3.35E-09 7.74E-09 (liner breach)

Small Isolation Failures 4

(Failure to seal-Type B)

NIA NIA NIA NIA Small Isolation Failures NIA NIA NIA NIA 5

(Failure to seal-Type C)

Other Isolation Failures 6

(e.g., dependent failures)

NIA NIA NIA NIA Failures Induced by 7

Phenomena (Early and l.69E-05 O.OOE+OO O.OOE+OO O.OOE+OO Late) 8 Bypass (Interfacing 9.12E-07 O.OOE+OO 0.00E+OO 0.00E+OO System LOCA)

CDP All CET end states 6.65p-05 O.OOE+OO O.OOE+OO O.OOE+OO 1 Based on data developed in Section 4.4. Only Classes 1 and 3b are impacted by the corrosion analysis.

The increase in Class 3b frequency leads to a reduction in Class 1 frequency to preserve overall CDP.

Page I 45

Table 6-4b:

PBNP Unit 2 Radionuclide Release Frequencies as a Function of Accident Class (EE Sensitivity)

Accident Frequency (per Rx-yr)

Classes Description (Containment EPRI Corrosion Corrosion Corrosion Release Type)

Methodology (3in10 yr)1 (1in10 yr) 1 (1in15yr) 1 1

No Contaimnent Failure 5.39E-05

-6.71E-l0

-3.84E-09

-8.89E-09 2

Large Isolation Failures 6.30E-09 0.00E+OO O.OOE+OO O.OOE+OO (Failure to Close)

Small Isolation Failures 3a (liner breach) 6.93E-07 O.OOE+OO O.OOE+OO O.OOE+OO 3b Large Isolation Failures l.73E-07 6.71E-10 3.84E-09 8.89E-09 (liner breach)

Small Isolation Failures 4

(Failure to seal - Type B)

NIA NIA NIA NIA Small Isolation Failures 5

(Failure to seal-Type C)

NIA NIA NIA NIA 6

Other Isolation Failures (e.g., dependent failures)

NIA NIA NIA NIA 7

Failures Induced by 2.06E-05 O.OOE+OO O.OOE+OO 0.00E+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.19E-06 0.00E+OO O.OOE+OO O.OOE+OO LOCA)

CDF All CET end states 7.65E-05 O.OOE+OO O.OOE+OO 0.00E+OO 1 Based on data developed in Section 4.4. Only Classes 1 and 3b are impacted by the corrosion analysis.

The increase in Class 3b frequency leads to a reduction in Class 1 frequency to preserve overall CDF.

Table 6-5:

PBNP Population Dose Estimates for Population Within 50 Miles <EE Sensitivity)

Accident Classes Person-Rem (50 (Containment Release Description Type) miles) 1 No Containment Failure 4.57E+03 2

Large Isolation Failures (Failure to Close) l.34E+05 3a Small Isolation Failures (liner breach) 4.57E+04 3b Large Isolation Failures (liner breach) 4.57E+05 4

Small Isolation Failures (Failure to seal -Type B)

NIA 5

Small Isolation Failures (Failure to seal-Type C)

NIA 6

Other Isolation Failures (e.g., dependent failures)

NIA 7

Failures Induced by Phenomena (Early and Late) l.65E+05 8

Bypass (Interfacing System LOCA) l.34E+06 Page j 46

Table 6-6a: PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 3/10 Years (EE Sensitivity)

Accident EPRI Methodology EPRI Methodology Plus Corrosion Classes Person-Rem Change Due to (Containment Description (50 miles)

Frequency Person-Rem/yr Frequency Corrosion Person-Person-Rem/yr Rem/yr(!)

Release Type)

(per Rx-yr)

(SO miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure H 4.57E+03 4.79E-05 2.19E-01 4.79E-05 2.19E-01

-2.67E-06 2

Large Isolation Failures 1.34E+05 5.31E-09 7.12E-04 5.31E-09 7.12E-04 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 6.04E-07 2.76E-02 6.04E-07 2.76E-02 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 l.51E-07 6.90E-02 l.52E-07 6.93E-02 2.67E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 l.69E-05 2.79E+OO l.69E-05 2.79E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System 1.34E+06 9.12E-07 l.22E+OO 9.12E-07 l.22E+OO 0.00E+OO LOCA)

CDP All CET end states NIA 6.65E-05 4.33E+OO 6.65E-05 4.33E+OO 2.64E-04 I) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Class I frequency to preserve overall CDP, thus the Person-Rem change for Class I is negative.

2) Characterized as IL. release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page J 47

Table 6-6b: PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 3/10 Years (EE Sensitivity)

Accident EPRI Methodology EPRI Methodology Plus Corrosion Classes Person-Rem Change Due to Description Corrosion Person-(Containment (50 miles)

Frequency Person-Rem/yr Frequency Person-Rem/yr Rem/yr<1l Release Type)

(per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure tzJ 4.57E+03 5.39E-05 2.46E-Ol 5.39E-05 2.46E-Ol

-3.07E-06 2

Large Isolation Failures l.34E+05 6.30E-09 8.43E-04 6.30E-09 8.43E-04 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 6.93E-07 3.17E-02 6.93E-07 3.17E-02 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 l.73E-07 7.93E-02 l.74E-07 7.96E-02 3.07E-04 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal -Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 2.06E-05 3.39E+OO 2.06E-05 3.39E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 l.19E-06 l.59E+OO l.19E-06 l.59E+OO 0.00E+OO LOCA)

CDF All CET end states NIA 7.65E-05 5.34E+OO 7.65E-05 5.35E+OO 3.04E-04

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDF, thus the Person-Rem change for Classl is negative.

2) Characterized as lLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page J 48

Table 6-7a:

PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/10 Years (EE Sensitivity)

Accident Classes EPRI Methodology EPRI Methodology Plus Person-Rem Corrosion Change Due to (Containment Description (50 miles)

Corrosion Person-Release Type)

Frequency Person-Rem/yr Frequency Person-Rem/yr Rem/yr<1l (per Rx-yr)

(SO miles)

(per Rx-yr)

(SO miles) 1 No Containment Failure t:-J 4.57E+03 4.62E-05 2.llE-01 4.62E-05 2.llE-01

-1.53E-05 2

Large Isolation Failures l.34E+05 5.31E-09 7.12E-04 5.31E-09 7.12E-04 0.00E+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 2.0lE-06 9.20E-02 2.0lE-06 9.20E-02 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 5.03E-07 2.30E-01 5.06E-07 2.31E-Ol 1.53E-03 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by 1.65E+05 1.69E-05 2.79E+OO l.69E-05 2.79E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System 1.34E+06 9.12E-07 1.22E+OO 9.12E-07 1.22E+OO 0.00E+OO LOCA)

CDF All CET end states NIA 6.65E-05 4.55E+OO 6.65E-05 4.55E+OO 1.52E-03

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDF, thus the Person-Rem change for Classl is negative.

2) Characterized as IL. release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page J 49

Table 6-7b:

PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/10 Years (EE Sensitivity)

Accident Classes EPRI Methodology EPRI Methodology Plus Person-Rem Corrosion Change Due to (Containment Description (50 miles)

Corrosion Person-Release Type)

Frequency Person-Rem/yr Frequency Person-Rem/yr Rem/yr<1l (per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure l;(J 4.57E+03 5.19E-05 2.37E-Ol 5.18E-05 2.37E-Ol

-l.76E-05 2

Large Isolation Failures l.34E+05 6.30E-09 8.43E-04 6.30E-09 8.43E-04 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 2.31E-06 l.06E-Ol 2.31E-06 l.06E-Ol O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 5.77E-07 2.64E-Ol 5.81E-07 2.66E-Ol l.76E-03 (liner breach) 4 "Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 2.06E-05 3.39E+OO 2.06E-05 3.39E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 l.19E-06 l.59E+OO l.19E-06 l.59E+OO O.OOE+OO LOCA)

CDP All CET end states NIA 7.65E-05 5.59E+OO 7.65E-05 5.60E+OO l.74E-03

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as lLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 50

Table 6-8a:

PBNP Unit 1 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1115 Years (EE Sensitivity)

Accident Classes EPRI Methodology EPRI Methodology Plus Person-Rem Corrosion Change Due to (Containment Description (50 miles)

Corrosion Release Type)

Frequency Person-Rem/yr Frequency Person-Rem/yr Person-Rem/yr<1l (per Rx-yr)

(50 miles)

(per Rx-yr)

(SO miles) 1 No Containment Failure l~J 4.57E+03 4.49E-05 2.0SE-01 4.49E-05 2.0SE-01

-3.54E-05 2

Large Isolation Failures l.34E+05 5.31E-09 7.12E-04 5.31E-09 7.12E-04 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 3.02E-06 l.38E-01 3.02E-06 1.38E-01 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 7.55E-07 3.45E-Ol 7.62E-07 3.49E-01 3.54E-03 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by 1.65E+05 l.69E-05 2.79E+OO l.69E-05 2.79E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 9.12E-07 1.22E+OO 9.12E-07 l.22E+OO O.OOE+OO LOCA)

CDP All CET end states NIA 6.65E-05 4.70E+OO 6.65E-05 4.71E+OO 3.SlE-03

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDP, thus the Person-Rem change for Classl is negative.

2) Characterized as lLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 51

Table 6-8b:

PBNP Unit 2 Annual Dose as a Function of Accident Class; Characteristic of Conditions for ILRT Required 1/15 Years (EE Sensitivity)

Accident Classes EPRI Methodology EPRI Methodology Plus Person-Rem Corrosion Change Due to (Containment Description (50 miles)

Corrosion Release Type)

Frequency Person-Rem/yr Frequency Person-Rem/yr Person-Rem/yr<1l (per Rx-yr)

(50 miles)

(per Rx-yr)

(50 miles) 1 No Containment Failure lZJ 4.57E+03 5.04E-05 2.31E-01 5.04E-05 2.31E-01

-4.07E-05 2

Large Isolation Failures l.34E+05 6.30E-09 8.43E-04 6.30E-09 8.43E-04 O.OOE+OO (Failure to Close) 3a Small Isolation Failures 4.57E+04 3.47E-06 l.59E-01 3.47E-06 l.59E-01 O.OOE+OO (liner breach) 3b Large Isolation Failures 4.57E+05 8.66E-07 3.96E-01 8.75E-07 4.00E-01 4.07E-03 (liner breach) 4 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type B) 5 Small Isolation Failures NIA NIA NIA NIA NIA NIA (Failure to seal-Type C) 6 Other Isolation Failures NIA NIA NIA NIA NIA NIA (e.g., dependent failures) 7 Failures Induced by l.65E+05 2.06E-05 3.39E+OO 2.06E-05 3.39E+OO O.OOE+OO Phenomena (Early and Late) 8 Bypass (Interfacing System l.34E+06 l.19E-06 1.59E+OO l.19E-06 l.59E+OO O.OOE+OO LOCA)

CDF All CET end states NIA 7.65E-05 5.77E+OO 7.65E-05 5.78E+OO 4.03E-03

1) Only release Classes 1 and 3b are affected by the corrosion analysis. The increase in Class3b frequency leads to a reduction in Classl frequency to preserve overall CDF, thus the Person-Rem change for Classl is negative.

2) Characterized as lLa release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release Classes 3a and 3b include failures of containment to meet the Technical Specification leak rate.

Page I 52

Table 6-9a:

PBNP Unit 1 ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions Including Age Adjusted Steel Liner Corrosion Likelihood (EE Sensitivity)

EPRI DOSE Base Case 3 in 10 Extend to 1 in 10 Extend to 1 in 15 Class Per-Rem Years Years Years CDF/Yr Per-CDF/Yr Per-CDF/Yr Per-Rem/Yr Rem/Yr Rem/Yr 1

4.57E+03 4.79E-05 2.19E-Ol 4.62E-05 2.llE-01 4.49E-05 2.05E-Ol 2

l.34E+05 5.31E-09 7.12E-04 5.31E-09 7.12E-04 5.31E-09 7.12E-04 3a 4.57E+04 6.04E-07 2.76E-02 2.0lE-06 9.20E-02 3.02E-06 l.38E-Ol 3b 4.57E+05 1.52E-07 6.93E-02 5.06E-07 2.31E-01 7.62E-07 3.49E-01 7

l.65E+05 l.69E-05 2.79E+OO l.69E-05 2.79E+OO l.69E-05 2.79E+OO 8

l.34E+06 9.12E-07 l.22E+OO 9.12E-07 l.22E+OO 9.12E-07 l.22E+OO Total NIA 6.65E-05 4.33E+OO 6.65E-05 4.55E+OO 6.65E-05 4.71E+OO ILRT Dose Rate from 3a and 3b 9.69E-02 3.23E-Ol 4.87E-01 Delta From 3 yr Total NIA 2.18E-Ol 3.76E-Ol Dose Rate From 10 yr NIA NIA l.58E-01 change From 3 yr NIA 5.04%

8.68%

in dose rate from base From 10 yr NIA NIA 3.47%

3b Frequency (LERF) 1.52E-07 5.06E-07 7.62E-07 From 3 yr NIA 3.54E-07 6.llE-07 Delta LERF From 10 yr NIA NIA 2.56E-07 CCFP%

27.08%

27.61%

28.00%

From 3 yr NIA 0.53%

0.92%

Delta CCFP%

From lOyr NIA NIA 0.39%

Page J 53

Table 6-9b:

PBNP Unit 2 ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions Including Age Ad.iusted Steel Liner Corrosion Likelihood (EE Sensitivity)

EPRI DOSE Base Case 3 in 10 Extend to 1 in 10 Years Extend to 1 in 15 Class Per-Rem Years Years CDF/Yr Per-CDF/Yr Per-CDF/Yr Per-Rem/Yr Rem/Yr Rem/Yr I

4.57E+03 5.39E-05 2.46E-OI 5.18E-05 2.37E-01 5.04E-05 2.31E-OI 2

l.34E+05 6.30E-09 8.43E-04 6.30E-09 8.43E-04 6.30E-09 8.43E-04 3a 4.57E+04 6.93E-07 3.17E-02 2.31E-06 l.06E-01 3.47E-06 1.59E-Ol 3b 4.57E+05 1.74E-07 7.96E-02 5.81E-07 2.66E-Ol 8.75E-07 4.00E-01 7

1.65E+05 2.06E-05 3.39E+OO 2.06E-05 3.39E+OO 2.06E-05 3.39E+OO 8

l.34E+06 l.19E-06 l.59E+OO l.19E-06 l.59E+OO 1.19E-06 l.59E+OO Total NIA 7.65E-05 5.35E+OO 7.65E-05 5.60E+OO 7.65E-05 5.78E+OO ILRT Dose Rate from 1.llE-01 3.71E-01 5.59E-O 1 3a and 3b Delta Total From 3 yr NIA 2.51E-Ol 4.32E-Ol Dose Rate From 10 yr NIA NIA 1.81E-01 change From 3 yr NIA 4.69%

8.08%

in dose rate from base From 10 yr NIA NIA 3.23%

3b Frequency (LERF) 1.74E-07 5.81E-07 8.75E-07 Delta From 3 yr NIA 4.07E-07 7.0lE-07 LERF From 10 yr NIA NIA 2.94E-07 CCFP%

28.71%

29.24%

29.63%

Delta From 3 yr NIA 0.53%

0.92%

CCFP%

From 10 yr NIA NIA 0.38%

Page I 54

7.0 Conclusions Permanently increasing the Type A ILRT interval to fifteen years is considered to be an insignificantly small change to the PBNP risk profile. This conclusion is based on the following results from Section 5.0 and the sensitivity calculations presented in Section 6.0:

RG 1.174 (Reference 8.4) provides guidance for determining the risk impact of plant specific changes to the licensing basis based on changes to CDF and LERF. Since the ILRT does not impact CDF, the relevant criterion is LERF. The increase in LERF resulting from a change in the Type A ILRT test interval from three in ten years to one in fifteen years is conservatively estimated for Unit 1 as 4.68E-08/yr due to internal events contribution and 6.l lE-07/yr due to internal flood and external events. The total combined impact for Unit 1 is 6.58E-07/yr.

For Unit 2, the impact is conservatively estimated as 4.67E-08/yr due to internal events contribution and 7.0lE-7/yr due to internal flood and external events. The total combined impact for Unit 2 is 7.48E-7/yr.

RG 1.174 (Reference 8.4) states that changes in LERF less than l.OE-07 per reactor year are considered "very small" and are acceptable without evaluation of total LERF. Regulatory Guide 1.174 (Reference 8.4) also states that when the calculated increase in LERF is in the "small" range of l.OE-07 per reactor year to l.OE-06 per reactor year, applications will be considered only if it can be reasonably shown that the total LERF is less than l.OE-05 per reactor year. The impact due to an increase in the Type A ILRT interval to one in fifteen years is "very small" when considering only internal events. When including the impact from internal flood and external events, the change to LERF is in the "small" range for both PBNP Unit 1 and Unit 2, therefore, the total LERF is evaluated. The resulting total LERF for Unit 1is6.58E-07/yr + 2.3E-06/yr (from Table 4.2-2) = 3.0E-06/yr. The resulting total LERF for Unit 2 is 7.48E-07/yr + 2.5E-06/yr (from Table 4.2-2) = 3.2E-06/yr. The total LERF for both Unit 1 and Unit 2 are below the RG 1.174 acceptance criteria for total LERF of l.OE-05/yr and therefore this change satisfies both the incremental and absolute criteria with regard to the RG 1.174 LERF metric.

The change in Type A test frequency to once per fifteen years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 2.88E-02 person-rem/yr for Unit 1 and 2.88E-02 person-rem/yr for Unit 2 when considering internal events only. Including the effect of internal flood and external events, the total change in plant risk is 0.405 person-rem/yr for Unit 1 and 0.461 person-rem/yr for Unit 2.

EPRI Report No. 1009325, Revision 2-A states that a very small population dose is defined as an increase of::::; 1.0 person-rem per year or::::; 1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This is consistent with the NRC Final Safety Evaluation for NEI 94-01 and EPRI Repoti No. 1009325 (Reference 8.29). Moreover, the risk impact when compared to other severe accident risks is negligible.

Page I 55

The increase in the conditional containment failure probability from the three in ten year interval to a permanent one time in fifteen year interval is 0.92% for both Unit 1 and Unit 2.

EPRI Report No. 1009325, Revision 2-A states that increases in CCFP of:::; 1.5 percentage points are very small. This is consistent with the NRC Final Safety Evaluation for NEI 94-01 and EPRI Report No. 1009325 (Reference 8.29). Therefore this increase is judged to be very small.

7.1.1 Previous Assessments The NRC in NUREG-1493 (Reference 8.6) has previously concluded that:

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

Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage rate tests is possible with minimal impact on public risk. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.

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

Page I 56

8.0 References 8.1 Industry Guideline for Implementing Performance-Based Option of 10 CPR Pmi 50, Appendix J, NEI 94-01, Revision 3-A, July 2012.

8.2 Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI, Palo Alto, CA EPRI TR-104285, August 1994.

8.3 Interim Guidance for Performing Risk Impact Assessments In Supp011 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.

8.4 An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 3, January 2018.

8.5 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.

8.6 Performance-Based Containment Leak-Test Program, NUREG-1493, September 1995.

8.7 Evaluation of Severe Accident Risks: Surry Unit 1, Main Report NUREG/CR-4551, SAND86-1309, Volume 3, Revision 1, Part 1, December 1990.

8.8 Letter from R. J. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-007, January 18, 2001.

8.9 United States Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No. 3 - Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing (TAC No. MBO 178), April 17, 200 I.

8.10 Impact of Containment Building Leakage on L WR Accident Risk, Oak Ridge National Laboratory, NUREG/CR-3539, ORNL/TM-8964, April 1984.

8.11 Reliability Analysis of Containment Isolation Systems, Pacific Northwest Laboratory, NUREG/CR-4220, PNL-5432, June 1985.

8.12 Technical Findings and Regulatory Analysis for Generic Safety Issue II.E.4.3

'Containment Integrity Check', NUREG-1273, April 1988.

8.13 Review of Light Water Reactor Regulatory Requirements, Pacific Northwest Laboratory, NUREG/CR-4330, PNL-5809, Vol. 2, June 1986.

8.14 Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAM', EPRI, Palo Alto, CA TR-105189, Final Rep011, May 1995.

Page I 57

8.15 Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG-1150, December 1990.

8.16 United States Nuclear Regulatory Commission, Reactor Safety Study, WASH-1400, October 1975.

8.17 Point Beach Nuclear Plant Units 1 and 2, License Amendment Request 287, Application to Adopt 10CFR50.69, "Risk-Informed Categorization and Treatment of Structure, Systems, and Components (SS Cs) for Nuclear Power Plant," Aug 31, 2017 and NRC 2017-0052, Supplement to LAR 287, Application to Adopt 10CFR50.69, "Risk-Informed Categorization and Treatment of Structure, Systems, and Components (SSCs) for Nuclear Power Plant."

8.18 S&L Evaluation 2017-10630, Rev. 0, "Permanent ILRT Interval Extension Risk Assessment," January 2018.

8.19 PBNP PRA Model Documentation Notebook, PRA 9.2, Rev. 1, "Other External Events Notebook."

8.20 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.

8.21 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.

8.22 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, P0293010002-1929-030602, March 2002.

8.23 Letter from D.E. Young (Florida Power, Crystal River) to U.S. Nuclear Regulatory Commission, 3F0401-11, dated April 25, 2001.

8.24 Point Beach Nuclear Plant Units 1 and 2 - Review of Individual Plant Examination of External Events (IPEEE) Submittal (TAC NOS M83661 and M83662) (MLl 12030452),

September 15, 1999.

8.25 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.

8.26 *Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI, Palo Alto, CA: 1009325 R2-A. (Also identified as EPRI TR-1018243.)

8.27 Letter from P.P. Sena III (FENOC) to Document Control Desk (NRC), dated June 18, 2009, Beaver Valley Power Station, Unit No. 1, Docket No. 50-334, License No. DPR-66, LER 2009-003-00, "Containment Liner Through Wall Defect Due to Corrosion."

Page I 58

8.28 Letter from J.E. Pollock (AEP Indiana Michigan Power) to Document Control Desk (NRC), dated March 16, 2001, submitting LER 316/2000-001-01, "Through-Liner Hole Discovered in Containment Liner."

8.29 Final Safety Evaluation For NEI Topical Report 94-01Revision2, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J" and EPRI Report No. 1009325, Revision 2, "Risk Impact Assessment of Extended Integrated Leak Rate Test Intervals," June 25, 2008 (ADAMS Accession No. ML081140105).

8.30 PBNP License Renewal Environmental Report (ML040580025), February 2004.

8.31 PBNP License Amendment Request 256, One Time Extension of Containment Integrated Leakage Rate Test Interval (ML073520398), Enclosure 3.

8.32 UFSAR 2017 (living documented updated as of02-07-2018), Point Beach Units 1 & 2 Final Safety Analysis Report, Section 5.1.2.

8.33 "Safety/Risk Assessment of Generic Issue (GI) 199, 'Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants,'"

August 2010 (ADAMS Accession Nos. ML100270639 and ML100270756).

8.34 EPRI NP-6395-D, "Probabilistic Seismic Hazard Evaluations at Nuclear Plant Sites in the Central and Eastern United States: Resolution of the Charleston Earthquake Issue,"

April 1989.

8.35 U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 2, 2009.

8.36 Point Beach Nuclear Plant, Units 1 and 2 - Issuance of Amendments Regarding Transition to a Risk-Informed, Performance-Based Fire Protection Program in Accordance with 10 CFR 50.48(c) (CAC NOS. MF2372 and MF2373) (ML16196A093), September 8, 2016.

8.37 NRC 2016-0013, Point Beach Nuclear Plant, Units 1 and 2 - Supplement 4 to License Amendment Request 271 Associated with NFPA 805, April 7, 2016.

8.38 Point Beach Nuclear Plant Units 1 and 2 - Issuance of Amendments Regarding Relocation of Surveillance Frequencies to Licensee Control (TAC NOS MF4379 and MF4380)

(ML15195A201), July 28, 2015.

8.39 Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4," USNRC, June 1991.

8.40 NEI Letter to USNRC, "Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations (F&Os)," February 21, 2017 (ADAMS Accession No. ML17086A431).

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8.41 USNRC Letter to Mr. Greg Krueger (NEI), "U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 7-12, and 12-13, Close Out of Facts and Observations (F&Os)," May 3, 2017 (ADAMS Accession No. MLl 7079A427).

8.42 Point Beach Nuclear Plant Procedure ORT-17, Containment Integrated Leak Rate Test Reports 8.42.l Unit 1 Report, Dated 10/06/1997.

8.42.2 Unit 2 Report, Dated 03/27/1997.

8.42.3 Unit 1 Report, Dated 03/23/2012.

8.42.4 Unit 2 Report, Dated 04/13/2011.

8.43 USNRC Letter to Mr. James H. McCarthy (FPL Energy), "Point Beach Nuclear Plant, Units 1 and 2 - Issuance of Amendments RE: Extension of Appendix J, Type A Integrated Leak Rate Test Interval at Point Beach Units 1 and 2 (TAC NOS. MD7013 AND MD7014), February 26, 2008 (ADAMS Accession No. ML080380356) 8.44 NRC 2013-0028, Point Beach Nuclear Plant, Units 1 and 2 - License Amendment Request 271 Transition to 10 CFR 50.48(c)-NFPA 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition, June 26, 2013 (ADAMS Accession No. ML13182A353).

8.45 Point Beach Nuclear Plant, Units 1 and 2 - License Amendment Request 271 Transition to 10 CFR 50.48(c)-NFPA 805, Attachment E, "NEI 04-02 Radioactive Release Transition," Rev. 0 (ADAMS Accession No.ML13182A350).

8.46 NRC 2014-0003, Point Beach Nuclear Plant, Units 1and2 - License Amendment Request 273 Application for Technical Specifications Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program, July 3, 2014 (ADAMS Accession No. ML14190A267).

8.47 USNRC Letter to Mr. Robert Coffey (NextEra Energy Point Beach), "Point Beach Nuclear Plant, Units 1 and 2-Staff Review of Mitigating Strategies Assessment Report of the Impact of the Reevaluated Seismic Hazard Developed in response to the March 12, 2012, 50.54(f) Letter (CAC NOS. MF7863 AND MF7864; EPID L-2016-JLD-0006),"

November 16, 2017 (ADAMS Accession No. ML17310B531).

8.48 NRC Regulatory Issue Summary 2007-06, "Regulatory Guide 1.200 Implementation,

March 22, 2007 (ADAMS Accession No. ML07650428).

8.49 PBN-BFJR-17-041, Point Beach Nuclear Plant, "Independent Review of PBN Internal Events and Internal Flood PRA Peer Review Finding Resolutions Point Beach Units 1 and 2, Revision 0.

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8.50 PBN-BFJR-17-035, Point Beach Nuclear Plant, "Point Beach PRA Review Finding Resolutions - Input to Independent Review," Revision 0.

8.51 PBN-BFJR-17-054, Point Beach Nuclear Plant, "Point Beach Units 1 & 2 Fire Probabilistic Risk Assessment Peer Review Findings Closure.

8.52 NRC 2012-0106, "10 CFR 50 Appendix E Evacuation Time Estimate Study for Point Beach Nuclear Plant," December 13, 2012.

8.53 Point Beach Nuclear Plant, Units 1 and 2, Issuance of License Amendments Regarding Use of Alternate Source Term, dated April 14, 2011 (ADAMS Accession No. MLl 10240054).

8.54 Point Beach Nuclear Plant, Units 1 and 2, Correction Letter, License Amendment Nos. 240 and 244, for Renewed Facility Operating Licenses DPR-24 and DPR-27, Respectively, Regarding Alternate Source Term (AST), dated May 4, 2011 (ADAMS Accession No. MLl 11220078).

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Appendix Al PRA Acceptability for the PBNP ILRT Interval Extension Risk Impact Assessment Introduction The Internal Events, Internal Flood, and Fire PRA models described below have been peer reviewed and there are no PRA upgrades that have not been peer reviewed. The PRA models credited in this request are the PRA models used in the NFP A 805 application (References 8.44 and 8.45) and the Surveillance Frequency Control Program (SFCP) application (Reference 8.46),

with routine maintenance updates applied. Capability Category (CC) II of the NRC-endorsed ASME/ANS PRA Standard is the target capability level for both of these applications. The acceptability (previously referred to as technical adequacy) of the PRA models was reviewed by the NRC for these respective applications and determined to be acceptable, as discussed in the Safety Evaluations, dated September 8, 2016 and July 28, 2015 (References 8.36 and 8.38).

As stated in the NRC Final Safety Evaluation for NEI 94-01, Revision 2 and EPRI Report No. 1009325, Revision 2 (Reference 8.29), CC I of the ASME PRA Standard shall be applied as the standard for assessing PRA quality for ILRT extension applications, as approximate values of CDF and LERF and their distribution among release categories, are sufficient to support the evaluation of changes to ILRT :frequencies. The NRC Safety Evaluation also states the assessment of external events can be taken from existing, previously submitted and approved analyses or other alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval. Therefore, the ILRT interval extension risk assessment is allowed to use the existing Internal Flooding and Fire PRA models and other existing seismic and external hazard evaluations described below.

Internal Events and Internal Flooding The PBNP results for the internal events and flooding hazard are from the plant-specific PRA model. The NextEra risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the PBNP units. As discussed further below, it is noted that modifications required to adopt NFP A 805 are also incorporated in the model.

Fire Hazards The PBNP Units 1 and 2 results for fire hazards are from the peer reviewed plant-specific fire PRA model. The Fire PRA model was developed consistent with NUREG/CR-6850 and utilizes methods previously accepted by the NRC. Almost all NFPA 805 related plant modifications required by License Conditions 4.F.3.b for Units 1and2 have been completed at this time. With the exception of the few remaining modifications required for electrical coordination/protection, which were already modeled in the PRA as part of the application to adopt a risk-informed, performance-based fire protection program in accordance with 10 CFR 50.48(c), the NextEra risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the PBNP units. However, the plant PRA models with these modifications included would best represent the plant conditions during the period of ILR T interval extension as the modifications will have been completed.

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Therefore, the use of the current Internal Events and Fire PRA models with the few remaining NFP A 805 modifications included is considered acceptable for use in this application.

Additionally, based on the approved methods utilized and given that the new heat release rates in NUREG-2178 are not cunently utilized, the Fire PRA is judged to provide a conservative estimate of fire risk at PBNP.

Seismic Hazards The PBNP, Units 1 and 2 results are from the seismic margins analysis (SMA) performed for the Individual Plant Evaluation-External Events (IPEEE) in response to GL 88-20 (References 8.24 and 8.39) for evaluation of safety significance related to seismic hazards. No plant specific approaches were utilized in development of the SMA.

Additionally, as discussed in the NRC staff review of the PBNP Mitigating Strategies Assessment (MSA) (Reference 8.47), the reevaluated seismic hazard for PBNP was previously reviewed by the NRC and it was concluded that a seismic risk evaluation was not merited. The NRC also previously concluded that the guidance for the required High Frequency confirmation was correctly implemented by PBNP with few components requiring modifications. Finally, the NRC concluded that sufficient information has been provided by PBNP to demonstrate that the plans for the development and implementation of guidance and strategies under Order EA 049 appropriately address the reevaluated seismic hazard information stemming from the 50.54(f) letter, dated March 12, 2012.

Other External Hazards The results for other external hazards are based on screening results from the Individual Plant Evaluation-External Events (IPEEE) in response to GL 88-20 (References 8.24 and 8.39) for evaluation of safety significance. The High Winds hazard was screened from applicability in the IPEEE.

All other external hazards were screened from applicability to PBNP, Units 1 and 2 per a plant-specific evaluation in accordance with GL 88-20 and updated to use the criteria in ASME PRA Standard RA-Sa-2009. Attachment 4 to the license amendment request (LAR) of the request to adopt 10 CFR 50.69 (Reference 8.17) provides a summary of the other external hazards screening results. Attachment 5 to the LAR to adopt 10 CFR 50.69 (Reference 8.17) provides a summary of the progressive screening approach for external hazards.

Peer Review Process The PRA models described above have been assessed against ASME/ANS RA-Sa-2009 and RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Info1med Activities," Revision 2 (Reference 8.35) consistent with NRC RIS 2007-06 (Reference 8.48).

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Specifically, the models were subject to the following industry peer reviews:

November 2010 full-scope peer review of the Point Beach Internal Events PRA model, including Intemal Flooding.

June 2011 full-scope peer review of the Point Beach Fire PRA model.

August 2011 focused-scope peer review of the Point Beach Internal Flooding PRA model.

October 2011 focused-scope peer review of the Point Beach Internal Events PRA model.

May 2013 focused-scope peer review (FSS) of the Point Beach Fire PRA model.

June 2013 focused-scope peer review (FQ) of the Point Beach Fire PRA model.

Based on the full-scope peer reviews and subsequent focused-scope peer reviews (Reference 8.50), the following are the net "Finding-Level" Facts and Observations (F&Os) remaining open for each PRA model:

Internal Events: 31 findings Internal Flood: 8 findings Fire: 41 findings These 80 fmdings were closed and submitted for independent review ofF&O closure. (These findings have previously been provided to the NRC as part of the NFPA 805 and SFCP applications.)

Findings were reviewed and closed using the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, "Close-out of Facts and Observations" (Reference 8.40) as accepted by NRC in the staff memorandum dated May 3, 201 7 (Reference 8.41). The results of this review have been documented and are available for NRC audit. As a result of the independent F&O closure, 6 F&Os are considered to remain open for the Internal Events model, 2 F&Os remain open for the Internal Flooding model, and 16 F&Os remain open for the Fire PRA model (References 8.49 and 8.51). A summary of the 24 remaining findings and open items with application specific dispositions is attached herein.

The intent of this risk assessment is to assess the risk associated with any additional containment liner degradation which may occur as a result of the ILRT extension. Note that, because the EPRI methodology is a bounding approach to estimating delta LERF based on scaling CDF (i.e., Class 3b frequency is based on CDF after subtracting the frequency of containment isolation failure (Class 2) and containment bypass (Class 8) scenarios) then only F&Os with a significant impact on CDF will affect the delta LERF for this application. F&Os that have a significant impact on total LERF also need to be evaluated for this application because the total calculated increas.e in LERF is in the "small" range of 1.0E-07 per rvactor year to 1.0E-06 pei:

reactor year.

The information in this appendix demonstrates that the PRA is of sufficient quality and level of detail to support this submittal, and has been subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRC.

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Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cateaorv CCC)

Independent Evaluation Extension Application Summary of F&O finding:

Loss of HVAC was evaluated in the PRA lacked systematic approach and HVAC notebook (PRA 5.25). The documentation for treatment of special initiating evaluation for some areas was revised, events. Examples given included loss of a 4kV bus, and for some areas fault tree models loss of HVAC. Discussion in the PRA were developed to evaluate the impact documentation needs more explanation for why not of the loss of HVAC. The calculations all special initiators were included.

provide a quantitative basis that these HVAC systems are not a significant Summary of resolution:

contributor to risk. As discussed in Additional explanation added to the Initiative Events of the 50.69 LAR, (PRA 2.0) Notebook to address this finding. A modeling assumptions overestimate the sensitivity run was done for the NFPA 805 and failure probability of the PAB electrical SFCP LARs that indicates CDF due to a failed 4kV room HVAC. This has a conservative bus initiator was between 1.9E-7 and 1.2E-9 and the impact on the risk results and will not LERF increase is between 3.9E-10 and 9.4E-12.

impact this application.

IE-A1 Not Met IE-A1-01 IE-A5 CC-I Summary of independent evaluation:

Although the independent review IE-82 Not Met The assessment of initiating events is adequately recommends addition of 4kV bus as IE-02 Not Met documented and includes a systematic assessment initiating event to close the F&O, the of special initiators including assessment of sensitivity cases show very small postulated loss of HVAC and loss of electrical impact to baseline results. The impact buses. As a result of the assessment, these on total LERF for this application is initiators are not modeled in detail. However, negligible and the impact on delta Including loss of an AC bus as a modeled initiator is LERF (with corrosion) would be judged as a worthwhile model improvement expected to be approximately two orders of magnitude less than the range specified for the increase in CDF.

Notes:

Therefore, this recommendation would The actual text of the associated findings from the not have a significant impact on this November 2010 full-scope and October 2011 application.

focused-scope peer reviews as well as the detailed discussion of the resolutions is included in Thus, this finding does not have an Attachment A of the SFCP application (Reference effect on the results utilized for this 8.46).

risk-informed application.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

CateQorv (CC)

Independent Evaluation Extension Application Summary of F&O finding:

Some of the electrical load limitations Electrical limitations, e.g., load management that existed at the time this finding was failures, may need to be considered in PRA model.

written are no longer in place. The remaining electrical load limitations Summary of resolution:

were reviewed during the preparation of Additional explanation added to PRA notebooks. All the Surveillance Frequency Control but one aspect of this F&O was accepted by Program LAR (Reference 8.46) where it October 2011 peer review. (See also SY-A21-01.)

was determined that no limitations were needed in the PRA model.

Summary of independent evaluation:

The electrical limitations of concern are addressed The remaining item is a documentation AS-86 Not Met by plant modifications. The justification for the failure issue only and does not affect the risk SY-A5 Met to manage EOG loads (in the event of an accident, results.

AS-86-01 SY-A21 Not Met with a LOOP, loss of alternate AC source, and 3 of 4 SY-86 Met EOGs unavailable) to be considered a negligible Therefore, there is no impact to this SY-815 Met human failure event did not include failure of 3 of 4 application.

EOGs to start. Accounting for failure of 3 of 4 diesels to start, the probability of using the load management procedure with only 1 EOG is still negligible. The corrected response should be documented in the HRA and/or EOG notebooks.

Notes:

The actual text of the associated findings from the November 2010 full-scope and October 2011 focused-scope peer reviews as well as the detailed discussion of the resolutions is included in Attachment A of the SFCP application (Reference 8.46).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category CCC)

Independent Evaluation Extension Application Summary of F&O finding:

The current DC battery model allows Inadequate treatment of time-based dependencies, for only limited recovery of offsite e.g.. recovery of offsite power, HVAC treatment, and power, i.e., the recovery of offsite battery depletion treatment.

power does not account for the extra Summary of resolution:

time afforded by battery depletion. This method could result in conservative Additional explanation was added to PRA notebooks CDF and LERF values.

and considered acceptable during the focused-scope peer review in October 2011. The two Conservative CDF/LERF values will not remaining items involved the conservative modeling adversely affect this application. The I

of offsite power recovery and battery depletion.

use of this approach increases the Summary of independent evaluation:

conservatism in the delta LERF and total LERF risk results for this Improvements have been made for the three application.

identified areas of Accident Sequence analysis, AS-87-01 AS-87 Not Met HVAC, DC power and AC power recovery.

Particularly for HVAC, where loss of HVAC analyses presented in HVAC Notebook PRA 5.25 support the initiating event and accident sequence model. Other changes were made to correct the DC power model and sequences. However, this finding is still considered open due to the perceived conservative modeling approach dealing with offsite power recovery and assumed battery life.

Notes:

The actual text of the associated findings from the November 2010 full-scope and October 2011 focused-scope peer reviews as well as the detailed discussion of the resolutions is included in Attachment A of the SFCP application (Reference 8.46).

Summary of F&O finding:

Concerns regarding consideration of excessive See response to AS-86-01.

electrical loads. All but one aspect addressed in the October 2011 peer review.

SY-A21-01 SY-A21 Not Met Notes:

Close out of SY-A21-01 is directly related to the AS-86-01 (i.e., the same argument was used regarding control of excess electrical loads being an extremely unlikelv event in which onlv one EOG is available).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cate~orv CCC)

Independent Evaluation Extension Application Summary of F&O finding:

The treatment of pre-initiators was Screening pre-initiators values were used in the reviewed during the preparation of the model. Use of screening values for all pre-initiators Surveillance Frequency Control only meets CC I.

Program LAR (Reference 8.46) where it was determined that the significant pre-Summary of resolution:

initiators were evaluated properly and The screening threshold was reset from 1 E-4 to no further model changes were 5E-4 to identify potentially significant pre-initiators required. Capability Category I is that may have been inappropriately screened. One sufficient for this ILRT interval additional mis-positioning event was identified as extension application and any slight needing further evaluation as a result of this changes in the pre-initiator values used assessment for both Units 1 and 2. The mis-position for the identified valves would have a HR-01 Not Met event was evaluated further to generate specific negligible impact on the PRA model.

HR-01-01 HR-02 (CC-I) values for the two valves (one valve for Unit 1, and the corresponding valve in Unit 2).

Therefore, there is no impact to this HR-03 (CC-I) application.

Summary of independent evaluation:

The identified events should be added to the model or further documentation is required for their omission and the documentation of the systematic approach that was used should also be improved.

Notes:

The actual text of the associated finding from the October 2011 focused-scope peer reviews as well as the detailed discussion of the resolution is included in Attachment A of the SFCP application (Reference 8.46).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category (CC)

Independent Evaluation Extension Application Summary of F&O finding:

This finding does not affect the use of No justification provided for equipment survivability the PRA model for calculating large or human actions credited under adverse early release frequency. Capability environments. This item is still open because no Category I is sufficient for this ILRT effort has been made to go beyond the interval extension application.

LE-C9 CC-I requirements of CC-I.

Consistent with CC-I for LE-C9, not taking credit for continued equipment LE-C10 CC-I Summary of independent evaluation:

operation or operator actions in LE-C9-01 LE-C11 CC-I It is noted that the full peer review identified this item adverse environments results in a LE-C12 CC-I as a suggestion and that it was subsequently conservative estimate of total LERF.

LE-D3 CC-I categorized as a finding by the follow-up focused peer review. Differences between the plant-specific The use of this approach increases the model that go beyond NUREG/CR-6595 need to be conservatism in the total LERF risk documented to support CC-II.

results for this application and does not impact the delta LERF results.

Summary of F&O finding:

The flag files were reviewed and Internal flood model inconsistently propagates determined to be complete.

initiating event data into the flag files used for Documentation updates are needed to quantification. Flag files need to be reviewed for close this finding. The documentation completeness and documentation updated to reflect updates should not affect the risk this.

results.

Summary of resolution:

Therefore, there is no impact to this The flag files were checked and some application.

inconsistencies were found and corrected. PRA 7.1, IFQU-A1 Met Internal Flood, notebook has been updated with this IFQU-A1-01 IFEV-82 Met information.

Summary of independent evaluation:

Additional inconsistencies were noted between the model and the documentation.

Notes:

The actual text of the associated finding from the August 2011 focused-scope peer reviews as well as the detailed discussion of the resolution is included in Attachment A of the SFCP application (Reference 8.46).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category (CC)

Independent Evaluation Extension Application Summary of F&O finding:

The treatment of operator actions in the Model does not adequately develop human failure internal flood model was reviewed.

events specific to internal flood scenarios. HFEs from internal events are "adjusted" with inadequate Documentation updates are needed to basis for those adjustments.

close this finding. The documentation updates should not affect the risk Summary of resolution:

results.

Additional explanation regarding the adequacy of the internal flood HFEs was provided.

Therefore, there is no impact to this application.

Summary of independent evaluation:

SR IFQU-A6 requires (in part) that for all HFEs included in the flood-induced accident sequences include flood scenario specific impacts on performance-shaping factors for control room and IFQU-AG-01 IFQU-A6 Not Met ex-control room actions. The HEP documentation/

evaluation for existing internal events HEPs credited in the flood evaluation continues to use generic multipliers to account for these impacts. Although more bases for the flooding HEPs has been provided, it does not include specific consideration of specific flood scenario impacts. Perform thorough check of internal flooding HFE HRA models and application of the HFEs in the internal flooding PRA model for accuracy and completeness.

Notes:

The actual text of the associated finding from the August 2011 focused-scope peer reviews as well as the detailed discussion of the resolution is included in Attachment A of the SFCP application (Reference 8.46).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement{s)

Cateciorv (CC)

Independent Evaluation Extension Application CS-C3-01 CS-C3 None referenced Summary of F&O finding:

The cable routing for the condenser for this finding Add the assumed cable routing for the turbine stop steam dump valves was performed and valves and steam dump valves in the Turbine documented as an example. The same Building and not documented in the Fire PRA process would apply for the turbine Notebook Circuit Selection and Cable Analysis.

stop valves.

Document the cable routing in the Fire PRA Documentation updates are needed to Notebook Circuit Selection and Cable Analysis of close this finding. The documentation the turbine stop valves and steam dump valves in updates should not affect the risk the turbine building.

results. Therefore, there is no impact on this application.

Summary of resolution:

PRA 8.3 (Fire PRA Cable Selection and Circuit Analysis Notebook) has documented the assumed cable routing used for these valves and provided the routing for one of the valves as a basis for the assumed routing.

Summary of independent evaluation:

Cable routing was only provided for one of the condenser steam dump valves. Additional justification should be provided for the turbine stop valves to close the F&O.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

Table V-1 provides additional discussion for the disposition.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cate~orv (CC)

Independent Evaluation Extension Application FSS-81-01 FSS-81 Met Summary of F&O finding:

The current methodology is judged to Control room abandonment is considered only in be conservativefor total CDF (and case of loss of habitability or loss of control due to a potentially LERF) associated with fire fire in the Main Control Room. Main Control Room risk, thus increasing the conservatism abandonment due to loss of control (for a fire in in the external events risk results (e.g.,

another room) is however a plausible cause. While delta LERF) for this application.

not crediting control room abandonment due to loss of control may be conservative, a justification should Documentation updates are needed to be provided.

close this finding. The documentation updates should not affect the risk Summary of resolution:

results. Therefore, there is no impact Control room abandonment is only credited for loss on this application.

of habitability scenarios in the main control room.

Summary of independent evaluation:

More complete resolution of this issue should be documented in a PRA report.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

Table V-1 provides additional discussion for the disposition. Not crediting control room abandonment for loss of control scenarios is also discussed in the associated NRC SE (Reference 8.36).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cateaorv (CC)

Independent Evaluation Extension Application FSS-E3-01 FSS-E3 CC-I Summary of F&O finding:

Capability Category I is sufficient for Uncertainty of the parameters used for modeling the this ILRT interval extension application.

significant fire scenarios was evaluated qualitatively, Documentation updates are needed to consistent with the requirements of SR FSS-E3 close this finding. The documentation Capability Category I. However, no statistical updates should not affect the risk representation of uncertainty intervals was given, as results. Therefore, there is no impact required by Capability Category II. SR FSS-H5 is on this application.

also assessed at Capability Category I because SR FSS-E3 is assessed at Capability Category I.

See also IGN-A 10-01 and UNC-A 1-01.

Summary of resolution:

PRA 8.17, Fire PRA Uncertainty and Sensitivity Analysis Notebook, specifically address this SR, along with associated SR FSS-H5.

Summary of independent evaluation:

The parametric uncertainty analysis was performed and documented in Appendix H of the Fire PRA Quantification Notebook (PRA 8.18) using UNCERT with Monte Carlo sampling techniques. Add a reference to PRA 8.17 Fire PRA Uncertainty and Sensitivity Analysis Notebook to point to Appendix H of the Fire PRA Quantification Notebook.

Additionally, the High Level Requirement for Uncertainty and Sensitivity Analysis (UNC) states that the Fire PRA shall identify sources of CDF and LERF uncertainties. Additional documentation is required for LERF uncertainties.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

Table V-1 provides additional discussion for the disoosition.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cateaorv CCC)

Independent Evaluation Extension Application FSS-G2-01 FSS-G2 Met Summary of F&O finding:

Documentation updates are needed to In the Multi-Compartment Fire Analysis (P2091-close this finding. The documentation 2900-04, Revision 1, May 2013), Subtask 4 updates should not affect the risk discusses screening multi-compartment fire results. Therefore, there is no impact scenarios based on hot gas layer dilution in the on this application.

exposed fire compartment. A finding is created to address potential cases where a Fire PRA target located in the connected compartment near a failed fire barrier or fire barrier element could be damaged by hot gases before hot gas layer dilution. These multi-compartment interactions could have been improperly screened from further consideration.

Summary of resolution:

Reviews of plant drawings and plant walkdowns were performed to confirm that the scenarios involving these screened fire compartments do not result in target failures in the immediate flow path of the postulated hot gas layer. Documentation that no targets have been improperly dismissed is provided in the Multi-Compartment Analysis Notebook PRA 8.11 (vendor document P2091-2900-04).

Summary of independent evaluation:

Section 6.5 of the Fire PRA Multi-Compartment Fire Analysis Notebook states that plant drawings were reviewed and walk downs were performed to confirm that the scenarios involving screened fire compartments based on dilution do not result in target failure in the immediate flow path of a postulated hot gas layer. The screened scenarios are listed in Table E-1 of Attachment E of the Fire PRA Multi-Compartment Fire Analysis Notebook.

This F&O remains open, pending inclusion of additional documentation in Appendix K of the process.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Cate~orv (CC)

Independent Evaluation Extension Application FSS-H1-03 FSS-H1 Met Summary of F&O finding:

Documentation updates are needed to Several documents submitted to the peer reviewers close this finding. The documentation were draft versions. Examples are: "Detailed Fire updates should not affect the risk Modeling in Selected Point Beach Nuclear Plant Fire results. Therefore, there is no impact Zones" (1 RCG27064.000.001 ), "Compartment on this application.

Analysis Notebook" (P2091-2900-01, Draft Rev. 2, May 2013), "Main Control Room Analysis" (P2091-2700-01, Revision 1, May2013). Finding FSS-H1-03 is created to ensure that such draft documents are reviewed, signed off, and their outputs are verified to be correctly implemented for quantification.

Also, the 2011 peer review created a finding (FSS-82-01) related to the modeling of human failure events in case of control room abandonment. While this finding is deemed resolved in the 2013 focused peer review based on explanations from EPM, the documentation of the resolution in Report P2091-2910-01 ("Post-Fire Human Reliability Analysis")

was not completed at the time of the peer review.

Accordingly, Finding FSS-H1-03 calls for proper documentation of the resolution of 2011 Finding FSS-82-01.

Finally, Finding FSS-H1-03 calls for documenting, in the relevant Fire PRA document, the basis for the fire resistance of wraps credited in the Fire PRA.

This could be done, for example, in Report P2091-2900-01 (Compartment Analysis Notebook).

Summary of resolution:

All PRA documents have been reviewed, signed off, and their outputs are verified to be correctly implemented in the quantification results. See Fire PRA notebooks PRA 8.1 through PRA 8.18.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Categorv (CC)

Independent Evaluation Extension Application Summary of independent evaluation:

Documents PRA 8.1 through 8.18 were reviewed.

All documents were replaced by finalized Fire PRA reports and were signed off by the Utility, the preparer, the reviewer, and the approver.

The issue with providing documentation that the fire resistant wrap was tested and acceptable was addressed by searching all the PRA provided documentation. Additional documentation should be provided regarding crediting fire wrap in the Fire PRA.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

PRM-82-01 PRM-82 Not Met Summary of F&O finding:

As of the time of this submittal, the only A review of the findings and resolutions from the remaining open internal events peer Internal Events Peer Review indicated several review findings identified in this fire findings against Accident Sequence, Success PRA finding are AS-86-01 and SY-A21-Criteria or Human Reliability Analysis. Findings AS-

01. These items have been 81-01, AS-82-01, AS-86-01, SY-A21-01, SY-A22-dispositioned for this application, as 01, HR-G?-01, and QU-83-01 could potentially discussed previously.

impact the fire PRA evaluation considerably. Other findings, such as SY-83-01 and DA-C14-01, are Internal fire risk insights are associated with common cause or common mode qualitatively assessed (in Section 6.3 of system failures that could be important for fire risk.

the risk assessment) to further Some or all of these findings could have an impact demonstrate that the proposed ILRT on the results of the FPRA.

Type A test extension will have a minimal risk impact from fire events.

Evaluate (qualitatively or quantitatively) these findings to determine the possible impact on the Therefore, there is no impact to this FPRA.

application.

Summary of independent evaluation:

This F&O is still open (for the remaining open Internal Events F&Os). No further review is required.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Independent Evaluation Extension Application PRM-89-01 PRM-89 Met Summary of F&O finding:

Documentation updates are needed to P2091-2500-01 documents the PBNP Plant close this finding. The documentation Response Model development. PBNP developed a updates should not affect the risk stand-alone fault tree to evaluate the fire non-results. Therefore, there is no impact suppression probability for sequences where the on this application.

electric-driven fire pump was failed by a fire. This was based on an internal events model for the fire protection system where it was used as a backup system for cooling the auxiliary feed water pumps.

The new model used a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> mission time and was used to calculate a point estimate for the non-suppression probability that was to be added to the appropriate fire scenarios for quantification. The internal events model for the fire protection system where it was used as a backup system for cooling the auxiliary feed water pumps used a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time. The structure of the overall model is such that the non-suppression probability and failure of the fire protection system may show up in the same scenarios. However, it is not possible to identify the dependency between the non-suppression probability and the random failure of the fire protection system. Failure to suppress the specific fire within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> will result in the failure of the fire protection system within the first hour of its 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time but this will not be caught because the dependency is not modeled Revise model to include a factor to address the dependency between the new model used to evaluate the fire non-suppression probability for sequences where the electric driven fire pump was failed by a fire and the model for the fire protection system where it was used as a backup system for cooling the auxiliary feed water pumps. This needs to be carefully documented.

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Independent Evaluation Extension Application Summary of resolution:

This finding is resolved. The model does not credit the use of the fire protection system for mitigation functions in the first one hour, when fire suppression activities may be occurring. Suppression failure is no longer modeled in the fault tree logic, but uses a point estimate from NUREG/CR-6850.

Summary of independent evaluation:

Appendix D of PRA 8.5, "Fire Induced Risk Model Notebook" documents how related F&Os are dispositioned. The notebook says that a point estimate from NUREG/CR-6850 is instead used for non-suppression probability. However, there is no "obvious" basic event in the FPRA model for the fire pump injection failure in the first hour.

IGN-A10-01 IGN-A10 CC-II Summary of F&O finding:

Documentation updates are needed to Propagating of the uncertainty intervals to the Fire close this finding. The documentation PRA results has not been done under supporting updates should not affect the risk requirement UNC-A2. The uncertainty has not been results. Therefore, there is no impact evaluated.

on this application.

Propagate the uncertainty intervals to the Fire PRA model.

See also FSS-E3-01 and UNC-A 1-01.

Summary of resolution:

Integrated uncertainties have not been performed, because several of the key factors like cable damage, zone of influence, and spurious short durations cannot be carried forward and estimated in codes like Uncert. Therefore the risk insight that can be gained from codes available to estimate mean CDF and LERF is minimal.

Summary of independent evaluation:

Quantification notebook, PRA 8.18, Appendix H only addresses the uncertainty for CDF and not LERF.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

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Independent Evaluation Extension Application HRA-82-01 HRA-B2 Met Summary of F&O finding:

The fire PRA HEPs were reviewed to A review of the HRA calculator events using the determine potential impact. Only about Caused Based Decision Tree methodology 10% of the HEPs that credited (CBDTM) shows that credit for graphically distinct is graphically distinct procedure steps taken for all HRA events. As discussed in EPRI TR would be increased by more than a 101259 and in the calculator documentation, credit factor of 2. Of these HEPs, only two for graphically distinct is only applicable in a flow are risk-significant HEPs with risk chart if the shape, color, etc. make the item standout achievement worth (RAW) values as more important than other steps or in a greater than 2. Based on this review, procedure if the item is separated from other steps the impact on the fire PRA model from by a caution statement. If all events are graphically this finding is judged to be minimal.

distinct, then in effect none are graphically distinct.

I The impacts on the external events Credit graphically distinct factors only for those delta LERF contribution for this events that stand out from the other procedural or application (based, in part, on Fire flow chart actions. Credit for graphically distinct CDF) would see an even smaller actions reduces pee tree by a factor of 3. In some change in risk based on the scaling cases, pee is the dominant contributor to the approach in the EPRI methodology.

cognitive decision. Therefore, the HRA would be Therefore, the resolution of this finding increased by a factor of 3.

would not have a significant impact on this application.

Summary of resolution:

The updated HRA for fire HFE recovery events do not assume "graphically distinct" for all steps. HFEs developed from internal events HFEs use the same assumption regarding "graphically distinct". New HFEs in EOPs (Table 7.4.2 of PRA 8.15) apply "graphically distinct" consistent with the internal events HFEs.

Summary of independent evaluation:

PRA 8.13, MCR Abandonment HRA, did not use the graphically distinct branch credit in the HRA calculator. PRA 8.15, Fire HRA Notebook, states that the graphically distinct branch credit would not be used but the attached HRA calculator datasheets show that the graphically distinct branch was taken credit for. This credit for graphically distinct branch should be removed. For this reason this F&O is not closed, pending resolution of this documentation discrepancv.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

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Independent Evaluation Extension Application HRA-C1-01 HRA-C1 CC-II Summary of F&O finding:

Documentation updates are needed to A median response time is chosen as 5 minutes for close this finding. The documentation all fire response actions. While five minutes is updates should not affect the risk generally acceptable to respond to the fire alarms results. Therefore, there is no impact and send a fire brigade out to the area, it may take on this application.

significantly more time to go through the verifications and system requirements for that fire area before reaching the operator manual action needed to respond to the event. The timing for these fire actions should be verified for feasibility, particularly for beyond Appendix R accidents with hardware failures in addition to the fire damage.

See F&O HRA-A 1-01 for performing an HRA walkdown.

Summary of resolution:

Operator interviews were performed as part of the compartment re-quantification task and addressed the assumed 5-minute additional response time.

Unless specifically justified, the response time was increased by 5 minutes or to a minimum of 5 minutes for very short duration times. This is judged to be a reasonable assumption. The fire recovery actions, applicable to specific fire scenarios, are longer term actions which are not significantly dependent upon the median response time.

Summary of independent evaluation:

Additional justification is required for the 5 minute delay.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Independent Evaluation Extension Application FQ-A1-01 FQ-A1 Met Summary of F&O finding:

The only remaining issue is A review of the FRANX database shows that some reconciliation of discrepancies found basic events that have been mapped to scenarios, between the FRANX mapping table and components, or cables are not found in the CAFTA the CAFTA model and its model. In particular:

documentation. The information in the mapping table should be reviewed to

1) 111 basic events mapped to cables are not in the eliminate the extraneous information CAFTA model. For example: Fl-P23-CAB--SO and and eliminate the discrepancies.

ESF-PT--N0-00469.

2) 21 basic events mapped to components are not Documentation updates are needed to in the CAFT A model. For example: 416-close this finding. The documentation BKRC01A5215 and R-AOV-CC-00371 updates should not affect the risk

3) 2 basic events mapped to scenarios are not results. Therefore, there is no impact found in the CAFT A model: Fl-1 CV11 OBCABSO on this application.

and Fl-1 CV111-CAB-SO.

A finding is created to ensure that basic events that are mapped to scenarios, components, or cables, are included in the CAFTA model, as appropriate. It could be that the basic events identified above are "leftover" from a previous model revision that needs to be cleaned up and that they have no impact on the results. Thus, this finding does not necessarily point to an incorrect model and rather points to a transparency issue.

Summary of resolution:

To address this finding, the Fire PRA FRANX databases were reviewed against the basic events modeled in the Fire PRA CAFTA fault trees. Based on the results of this review, most of the events were found to be mapped correctly. Only six (6) basic events (identified in Table 1 of EPM Report R2168-1003c-002, "NFPA805 Fire PRA Dispositions to Facts and Observations (F&Os)")

were identified that were mapped to equipment or scenarios in FRANX that were incorrectly excluded from the CAFTA models. Each of these events involved incorrect BE naming from the Main Control Room (MCR) analysis.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category (CC)

Independent Evaluation Extension Application This issue is preventing these events from being included in the MCR analysis quantification. For completeness, the correct six BEs for the analysis are:

1251BS-LP--D03, 125-BAT-LP-0305, 125-BAT-LP--0305, 125-BS-LP-016, 1251 BS-LP--049, and CV-AOV-CC-01296.

Subsequently, PRA 8.12, Fire PRA Main Control Room Abandonment Analysis Notebook, was finalized. Review of this notebook for the six "missing" basic events previously identified indicate that the correct basic event names are now used in the analysis.

Summary of independent evaluation:

The FRANX mapping was reviewed and compared to the BEs in the CAFTA logic model for Unit 1 and Unit 2 BEs. Six discrepancies were identified previously, and these were corrected in PRA 8.12, "Fire PRA Main Control Room Abandonment Analysis Notebook". However, a number of BEs were found in the mapping table which could not be found in the CAFTA logic model. This F&O remains open pending reconciliation of the FRANX data to the notebook information.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

Table V-1 provides additional discussion forthe disposition.

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Independent Evaluation Extension Application FQ-A4-02 FQ-A4 Met Summary of F&O finding:

Documentation updates are needed to Fire PRA quantification is understood to be close this finding. The documentation performed using the Fire PRA plant response model updates should not affect the risk that meets Technical Element PRM (plant response results. Therefore, there is no impact model) of the ASME/ANS Standard (see Note 2 of on this application.

SR FQ-A4). In that context, some multiple spurious operations (MSOs) appear to not have been adequately dispositioned and/or modeled in the Fire PRA. Examples are: loss of reactivity control, excessive RCS injection, and RCS overcooling.

Expert Panel discussion listed in Document P2092-11 OA-001 Rev. 0 (dated August 2010) included recommendations to revise the PRA model to address the potential impact due to fire. However, a later document (P2091-2500-02 Rev. 0, dated May 2011) appears to not address all MSOs nor provided justification for not being included in the PRA model as the earlier document has recommended. A finding is created to ensure that the generic list of MSOs from the industry owner groups be reviewed to verify that all MSOs relevant to Point Beach are considered and their disposition properly documented.

Summary of resolution:

This finding was addressed through evaluation of each MSO in PRA 8.8 (which contains vendor documents P2092-110A-001 and P2091-2500-02) identified by the expert panel for inclusion into the fire PRA to identify either that the failure mode is modeled, or provide a basis for exclusion.

The MSOs related to emergency diesel generator (EOG) overload are addressed by NFPA 805 LAR (Table S-3) implementation item IMP-157. The fire response procedures will ensure EOG overload due to fire impact is prevented.

All MSOs were determined to either be included in the PBNP fire PRA model, or had been adequately evaluated via sensitivity analyses or otherwise, such Page I 83

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CateQorv (CC)

Independent Evaluation Extension Application that no further action is required. Table 4.1-2 of PRA 8.5 lists the MSOs included in the fire PRA model.

Summary of independent evaluation:

There is no documentation available which relates the generic PWROG MSO list to any model changes or justification for disposition as suggested in the MSO expert panel. This F&O remains open pending improvement of the traceability of the MSO information to the expert panel information.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Independent Evaluation Extension Application FQ-81-01 FQ-81 Met Summary of F&O finding:

Documentation updates are needed to Supporting Requirement FQ-81 calls for CDF close this finding. The documentation quantification in accordance with HLR-QU-B.

updates should not affect the risk Supporting Requirements QU-86, QU-87, and QU-results. Therefore, there is no impact 88 address the treatment of mutually exclusive on this application.

events in the Fire PRA. A review of these mutually exclusive events appears to indicate that some important combinations may be missing or inconsistently applied. See for example Gate MEX-DC. A finding is created to ensure that mutually exclusive event combinations are systematically reviewed for appropriateness.

Summary of resolution:

The particular fault tree logic gate of concern to the peer review team during their review was gate DC-TM-03 (which is an input to gate MEX-DC). This gate does capture all of the required combinations.

The reason for the confusion is that testing and maintenance unavailability was not modeled for any of the batteries explicitly, except for the swing battery D-305. The basis for this modeling is given in Section 3.3 of PRA 4.0 (Data Analysis Notebook) for the internal events PRA model. No other inconsistencies were noted in review of the MEX logic.

Summary of independent evaluation:

Section 3.3 of the Internal Events PRA Data Notebook discusses the observed performance of concurrent maintenance between the DC batteries and their battery chargers. These practices form the basis of the MEX modeling for the DC system components. The fault tree for Point Beach was reviewed. The mutually exclusive gate, MEX-DC, was reviewed along with a sampling of others. The gate was deemed to be correct as were the other gates in the sampling. No other inconsistencies were noted.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category (CC)

Independent Evaluation Extension Application PBN Fire Quantification notebook PRA 8.18 was reviewed. It was noted that there is no documentation or discussion of the fire-specific mutually exclusive events assessment and modeling in the fire quantification notebook. This F&O remains open pending inclusion of documentation of any fire-related MEX modeling changes.

Notes:

Description of F&O is the same as provided in Table V-1 ofthe NFPA 805 LAR (Reference 8.45).

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

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Independent Evaluation Extension Application FQ-E1-01 FQ-E1 Met Summary of F&O finding:

Documentation updates are needed to Supporting Requirement FQ-E1 calls for a review of close this finding. The documentation the CDF and LERF quantification results in updates should not affect the risk accordance with HLR-LE-F. Supporting results. Therefore, there is no impact Requirements LE-F1 associated with that HLR on this application.

requires, for Capability Category II, a quantitative evaluation of the relative contribution to LERF from Additionally, SR LE-F1 would currently plant damage states and significant LERF meet Capability Category I. Capability contributors from Table 2-2.8-9 in the ASME/ANS Category I is sufficient for this ILRT standard (note: the table number given here interval extension application.

corrects an apparent typo given in the SR text).

While the Quantification Notebook provides LERF contribution by compartment, scenarios, and equipment failure modes, the LERF contributors from Table 2-2.8-9 do not appear to be evaluated in the notebook.

Summary of resolution:

Quantification of the Fire PRA is complete. The LERF contributions have been reported by fire compartment, scenarios, and equipment failure modes. As noted in Appendix A of PRA 8.18, the significant contributors to LERF are identified quantitatively in Section 3.0 of PRA 8.18 and include the LERF contributors in Table 2-2.8-9 of the ASME/ANS standard. Contributors that do not meet the significance requirements for reporting defined in Fire PRA Quantification Notebook Section 3.8 (i.e., F-V > 0.005 or RAW> 2) are not addressed in the notebook.

Summary of independent evaluation:

The specific requirement to quantitatively evaluate relative contributions per plant damage state has not been addressed. FQ-E1 also requires that a defined basis be provided to support the claim of non-applicability of any of the requirements of FQ-E 1.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Independent Evaluation Extension Application FQ-F1-05 FQ-F1 Met Summary of F&O finding:

Documentation updates are needed to Supporting Requirement FQ-F1 calls for close the two remaining items in this documentation of the CDF and LERF analyses in finding. The documentation updates accordance with HLR-QU-F. Supporting should not affect the risk results.

Requirement QU-F4 associated with that HLR Therefore, there is no impact on this requires the characterization of sources of application.

uncertainties and related assumptions. However, several assumptions listed in the Quantification Notebook do not provide such characterization. For example:

1) In Section 2.4.3, instrument air is assumed failed in the Fire PRA. It should be clarified that instrument air failure is not credited as a success in the Fire PRA.

2) In Section 2.4.4, the effect of not crediting the charging pump low pressure trip modification is qualitatively evaluated, but no characterization of the potential adverse impacts that this modification may have is given.

3) In Section 2.4.6, the failure of the MS IVs to close is eliminated from further consideration, but the justification given for this assumption is not substantiated with sufficient details.

4) In Section 2.5.3.6.1, an assumption is made that the probability of a hot short lasting greater than 10 minutes is 0.1. But the basis for this assumption is not clearly stated. If none is available, a sensitivity study to characterize the impact of this assumption is needed.

Summary of resolution:

Generic assumptions made in the fire PRA are now listed in Section 2.2 of PRA 8. 18, as such, the section numbers and example assumptions quoted in the finding are no longer accurate.

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Independent Evaluation Extension Application

1) Section 2.2.2 (IA): The success of Instrument Air was not credited in the model, except in cases where the assumption that air was failed provided a nonconservative input to the model.

2) The charging pump low pressure trip is now incorporated into the fire PRA (see Item 14 of Section 6.0 of Appendix A of PRA 8.5).

3) The failure of the MSIVs to close is now incorporated into the fire PRA (see MS-MSV 02017 and MS-MSV-00-02018 in Table B-1 of Appendix B of PRA 8.5). A plant modification which addresses this failure mode has been identified (MOD-14 of Attachment S of NFPA 805 LAR).

4) Section 2.2.1: Control circuits for air operated valves are generally provided with DC power at PBNP. FAQ 08-0051 addresses clearing of AC hot shorts vs. time. Interim NRC Staff guidance provided in the closure of that FAQ provides a probability value of less than 0.03 for an AC hot short duration greater than 10 minutes. The assumed value of 0.1 for the PBNP fire PRA is considered bounding for DC circuit hot shorts based on results of current DC circuit testing underway at NRC in support of a draft FAQ which will address the duration of DC hot shorts.

Summary of independent evaluation:

1) Instrument Air is failed in the Fire PRA as described in PRA 8.18, Fire PRA Quantification.

However, no documentation is provided for cases where the assumption that air was failed provided a non-conservative input to the model and was not used. This documentation still needs to be provided.

2) The charging pump low pressure trip logic has been incorporated into the Fire PRA logic and is documented in Appendix A of PRA 8.5 Fire Induced Risk Model. However, Aooendix A of PRA 8.17 Page I 89

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Independent Evaluation Extension Application Uncertainty and Sensitivity Analysis states that this mod is not currently incorporated. Therefore the documentation is not consistent with the model.

3) The failure of MSIVs to close is documented in table B-1 of Appendix B of PRA 8.5 Fire Induced Risk Model, and is confirmed to be in the CAFTA fault tree.

4) NUREG-7150, Section 6, Conditional Probability of Spurious Operation Duration for Control Circuits, Table 6-3 provides the probability of spurious operation duration probability values for AC and DC control circuits. For 10 minutes or greater AC and DC probabilities are listed as 7.10E-3 and 2.20E-2 respectively. As such, the use of 0.1 is bounding for both AC and DC circuits.

Therefore, this F&O is considered to be open until items 1 and 2 are addressed in the documentation.

Notes:

Description of F&O is the same as provided in Table V-1 of the NFPA 805 LAR (Reference 8.45).

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Independent Evaluation Extension Application UNC-A1-01 UNC-A1 Not Met Summary of F&O finding:

Documentation updates are needed to Contrary to the requirements of QU-E3, PBNP has close this finding. The documentation not calculated a mean CDF and uncertainty. Also, updates should not affect the risk because they have currently not completed final results. Therefore, there is no impact quantification of CDF and LERF, they are not really on this application.

able to review contributors for reasonableness (e.g.,

to assure excessive conservatisms have not skewed See also FSS-E3-01 and IGN-A10-01.

the results, level of plant specificity is appropriate for significant contributors, etc.) as required by LE-F2.

The current results are definitely driven by conservatisms in the model and thus preclude performing a representative review of the contributors.

PBNP needs to complete the quantification of their model to the point where they have a fire CDF that is acceptable (e.g., of the order of 5E-05/year). As part of the final quantification, PBNP needs to calculate the mean CDF and the associated uncertainty interval. PBNP should then review both the CDF and LERF contributors for reasonableness.

Summary of resolution:

PBNP has completed the fire PRA quantification and has achieved reasonable risk numbers documented in the quantification notebook, PRA 8.18. Integrated uncertainties have not been performed since several of the key factors such as cable damage, zone of influence, and spurious short durations cannot be carried forward and estimated in the UNCERT software. Therefore, the risk insights from available codes that can be gained to estimate mean CDF and LERF is minimal.

As discussed in the associated NRC SE (Reference 8.36), the FPRA was updated to include uncertainty parameters and SOKC for component failure types, ignition frequencies, non-suppression probabilities, and induced hot short probabilities as part of the integrated analysis.

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Finding Supporting Peer Review Description of Finding, Resolution, and Disposition for ILRT Interval Capability Number Requirement(s)

Category (CC)

Independent Evaluation Extension Application Summary of independent evaluation:

The risk values present in PRA 8.18 Fire PRA Quantification Notebook have been reduced to acceptable levels. PRA 8.17, Uncertainty and Sensitivity Analysis does describe the assumptions and sources of uncertainty in the model. However, Appendix H of the Quantification notebook only provides parametric uncertainty analysis for CDF.

This analysis needs to be updated to also include LERF. This F&O remains open pending inclusion of LERF uncertainty results.

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