ML14315A084

License Amendment Request - Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML14315A084
Person / Time
Site:	Peach Bottom
Issue date:	11/07/2014
From:	Jim Barstow Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML14315A084 (138)

Text

Exelon Generation 200 Exelon Way Kennett Square, PA 19348 www.exeloncorp.com 10 CFR 50.90 November 7, 2014 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Peach Bottom Atomic Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-44 and DPR-56 NRG Docket Nos. 50-277 and 50-278

Subject:

License Amendment Request - Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGG) requests proposed changes to modify the Technical Specifications (TSs). The proposed amendment revises the Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3 Technical Specification 5.5.12, "Primary Containment Leakage Rate Testing Program" to allow for the permanent extensions of Type A Integrated Leak Rate Testing and Type C Leak Rate Testing frequencies for both Units 2 and 3.

The proposed change has been reviewed by the PBAPS Plant Operations Review Committee, and approved by the Nuclear Safety Review Board in accordance with the requirements of the EGG Quality Assurance Program.

EGG requests approval of the proposed amendment by September 4, 2015 in order to support the extension of the Unit 3 ILRT, which is required to be performed during the upcoming outage in the Fall of 2015. Once approved, this amendment shall be implemented within 30 days. Additionally, there are no commitments contained within this letter.

Attachment 1 contains the evaluation of the proposed changes. Attachment 2 provides the marked up TS and Bases pages. The Bases pages are being provided for information only.

U.S. Nuclear Regulatory Commission LAA - Revise Technical Specifications Section 5.5.12 November 7, 2014 Page2 The proposed amendment is risk-informed and follows the guidance in Regulatory Guide 1 .174, Revision 2. PBAPS, Units 2 and 3 performed a plant-specific evaluation to assess the risk impact of the proposed amendment. A copy of the risk assessment is provided in Attachment 3.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), EGC is notifying the Commonwealth of Pennsylvania of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State Official.

Should you have any questions concerning this letter, please contact Tom Loomis at (610) 765-5510.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 7TH day of November 2014.

James Barstow Director, Licensing & Regulatory Affairs Exelon Generation Company, LLC Attachments: 1) Evaluation of the Proposed Change

2) Markup of Technical Specification and Bases Pages

3) Risk Assessment for PBAPS Regarding the ILRT (Type A)

Permanent Extension Request cc: USNRC Region I, Regional Administrator USNRC Senior Resident Inspector, PBAPS USNRC Senior Project Manager, PBAPS R.R. Janati, Commonwealth of Pennsylvania S. T. Gray, State of Maryland

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

SUBJECT:

Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 No Significant Hazards Consideration 4.4 Conclusion

6.0 REFERENCES

Peach Bottom Atomic Power Station

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE 1.0

SUMMARY

DESCRIPTION This evaluation supports a request to amend Renewed Facility Operating Licenses DPR-44 and DPR-56 for Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3. The proposed changes would revise the Operating Licenses by amending Technical Specification (TS) Section 5.5.12, "Primary Containment Leakage Rate Testing Program." The proposed changes to the Technical Specification contained herein would revise PBAPS, Units 2 and 3 TS 5.5.12 by replacing the reference to Regulatory Guide (RG) 1.163 (Reference 1) with a reference to Nuclear Energy Institute (NEI) Topical Report NEI 94-01, Revision 3-A, dated July 2012 (Reference 2) and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008 (Reference 8), as the implementation documents used by PBAPS to implement the Units 2 and 3 performance-based leakage testing program in accordance with Option B of 10 CFR Part 50, Appendix J. The proposed change would also delete the listing of one time exceptions previously granted to Integrated Leak Rate Test (ILRT) test frequencies.

2.0 DETAILED DESCRIPTION PBAPS, Units 2 and 3 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," currently states, in part:

"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 exceptions to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J:

a. Section 10.2: MSIV leakage is excluded from the combined total of 0.6 La for the Type B and C tests.

Unit 2:

b. Section 9.2.3: The first Type A test performed after the October 2000 Type A test shall be performed no later than October 2015.

Unit 3:

b. Section 9.2.3: The first Type A test performed after the December, 1991 Type A test shall be performed no later than December, 2006."

The proposed changes to PBAPS, Units 2 and 3 TS 5.5.12 will remove Unit 2 and Unit 3 TS exception (b), and replace the reference to RG 1.163 with a reference to NEI Topical Report NEI 94-01 Revisions 2-A and 3-A. The proposed change will revise TS 5.5.12 to state, in part:

"A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) and 10 CFR Part 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J,"

Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exemption.

a. Section 10.2: MSIV leakage is excluded from the combined total of 0.6 La for the Type B and C tests. contains the plant specific risk assessment conducted to support this proposed change.

This risk assessment followed the guidelines of NRC RG 1.174, Revision 2 (Reference 3) and NRC RG 1

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE 1.200, Revision 2 (Reference 4). The risk assessment concluded that the increase in risk as a result of this proposed change is small and is well within established guidelines.

3.0 TECHNICAL EVALUATION

3.1 Description of Primary Containment System The Primary Containment is a pressure suppression system and houses the reactor vessel, the reactor coolant recirculation systems, and other primary system piping. The Primary Containment system consists of a Drywell, a pressure Suppression Chamber which stores a large volume of water, a connecting vent system between the Drywell and the suppression pool, isolation valves, vacuum breakers, containment cooling systems, and other service equipment. The Primary Containment is designed for a maximum internal pressure of 62 psig coincident with a maximum temperature of 281°F.

The maximum external pressure is 2 psi above internal pressure.

Vacuum breakers are provided in the vent headers and located in the Suppression Chamber to equalize the pressure between the Drywell and the Suppression Chamber. A vacuum breaker system is also provided between the Suppression Chamber and Secondary Containment. Cooling systems are provided to remove heat from the Drywell and from the water in the Suppression Chamber. Appropriate isolation valves are provided to ensure containment of radioactive materials.

The vent system conducts flow from the Drywell to the Suppression Chamber and distributes this flow uniformly in the suppression pool. The suppression pool condenses the steam portion of this flow and the Suppression Chamber contains the non-condensable gases and fission products. The Suppression Chamber-to-Drywell vacuum breakers and the Suppression Chamber-to-Secondary Containment vacuum breaker system limit the pressure differential so as not to exceed the design limit of 2 psi. The Suppression Chamber is designed for the same leakage rate as the Drywell.

The Primary Containment was designed, fabricated, and inspected in compliance with the requirements of ASME Boiler and Pressure Vessel Code, Section Ill, Subsection B (1965) with all applicable Addenda through Summer 1966.

The Drywell is a light bulb-shaped steel pressure vessel with a spherical lower portion, 67 ft in diameter, and a cylindrical upper portion 38 ft 6 inches in diameter. The overall height is approximately 114 ft.

The Drywell is enclosed in reinforced concrete for shielding purposes. Above the Drywell foundation, the concrete is separated from the containment vessel by an air gap of approximately 2 inches.

The stiffened pressure Suppression Chamber is a steel pressure vessel in the shape of a Torus. It is located below and encircles the Drywell, with a centerline diameter of approximately 111 ft and a cross-sectional diameter of 31 ft. It contains approximately 125,000 cu ft of water and has a gas space volume.

The Suppression Chamber is supported on braced vertical columns to carry its dead and live loading to the reinforced concrete foundation slab of the reactor building.

The vent system outside the torus consists of eight circular vent pipes, each having a diameter of 6 ft 9 inches. These vent pipes are connected to the vent header located inside the Torus. The vent pipes and vent header have the same temperature and pressure design requirements as the containment. Jet deflectors are provided in the Drywell at the entrance of each vent pipe to prevent damage to the vent pipes from jet forces, which might accompany a pipe break in the Drywell. The pipes are provided with two-ply, testable expansion joints to accommodate differential motion between the Drywell and Suppression Chamber.

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ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 3.1.1 Pipe Penetrations Two general types of pipe penetrations are provided: (1) those which must accommodate thermal movement, and; (2) those which experience relatively little thermal stress. The piping penetrations which accommodate thermal movement are the high temperature lines such as the steam lines, feedwater lines, and other reactor auxiliary system lines. The drywall nozzle passes through the concrete shield and is attached to a bellows expansion joint which, in turn, is attached to a penetration adapter to form a containment pressure boundary. The process line which passes through the penetration is attached to the penetration adapter and is free to move axially. A guard pipe immediately surrounds the process line and is designed to protect the bellows and containment boundary should the process pipe fail within the penetration.

The bellows expansion joints are of two-ply construction and permit leak testing of these penetrations at pressures up to the primary containment design pressure. The bellows are fabricated from stainless steel. Non-destructive tests of the assemblies include radiography and liquid penetrant tests of welds, and pneumatic pressure tests of bellows.

3.1.2 Electrical Penetrations UFSAR Figure 5.2.5 depicts a typical electrical penetration that is used for power, control and instrumentation cable penetrations. The assembly is welded to the nozzle on the outside end.

Electrical penetrations are provided with double seals and are separately testable at design pressure.

The test taps and the seals are located so that tests of the electrical penetrations can be conducted without entering or pressurizing the drywell or suppression chamber.

3.1.3 Traversing In-Core Probe Penetrations Penetrations of the insertion guide tubes through the primary containment are sealed by brazing to the flanged penetration adapters. Since the 1965 edition of the ASME Boiler and Pressure Vessel Code, Section Ill, does not have provisions for qualifying the brazing procedures or performance, these seals are made in accordance with the requirements of Section VIII of this code.

3. 1 .4 Personnel and Equipment Access Locks Two 12-ft diameter equipment hatches are provided for the drywall. These hatches have bolted heads with double seals to allow testing. Combined with one equipment hatch is a personnel airlock having two 2 ft 6 inch by 6 ft gasketed doors in series. The doors are designed and constructed to withstand the drywell design pressure. The doors are mechanically interlocked so at least one door is closed at all times when containment is required. The locking mechanisms are designed so that a tight seal will be maintained when the doors are subjected to either internal or external pressures. The seals on the doors are capable of being tested by pressurizing the air lock. A special device locks the inner door against unseating pressure when the airlock is pressurized for test without pressurizing the primary containment.

A bolted personnel access hatch on the drywell head and a bolted closure head for the CAD removal hatch are provided with testable double seals.

3.1.5 Access to the Pressure Suppression Chamber Access to the pressure suppression chamber from the reactor building is provided at two locations. The entrances have t~stable, double-sealed, bolted covers.

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE 3.1.6 Access for Refueling Operations The drywell vessel head is removed during refueling operations. The head is held in place by bolts and is provided with testable double seals.

3.2 Justification for the Technical Specification Change 3.2.1 Chronology of Testing Requirements of 10 CFR Part 50, Appendix J The testing requirements of 10 CFR Part 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. Title 10 CFR Part 50, Appendix J also ensures that 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 the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant design basis accident. Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Type B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

In 1995, 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR Part 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also in 1995, RG 1.163 (Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference

5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A (ILRT) test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRG risk assessment contained in NUREG-1493, (Reference 6) and Electric Power Research Institute (EPRI) TR-104285 (Reference 7) both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "should be used only in cases where refueling schedules have been changed to accommodate other factors."

In 2008, NEI 94-01, Revision 2-A (Reference 8), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRG Safety Evaluation Report (SER) on NEI 94-01. The NRG SER was included in the front matter of this NEI report. Nuclear Energy Institute 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (September 1995). It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.

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ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE In 2012, NEI 94-01, Revision 3-A (Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. Nuclear Energy Institute 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference 9) and June 8, 2012 (Reference 10) as an acceptable methodology for complying with the provisions of Option B to 10 CFR Part 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs of June 25, 2008 and June 8, 2012 are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification of extending test intervals is based on the performance history and risk insights. Extensions of Type Band Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensee's allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

The NRC has provided the following concerning the use of grace in the deferral of ILRTs past the 15 year interval in NEI 94-01, Revision 2-A, NRC SER Section 3.1.1.2:

"As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons.

Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists."

NEI 94-01, Revision 3-A, Section 10.1 concerning the use of grace in the deferral of Type B and Type C LLRTs past intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing, states:

"Consistent with standard scheduling practices for Technical Specifications Required Surveillances, intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing given in this section may be extended by up to 25% of the test interval, not to exceed nine months.

Notes: For routine scheduling of tests at intervals over 60 months, refer to the additional requirements of Section 11.3.2.

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine month extension) does not apply to valves that are restricted and/or limited to 30 month intervals in Section 10.2 (such as BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance."

The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SER Section 4.0:

"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 5

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time."

3.2.2 Current PBAPS ILRT Requirements Title 10 CFR Part 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On June 18, 1996 the NRC approved License Amendment No.

214 for PBAPS, Unit 2 and Amendment 219 for Unit 3 (Reference 13) authorizing the implementation of 10 CFR Part 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR Part 50, Appendix J, Option B, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR Part 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (Reference 5) rather than using test intervals specified in American National Standards Institute (ANSI)/American Nuclear Society (ANS) 56.8-1994. Nuclear Energy Institute 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure). Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months .

.Adoption of the Option B performance based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the "as found" leakage history to determine a frequency for leakage testing which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a post tensioned, shallow domed concrete containment similar to PBAPS' containment structures. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT) from the original three tests per ten years to one test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types 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, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk.

3.2.3 PBAPS 10 CFR Part 50, Appendix J, Option B Licensing History August 14, 2000 The Commission issued on August 14, 2000 Amendments Nos. 233 and 237 to Facility Operating License Nos. DPR-44 and DPR-56 for the PBAPS, Units 2 and 3 (Reference 19). The Updated Final Safety Analysis Report was updated to reflect credit for use of a limited amount of containment overpressure in calculations of net positive suction head available for emergency core cooling pumps.

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ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE October 4, 2001 The Commission issued on October 4, 2001 Amendment No. 244 to Facility Operating License No. DPR-56 for PBAPS, Unit 3 (Reference 14). This amendment revised TS 5.5.12 to allow a one-time change in the containment integrated leak rate test (ILRT) interval from the current 1O years to a test interval of 15 years. This would require the licensee to perform the first Type A test after the December, 1991 Type A test no later than December, 2006.

September 14, 2007 The Commission issued on September 14, 2007 Amendments Nos. 263 and 267 to Renewed Facility Operating License Nos. DPR-44 and DPR-56 for PBAPS, Units 2 and 3 (Reference 15). These amendments modified TS Surveillance Requirement 3.6.1.3.14, "Primary Containment Isolation Valves."

Specifically, the proposed change revised the allowed MSIV leakage from 11.5 standard cubic feet per hour (scfh) per valve to 46 scfh total leakage through all four valves.

September 5, 2008 The Commission issued on September 5, 2008 Amendment Nos. 269 and 273 to Renewed Facility Operating License Nos. DPR-44 and DPR-56 for the PBAPS, Units 2 and 3 (Reference 16). The amendments revised the PBAPS, Units 2 and 3 TSs to support application of an alternative source term methodology.

TS SR 3.6.1.3.14 was revised to increase the allowable limit for the combined leakage rate for all MSIV leakage paths to less than or equal to 204 scfh for all four main steam lines and less than or equal to 116 scfh for any one main steam line, when tested at greater than or equal to 25 psig. TS Section 5.5.12 was revised to increase the allowed primary containment leakage from 0.5 to 0.7 percent of primary containment air weight per day.

July 20, 201 O The Commission issued on July 20, 2010 Amendment No. 276 to Renewed Facility Operating License No. DPR-44 for PBAPS Unit 2 (Reference 17). This amendment revised TS 5.5.12 to allow a one-time change in the containment integrated leak rate test (ILRT) interval from the current 10 years to a test interval of 15 years. This would require the licensee to perform the first Type A test after the October, 2000 Type A test no later than October, 2015.

August 25, 2014 The Commission issued on August 25, 2014 Amendment Nos. 293 and 296 to Renewed Facility Operating License Nos. DPR-44 and DPR-56 for PBAPS, Units 2 and 3 (Reference 18). The amendments authorized an increase in the maximum licensed thermal power level for PBAPS, Units 2 and 3, from 3514 megawatts thermal (MWt) to 3951 MWt, which is an increase of approximately 12.4 percent.

TS SR 3.6.1.3.14 was revised to decrease the allowable limit for the combined leakage rate for all MSIV leakage paths to less than or equal to 179 scfh for all four main steam lines and less than or equal to 85 scfh for any one main steam line, when tested at greater than or equal to 25 psig.

As part of the proposed EPU, PBAPS is eliminating containment accident pressure (CAP) credit assumptions in the safety analysis in the Fall of 2014 for Unit 2 and the Fall of 2015 for Unit 3. Although the current licensing basis credits the use of CAP to assure ECCS pump NPSH requirement is met in these analyses, the EPU analyses will no longer assume CAP credit in the NPSH analyses. The elimination of CAP credit from the licensing basis is accomplished through system modifications and methodology changes that are factored into the safety analyses.

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE 3.2.4 Integrated Leakage Rate Testing History (ILRT)

As noted previously, PBAPS TS 5.5.12 currently requires Type A, B, and C testing in accordance with RG 1.163, which endorses the methodology for complying with Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Tables 3.2-1 and 3.2-2 list the past Type A ILRT results for Units 2 and 3, respectively.

Table 3.2-1, Unit 2 Type A ILRT History Leakage Rate <1>

Test Date (Containment air weight %/day)

May 1973 0.127 June 1976 0.016 July 1980 0.105 June 1985 0.70 Retest 0.0156 <2l January 1989 0.233 March 1991 0.2135 October 2000 0.3365 (1)

On September 5, 2008 PBAPS design basis containment leak rate, La, was changed from a value of 0.5 wt%/day at containment peak pressure, to a value of 0. 7 wt%/day as expressed in TS 5.5.12 (Reference 16).

(2)

The first attempted test was terminated primarily due to leakage through the valve packing of a torus vacuum relief valve, A0-25028. Identified leakage sources were repaired and a second ILRT was completed successfully.

Table 3.2-2, Unit 3 Type A ILRT History Leakage Rate <1>

Test Date (Containment air weight %/day)

February 1974 0.116 April 1977 1.129 <2 >

Retest 0.322 September 1981 0.389 <3>

Retest 0.185 August 1983 0.784 <4 >

Retest 0.105 January 1986 0.088 November 1989 0.229 December 1991 0.139 October 2005 0.2781 (1)

On September 5, 2008 PBAPS design basis containment leak rate, La, was changed from a value of 0.5 wt%/day at containment peak pressure, to a value of 0. 7 wt%/day as expressed in TS 5.5.12 (Reference 16).

Analysis of the ILRT data indicated that leakage from the containment was approximately 1o (2) standard cubic feet per minute (SCFM). The leak was identified on the airside of a Torus water level instrument. The leak was isolated via the instrument root valve and the ILRT was completed successfully.

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE (3)

The major source of leakage was identified as a missing 0-ring on Pressure Transmitter PT-3 012C (Drywell Pressure Transmitter). Failure to install the 0-ring was an activity-based omission during instrument maintenance. Isolation of the instrument resulted in leakage from this source to be approximately 25,000 seem. Following installation of the missing 0-ring, the ILRT was completed successfully.

(4)

The major source of leakage was identified as packing leakage from M0-3-10-034A (RHR Loop A Full Flow Test Line Block Valve). The valve was repacked on backseat, and the ILRT was completed successfully.

The results of the last two Type A ILRTs for both PBAPS, Units 2 and 3 are less than the previous maximum allowable containment leakage rate of 0.5 wt%/day and the current maximum allowable containment leakage rate of 0. 7 wt%/day at the test pressure of 49.1 psig. As a result, since both tests for both units were successful, both units have been placed on extended ILRT frequencies. The current ILRT interval frequency for PBAPS Units 3 is ten years and Unit 2 is 15 years.

3.3 Plant Specific Confirmatory Analysis 3.3.1 Methodology An evaluation has been performed to assess the risk impact of extending the PBAPS, Units 2 and 3 ILRT intervals from 10 years to 15 years. The purpose of this analysis is to provide an assessment of the risk associated with implementing a permanent extension of the PBAPS, Units 2 and 3 containment Type A ILRT interval from ten years to fifteen years. The risk assessment follows the guidelines from NEI 94-01 (Reference 2), the methodology outlined in EPRI TR-104285 (Reference 7), the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (Reference 20), the NRG regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 (Reference 3), and the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the October 2008 EPRI final report (Reference 20).

The NRG report on performance-based leak testing, NUREG-1493 (Reference 6), analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined for a comparable BWR plant, that increasing the containment leak rate from the nominal 0.5 percent per day to 5 percent per day leads to a barely perceptible increase in total population exposure, and increasing the leak rate to 50 percent per day increases the total population exposure by less than 1 percent. Because ILRTs represent substantial resource expenditures, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for PBAPS.

This analysis has been performed to confirm these conclusions based on PBAPS specific PRA models and available data.

Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference 7) methodology to perform the risk assessment. In October 2008, EPRI 1018243 (Reference 20) was issued to develop a generic methodology for the risk impact assessment for ILRT interval extensions to 15 years using current performance data and risk informed guidance, primarily NRG Regulatory Guide 1.174 (Reference 3).

This more recent EPRI document considers the change in population dose, large early release frequency (LEAF), and containment conditional failure probability (CCFP), whereas EPRI TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for PBAPS, Units 2 and 3 employs the EPRI 1018243 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary.

9

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE In the SER issued by NRC letter dated June 25, 2008 (Reference 9), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to extend the ILRT surveillance interval to 15 years, subject to the iimitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2.

Table 3.3-1, EPRI Report No.1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SEl PBAPS Resoonse

1. The licensee submits documentation PBAPS PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 and Attachment 3, "Risk Assessment for their PRA is consistent with the PBAPS Regarding the ILRT (Type A) Permanent requirements of RG 1.200 relevant to the Extension Request," Appendix A, "PRA Technical ILRT extension. Adeauacv."

2. The licensee submits documentation Since the ILRT extension was demonstrated to have indicating that the estimated risk increase negligible impact on CDF for PBAPS, the relevant associated with permanently extending the criterion is LERF. The increase in internal events ILRT surveillance interval to 15 years is LERF resulting from a change in the Type A ILRT test small, and consistent with the clarification interval for the base case with corrosion included is provided in Section 3.2.4.5 of this SE. 3.78E-08/yr. In using the EPRI Expert Elicitation methodology, the change is estimated as 8.24E-09/yr.

Both of these values fall within the very small change region of the acceptance guidelines in RG 1.174.

Specifically, a small increase in population The change in dose risk for changing the Type A test dose should be defined as an increase in frequency from three-per-ten years to once-per-population dose of less than or equal to fifteen-years, measured as an increase to the total either 1.0 person-rem per year or 1% of integrated dose risk for all internal events accident the total population dose, whichever is less sequences for PBAPS, is 5.99E-02 person-rem/yr restrictive. (0.52%) using the EPRI guidance with the base case corrosion included. The change in dose risk drops to 1.60E-02 person-rem/yr (0.14%) when using the EPRI Expert Elicitation methodology, In addition, a small increase in CCFP The change in CCFP of about 1% as a result of should be defined as a value marginally extending the test interval to 15 years from the greater than that accepted in a previous original 3-in-10 year requirement is judged to be one-time 15 year ILRT extension requests. relatively insignificant, and is less than the NRC SE This would require that the increase in acceptance criteria of < 1.5%.

CCFP be less than or equal to 1.5 percentage point.

3. The methodology in EPRI Report No. The representative containment leakage for Class 3b 1009325, Revision 2, is acceptable except sequences used by PBAPS is 100 La, based on the for the calculation of the increase in recommendations in the latest EPRI report expected population dose (per year of (Reference 20) and as recommended in the NRC SE reactor operation). In order to make the on this topic (Reference 9). It should be noted that methodology acceptable, the average leak this is more conservative than the earlier previous rate accident case (accident case 3b) used industry ILRT extension requests, which utilized 35 La by the licensees shall be 100 La instead of for the Class 3b sequences.

35 La.

10

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE Limitation/Condition (From Section 4.2 of SEl PBAPS Resoonse

4. A licensee amendment request (LAA) is For PBAPS, plant modifications made in support of required in instances where containment the EPU effort eliminate reliance on containment over-pressure is relied upon for emergency accident pressure (CAP) credit to provide adequate core cooling system (ECCS) performance net positive suction head (NPSH) margin. Rather than proposing an increased reliance on CAP credit, PBAPS has decided to make plant modifications and apply methodology changes that will increase NPSH margin for these pumps to the extent that reliance on CAP can be eliminated. For Unit 2, these modifications will be completed in the Fall of 2014.

For Unit 3, these modifications will be completed in the Fall of 2015.

3.3.2 Technical Adequacy of the PAA Technical adequacy is presented in Appendix A, "PAA Technical Adequacy," of Attachment 3 of this submittal.

The Technical Adequacy was performed in accordance with the guidance provided in Regulatory Guide 1.200, Revision 2 (Reference 4). The guidance in AG 1.200 indicated that the steps below should be followed to perform this study.

3.3.2.1 Demonstrate the Technical Adequacy of the PAA

• Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PAA model and justify why the change does not impact the PAA results used to support the application.

• Document peer review findings and observations that are applicable to the parts of the PAA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

• Document that the parts of the PAA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide. Provide justification to show that where specific requirements in the standard are not met, it will not unduly impact the results.

• Identify key assumptions and approximations relevant to the results used in the decision-making process.

3.3.2.2 Plant Changes Not Yet Incorporated Into The PAA Model A PAA updating requirements evaluation (URE- Exelon PAA model update tracking database) is created for all issues that are identified that could impact the PAA model. The URE database includes the identification of those plant changes that could impact the PAA model.

A review of the open UREs indicates that there are no plant changes that have not yet been incorporated into the PAA model that would affect this application. Note that the PAA model is also being updated in 2014 to incorporate changes into the PAA model. Preliminary results indicate that the base case CDF and LEAF values are not significantly changing such that the conclusions for this risk assessment would not change upon completion of the updates.

11

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 3.3.2.3 Consistency with Applicable PAA Standards Several assessments of technical capability have been made for the PBAPS internal events PAA models.

These assessments are as follows and further discussed in the paragraphs below.

• An independent PAA peer review was conducted under the auspices of the BWR Owners Group in 1998, following the Industry PAA Peer Review process (Reference 11 ). This peer review included an assessment of the PAA model maintenance and update process.

• In 2004, a gap analysis was performed to assess gaps between the peer review scope/detail of the Industry PAA Peer Review results relative to the available version of the ASME PAA Standard (Reference 29) and the draft version of Regulatory Guide 1.200, DG-1122 (Reference 12). In 2006, an assessment of the extent to which the previously defined gaps had been addressed was performed in conjunction with a PAA model update.

• During 2005 and 2006 the PBAPS Units 2 and 3 PAA model results were evaluated in the BWR Owners Group PAA cross-comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process (Reference 21 ).

• After the completion of the most recent PAA update, an industry peer review in accordance with the combined ASME/ANS PAA Standard (Reference 30) and Regulatory Guide 1.200, Revision 2 (Reference 4) was performed in November 2010. The results of that assessment are used as the basis for the capability assessment provided in Tables A-1 and A-2.

A summary of the disposition of the 1998 Industry PAA Peer Review facts and observations (F&Os) for the PBAPS Units 2 and 3 PAA models was documented as part of the statement of PAA capability for MSPI in the PBAPS MSPI Basis Document (Reference 21 ). As noted in that document, there were no significance level A F&Os from the peer review, and all significance level B F&Os were addressed and closed out with the completion of the PB205C and PB305C models of record. Also noted in that submittal was the fact that, after allowing for plant-specific features, there are no MSPI cross-comparison outliers for PBAPS (refer to the third bulleted item above).

A Gap Analysis for the 2002 PBAPS, Units 2 and 3, PAA models (PB202 and PB302, respectively) was completed in January 2004. This Gap Analysis was performed against PAA Standard RA-S-2002 (Reference 29) and associated NRC comments in draft Regulatory Guide DG-1122 (Reference 12), the draft version of Regulatory Guide 1.200 Revision 0. This gap analysis defined a list of 83 supporting requirements from the Standard for which potential gaps to Capability Category II of the Standard were identified. For each such potential gap, a PAA URE was documented for resolution.

A PAA model update was completed in 2006, resulting in the PB205C and PB305C updated models. In updating the PAA, changes were made to the PAA to address most of the identified gaps, as well as to address other open UREs. Following the update, an assessment of the status of the gap analysis relative to the new model and the updated requirements in Addendum A of the ASME PAA Standard concluded that 59 of the gaps were fully resolved (i.e., are no longer gaps), and another seven were partially resolved.

As indicated above, a PAA model update was completed in 2010, resulting in the PB209A and PB309A updated models. This model was subject to a peer review in November 2010 (Reference 31). In general, the peer review results supported the high quality of the PAA model as approximately 95% of all the supporting requirements were characterized as meeting Capability Category II or better. Those supporting requirements that were assessed as not meeting Capability Category II are described in Appendix A, Table A-1, "Status Of Gaps To Capability Category II From The 2010 Peer Review," with their impact on this application noted. All of the findings were identified in Table A-1 and 12

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE their "Importance to the Application" was determined as "Not Significant" with corresponding justification or "None."

3.3.2.4 Applicability Of Peer Review Findings And Observations The remaining set of findings from the 201 O peer review related to the current ANS/ASME PAA Standard for internal events and internal flood associated with supporting requirements that are otherwise met at Capability Category II are described in Attachment 3, Appendix A, Table A-2 "Status Of Open Findings From The 2010 Peer Review" with their impact on this application noted. All of the findings were identified in Table A-2 with their "Importance to the Application" was determined as "Not Significant" with corresponding justification or "None."

3.3.2.5 External Events Although EPRI report 1018243 (Reference 20) recommends a quantitative assessment of the contribution of external events (for example, fire and seismic) where a model of sufficient quality exists, it also recognizes that the external events assessment can be taken from existing, previously submitted and approved analyses or another alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval. Based on this, currently available information for external events models was referenced, and a multiplier was applied to the internal events results based on the available external events information. This is further discussed in Attachment 3 Section 5.7 of the risk assessment.

3.3.2.6 PAA Quality Summary Based on the above, the PBAPS PAA is of sufficient quality and scope for this application. The modeling is detailed; including a comprehensive set of initiating events (transients, LOCAs, and support system failures) including internal flood, system modeling, human reliability analysis and common cause evaluations. The PBAPS PAA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that these PAA models are suitable for use in the risk-informed process used for this application.

3.3.2.7 Identification Of Key Assumptions The methodology employed in this risk assessment contained in Attachment 3 of this submittal followed the EPRI guidance as previously approved by the NRC. The analysis included the incorporation of several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. None of the sensitivity studies or bounding analysis indicated any source of uncertainty or modeling assumption that would have resulted in exceeding the acceptance guidelines. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LEAF, there are no identified key assumptions or sources of uncertainty for this application (i.e., those which would change the conclusions from the risk assessment results presented here).

3.3.2.8 Summary A PAA technical adequacy evaluation was performed consistent with the requirements of RG-1.200 Revision 2. This evaluation combined with the details of the results of this analysis demonstrates with reasonable assurance that the proposed extension to the ILRT interval for PBAPS, Units 2 and 3 to fifteen years satisfies the risk acceptance guidelines in AG 1.174.

3.3.3 Summary of Plant-Specific Risk Assessment Results The findings of the PBAPS, Units 2 and 3 Risk Assessment contained in Attachment 3 confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from 13

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE three in ten years to one in 15 years is small. The PBAPS plant-specific results for extending ILRT interval from the current 1O years to 15 years are summarized below:

Based on the results from Attachment 3, Section 5, "Results," and the sensitivity calculations presented in , Section 6 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to fifteen years are:

• RG 1.174 (Reference 3) 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 GDF below 1.0E-06/yr and increases in LEAF below 1.0E-07/yr. "Small" changes in risk are defined as increases in GDF below 1.0E-05/yr and increases in LEAF below 1.0E-06/yr.

Since the ILRT extension was demonstrated to have negligible impact on GDF for PBAPS, the relevant criterion is LEAF. The increase in internal events LEAF resulting from a change in the Type A ILRT test interval for the base case with corrosion included is 3.78E-08/yr (see Attachment 3, Table 5.6-1). In using the EPRI Expert Elicitation methodology, the change is estimated as 8.24E-09/yr (see Table 6.2-2). Both of these values fall within the very small change region of the acceptance guidelines in RG 1.174.

• The change in dose risk for changing the Type A test frequency from three-per-ten years to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all internal events accident sequences for PBAPS, is 5.99E-02 person-rem/yr (0.52%) using the EPRI guidance with the base case corrosion included (Attachment 3, Table 5.6-1). The change in dose risk drops to 1.60E-02 person-rem/yr (0.14%) when using the EPRI Expert Elicitation methodology (Attachment 3, Table 6.2-2). The values calculated per the EPRI guidance are all lower than the acceptance criteria of :S1 .0 person-rem/yr or <1.0% person-rem/yr defined in Attachment 3, Section 1.3.

• The increase in the conditional containment failure frequency from the three in ten year interval to one in fifteen years including corrosion effects using the EPRI guidance (see Attachment 3, Section 5.5) is 1.02%. This value drops to 0.22% using the EPRI Expert Elicitation methodology (see Attachment 3, Table 6.2-2). Both of these values are below the acceptance criteria of less than 1.5% defined in Attachment 3, Section 1.3.

• To determine the potential impact from external events, a bounding assessment from the risk associated with external events was performed utilizing available information. As shown in Table 5.7-2, the total increase in LEAF due to internal events and the bounding external events assessment is 7.31 E-07/yr. This value is in Region II of the AG 1.174 acceptance guidelines.

• As shown in Attachment 3, Table 5.7-4, the same bounding analysis indicates that the total LEAF from both internal and external risks is 6.36E-06/yr, which is less than the AG 1.174 limit of 1.0E-05/yr given that the ~LEAF is in Region II (small change in risk).

• Including age-adjusted steel liner corrosion effects in the ILRT assessment was demonstrated to be a small contributor to the impact of extending the ILRT interval for PBAPS.

Therefore, increasing the ILRT interval on a permanent basis to a one-in-fifteen year frequency is not considered to be significant since it represents only a small change in the PBAPS risk profiles.

3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference 6) has previously concluded the following:

• Reducing the frequency of Type A tests (ILRTs) from three per 1O years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small 14

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 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. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.

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

Details of the PBAPS, Units 2 and 3, risk assessment are contained in Attachment 3 of this submittal.

3.4 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, PBAPS has assessed other non-risk based considerations relevant to the proposed amendment. PBAPS has multiple inspections and testing programs that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

3.4.1 Safety-Related Coatings Inspection Program PBAPS implements a safety-related coatings program that ensures Design Bases Accident (OBA) qualified coating systems are used inside Primary Containment. The program assures that safety-related OBA qualified coatings (service level 1) are selected, procured, applied and inspected in a manner that conforms to the applicable 10 CFR 50, Appendix B criteria. Unqualified coatings are controlled and tracked to ensure that emergency core cooling systems will not be adversely affected by the coating debris following an accident. The program objective is to conform to licensee commitments made in response to Generic Letter 98-04. Safety-related coatings are also monitored in accordance with a formal Maintenance Rule (10 CFR 50.65) condition-monitoring program. Engineering reviews and evaluates the results of coating condition examinations performed by qualified examiners.

Inspections of coatings systems are scheduled every Containment lnservice Inspection (GISI} period to verify containment coating condition.

3.4.2 Containment lnservice Inspection Program This lnservice Inspection (ISi} Program Plan details the requirements for the examination and testing of ISi Class 1, 2, 3, and MC pressure retaining components, supports, and containment structures at PBAPS, Units 2, 3, and 2/3 (Common). Unit Common components are included in the Unit 2 sections, reports, and tables. This ISi Program Plan also includes GISI, Risk-Informed lnservice Inspections (RISI),

Augmented lnservice Inspections (AUG), and System Pressure Testing (SPT} requirements imposed on or committed to by PBAPS.

The Fourth ISi Interval for PBAPS, Units 2 and 3 is effective from November 5, 2008, through November 4, 2018. With the update to the ISi Program for the Fourth ISi Interval for ISi Class 1, 2, and 3 components, including their supports, EGC has also updated the GISI Program to its Second GISI Interval for ISi Class MC components at the same time. This update will enable all of the ISi and GISI Program components I elements to be based on the same effective Edition and Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,Section XI, as well as share a common interval start and end date. The common ASME Code of Record for the Fourth ISi Interval and the Second GISI Interval is the 2001 Edition through the 2003 Addenda.

15

ATTACHMENT1 EVALUATION Of THE PROPOSED CHANGE Paragraph IWA-2430(d)(1) of ASME Section XI allows an inspection interval to be extended or decreased by as much as one year, and Paragraph IWA-2430(e) allows an inspection interval to be extended when a unit is out of service continuously for six months or more. The extension may be taken for a period of time not to exceed the duration of the outage. See Table 3.4-1 below for intervals, periods, and extensions that apply to PBAPS's Second GISI Interval.

The Fourth ISi Interval and the Second GISI Interval are divided into three inspection periods as determined by calendar years within the intervals. Tables 3.4-1 and 3.4-2 identify the period start and end dates for the Second and Third GISI Interval as defined by Inspection Program B. In accordance with Paragraph IWA-2430(d)(3), the inspection periods specified in these Tables may be decreased or extended by as much as one year to enable inspection to coincide with PBAPS's refueling outages.

Table 3.4-1 Units 2 and 3 Second CISI Interval/Period/Outage Matrix (For ISi Class MC Component Examinations)

Unit2 Period Interval Period Unit3 Outage Projected Start Date to Start Date to Start Date to Projected Outage Number Outage Start End Date End Date End Date Outage Start Number Date Date P2R18 Scheduled 1st l st Scheduled P3Rl7 09/10 11105/08 to 11105/08 to 09109 11104/12 2°d(Unit 2) 05/05/12 P2R19 Scheduled 11105/08 to Scheduled P3R18 09/12 11/04/18 09/11 P2R20 Scheduled 2na 2°d (Unit 3) 2na Scheduled P3R19 10/14 11105/12 to 11105/08 to 05/06/12 to 09/13 11104/15 2 11104/18 1 05/05115 2 P2R21 Scheduled 3ra 3ra Scheduled P3R20 10/16 11/05/15 to 05/06/15 to 09/15 11104/18 11104/18 P2R22 Scheduled Scheduled P3R21 10/18 10/17 Note 1: The PBAPS, Unit 3 Third Period and the First GISI Interval were extended by 365 days per First GISI Interval Relief Request GRR-12. Per this First GISI Interval relief request, the Second GISI Interval for PBAPS, Unit 3 will overlap the duration of the First GISI Interval for one year in order to start the Second GISI Interval on time and keep it aligned with the Unit 2 Second GISI Interval while still finishing examinations in the First GISI Interval. It will also facilitate both PBAPS, Units 2 and 3 having the same GISI Interval start and end dates, and codes of record, as well as this common interval date matching the ISi Program dates. As required by ASME Section XI, the intervals will be scheduled in ten-year increments from this point forward with the modifications similar to Paragraph IWA-2430 fully available to future intervals and periods including a one-year extension

• allowance based on the new synchronized unit interval date.

Note 2: The PBAPS, Units 2 and 3 Second Period was reduced by one year and the First Period was extended by one year as permitted by Paragraph IWA-2430(d)(3) in order to coincide with the plant refueling outage schedule.

16

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE Table 3.4-2 Units 2 and 3 Third CISI Interval/Period/Outage Matrix (For ISi Class MC Component Examinations) 1 Unit2 Period Interval Period Unit3 Outage Projected Start Date to Start Date to Start Date to Projected Outage Number Outage Start End Date End Date End Date Outage Start Number Date Date P2R23 Scheduled l st l st Scheduled P3R22 10/20 11/05/18 to 11/05/18 to 10/19 11/04/22 2nd(Unit 2) 05105122 P2R24 Scheduled 11/05/18 to Scheduled P3R23 10/22 11/04/28 10/21 P2R25 Scheduled 2 na 2nd (Unit 3) 2nd Scheduled P3R24 10/24 11/05/22 to 11/05/18 to 05106122 to 10/23 11/04/25 11/04/28 05105125 P2R26 Scheduled 3rn 3rn Scheduled P3R25 10/26 11/05/25 to 05106125 to 10/25 11/04/28 11104/28 P2R27 Scheduled Scheduled P3R26 10/28 10/27 Note 1: The PBAPS Third Period GISI dates are approximations, as the third GISI Interval inspection Program has not been developed at this time.

Containment ISi Plan The PBAPS Containment ISi Plan includes ASME Section XI ISi Class MC pressure retaining components and their integral attachments that meet the criteria of Subarticle IWA-1300. This Containment ISi Plan also includes information related to augmented examination areas, component accessibility, and examination review.

PBAPS has no ISi Class CC components, which meet the criteria of Subarticle IWL-1100; therefore, no requirements to perform examinations in accordance with Subsection IWL are incorporated into this Containment ISi Plan. Since both PBAPS units' containment vessels are freestanding structural steel containment vessel, only Subsection IWE is applied.

The examination of containment components are performed per procedures ER-AA-330-007, "Visual Examination of Section XI Class MC Surfaces and Class CC Liners" and ER-AA-330-008, "Exelon Service Level 1 and Safety Related (Service Level 3) Protective Coatings."

Augmented Examination Areas The containment sections of the ISi Classification Basis Document discuss the containment design and components. Metal containment surface areas subject to accelerated degradation and aging require augmented examination per Examination Category E-C and Paragraph IWE-1240.

A significant condition is a condition that is identified as requiring application of additional augmented examination requirements under Paragraph IWE-1240.

In the First GISI Interval, the Augmented Inspection Program AUG-C1 addressed wetted and submerged Suppression Chamber (Torus) Interior Surfaces for both PBAPS, Units 2 and 3. However, this 17

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Augmented Inspection Program is no longer active since the First GISI Interval Relief Requests CRR-10 and CRR-11 were not resubmitted for the Second GISI Interval.

In accordance with ASME Section XI, Paragraph IWE-1241, augmented examinations were to be performed on those surface areas, which were likely to experience accelerated degradation and aging.

At PBAPS, this included the wetted (i.e., immersion zone} and submerged portions of the suppression chamber. These areas have undergone examinations in the past to quantify and evaluate coating problems and pitting. Results of examinations performed in both Units in 1991, again in PBAPS, Unit 3 in 1997, and in PBAPS, Unit 2 in 1998, revealed numerous pits and degraded coatings. In conjunction with these results, an evaluation was performed in ABB lmpell Report No. 03-0670-1360. This report concluded that the structural integrity of the suppression chamber was maintained, and continued operation was justified. The report also established an evaluation methodology, acceptance criteria, and a suggested reexamination schedule. In 2005, MPR Associates performed an evaluation of the differences between PBAPS Units 2 and 3 water chemistry and corrosion rates. In 2006, 100% of the wetted surface of the Unit 2 torus was inspected and pit depth measurements were taken. The torus was determined to be structurally sound until 2010. The results of this inspection are documented in PIMS AR A1545908 Eval 38. In 2007, 100% of the wetted surface of the Unit 3 torus was inspected and pit depth measurements were taken. The torus was determined to be structurally sound until 2011. The results of this inspection are documented in PIMS AR A1554416 Eval 32.

Based upon the examination results and discussions, the immersion zone and submerged surfaces in the suppression chamber in both units were classified as augmented examination areas subject to Examination Category E-C. However, in lieu of the examinations stated in Table IWE-2500-1, Examination Category E-C, PBAPS followed approved Relief Request CRR-11 that established alternative examination criteria. Relief Request CRR-11 utilized results from previous examinations and evaluations to implement an alternative examination program that provided an acceptable level of quality and safety in accordance with 10CFR50.55a (a}(3}(i}.

There were no other Examination Category E-C augmented examination surfaces identified during the development of this ISi Program Plan, as of its issuance. This conclusion was based on a review of design documents, and satisfactory results from thorough, documented examinations of dry, accessible containment surfaces. In 1985, three typical drywell surfaces were selected as representative examination areas. These three areas have been visually examined on a regular basis since 1985. In 1992 (Unit 2) and 1993 (Unit 3), the examinations were expanded to include a general area visual examination of the drywell and suppression chamber as well as the specific visual examinations on the three representative areas.

In the First GISI Interval, these wetted and submerged suppression chamber (Torus} surfaces were identified as augmented surface areas requiring examination in accordance with Table IWE-1240. These surface areas had been categorized in accordance with ASME Section XI, Table IWE-2500-1, Examination Category E-C, Item Number E4.11, requiring visual examination of 100% of the surface areas identified during.each inspection period until the areas examined remain essentially unchanged for the next three inspection periods.

In the Second GISI Interval, these wetted and submerged suppression chamber (Torus} augmented surface areas will require visual examination of 100% of the surface areas identified during each inspection period until the areas examined remain essentially unchanged for the next inspection period.

Once an augmented area remains unchanged for one full period, the areas fall back to the normal Examination Category E-A examination schedule. The Torus submerged areas were coated in 2012 for Unit 2 and 2013 for Unit 3 in order to arrest further pitting.

18

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Table 3.4-3 Units 2 and 3 lnservice Inspection Summary Examination Category Relief Total Number (with Item Exam Request/

Description of Notes Examination Number Requirements TAP Components Category Number Description)

E-A E1 .11 Containment Vessel Pressure General Visual 19 14R-48 Containment Retaining Boundary -

Surfaces Accessible Surface Areas E1 .11 Containment Vessel Pressure Visual, VT-3 38 14R-48 5 Retaining Boundary -

Bolted Connections, Surfaces E1.12 Containment Vessel Pressure Visual, VT-3 1 14R-48 6 Retaining Boundary -

Wetted Surfaces of Submeraed Areas E1.20 Containment Vessel Pressure Visual, VT-3 1 6 Retaining Boundary -

BWR Vent System Accessible Surface Areas E1.30 Containment Vessel Pressure General Visual 1 Retaining Boundary -

Moisture Barriers E-C E4.11 Containment Surface Areas - Visual, VT-1 1 7 Containment Visible Surfaces Surfaces E4.12 Containment Surface Areas - Ultrasonic 1 Requiring Surface Area Grid Augmented Examination Note 5 Bolted connections examined per Item Number E1 .11 require a General Visual examination each period and a VT-3 visual examination once per interval and each time the connection is disassembled during a scheduled Item Number E1 .11 examination.

Additionally, a VT-1 visual examination shall be performed if degradation or flaws are identified durihg the VT-3 visual examination. These modifications are required by 10 CFR 50.55a(b)(2)(ix)(G) and 10 CFR 50.55a(b)(2)(ix)(H).

Note 6 Item Numbers E1.12 and E1.20 require VT-3 visual examination in lieu of General Visual examination, as modified by 10 CFR 50.55a(b)(2)(ix)(G).

Note 7 Item Number E4.11 requires VT-1 visual examination in lieu of Detailed Visual examination, as modified by 10 CFR 50.55a(b)(2)(ix)(G).

Relief Requests Table 3.4-4 contains an index of Requests for Relief written in accordance with 10 CFR 50.55a(a)(g)(5)(iii) as applicable to the GISI Program. Note that only Requests for Alternatives or Requests for Relief applicable to the requirements for Class MC components are addressed in Table 3.4-4.

19

ATTACHMENT 1 EVALUATION Of THE PROPOSED CHANGE Table 3.4-4, Second Ten-year CISI Interval Relief Requests Relief Revision Status (Program) Description/

Request Date Approval Summary 14R-48 0 Granted (GISI) Alternative Examination Requirements of ASME (CRR-13) 11/05/08 Section XI, Paragraph IWE-1232, "Inaccessible Surface Areas." Revision O qranted per NRC SE dated 02/26/09.

10 CFR 50.55a Relief Request 14R-48 (CRR-13)

Paragraph IWE-1232(a) ("Inaccessible Surface Areas") states that portions of Class MC containment vessels, parts, and appurtenances that are embedded in concrete or otherwise made inaccessible during construction of the vessel or as a result of vessel repair, modification, or replacement are exempted from examination, provided:

(1) No openings or penetrations are embedded in the concrete; (2) All welded joints that are inaccessible for examination are double butt welded and are fully radiographed and, prior to being covered, are tested for leak tightness using a gas medium test, such as Halide Leak Detector Test; and (3) The vessel is leak rate tested after completion of construction or repair/replacement activities to the leak rate requirements of the Design Specifications.

Pursuant to 10 CFR 50.55a(g)(S)(iii), relief was requested on the basis that conformance with these code requirements is impractical as conformance would require extensive modifications to the primary containment.

When the drywell was being constructed, a 24-inch manhole was placed in the bottom head of the drywell. During construction, when the manhole was no longer needed, the penetration was seal welded, inspected, and embedded in concrete.

• Based on the original construction drawings the manhole is a bolted, gasket connection that was seal welded, the handles were ground smooth and either a magnetic particle test or dye penetrant examination was performed. The N-3 manhole was seal welded and cannot meet the Paragraph IWE-1232(a)(2) code requirement for a double butt weld.

Adding a double butt weld would involve a modification to the drywell that would require excavation of the concrete around the bottom head of the drywell or removal of the drywell floor thus making the code requirement impractical.

Integrated Leak Rate Testing will be performed in accordance with the station Appendix J Program, which is maintained independent of the ASME Section XI program.

Augmented Inspection Program Requirements Augmented Inspection Program requirements are those inspections that are performed above and beyond the requirements of ASME Section XI. Below is a summary of those examinations performed by PBAPS that are not specifically addressed by ASME Section XI, or the inspections that will be performed in addition to the requirements of ASME Section XI on a routine basis during the Fourth ISi Interval and Second GISI Interval. The Augmented Inspection Plans for PBAPS that are associated with the integrity of the primary containment are listed in the table below.

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Table 3.4-5 Units 2 and 3 Augmented Inspection Program Matrix Examination Aug Description Exam Total Number Relief Notes Category Number Requirements of Request/

(with Components TAP Examination Number Category Description)

AUG-C3 Sludge Accumulation on Visual - Sludge 1 the Torus Floor AUG AUG-CA Examination of Class MC Visual, VT-3 50 Supports Augmented Components AUG-CB Examination of Drywell Visual, VT-3 16 External Components Located Outside Stabilizer Access Hatches AUG-CC Examination of Drywell Functional Test 5 Airgap Drain Lines & Visual AUG-CD Examination of Bolting in

• Visual 9 ECCS Suction Strainers Component Accessibility ISi Class MC components subject to examination shall remain accessible for either direct or remote visual examination from at least one side for the life of the plant per the requirements of ASME Section XI, Paragraph IWE-1230.

Paragraph IWE-1231 (a)(3) requires 80% of the pressure-retaining boundary that was accessible after construction to remain accessible for either direct or remote visual examination, from at least one side of the vessel, for the life of the plant.

Portions of components embedded in concrete or otherwise made inaccessible during construction are exempted from examination, provided that the requirements of ASME Section XI, Paragraph IWE-1232 have been fully satisfied. (Note that Relief Request 14R-48 (CRR-13) has been approved to take credit for the integrated leak rate testing in accordance with the PBAPS Appendix J program in lieu of performing the required examinations for Penetration N-3 which does not meet the exemption criteria of Paragraph IWE-1232(a)(2).)

In addition, inaccessible surface areas exempted from examination include those surface areas where visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan, or augmented examination in accordance with Paragraph IWE-1240.

Inaccessible Areas For Class MC applications, PBAPS 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 21

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE areas. For each inaccessible area identified, PBAPS shall provide the following in the Owners Activity Report-1, as required by 10 CFR 50.55a(b)(2)(ix)(A):

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

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

• A description of necessary corrective actions.

PBAPS has not needed to implement any new technologies to perform inspections of any inaccessible areas at this time. However, Exelon Generation Company, LLC (EGC) 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 applicabiliN to PBAPS. 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.

Responsible Individual ASME Section XI, Subsection IWE, requires a Responsible Individual to be involved in the development, performance, and review of the CISI examinations. The Responsible Individual assigned to perform these duties shall meet the requirements of ASME Section XI, Paragraph IWE-2320.

Structural Attachments Surfaces of attachment welds between structural attachments and the containment pressure boundary or reinforcing structure will be subject to examination per Subsection IWE. To establish which containment attachments are subject to this examination requirement, guidance has been taken from ASME Section Ill, Subsection NE. In accordance with ASME Section Ill, Subsection NE, Paragraph NE-1132.1 (d),

structural attachments are those attachments that perform a pressure retaining function or are in the containment vessel support load path. Therefore, examinations will be required on welded attachments associated with the containment vessel supports, such as the suppression chamber column supports.

However, examinations will not be required on welded attachments associated with components that are not pressure retaining or are not in the containment vessel support load path, such as pipe supports, stairways and structural steel.

Examination Methods & Personnel Qualifications The examination methods used to perform Code examinations for the nonexempt Class MC components are in accordance with 10 CFR 50.55a requirements and the applicable ASME Codes.

Personnel performing IWE examinations shall be qualified in accordance with EGC's written practice, or approved vendor written practice for certification and qualification of nondestructive examination personnel.

3.4.3 Supplemental Inspection Requirements With the implementation of the proposed change, TS 5.5.12 will be revised by replacing the reference to RG 1.163 (Reference 1) with reference to NEI 94-01, Revision 3-A (Reference 2). This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity be conducted. This inspection must be conducted prior to each Type A test and during at least three other outages before the next Type A test if 22

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE the interval for the Type A test has been extended to 15 years in accordance with the following sections of NEI 94-01, Revision 3-A:

• Section 9.2.1, "Pretest Inspection and Test Methodology"

• Section 9.2.3.2, "Supplemental Inspection Requirements" IWE examinations will be scheduled in accordance with the GISI Program including the scheduling of at least one complete visual inspection prior to PBAPS, Units 2 and 3 ILRT tests thus meeting the inspection requirements of TS SR 3.6.1.1.1.

3.4.4 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program PBAPS Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, and containment isolation valves in accordance with 10 CFR Part 50, Appendix J, Option B, and RG 1.163. The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life. The Types Band C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with TS 5.5.12, the allowable maximum pathway total Types Band C leakage is 0.6 La where La equals approximately 175,000 seem.

In addition to the TS Limit, a limit of 87,795 seem, or 0.5 La is imposed by the Maintenance Rule Program.

As discussed in NUREG-1493 (Reference 6), Type Band Type C tests can identify the vast majority of all potential containment leakage paths. Type Band Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the Type B and Type C test results from 2000 through the Fall of 2012 for PBAPS, Unit 2 and from 2005 through the Fall of 2013 for PBAPS, Unit 3 has shown an exceptional amount of margin between the actual As-Found (AF) and As-Left (AL} outage summations and the regulatory requirements as described below:

• The As-Found minimum pathway leak rate average for PBAPS, Unit 2 shows an average of 22.1 %

of 0.6 La with a high of 26.6% of 0.6 La or 0.1598 La.

• The As-Left maximum pathway leak rate average for PBAPS, Unit 2 shows an average of 55.2%

0.6 La with a high of 62.8% of 0.6 La or 0.3768 La.

• The As-Found minimum pathway leak rate average for PBAPS, Unit 3 shows an average of 21.7%

of 0.6 La with a high of 27.1 % of 0.6 La or 0.1629 La.

• The As-Left maximum pathway leak rate average for PBAPS, Unit 3 shows an average of 49.8% of 0.6 La with a high of 51.8% of 0.6 La or 0.3107 La.

Tables 3.4-6 and 3.4-7 provide local leak rate test (LLRT) data trend summaries for PBAPS since the performance of the Unit 2 2000 ILRT and the Unit 3 2005 ILRT.

This summary shows that there has been D..Q As-Found failure that resulted in exceeding the TS 5.5.12 limit of 0.6 La (105,000 seem) and demonstrates a history of successful tests through Fall of 2013.

The summary above shows that there has been no As-Found failure that resulted in exceeding the TS 5.5.12 limit of 0.6 La (105,000 seem) and demonstrates a history of successful tests through Fall of 2013. However, during the P2R20 refueling outage currently in-progress, planned local leak rate testing identified a condition involving higher than allowable through-seat leakage of two redundant feedwater system check valves (28A and 96A). Pursuant to 10CFR 50.72(b)(3)(ii)(A), this recent issue was reported 23

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE to the NRC on 10/29/14 as a non-compliance with maximum allowable primary containment leakage rate (La)* This condition has been entered in the plant corrective action program and the results of the investigation will be reported to the NRC as a Licensee Event Report (LER) in the near term. It should be noted that prior to this occurrence, the As-Found (AF) minimum pathway summations represent the generally solid performance of the maintenance of Type Band Type C tested components while the As-Left (AL) maximum pathway summations represent the effective management of the Containment Leakage Rate Testing Program by the program owner.

Table 3.4-6, Unit 2 Type B and C LLRT Combined As-Found/As-Left Trend Summary RFO 2000 ~ 2004 2006 2008 2010 2012 AF Min Path 25178 21791 21392 20240 27965 19761 25867 (seem)

Fraction of La 0.1439 0.1245 0.1222 0.1156 0.1598 0.1192 0.1478 AL Max Path 61171 59042 43644 53701 59033 63432 65937 (seem)

Fraction of La 0.3495 0.3373 0.2493 0.3069 0.3373 0.3624 0.3768 AL Min Path 20244 21379 18937 28108 20281 26689 29089 (seem)

Fraction of La 0.1157 0.1222 0.1082 0.1606 0.1159 0.1525 0.1662 Table 3.4-7, Unit 3 Type Band C LLRT Combined As-Found/As-Left Trend Summary RFO 2005 2007 2009 2011 2013 AF Min Path (seem) 26436 17830 22495 18764 28513 Fraction of La 0.1511 0.1019 0.1285 0.1072 0.1629 AL Max Path (seem) 47110 59954 46341 53562 54379 Fraction of La 0.2692 0.3426 0.2648 0.3061 0.3107 AL Min Path (seem) 18221 23930 18962 26283 20070 Fraction of La 0.1041 0.1367 0.1083 0.1502 0.1147 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4-8 and 3.4-9 identify the components that have not demonstrated acceptable performance during the previous two outages for PBAPS, Units 2 and 3 respectively:

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Table 3.4-8, Unit 2 Type B and C LLRT Program Implementation Review 2010-2R18 Component 111 As- Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure <2 > Action Interval SCCM SCCM CHK-2-06-28A 7672 7000 7672 Not Evaluated - Did 30 month Identified not exceed 9000 seem limit. No action.

A0-2-078- Leakage 7500 55 Piping Maintenance 30 month 2502A, 26A Off Scale corrosion performed. 26A TORUS VAC products valve did not 8KR on seat of exceed Admin 2502A. Limit.

A0-2-078- Leakage 7500 20 Piping Maintenance 30 month 25028,268 Off Scale corrosion performed. 268 TORUS VAC products valve did not 8KR on seat of exceed Admin 25028. Limit.

CHK-2-07C- 20/507 500/500 20/507 Not Evaluated - Did 30 month 40143, SV Identified not exceed 9000 07C-49498, seem limit. No CAD INJ action.

SV-2-07D- 30/972 100/100 30/972 Not Evaluated - Did 30 month 26718, 29788, Identified not exceed 9000 02ANAL seem limit. No action.

M0-2-10-26A, 10000 5000 7850 Seat Valve body seat 30 month M0-2-10-31A leakage of repair. As-Left the 26A leakage valve. evaluated. Did not exceed 9000 seem limit. Valve scheduled for replacement in 2R19.

M0-2-10-268, 5600 5000 5600 Not Evaluated - Did 30 month M0-2-10-318 Identified not exceed 9000 seem limit. No action.

A0-2-10-468, 8750/20 7000/250 20/20 Seat Lapped body seat 30 month A0-2-10-1638 Leakage of 468 valve and

& HV-2 of the 468 cleaned disc 234518 valve. surface.

CHK-2 Leakage 750 20 Seat Lapped body seat 30 month 232028, HV Off Scale Leakage and cleaned disc.

16-23333 on 23333 232028 valve did valve. not exceed Admin Limit.

A0-2-20-82, 4650/ 1000/1000 950/20 Debris in Removed debris 30 month A0-2-20-83 Leakage 82 valve. and retested D/W Floor Off Scale valve.

DANS 25

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE 2010-2R18 Component\ As- Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure <2> Action Interval SCCM SCCM CHK-2-23-65 8280 5000 398 Heavy Machined body 30 month wear on seat, rebuilt valve. valve.

2012*2R19 Component As-found Adm in As-left Cause of Corrective Scheduled SCCM Limit SCCM Failure Action Interval SCCM MSL Drain MO- 7710 1500 20 Scoring Lapped disc 30 month 2-01A-74, MO- found on 77 and retested.

2-01A-77 valve disc.

CHK-078- 20/791 500/500 20/791 Not Evaluated- 30 month 40095A&8 Identified Did not exceed 9000 seem limit. No action.

CHK-2-07C- 20/791 500/500 20/791 Not Evaluated- 30 month 40142, SV Identified Did not exceed 07C-4949A, 9000 seem CAD INJ limit. No action.

CHK-2-07C- Leakage 500/500 20/106 Debris Cleaned seat 30 month 40145, SV Off found on and retested.

07C-49518, Scale/20 CHK-2-07C-CAD INJ 40145 valve seat.

SV-2-07D- 30/1846 500/500 30/1846 Not Evaluated- 30 months 26718, 29788, Identified Did not exceed 02ANAL 9000 seem limit. No action.

M0-2-10-26A, 43000 5000 375 Seat Valve replaced 30 months M0-2-10-31A leakage of the 26A valve.

CHK-2-07D- 44/1255 500/500 44/1255 Not Evaluated- 30 months 40140, SV Identified Did not exceed 07D-2980 9000 seem limit. No action.

M0-2-10-34A, 100000 7000 2000 Debris Repair via 30 months 38A, 39A, found in valve flushed TORUS 39A valve. to dislodge COOUSPRAY debris in seats.

M0-2 43000 5000 375 Excessive Replaced 26A 30 months 26A, M0-2 Leakage 31A 26A valve.

A0-2-20-82, Off 1000/1000 20/3280 Debris Maintenance 30 months A0-2-20-83 Scale/6351 found in 82 performed.

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ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 2012-2R19 Component As-found Ad min As-left Cause of Corrective Scheduled SCCM Limit SCCM Failure Action Interval SCCM D/W Floor valve.

DRNS CHK-2-23-65 15200 5000 6750 Seat Lapped body 30 months Leakage seat and cleaned disc seat.

Table 3.4-9, Unit 3 Type B and C LLRT Program Implementation Review 2011-3R18 Component As-found Admin As-left Cause of Corrective Scheduled (1)

SCCM Limit SCCM Failure <2> Action Interval SCCM MSL Drain 5914 1500 5914 Not Identified Evaluated- 30 months M0-3-01A- Did not exceed 74, M0 9000 seem 01A-77 limit. No action.

A0-3-078- 2875 250 550 Debris found Maintenance 30 months 3523 in valve. performed.

SV-3-07D- 20/1620 100/100 20/20 Debris found Maintenance 30 months 3671G, in 3671G performed.

3978G, 02 valve.

ANAL A0-3 39000/20 7000/250 20/20 Seat Lapped body 30 months 46A, HV Leakage of seat and 10-33451A the 46A cleaned disc.

valve.

M0-3-13-15, 1055 1000 1055 Not Identified Evaluated- 30 months 16 RCIC Did not exceed STEAM 9000 seem SUPPLY limit. No action.

A0-3 864 750 864 Not ldentif ied Evaluated- 30 months 39698, CHK- Did not exceed 3-16-33312 9000 seem limit. No action.

A0-3-20-94, Leakage 1000/1000 695/25 Debris found Maintenance 30 months A0-3-20-95 Off in 94valve. performed.

DW EQUIP Scale/2333 DRN 27

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 2013-3R19 Component As-found Admin As-left Cause of Corrective Scheduled SCCM Limit SCCM Failure Action Interval SCCM MSL Drain 15500 1500 20 Valve disc in Valve repaired 30 months M0-3-01A- the 77 valve to acceptable 74, M0 found leakage value.

01A-77 scored. Laooed disc.

A0-3-01J- 660 500 660 Not Identified Evaluated- 30 months 316, A0 Did not exceed 01J-317 9000 seem limit. No action.

A0-3-078- 364 250 364 Not Identified Evaluated- 30 months 3523 Did not exceed 9000 seem limit. No action.

SV-3-070- Leakage 100/100 100/27 Debris found Maintenance 30 months 3671G, Off in 3671G performed.

3978G, 02 Scale/2240 valve.

ANAL A0-3 Leakage 7000/250 20/20 Seat leakage* Lapped body 30 months 46A, HV Off of the 46A seat and 10-33451A Scale/20 valve. cleaned up disc.

M0-3 7457 5000 7457 Not Identified Evaluated- 30 months 268, M0 Did not exceed 10-318 9000 seem limit. No action.

A0-3 63750/20 7000/250 111/20 Seat leakage Lapped body 30 months 468, HV of the 468 seat and 10-334518 valve. cleaned up disc.

M0-3-14-12A 9300 1500 74 Debris found Maintenance 30 months in valve. performed.

M0-3-14-128 2200 1500 2200 Not Identified Evaluated- 30 months Did not exceed 9000 seem limit. No action.

A0-3 1665 750 355 Debris found Repaired as 30 months 39698, CHK- in 33312 part of outage 3-16-33312 valve. leakage management.

A0-3-20-82, Leakage 750 21 Debris found Maintenance 30 months A0-3-20-83 Off Scale in 82 valve. performed. 83 OW FLOOR valve did not ORN exceed Admin Limit.

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ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 2013-3R19 Component As-found Admin As-left Cause of Corrective Scheduled SCCM Limit SCCM Failure Action Interval SCCM CHK-3-23-65 9500 5000 53 Seat Lapped body 30 months Leakage seat and cleaned up disc.

A0-3-23C- 1945 1500 1945 Not Identified Evaluated- 30 months 137 Did not exceed 9000 seem limit. No action.

(1)

All valves are in penetrations having at least two valves. Single valves reported are the result of specific tests for the single valves in a penetration.

(2)

"Cause of Failure" valves denoted with "Not Identified" was the result of an evaluation to determine if the leakage measured would have an impact on the overall outage leakage goal of 65,000 seem. The evaluation considered such topics as radiological dose that would occur to support the repair, system availability during the outage, discovery time of the leakage versus the remaining outage time and availability of parts and the work force to support the repair activity.

Schedule interval either remained or was reduced to 30 months as a result.

3.4.6 On-Line Monitoring of Primary Containment Atmosphere During power operation the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment. As a result of this operational requirement, primary containment is typically maintained at an average positive pressure of 0.5 psig. Primary pressure is continuously indicated and periodically monitored from the Main Control Room. Abnormal (high or low) drywell pressure is annunciated in the Main Control Room at setpoints of 0.25 psig and 0.75 psig.

Primary containment pressure is periodically monitored in accordance with plant surveillance tests. Daily surveillance logs for Modes 1, 2 and 3 include drywell pressure as one of the parameters logged once per shift. Additionally, control room operators perform a containment gross leakage rate detection test, once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This test involves review of primary containment pressure trends and nitrogen makeup periodicity for the latest 72-hour period to identify excessive primary containment leakage trends. In the event of unsatisfactory test results, or in the case of abnormal drywell pressure annunciation, operators would review current plant conditions and evolutions that could explain an unacceptable containment leakage trend, and initiate troubleshooting of systems that typically influence containment leakage when in an unisolated condition. If a primary containment leak were identified, then the Technical Specification action for an inoperable primary containment would be entered.

3.5 Operating Experience During the conduct of the various examinations and tests conducted in support of the Containment related programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed.

For the PBAPS Primary Containments, there are four issues of degradation or potential degradation that have been identified for discussion in this submittal. The four areas of note involve:

• Licensee Event Report (LER) 2-06-03

• Generic Letter 87-05 29

ATTACHMENT 1 EVALUATION Of THE PROPOSED CHANGE

• Through-Wall Torus Shell Crack at James A. Fitzpatrick Nuclear Power Plant

• NRC Information Notice 92-20, Inadequate Local Leak Rate Testing Each of these areas is discussed in detail in Sections 3.5.1 through 3.5.4, respectively.

3.5.1 Licensee Event Report (LEA) 2-06-03 On 10/7/06 at 1802 hours0.0209 days <br />0.501 hours <br />0.00298 weeks <br />6.85661e-4 months <br />, an Unusual Event was declared for Unit 2 as a result of the discovery of a leak at an elbow for piping that penetrates the Primary Containment Suppression Pool (i.e., Torus). The 4" piping is the High Pressure Coolant Injection (HPCl)/Reactor Core Isolation Cooling (RCIC) Torus Flush line. This line is normally isolated from the HPCl/RCIC systems by a closed motor-operated valve and is only used during testing activities. The leak was discovered by an equipment operator at approximately 1741 hours0.0202 days <br />0.484 hours <br />0.00288 weeks <br />6.624505e-4 months <br /> during a planned inspection associated with a RCIC system check valve. The leak occurred on the intrados of a 45 degree elbow of the 4" piping. The elbow was located approximately I foot above the Torus penetration (i.e., the leak was outside of Primary Containment). The cause of the crack in the elbow was due to cavitation and abrasive erosion and/or localized water-jet cutting resulting from excessively high flow velocities through this piping during test conditions in conjunction with an apparent lack of fusion between the weld backing ring and the weld root at the elbow weld. The leaking elbow was replaced and non-destructive testing was performed. The similar pipe on Unit 3 was examined and no significant concerns were noted. Extensive walk downs of similar piping that is attached to the Torus was conducted for both Units 2 and 3. There were no similar deficiencies discovered. Selected ultrasonic testing was performed on Units 2 and 3 Torus attached piping that involved higher flow rates. These examinations also did not identify any similar concerns.

Cause of the Event Detailed failure analyses of the cracks in the HPCl/RCIC Flush return line elbow were performed. The failure analysis determined that axial and circumferential flaws developed as a result of cavitation and abrasive erosion and/or water jet cutting. The underlying cause of the issue was due to excessively high flow velocities through this piping during test conditions in conjunction with an apparent lack of fusion between the weld backing ring and the weld root at the elbow weld. These analyses identified that a portion of the original installation weld-backing ring was missing. This observation suggests lack of fusion between the weld root and the backing ring when performed during original plant construction. Evidence suggests that flow underneath the backing ring created localized erosion immediately adjacent (downstream) to the weld root.

Analysis of the Event There were no actual safety consequences associated with this event. The leaking elbow is in common piping for the HPCl/RCIC 'Flush' line that returns to the Torus. This line is normally isolated from the HPCl/RCIC systems by a closed motor-operated valve and is only used during testing activities.

Therefore, there was no impact on HPCI or RCIC system functional capability.

The 4" carbon steel piping is attached to the Torus and is not isolable from the Torus (i.e., Primary Containment). The piping terminates under the normal Torus water level and therefore, the water in the Torus serves as another barrier to prevent radioactive gaseous releases from the Torus air space during design basis events. Therefore, there were no actual gaseous releases involved with this event.

The HPCl/RCIC 'Flush' line is pressurized during Integrated Leak Rate Tests (ILRTs). The leakage would have been detected during this test. The last ILRT was successfully completed on 10/4/00 and there was no leakage identified at that time. Further examination of the leaking elbow noted that axial and circumferential cracking existed at the elbow intrados. Failure analyses of the elbow determined that only minimal leakage existed at the elbow with the as-found indications. This minimal leakage only occurred 30

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE when the HPCI or RCIC system was being operated in the test mode involving return flow being routed to the Torus.

In the unlikely event that a worst-case design basis event had occurred and the elbow did not maintain its integrity, additional leakage would have occurred. If both subsystems of containment cooling (including containment spray) were used during the design event, the Torus water level would only be minimally impacted. If only one subsystem of containment cooling were used with no containment spray, then water leakage would have occurred until the HPCl/RCIC 'Flush' line became uncovered (approximately 5 feet below normal Torus water level) and a gaseous release could have occurred. The water leakage would be contained within the Torus Room. The gaseous leakage would be processed through the secondary containment and Standby Gas Treatment System. The Torus Room is within the Secondary Containment boundary.

Corrective Actions The leaking elbow was replaced and non-destructive testing was performed. The similar pipe on Unit 3 was examined and no significant concerns were noted. Extensive walk downs of similar piping that is attached to the Torus were conducted for both Units 2 and 3. There were no similar deficiencies discovered. Selected ultrasonic testing was performed on Units 2 and 3 Torus attached piping that involved higher flow rates. These examinations also did not identify any similar concerns.

Plant test procedures were revised to prevent using the HPCl/RCIC Torus Flush line at high flow conditions.

3.5.2 Generic Letter 87-05. Request for Additional Information - Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells Generic Letter 87-05 described Drywell shell degradation, which occurred at Oyster Creek Nuclear Generating Station as a result of water intrusion into the air gap between the outer Drywell surface and the surrounding concrete and subsequent wetting of the sand cushion at the bottom of the air gap. The initial response to this generic letter for PBAPS was provided in a letter to the NRC dated May 11, 1987 (Reference 28).

The cause of this degradation was determined to be from water entering the drywell air gap region, and becoming trapped in the sand cushion region at the base of the air gap. The air gap region surrounds the outside surface of the drywell and extends from the sand cushion region at the bottom, to just below the drywell bellows region at the top. During refueling activities, a potential leakage path could exist through the drywell bellows region, as experienced on the reported Mark I containment. The drywell bellows provides a flexible seal between the drywell and the reactor cavity. The drywell to concrete seal drains are also located in this bellows area. Leakage of these components could allow water to enter the air gap region. However, such water intrusion is not considered credible at PBAPS, in that any leakage through the drywell bellows is normally channeled to seal rupture collection pipes and is alarmed in the main control room.

The PBAPS design incorporates an 8" pipe to divert potential drywell bellows leakage to a waste collection tank. This 8" drain line is fed by four, 4" seal rupture drains equally spaced around the reactor cavity. A flow of ten gallons per minute through the 8" drain line will result in an annunciator alarm on the refueling floor panel and also will result in an alarm in the main control room. Functionality of the alarm and flow switch is verified periodically. Further, unlike the design at the Mark I containment that reported leakage, the PBAPS reactor cavity seal drain line design incorporates full penetration welds, instead of bolted connections. Additionally, the PBAPS design incorporates a weir wall that prevents drywell bellows leakage from entering the drywell air gap before being drained away by the seal rupture drains.

The PBAPS design also prevents inleakage to the sand cushion by use of a sheet metal cover which is sealed to the drywell shell. This sealed cover separates the sand cushion from the air gap region.

31

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Located above the sealed cover plate are an additional four, 4" air gap drains that drain any inleakage away from the sealed cover plate.

This rigorous design, along with the monitoring and testing measures described, provide substantial defense against water entering the drywell air gap region. With no water intrusion, potential degradation on the outside surface of the drywell is prevented.

Additionally, as part of the PBAPS Primary Containment lnservice Inspection Program, several examinations and tests of components associated with the drywell air gap region confirm that abnormal conditions which could lead to containment degradation do not exist. These examinations and tests are discussed below.

The following examinations are performed on the four drywell air gap drain lines:

1. A functional test (i.e., smoke test) is performed on the four drywell air gap drains once every 1O year interval to verify that the drywell air gap drain lines are unclogged and functional. The test also verifies that the drain lines are free of water.

2. A visual examination is performed on the drywell air gap drain lines once each period when the refueling cavity is flooded to look for signs of leakage.

The above described examinations and tests have been routinely performed with acceptable results for both units.

Additionally, when stabilizer access hatches (penetrations N-110A through N-110H} are opened to perform the Examination Category E-A examinations on the weld to the shear lugs attached to the exterior of the drywell shell at elevation 194 ft. 8 in., a VT-3 visual examination is performed on the following items:

1. The drywell exterior stabilizer support.

2. The accessible exterior surface of the drywell to look for evidence of degradation or leakage.

3. The accessible drywell air gap to look for items that could trap water in the unlikely event of leakage through the refueling bellows.

To date, the results of these examinations confirmed that no evidence of moisture or degradation exists.

3.5.3 Through-Wall Torus Shell Crack at James A. Fitzpatrick Nuclear Power Plant A through-wall Torus shell crack was discovered at the James A. Fitzpatrick Nuclear Power Plant (JAF) on June 27, 2005. EGC reviewed the issue for applicability to PBAPS, and documented the results in the corrective action program.

The JAF High Pressure Coolant Injection (HPCI) turbine exhaust line that discharges into the suppression pool is open ended and does not have an end cap or a sparger. The PBAPS system configurations would not introduce the type of event that occurred at JAF. With respect to PBAPS, the HPCI system design does employ the use of a sparger on the turbine exhaust line. VT-2 and VT-3 inspections were performed on the nozzle and the Torus shell next to the HPCI and RCIC (Reactor Core Isolation Cooling) exhaust penetrations and the support legs to the Torus shell with satisfactory results. No further actions were required.

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ATTACHMENT1 EVALUATION Of THE PROPOSED CHANGE 3.5.4 NRG Information Notice 92-20, Inadequate Local Leak Rate Testing NRG Information Notice 92-20 was issued to alert licensees to problems with local leak rate testing of two-ply stainless steel bellows used on piping penetrations at some plants. Specifically, local leak rate testing could not be relied upon to accurately measure the leakage rate that would occur under accident conditions since, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to this problem.

There are two categories of primary containment bellows at PBAPS:

• Bellows on the vent lines between the drywall and the torus.

• Bellows on various drywall pipe penetrations.

The bellows listed in UFSAR Table 5.2.2, "Containment Penetrations Compliance with 10CFR 50, Appendix J," are testable bellows and are tested in accordance with 10 CFR 50, Appendix J, Option B, Type B testing. Until Option B was adopted, Type B testing was performed every two years.

Since that time, the test frequency has been extended to once every six years. A review of records since June 1977 has revealed no failures of these bellows leakage tests. Additionally, local leak rate test procedures for containment expansion bellows include verification of flow through the annulus between plys of the bellows, which ensures that restrictions between the plys that could conceal a leakage path do not exist.

3.6 License Renewal Aging Management UFSAR Appendix Q, "License Renewal UFSAR Supplement," contains the UFSAR Supplement as required by 10 CFR 54.21(d) for the Peach Bottom License Renewal Application (LRA). The NRG issued SER NUREG-1769, "Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3" (Reference 23) that provided their safety evaluation of the Peach Bottom LRA.

The aging management activity descriptions presented in this appendix represent commitments for managing aging of the in-scope systems, structures and components during the period of extended operation.

As part of the license renewal effort, it had to be demonstrated that the aging effects applicable for the components and structures within the scope of license renewal would be adequately managed during the period of extended operation.

In many cases, existing activities were found adequate for managing aging effects during the period of extended operation. In some cases, aging management reviews revealed that existing activities required enhancement to adequately manage applicable aging effects. In a few cases, new activities were developed to provide added assurance that aging effects are adequately managed.

The following programs/activities are credited with the aging management of the Primary Containment (Drywall and Torus):

• Primary Containment lnservice Inspection Program (PIMS Tracking T04345)

The Primary Containment ISi program consists of inspections that manage loss of material in the primary containment for Class MC pressure-retaining components, their integral attachments, and Class MC component supports; and loss of sealing for the Drywall internal moisture barrier at the juncture of the Containment wall and the concrete floor. PBAPS complies with ASME Section XI 33

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Code, Subsection IWE, Edition and Addenda per the ISi program. The Primary Containment ISi program provides reasonable assurance that aging effects are detected and addressed prior to loss of intended function.

• Primary Containment L~akage Rate Testing Program (PIMS Tracking T04325)

The Primary Containment Leakage Rate Testing Program is that portion of the PBAPS Primary Containment Leakage Rate Testing Program that is being credited for license renewal. The Primary Containment Leakage Rate Testing Program provides for aging management of pressure boundary degradation due to loss of material in a wetted gas environment in containment atmosphere control and dilution, RHR, and Primary Containment Isolation Systems penetrating Primary Containment.

The Primary Containment Leakage Rate Testing Program also manages change in material properties and cracking of gaskets and 0-rings for the Primary Containment pressure boundary access penetrations. The program complies with the requirements of 10CFR50 Appendix J, Option B, and provides reasonable assurance that aging effects are detected and addressed prior to loss of intended function.

3.7 NRC SER Limitations and Conditions 3.7.1 Limitations and Conditions Applicable to NEI 94-01 Revision 2-A The NRG staff found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.7-1 were satisfied:

Table 3.7-1, NEI 94-01 Revision 2-A Limitations and Conditions Limitation/Condition lFrom Section 4.0 of SEl PBAPS Resoonse For calculating the Type A leakage rate, the PBAPS will utilize the definition in NEI 94-01 licensee should use the definition in the NEI TR Revision 3-A, Section 5.0. This definition has 94-01, Revision 2, in lieu of that in ANSI/ANS- remained unchanged from Revision 2-A to 56.8-2002. (Refer to SE Section 3.1.1.1.) Revision 3-A of NEI 94-01.

The licensee submits a schedule of containment Reference Sections 3.4.2 and 3.5 of this inspections to be performed prior to and between submittal.

Type A tests. (Refer to SE Section 3.1.1.3.)

The licensee addresses the areas of the Reference Sections 3.4.2 and 3.5 of this containment structure potentially subjected to submittal.

deqradation. (Refer to SE Section 3.1.3.)

The licensee addresses any tests and inspections There are no major modifications planned.

performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.)

The normal Type A test interval should be less PBAPS will follow the requirements of NEI 94-01 than 15 years. If a licensee has to utilize the Revision 3-A, Section 9.1. This requirement has provision of Section 9.1 of NEI TR 94-01, Revision remained unchanged from Revision 2-A to 2, related to extending the ILRT interval beyond Revision 3-A of NEI 94-01.

15 years, the licensee must demonstrate to the In accordance with the requirements of 94-01 NRG staff that it is an unforeseen emergent Revision 2-A, SER Section 3.1.1.2, PBAPS will condition. (Refer to SE Section 3.1.1.2.) also demonstrate to the NRG staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is reauired.

34

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE Limitation/Condition

<From Section 4.0 of SEl PBAPS Resoonse For plants licensed under 10 CFR Part 52, Not applicable. PBAPS was not licensed under applications requesting a permanent extension of 10 CFR Part 52.

the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data.

3.7.2 Limitations and Conditions Applicable to NEI 94-01 Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation for the optional performance-based requirements of Option B to i 0 CFR Part 50, Appendix J. However, the NRG staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01 Revision 3-A, NRC SER 4.0, Limitations and Conditions):

Topical Report 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 be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type Band 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 TR 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

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

• ISSUE 1 - The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.

• ISSUE 2 - In addition, a corrective action plan shall be developed to restore the margin to an acceptable level.

• 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 1 The post-outage report shall include the margin between the Type Band Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

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ATTACHMENT 1 EVALUATION Of THE PROPOSED CHANGE Response to Condition 1, Issue 2 When the potential leakage understatement adjusted Type B and C MNPLR total is greater than the PBAPS Maintenance Rule leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the PBAPS Maintenance Rule 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 what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Response to Condition 1, Issue 3 PBAPS 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.

Topical Report 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 leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending I

specified in NEI TR 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 and 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 Condition 2 presents two (2) separate issues that are required to be addressed. They are 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 TR 94-01, Revision 3, Section 12.1.

• 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 36

ATTACHMENT1 EVALUATION OFTHEPROPOSED CHANGE an estimate of the amount of understatement in the Type Band 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 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25% in the LLRT periodicity. As such, PBAPS will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the As-Left leakage total for each Type C component currently on the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRT's being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on line or following an outage). When the potential leakage understatement adjusted leak rate total for those Type C components being tested on a 75-month extended interval is summed with the non-adjusted total of those Type C components being tested at less than the 75-month interval and the total of the Type B tested components, if the MNPLR is greater than the PBAPS Maintenance Rule leakage summation limit of 0.50 La. but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the PBAPS Maintenance Rule 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 what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

Response to Condition 2, Issue 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the PBAPS Maintenance Rule leakage summation limit of 0.50 La. then the acceptability of the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, Parts 1, 2 which deal with the MNPLR Type Band C summation margin, NEI 94-01, Revision 3-A also has a margin related requirement as 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 Band Type C leakage summation, and the margin between the Type Band Type C leakage rate summation and its regulatory limit. Adverse trends in the Type Band 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.

At PBAPS, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Type Band C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components which have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

At PBAPS an adverse trend is defined as three (3) consecutive increases in the final pre-RCS Mode Change Type Band C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

37

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE 3.8 Conclusion NEI 94-01, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, describes an NRG-accepted approach for implementing the performance-based requirements of 10 CFR Part 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A 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. PBAPS is adopting the guidance of NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, for the PBAPS, Units 2 and 3, 10 CFR Part 50, Appendix J testing program plan.

Based on the previous ILRT tests conducted at PBAPS, Units 2 and 3, it may be concluded that the permanent extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type Band Type C testing performed in accordance with Option B of 10 CFR Part 50, Appendix J and the overlapping inspection activities performed as part of the following PBAPS, Units 2 and 3 inspection programs:

• Containment lnservice Inspection Program (IWE)

• Containment Inspections per TS SR 3.6.1.1.1

• Containment Coatings Inspection and Assessment Program This experience is supplemented by risk analysis studies, including the PBAPS, Units 2 and 3 risk analysis provided in Attachment 3. The findings of the risk assessment confirm the general findings of previous stuoies, on a plant-specific basis, that extending the ILRT interval from ten to 15 years results in a very small change to the PBAPS, Units 2 and 3 risk profiles.

4.0 REGULATORY EVALUATION

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

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 Part 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test.

The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed. Under the performance-based option of 10 CFR Part 50, Appendix J, the test frequency is based upon an evaluation that reviewed "as-found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequency will not directly result in an increase in containment leakage.

EPRI TR-1009325, Revision 2, provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance. NEI 94-01, Revision 3-A, 38

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Section 9.2.3.1 states that Type A ILRT intervals of up to 15 years are allowed by this guideline. The Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI Report 1018243 (Formerly TR-1009325, Revision 2) indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.

The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J.

This guidance includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in AG 1.163. The NRC staff finds that the Type A testing methodology as described in ANSl/ANS-56.8-2002, and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serves to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in AG 1.177 and AG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER) ..

The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR Part 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.' The NRC staff, therefore, found that this guidance, as modified to include tw,o limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, in a licensing action to satisfy the requirements of Option B to 10 CFR Part 50, Appendix J.

4.2 Precedent This request is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years, as previously authorized by the NRC:

• Nine Mile Point Nuclear Station, Unit 2 (Reference 24)

• Arkansas Nuclear One, Unit 2 (Reference 25)

• Palisades Nuclear Plant (Reference 26)

• Virgil C. Summer Nuclear Station, Unit 1 (Reference 27) 39

ATTACHMENT 1 EVALUATION Of THE PROPOSED CHANGE 4.3 No Significant Hazards Consideration Exelon Generation Company, LLC (EGC) 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 amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed amendment to the TS involves the extension of the PBAPS, Units 2 and 3 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The current Type A test interval of 120 months (10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months.

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. The proposed extension 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 containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident. The change in dose risk for changing the Type A test frequency from three-per-ten years to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all internal events accident sequences for PBAPS, is 5.99E-02 person-rem/yr (0.52%) using the EPRI guidance with the base case corrosion included.

The change in dose risk drops to 1.60E-02 person-rem/yr (0.14%) when using the EPRI Expert Elicitation methodology. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

As documented in NUREG-1493, Type Band C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The PBAPS, Units 2 and 3 Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and; (2) time based. Activity based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance. Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with ASME Section XI, the Maintenance Rule, and TS requirements serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed extensions do not significantly increase the consequences of an accident previously evaluated.

The proposed amendment also deletes exceptions previously granted to allow one-time extensions of the ILRT test frequency for both Units 2 and 3. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that has no effect on any component and no impact on how the units are operated.

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ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE Therefore, the proposed change does not result in 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.

The proposed amendment to the TS involves the extension of the PBAPS, Unit 2 and 3 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) or a change to the manner in which the plant is operated or controlled.

The proposed amendment also deletes exceptions previously granted to allow one-time extensions of the ILRT test frequency for both Units 2 and 3. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated.

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

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

Response: No.

The proposed amendment to TS 5.5.12 involves the extension of the PBAPS, Units 2 and 3 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.

The proposed change involves only the extension of the interval between Type A containment leak rate tests and Type C tests for PBAPS, Units 2 and 3. The proposed surveillance interval extension is bounded by the 15-year ILRT Interval and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusion that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section XI, TS and the Maintenance Rule serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing. The combination of these factors 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 changes to the Type A and Type C test intervals.

The proposed amendment also deletes exceptions previously granted to allow one time extensions of the ILRT test frequency for both Units 2 and 3. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action and does not change how the units are operated and maintained. Thus, there is no reduction in any margin of safety.

41

ATTACHMENT1 EVALUATION Of THE PROPOSED CHANGE Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, EGG concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

4.4 Conclusion 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 be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

A 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 need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995

2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, July 2012

3. Regulatory Guide 1.174, Revision 2, An Approach For Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes To The Licensing Basis, May 2011

4. Regulatory Guide 1.200, Revision 2, An Approach For Determining The Technical Adequacy Of Probabilistic Risk Assessment Results For Risk-Informed Activities, March 2009

5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, July 1995

6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995

7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Te$ting Intervals, August 1994

8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, October 2008

9. Letter from M. J. Maxin (NRG) to J. C. Butler (NEI), dated June 25, 2008, 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 42

ATTACHMENT1 EVALUATION OF THE PROPOSED CHANGE Research Institute (EPRI} Report No. 1009325, Revision 2, August 2007, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals" (TAC No. MC9663)

10. Letter from S. Bahadur (NRG) to B. Bradley (NEI}, dated June 8, 2012, 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}

11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997

12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002.

13. Letter from J. Shea (NRG) to G. Hunger (PECO}, dated June 18, 1996, Technical Specifications Regarding 10 CFR 50, Appendix J, Option B, Containment Leakage Rate Testing Requirements, Peach Bottom Atomic Power Station, Unit Nos. 2 and 3 (TAC NOS. M94853 and M94854)

14. Letter from J Boska (NRG) to 0. Kingsley (Exelon}, dated October 4, 2001, Peach Bottom Atomic Power Station, Unit 3 - Issuance of Amendment RE: Extension of The Containment Integrated Leak Rate Test (TAC NO. MB2094)

15. Letter from J. Hughey (NRG) to C. Crane (Exelon), dated September 14, 2007, Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendment RE: Main Steam Isolation Valve Leakage (TAC NOS. MD4823 and MD4824)

16. Letter from J. Hughey (NRG) to C. Pardee (Exelon}, dated September 5, 2008, Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendments RE: Application of Alternative Source Term Methodology (TAC NOS. MD6806 and MD6807)

17. Letter from J. Hughey (NRG) to M. Pacilio (Exelon), dated July 20, 2010, Peach Bottom Atomic Power Station, Unit 2 - Issuance of Amendment RE: One-Time Five-Year Containment Type A Integrated Leak Rate Test Interval Extension (TAC NO. ME2159)

18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendments RE: Extended Power Uprate (TAC NOS.

ME9631 and ME9632)

19. Letter from B. Buckley Sr. (NRG) to J. Hutton (PECO), dated August 14, 2000, Peach Bottom Atomic Power Station, Unit Nos. 2 and 3 - Issuance of Amendment Regarding Crediting of Containment Overpressure for Net Positive Suction Head Calculations for Emergency Core Cooling Pumps (TAC NOS. MA6291and MA6292)

20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243

21. Peach Bottom Atomic Power Station Mitigating Systems Performance Index Basis Document, Rev. 2, March 27, 2007

22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010

23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3, March 2003 43

ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE

24. Letter from R. V. Guzman (NRC) to S. L. Belcher (NMP), dated March 30, 2010, Nine Mile Point Nuclear Station, Unit No. 2 - Issuance of Amendment RE: Extension of Primary Containment Integrated Leakage Rate Testing Interval (TAC No. ME1650)

25. Letter from N. K. Kalyanam (NRC) to Vice President, Operations (ANO), dated April 7, 2011, Arkansas Nuclear One, Unit No. 2 - Issuance of Amendment RE: Technical Specification Change to Extend Type A Test Frequency to 15 Years (TAC No. ME4090)

26. Letter from M. L. Chawala (NRC) to Vice President, Operations (PNP), dated April 23, 2012, Palisades Nuclear Plant - Issuance of Amendment to Extend the Containment Type A Leak Rate Test Frequency to 15 Years (TAC No. ME5997)

27. Letter from S. Williams (NRC) to T. D. Gatlin (VCSNS), dated February 5, 2014, Virgil C. Summer Nuclear Station, Unit 1 - Issuance of Amendment Extending Integrated Leak Rate Test Interval (TAC No. MF1385)

28. Letter from J. Gallagher (Philadelphia Electric Company) to S. Varga (U.S. Nuclear Regulatory Commission), Peach Bottom Atomic Power Station Generic Letter 87-05 dated March 12, 1987 Degradation of Mark I Drywells, dated May 11, 1987

29. American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, New York, New York, April 2002

30. ASME/American Nuclear Society, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, March 2009

31. Peach Bottom Atomic Power Station PRA Peer Review Report, BWROG Final Report, May 2011

32. Letter from Mr. C. H. Cruse (Constellation Nuclear, Calvert Cliffs Nuclear Power Plant) to U.S.

Nuclear Regulatory Commission, Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Accession Number ML020920100, March 27, 2002 44

ATTACHMENT 2 Markup of Technical Specification and Bases Pages 5.0-17 83.6-5

Programs and Manuals 5.5 5.5 Programs and Manuals

5. 5.11 Safety Function Determination Program CSFDP) (continued)

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

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

3. A required system redundant to support system(s) for the supported systems (b.1) and (b.2) above is also inoperable.

c. The SFDP identifies where a loss of safety function exists.

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

5.5.12 Primary Containment Leakage Rate Testing Program 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 Regulatery Guide 1.163, "Pe1fermanee Ba3ed Centa1nment Leak*

Test Program," dated September 1995, as mGdified by ths following exceptions to ~EI 94 01, Rev. 0, "Industry Guideline fer Implementing Perfermanee Ba3ed Optien of 10 CFR Part 50, Appendix

-cl-" :

Section 10.2: MSIV leakage is excluded from the combined total of 0.6 La for the Type B and C tests.

Section 9.2.3: The first Type A test performed after the October 2000 Type A test shall be performed no later than October 2015.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 49.1 psig.

The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.7% of primary containment air weight per day.

Leakage Rate acceptance criteria are:

a. Primary Containment leakage rate acceptance criterion is ~

~N-E-1-94---01-.-.-ln-du-s~t~~G-u-id_e_lin_e_fo_r__, 1.0 La. During the first unit startup following testing in Implementing Performance-Based accordance with this program, the leakage rate acceptance Optionof10CFRPart50,Appendix criteria are~ 0.60 La for the Type Band Type C tests and~

J,"Revision3-A,datedJuly2012, 0.75 La for Type A tests; and the conditions and limitations specified in NEI 94-01, Revision 2-A,1------------------------~~c=o~n=t~in~u=e=d~

dated October 2008, as modified by the following exemption PBAPS UN IT 2 5.0-17 Amendment No. ~

Primary Containment B 3.6.1.1 BASES (continued)

REFERENCES 1. UFSAR, Section 14.9.

2. Letter G94-PEPR-183, Peach Bottom Improved Technical Specification Project Increased Drywell and Suppression Chamber Pressure Analytical Limits, from G.V. Kumar (GE) to A.A. Winter (PECO), August 23, 1994.

3. 10 CFR 50, Appendix J, Option B.

4. Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and DPR-56, dated February 18, 1988.

3-A and 2-A

5. NEI 94-01, Rev1s1 G, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J."

6. 9-4, "Containment System Leakage Testing Requirements."

7. Peach Bottom Atomic Power Station Evaluation for Extended Final Feedwater Reduction, NEOC-32707P, Supplement 1, Revision 0, May, 1998.

8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

PBAPS UN IT 2 B 3.6-5 Revision No. 6

Programs and Manuals 5.5 5.5 Programs and Manuals

5. 5.11 Safety Function Determination Program (SFDP) (continued)

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

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

3. A required system redundant to support system(s) for the supported systems (b.1) and (b.2) above is also inoperable.

c. The SFDP identifies where a loss of safety function exists.

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

5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate NEl94-01,"lndustryGuideline testing of the containment as required by 10 CFR 50.54(0) and 10 forlmplementing CFR 50, Appendix J, Option B, as modified by approved exemptions.

Performance-BasedOptionof This program shall be in accordance with the guidelines contained 10CFRPart50,AppendixJ," in Regulato1y Guide 1.163, "PerfermaAee Based CoAtaiAmeAt Leal<

Revision3-A,datedJuly Test P1 ogr am," dated September 1995, as modHied by tt'le followir:i9 2012, and the conditions and 1 ...,,,.....,...,,,......+-;..,.,,....,_-+io...-M-i;;+-Qi&-=-1'l-'l--M.......,_-A-.....u...H-w...,.,..~-~.;..,.i.,....;i....;:...,.,....-i;;.,...

limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exemption

a. Section 10.2: MSIV leakage is excluded from the combined total of 0.6 La for the Type B and C tests.

b. Section 9.2.3: Tt'le first Type A test perforMed after tt'le December , 1991 Type A test sflal 1 be performed no 1 ater U1ar:i DeceR:iber, 2006.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 49.1 psig.

The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.7% of primary containment air weight per day.

Leakage Rate acceptance criteria are:

a. Primary Containment leakage rate acceptance criterion is~

1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are ~ 0.60 La for the Type B and Type C tests and ~

0.75 La for Type A tests; continued PBAPS UN IT 3 5.0-17 Amendment No. 273

Primary Containment B 3.6.1.1 BASES (continued)

REFERENCES 1. UFSAR, Section 14.9.

2. Letter G94-PEPR-183, Peach Bottom Improved Technical Specification Project Increased Drywell and Suppression Chamber Pressure Analytical Limits, from G.V. Kumar (GE) to A.A. Winter (PECO), August 23, 1994.

3. 10 CFR 50, Appendix J, Option B.

4. Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and DPR-56, dated February 18, 1988.

13-A and 2-A 1-

5. NEI 94-01, Revis~. "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J."

12002 t-

'----'6. ANSI/ANS-56.~i:-9-94, "Containment System Leakage Testing Requirements."

7. Peach Bottom Atomic Power Station Evaluation for Extended Final Feedwater Reduction, NEDC-32707P, Supplement l, Revision 0, May, 1998.

8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

PBAPS UNIT 3 B 3.6-5 Revision No. -&7-

ATTACHMENT 3 Risk Assessment for PBAPS Regarding the ILRT {Type A)

Permanent Extension Request 1

RM DOCUMENTATION NO. PB-LAR-13 REV: 0 PAGE NO. 1 STATION: Peach Bottom Atomic Power Station (PBAPS)

UNIT(s) AFFECTED: 2&3 TITLE: Risk Assessment for PBAPS Regarding the ILRT (Type A) Permanent Extension Request

SUMMARY

PBAPS is pursuing a License Amendment Request (LAR) to permanently extend the Integrated Leak Rate Test (ILRT) to 15 years.

• The purpose of this document is to provide an assessment of the risk associated with implementing a permanent extension of the PBAPS Unit 2 and Unit 3 containment ILRT interval to 15 years.

This is a Category I Risk Management Document in accordance with ER-M-600-1012, which requires independent review and approval.

[ X ] Internal RM Documentation ( ] External RM Documentation Electronic Calculation Data Files:

Microsoft Excel PB_ILRT-Final.xlsx, 9/30/2014, 9:46 AM, 364 KB Method of Review: [ X ] Detailed [ ] Alternate [ J Review of External Document This RM documentation supersedes: N/A in its entirety.

Prepared by: Donald E. Vanover I D~E.V~ I lt>/7/2t>14 Print Sign Date Reviewed by: Robert J. Wolfgang I I 10/1b..0M.

Print r&ate Approved by: Eugene M. Kel~

Print I

I~ Oat

TABLE OF CONTENTS Section Page 1.0 OVERVIEW ....................................................................................................................... 5 1.1 PURPOSE ............................................................................................................. 5

1.2 BACKGROUND

..................................................................................................... 5 1.3 ACCEPTANCE CRITERIA .................................................................................... 6 2.0 METHODOLOGY .............................................................................................................. 8 3.0 GROUND RULES ............................................................................................................. 9 4.0 INPUTS ........................................................................................................................... 10 4.1 GENERAL RESOURCES AVAILABLE ............................................................... 10 4.2 PLANT-SPECIFIC INPUTS ................................................................................. 15 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) ......................... 24 4.4 IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE ....................................................... 27 5.0 RESULTS ........................................................................................................................ 32 5.1 STEP 1 - QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR ................................................................ 33 5.2 STEP 2 - DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR .................................................. 39 5.3 STEP 3 - EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS .................................................................. 42 5.4 STEP 4 - DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY ........................................................................ 45 5.5 STEP 5 - DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY ......................................................... 45 5.6

SUMMARY

OF INTERNAL EVENTS RESULTS ............................................... .46 5.7 EXTERNAL EVENTS CONTRIBUTION .............................................................. 48

5. 7 .1 PBAPS Fire Risk Discussion ................................................................ 49 5.7.2 PBAPS Seismic Risk Discussion ......................................................... 51 5.7.3 Other External Events Discussion ........................................................ 52

5. 7.4 External Events Impact Summary ........................................................ 52 5.7.5 External Events Impact on ILRT Extension Assessment ..................... 53 5.8 CONTAINMENT OVERPRESSURE IMPACTS ON CDF ................................... 56 6.0 SENSITIVITIES ............................................................................................................... 58 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS ................................ 58 6.2 EPRI EXPERT ELICITATION SENSITIVITY ....................................................... 59

7.0 CONCLUSION

S .............................................................................................................. 62

8.0 REFERENCES

................................................................................................................ 64 APPENDIX A PRA TECHNICAL ADEQUACY 2

LIST OF TABLES Table 4.1-1 EPRl/NEI Containment Failure Classifications ........................................................ 13 Table 4.2-1 Peach Bottom EPU Level 2 PRA Model Release Categories and Frequencies ............................................................................................................. 16 Table 4.2-2 Collapsed Accident Progression Bin (APB) Descriptions from NUREG/CR-4551 ......................................................................................................................... 17 Table 4.2-3 Calculation of PBAPS Population Dose Risk at 50 Miles from NUREG/CR-4551 ......................................................................................................................... 19 Table 4.2-4 Calculation of Updated Peach Bottom Population Dose Risk at 50 Miles ............... 21 Table 4.2-5 PBAPS Level 2 Nodal Assumptions for APB Assignments ..................................... 23 Table 4.4-1 Steel Liner Corrosion Base Case ............................................................................ 29 Table 5.0-1 Accident Classes ..................................................................................................... 32 Table 5.1-1 Containment Release Type Assignment from the NUREG/CR-4551 Consequence Model ................................................................................................ 34 Table 5.1-2 Accident Class 7 Failure Frequencies and Population Doses (Peach Bottom EPU Base Case Level 2 Model) .............................................................................. 37 Table 5.1-3 Radionuclide Release Frequencies as a Function of Accident Class (Peach Bottom Base Case) .................................................................................................. 38 Table 5.2-1 Peach Bottom Population Dose Estimates for Population Within 50 Miles ............ .40 Table 5.2-2 PBAPS Annual Dose as a Function of Accident Class; Characteristic of Conditions for 3 in 10 Year ILRT Frequency .......................................................... .41 Table 5.3-1 PBAPS Annual Dose as a Function of Accident Class; Characteristic of Conditions for 1 in 10 Year ILRT Frequency ........................................................... 43 Table 5.3-2 PBAPS Annual Dose as a Function of Accident Class; Characteristic of Conditions for 1 in 15 Year ILRT Frequency .......................................................... .44 Table 5.5-1 PBAPS ILRT Conditional Containment Failure Probabilities ................................... 46 Table 5.6-1 PBAPS ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions (Including Age Adjusted Steel Liner Corrosion Likelihood) ..................................................... .47 Table 5.6-2 PBAPS ILRT Extension Comparison to Acceptance Criteria ................................... 48 Table 5.7-1 PBAPS External Events Contributor Summary ...................................................... 53 Table 5.7-2 PBAPS 3b (LERF/YR) as a Function of ILRT Frequency for Internal and External Events (Including Age Adjusted Steel Liner Corrosion Likelihood) ........... 54 3

Table 5.7-3 Comparison to Acceptance Criteria Including External Events Contribution for PBAPS ................................................................................................................ 55 Table 5.7-4 Impact of 15-yr ILRT Extension on LERF for PBAPS .............................................. 56 Table 6.1-1 Steel Liner Corrosion Sensitivity Cases for PBAPS ................................................ 58 Table 6.2-1 EPRI Expert Elicitation Results ................................................................................ 60 Table 6.2-2 PBAPS ILRT Cases: 3 in 10 (Base Case), 1 in 10, and 1 in 15 Yr intervals (Based on EPRI Expert Elicitation Leakage Probabilities) ....................................... 61 Table A-1 Status of Gaps to Capability Category II from the 2010 Peer Review ........................ 73 Table A-2 Status of Open Findings from the 2010 Peer Review ................................................ 80 4

1.0 OVERVIEW The risk assessment associated with implementing a permanent extension of the PBAPS Unit 2 and Unit 3 Integrated Leak Rate Test (ILRT) interval to 15 years is described in this document.

1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with implementing a permanent extension of the Peach Bottom Units 2 and 3 (PB2 and PB3) containment Type A ILRT interval from ten years to fifteen years. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology outlined in EPRI TR-104285 [2], the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals [3], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], and the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [5]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the October 2008 EPRI final report [3].

1.2 BACKGROUND

Revisions to 10CFR50, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing requirements from three-in-ten years to at least once per ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than the normal containment leakage of 1.0La (allowable leakage).

The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during development of the performance-based Option B to Appendix J.

Section 11.0 of NEI 94-01 states that NUREG-1493 [6], "Performance-Based Containment Leak Test Program," provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. To supplement the NRC's rulemaking basis, NEI 5

undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 [2].

The NRC report on performance-based leak testing, NUREG-1493 [6], analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined for a comparable BWR plant, that increasing the containment leak rate from the nominal 0.5 percent per day to 5 percent per day leads to a barely perceptible increase in total population exposure, and increasing the leak rate to 50 percent per day increases the total population exposure by less than 1 percent. Because ILRTs represent substantial resource expenditures, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for PBAPS. The current analysis is being performed to confirm these conclusions based on PBAPS specific PRA models and available data.

Earlier ILRT frequency extension submittals have used the EPRI TR-104285 [2] methodology to perform the risk assessment. In October 2008, EPRI 1018243 [3] was issued to develop a generic methodology for the risk impact assessment for ILRT interval extensions to 15 years using current performance data and risk informed guidance, primarily NRC Regulatory Guide 1.174 [4]. This more recent EPRI document considers the change in population dose, large early release frequency (LERF), and containment conditional failure probability (CCFP), whereas EPRI TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for PB2 and PB3 employs the EPRI 1018243 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary.

1.3 ACCEPTANCE CRITERIA The acceptance guidelines in RG 1.174 are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 1.0E-06 per reactor year and increases in large early release frequency (LERF) less than 1.0E-07 per reactor year. Note that a separate discussion in Section 5.8 confirms that the CDF is negligibly impacted by the proposed change for PBAPS.

Therefore, since the Type A test has only a minimal impact on CDF for PBAPS, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 1.0E-06 per reactor year, provided that the total LERF from all contributors (including external events) can be reasonably shown to be less than 1.0E-05 per reactor year. RG 1.174 discusses defense-in-6

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) is also calculated to help ensure that the defense-in-depth philosophy is maintained.

With regard to population dose, examinations of NUREG-1493 and Safety Evaluation Reports (SERs) for one-time interval extension (summarized in Appendix G of [3]) indicate a range of incremental increases in population dose 1 that have been accepted by the NRC. The range of incremental population dose increases is from S0.01 to 0.2 person-rem/yr and 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (Figure 7-2 of NUREG-1493) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, the NRC SER on this issue [7] defines a small increase in population dose as an increase of s 1.0 person-rem per year, or S1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This definition has been adopted for the PBAPS analysis.

The acceptance criteria are summarized below.

1. The estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years must be demonstrated to be small. (Note that Regulatory Guide 1.174 defines very small changes in risk as increases in CDF less than 1.0E-06 per reactor year and increases in LERF less than 1.0E-07 per reactor year. Since the type A ILRT test does not have a significant impact on CDF for PBAPS, the relevant risk metric is the change in LERF. Regulatory Guide 1.174 also defines small risk increase as a change in LERF of less than 1.0E-06 reactor year.) Therefore, a small change in risk for this application is defined as a LERF increase of less than 1.0E-06.

2. Per the NRC SE, a small increase in population dose is also defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive.

3. In addition, the SE notes that a small increase in Conditional Containment Failure Probability (CCFP) should be defined as a value marginally greater than that accepted in previous one-time 15-year ILRT extension requests (typically about 1% or less, with the largest increase being 1.2%). This would require that the increase in CCFP be less than or equal to 1.5 percentage points.

1 The one-time extensions assumed a large leak (EPRI class 3b) magnitude of 35La, whereas this analysis uses 100La.

7

2.0 METHODOLOGY A simplified bounding analysis approach consistent with the EPRI methodology is used for evaluating the change in risk associated with increasing the test interval to fifteen years [3]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current PBAPS PRA models of record (modified to represent pending EPU conditions) and the subsequent containment responses to establish the various fission product release categories including the release size.

The six general steps of this assessment are as follows:

1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report [3].

2. Develop plant-specific population dose rates (person-rem per reactor year) for each of the eight containment release scenario types from plant specific consequence analyses.

3. Evaluate the risk impact (i.e., the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years.

4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 and compare this change with the acceptance guidelines of RG 1.174 [4].

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

6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis and to variations in the fractional contributions of large isolation failures (due to liner breach) to LERF.

Furthermore,

• Consistent with the previous industry containment leak risk assessments, the PBAPS assessment uses population dose as one of the risk measures. The other risk measures used in the PBAPS assessment are the conditional containment failure probability (CCFP) for defense-in-depth considerations, and change in LERF to demonstrate that the acceptance guidelines from RG 1.174 are met.

• This evaluation for PBAPS uses ground rules and methods to calculate changes in the above risk metrics that are consistent with those outlined in the current EPRI methodology [3].

8

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

• The PBAPS Level 1 and Level 2 internal events PRA models provide representative core damage frequency and release category frequency distributions to be utilized in this analysis.

• It is appropriate to use the PBAPS internal events PRA model as a gauge to effectively describe the risk change attributable to the ILRT extension. It is reasonable to assume that the impact from the ILRT extension (with respect to percent increases in population dose) will not substantially differ if external events were to be included in the calculations; however, external events have been accounted for in the analysis based on the available information for PBAPS.

• Dose results for the containment failures modeled in the PRA can be characterized by information provided in NUREG/CR-4551 [8]. The population dose results are estimated by scaling the NUREG/CR-4551 results by the more recent population data for PBAPS (extrapolated to 2030) compared to the population estimates for PBAPS which was used as the reference plant in NUREG/CR-4551. An additional factor is also applied to account for the EPU power levels compared to the original licensed thermal power levels.

• Accident classes describing radionuclide release end states and their definitions are consistent with the EPRI methodology [3] and are summarized in Section 4.2.

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

• The representative containment leakage for Class 3a is 1O La and for Class 3b sequences is 1OOLa, based on the recommendations in the latest EPRI report [3]

and as recommended in the NRC SE on this topic [7]. It should be noted that this is more conservative than the earlier previous industry ILRT extension requests, which utilized 35La for the Class 3b sequences.

• Based on the EPRI methodology and the NRC SE, the Class 3b sequences are categorized as LERF and the increase in Class 3b sequences is used as a surrogate for the LiLERF metric.

• The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension, but is accounted for in the EPRI methodology as a separate entry for comparison purposes. Since the containment bypass contribution to population dose is fixed, no changes on the conclusions from this analysis will result from this separate categorization.

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

• The use of the estimated 2030 population data is appropriate for this analysis.

Precise evaluations of the projected population would not significantly impact the quantitative results, nor would it change the conclusions.

• An evaluation of the risk impact of the ILRT on shutdown risk is addressed using the generic results from EPRI TR-105189 [9].

9

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:

1. NUREG/CR-3539 [1 O]

2. NUREG/CR-4220 [11]

3. NUREG-1273 [12]

4. NUREG/CR-4330 [13]

5. EPRI TR-105189 [9]

6. NUREG-1493 [6]

7. EPRI TR-104285 [2]

8. Calvert Cliffs liner corrosion analysis [5]

9. EPRI 1018243 [3]

10. NRC Final Safety Evaluation [7]

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 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 EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations. EPRI 1018243 complements the previous EPRI report and provides the results of an expert elicitation process to determine the relationship between pre-existing containment leakage probability and magnitude. Finally, the NRC Safety Evaluation (SE) documents the acceptance by the NRC of the proposed methodology with a few exceptions.

10

These exceptions (associated with the ILRT Type A tests) were addressed in the Revision 2-A of NEI 94-01 (and maintained in Revision 3-A of NEI 94-01) and the final version of the updated EPRI report [3], which was used for this application.

NUREG/CR-3539 [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 [14] as the basis for its risk sensitivity calculations. ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small.

NUREG/CR-4220 [111 NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985.

The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of 1E-3 to 1E-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event.

NUREG-1273 [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.

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

However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies:

"... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment."

11

EPRI TR-105189 [91 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk.

This study performed 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 result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by 1.0E-8/yr to 1.0E-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years.

NUREG-1493 [61 NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing frequencies and/or relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies:

• Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk.

• Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk.

EPRI TR-104285 [21 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 Integrated Leak Rate Test (ILRT) and (Local Leak Rate Test) LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150 [15] Level 3 population dose models to perform the analysis. The study also used the approach of NUREG-1493 [6] in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals.

EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident:

1. Containment intact and isolated

2. Containment isolation failures due to support system or active failures

3. Type A (ILRT) related containment isolation failures

4. Type B (LLRT) related containment isolation failures

5. Type C (LLRT) related containment isolation failures 12

6. Other penetration related containment isolation failures

7. Containment failure due to core damage accident phenomena

8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded:

"These study results show that the proposed CLRT [containment leak rate tests]

frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms ... "

Release Category Definitions Table 4.1-1 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology [3]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report.

TABLE 4.1-1 EPRl/NEI CONTAINMENT FAILURE CLASSIFICATIONS 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 IPEs) 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 8-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 in service inspection and testing (ISl/IST) program.

13

TABLE 4.1-1 EPRl/NEI CONTAINMENT FAILURE CLASSIFICATIONS CLASS DESCRIPTION 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.

Calvert Cliffs Liner Corrosion Analysis (51 This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms was factor~d into the risk assessment for the ILRT one-time extension. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner.

EPRI 1018243 [3]

This report presents a risk impact assessment for extending integrated leak rate test (ILRT) surveillance intervals to 15 years. This risk impact assessment complements the previous EPRI report, TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals.

The earlier report considered changes to local leak rate testing intervals as well as changes to ILRT testing intervals. The original risk impact assessment considers the change in risk based on population dose, whereas the revision considers dose as well as large early release frequency (LERF) and conditional containment failure probability (CCFP). This report deals with changes to ILRT testing intervals and is intended to provide bases for supporting changes to industry and regulatory guidance on ILRT surveillance intervals.

The risk impact assessment using the Jeffrey's Non-Informative Prior statistical method is further supplemented with a sensitivity case using expert elicitation performed to address conservatisms.

The expert elicitation is used to determine the relationship between pre-existing containment leakage probability and magnitude. The results of the expert elicitation process from this report are used as a separate sensitivity investigation for the PBAPS analysis presented here in Section 6.2.

14

NRC Safety Evaluation Report [71 This SE documents the NRC staffs evaluation and acceptance of NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, subject to the limitations and conditions identified in the SE and summarized in Section 4.0 of the SE. These limitations (associated with the ILRT Type A tests) were addressed in the Revision 2-A of NEI 94-01 which are also included in Revision 3-A of NEI 94-01 [1] and the final version of the updated EPRI report [3]. Additionally, the SE clearly defined the acceptance criteria to be used in future Type A ILRT extension risk assessments as delineated previously in the end of Section 1.3.

4.2 PLANT-SPECIFIC INPUTS The PB2 and PB3 specific information used to perform this ILRT interval extension risk assessment includes the following:

• Level 1 and Level 2 PRA model quantification results [16, 17]

• Population dose within a 50-mile radius for various release categories [8]

PB2 and PB3 Internal Events Core Damage Frequencies The current PB2 and PB3 Internal Events PRA models of record are based on an event tree I linked fault tree model characteristic of the as-built, as-operated plant. Based on the results reported in Reference [16], the internal events Level 1 PRA core damage frequency (CDF) is 3.64E-06/yr for PB2 and 3.44E-06/yr for PB3. Note that an application-specific Unit 2 model [17]

was developed to support the Extended Power Uprate (EPU) license amendment request. That model incorporated a few changes and also accounted for EPU conditions. The CDF for Unit 2 from that model is 3.69E-06/yr. Since that model currently represents the highest CDF and includes expected changes due to EPU implementation, the Level 1 and Level 2 results from that model will be used for this assessment.

PBAPS Internal Events Release Categorv Frequencies The Level 2 Model that is used for PBAPS was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. Table 4.2-1 summarizes the pertinent Peach Bottom Unit 2 results for EPU conditions in terms of release category. The total Large Early Release Frequency (LERF) which corresponds to the H/E release category in Table 4.2-1 was 15

found to be 4.74E-7/yr. The total release frequency is 2.28E-06/yr. With a total CDF of 3.69E-06/yr, this corresponds to an "OK" release limited to normal leakage of 1.41 E-6/yr.

TABLE 4.2-1 PEACH BOTTOM EPU LEVEL 2 PRA MODEL RELEASE CATEGORIES AND FREQUENCIES CATEGORY FREQUENCY/YR HIE - High Early (LERF) 4.74E-07 M/E - Medium Early O.OOE+OO LIE - Low Early 1.50E-08 LL/E - Low Low Early O.OOE+OO H/I - High Intermediate 8.82E-07 M/I - Medium Intermediate 6.36E-10 Lii - Low Intermediate 2.19E-07 LL/I - Low Low Intermediate 1.35E-07 H/L - High Late 5.65E-10 MIL - Medium Late 4.56E-07 LIL - Low Late 9.64E-08 LL/L - Low Low Late 1.00E-09 Total Release Frequency 2.28E-06 Core Damage Frequency 3.69E-06 PBAPS Population Dose Information The population dose is calculated by using data provided in NUREG/CR-4551 and adjusting the results for the current Peach Bottom Unit 2 Level 2 model results and more recent population estimates. Each accident sequence was associated with an applicable collapsed Accident Progression Bin (APB) from NUREG/CR-4551. The collapsed APBs are characterized by 5 attributes related to the accident progression. Unique combinations of the 5 attributes result in a set of 10 bins that are relevant to the analysis. Information from PBAPS PRA Containment Event Trees (CETs) was used to classify each of the Level 2 sequences using these attributes. The definitions of the 10 collapsed APBs are provided in NUREG/CR-4551 and are reproduced in Table 4.2-2 for references purposes. Table 4.2-3 summarizes the calculated population dose associated with each APB from NUREG/CR-4551.

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TABLE4.2-2 COLLAPSED ACCIDENT PROGRESSION BIN (APB) DESCRIPTIONS FROM NUREG/CR-4551 COLLAPSED DESCRIPTION APB NUMBER 1 CD, VB, Early CF, WW Failure, RPV Pressure> 200 psi at VB Core damage occurs followed by vessel breach. The containment fails early in the wetwell (i.e., either before core damage, during core damage, or at vessel breach) and the RPV pressure is greater than 200 psi at the time of vessel breach (this means Direct Containment Heating (OCH) is possible).

2 CD, VB, Early CF, WW Failure, RPV Pressure< 200 psi at VB Core Damage occurs followed by vessel breach. The containment fails early in the wetwell (i.e., either before core damage, during core damage, or at vessel breach) and the RPV pressure is less than 200 psi at the time of vessel breach (this means OCH is not possible).

3 CD, VB, Early CF, OW Failure, RPV Pressure > 200 psi at VB Core damage occurs followed by vessel breach. The containment fails early in the drywell (i.e., either before core damage, during core damage, or at vessel breach) and the RPV pressure is greater than 200 psi at the time of vessel breach (this means OCH is possible).

4 CD, VB, Early CF, OW Failure, RPV Pressure < 200 psi at VB Core Damage occurs followed by vessel breach. The containment fails early in the drywell (i.e., either before core damage, during core damage, or at vessel breach) and the RPV pressure is less than 200 psi at the time of vessel breach (this means OCH is not possible).

5 CD, VB, Late CF, WW Failure, N/A Core Damage occurs followed by vessel breach. The containment fails late in the wetwell (i.e., after vessel breach during Molten Core-Concrete Interaction (MCCI)) and the RPV pressure is not important since, even if OCH occurred, it did not fail containment at the time it occurred.

6 CD, VB, Late CF, OW Failure, N/A Core Damage occurs followed by vessel breach. The containment fails late in the drywell (i.e., after vessel breach during MCCI) and the RPV pressure is not important since, even if OCH occurred, it did not fail containment at the time it occurred.

7 CD, VB, No CF, Vent, NIA Core Damage occurs followed by vessel breach. The containment never structurally fails, but is vented sometime during the accident progression.

RPV pressure is not important (characteristic 5 is N/A) since, even if it occurred, OCH does not significantly affect the source term as the containment does not fail and the vent limits its effect.

17

TABLE4.2-2 COLLAPSED ACCIDENT PROGRESSION BIN (APB) DESCRIPTIONS FROM NUREG/CR-4551 COLLAPSED DESCRIPTION APB NUMBER 8 CD, VB, No CF, N/A, N/A Core damage occurs followed by vessel breach. The containment never fails structurally (characteristic 4 is N/A) and is not vented. RPV pressure is not important (characteristic 5 is NIA) since, even if it occurred, OCH did not fail containment. Some nominal leakage from the containment exists and is accounted for in the analysis so that while the risk will be small it is not completely negligible.

9 CD, No VB, N/A, N/A, N/A Core damage occurs but is arrested in time to prevent vessel breach. There are no releases associated with vessel breach or MCCI. It must be remembered, however, that the containment can fail due to overpressure or venting even if vessel breach is averted. Thus, the potential exists for some of the in-vessel releases to be released to the environment.

10 No CD, N/A, N/A, N/A, N/A Core damage did not occur. No in-vessel or ex-vessel release occurs. The containment may fail on overpressure or be vented. The RPV may be at high or low pressure depending on the progression characteristics. The risk associated with this bin is negligible.

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TABLE4.2-3 CALCULATION OF PBAPS POPULATION DOSE RISK AT 50 MILES FROM NUREG/CR-4551 COLLAPSED FRACTIONAL NUREG/CR-4551 NUREG/CR-4551 NUREG/CR-4551 BIN# APB POPULATION COLLAPSED BIN POPULATION CONTRIBUTIONS DOSE RISK AT 50 FREQUENCIES DOSE AT 50 TO RISK (MFCR) MILES (PER YEAR) 131 MILES (1)

(FROM A TOTAL (PERSON-REM) 141 OF 7.9 PERSON-REM/YR, MEAN)

(2) 1 0.021 0.1659 9.55E-08 1.74E+06 2 0.0066 0.05214 4.77E-08 1.09E+06 3 0.556 4.3924 1.48E-06 2.97E+06 4 0.226 1.7854 7.94E-07 2.25E+06 5 0.0022 0.01738 1.30E-08 1.34E+06 6 0.059 0.4661 2.04E-07 2.28E+06 7 0.118 0.9322 4.77E-07 1.95E+06 8 0.0005 0.00395 7.99E-07 4.94E+03 9 0.01 0.079 3.86E-07 2.05E+05 10 0 0 4.34E-08 0 Totals 1.0 7.9 4.34E-6

<1> Mean Fractional Contribution to Risk is obtained from Table 5.2-3 of NUREG/CR-4551.

<2> The total population dose risk at 50 miles from internal events in person-rem is provided in Table 5.1-1 of NUREG/CR-4551. The contribution for a given APB is the product of the total Population Dose Risk at 50 miles and the fractional APB contribution.

<3> NUREG/CR-4551 provides the conditional probabilities of the collapsed APBs in Figure 2.5-6. These conditional probabilities are multiplied by the total internal CDF to calculate the collapsed APB frequency.

<4> Obtained from dividing the population dose risk shown in the third column of this table by the collapsed bin frequency shown in the fourth column of this table.

19

Population Estimate Methodology The person-rem results in Table 4.2-3 can be used as an approximation of the dose for Peach Bottom. The total population within a 50-mile radius of Peach Bottom is projected to be 6.18E+06 by the year 2030 [18] based on calculating the 10 year growth factor for radial intervals using 2000 and 2010 census data from the SECPOP2000 code. The use of the 2030 estimate based on the recent SECPOP2000 data is judged to be sufficient to perform this assessment.

This population value is compared to the population value that is provided in NUREG/CR-4551 in order to get a "Population Dose Factor that can be applied to the APBs to obtain dose estimates for Peach Bottom.

Total Peach Bottom 2030 Population at 50 Miles= 6.18E+06 Peach Bottom 1980 Population from NUREG/CR-4551 = 3.02E+06 Population Dose Factor = 6.18E+06 / 3.02E+06 = 2.05 The difference in the doses at 50 miles is assumed to be in direct proportion to the difference in the population within 50 miles of the site. An additional factor of 1.20 is applied to account for EPU power levels which represent 120% of the original licensed thermal power. This approach provides a first-order approximation for Peach Bottom of the population doses associated with each of the release categories from NUREG/CR-4551. This is considered adequate since the conclusions from this analysis will not be substantially affected by the actual dose values that are used.

Table 4.2-4 shows the results of applying the population factor and power level factor to the NUREG/CR-4551 population dose results at 50 miles to obtain the adjusted population dose at 50 miles for Peach Bottom. The population factor of 2.05 and the power level factor of 1.20 results in a total factor of 2.46 being applied to each bin.

20

TABLE4.2-4 CALCULATION OF UPDATED PEACH BOTTOM POPULATION DOSE RISK AT 50 MILES ACCIDENT NUREG/CR-4551 BIN MULTIPLIER PEACH BOTTOM PROGRESSION POPULATION USED TO OBTAIN ADJUSTED BIN# DOSE AT 50 PEACH BOTTOM POPULATION DOSE MILES POPULATION AT 50 MILES (PERSON-REM) DOSE (PERSON-REM) 1 1.74E+06 2.46 4.28E+06 2 1.09E+06 2.46 2.68E+06 3 2.97E+06 2.46 7.31E+06 4 2.25E+06 2.46 5.54E+06 5 1.34E+06 2.46 3.30E+06 6 2.28E+06 2.46 5.61E+06 7 1.95E+06 2.46 4.80E+06 8 4.94E+03 2.46 1.22E+04 9 2.05E+05 2.46 5.04E+05 10 0 2.46 O.OOE+OO Application of Peach Bottom PRA Model Results to NUREG/CR-4551 Level 3 Output A major factor related to the use of NUREG/CR-4551 in this evaluation is that the results of the current Peach Bottom EPU PRA Level 2 model are not defined in the same terms as reported in NUREG/CR-4551. In order to use the Level 3 model presented in that document, it was necessary to apply the Peach Bottom EPU PRA Level 2 model results into a format which allowed for the scaling of the Level 3 results based on current Level 2 output. This subsection provides a description of the process used to apply the Peach Bottom EPU PRA Level 2 model results into a form that can be used to generate Level 3 results using the NUREG/CR-4551 documentation.

Note that this is the same approach that was used in 2009 one-time ILRT extension for Peach Bottom Unit 2 [19].

The basic process that was pursued to obtain Level 3 results based on the Peach Bottom EPU Level 2 model and NUREG/CR-4551 was to define a useful relationship between the Level 2 and Level 3 results. Consequently, each non-zero sequence of the Peach Bottom EPU Level 2 model was reviewed and assigned into one of the collapsed Accident Progression Bins (APBs) from 21

NUREG/CR-4551. The Level 2 model contains a significantly larger amount of information about the accident sequences than what is used in the collapsed APBs in NUREG/CR-4551 and this assignment process required simplification of accident progression information and assumptions related to categorizations of certain items. The relevant assumptions used for these assignments are shown in Table 4.2-5. Other nodes are included in the Peach Bottom EPU Level 2 model, but these were not utilized (or did not contribute) to the APB assignment performed here for the ILRT assessment. Additionally, it should be noted that these bin assignments influence the total base case population dose estimated for PBAPS, but do not influence the change in dose calculated for the ILRT extension risk assessment.

22

TABLE4.2-5 PBAPS LEVEL 2 NODAL ASSUMPTIONS FOR APB ASSIGNMENTS ACCIDENT PBAPS PRA ASSUMPTION CLASS CONTAINMENT EVENT TREE NODE 1or3 IS - Containment If the containment is not isolated, it is assumed that it will be Isolation open for the equivalent of an un-scrubbed release as soon as the vessel is breached. No depressurization is asked prior to this node; it is assumed that RPV pressure is >= 200 psi for these sequences. This is APB 3.

OP - Operator It is assumed that success on this branch results in RPV depressurizes the pressure below 200 psi.

RPV RX - Core Melt A success on this branch signifies that there is no vessel Arrested in Vessel breach. The sequences following this path are generally grouped in APB 9. However, there are cases in which combustible gas venting (GV) fails followed by containment failure (CZ); this is assumed to result in a high early release and is categorized as APB 4 event for low pressure and APB 3 for high pressure.

GV - Combustible If GV succeeds following success of RX, then APB 9 is Gas Venting assigned. If GV succeeds following failure of RX, then this is Initiated assumed to result in an early release and is categorized as a APB 4 event for low pressure and APB 3 for high pressure.

CZ/SI- Given that the core melt has not been contained in the RPV, Containment failure in node CZ is assumed to result in an un-scrubbed Intact/Mark I Shell release through the drywall. Failure in node SI is also Failure assumed to result in an un-scrubbed release due to fission product release through the gap between the liner and the concrete. The sequences with failures in these nodes are assigned to APB 3 or APB 4 depending on RPV pressure.

NC- No Large A large containment failure instigated by a gradual Containment pressurization of containment following vessel breach is Failure assigned to the "late containment failure" bins. The sequences contributing to these bins need to be separated into either WW or OW failures. The majority fall into APB 6 for late OW failure as opposed to APB 5 for late WW failure.

VC - Containment Sequences with successful containment vent benefit are Vent typicaly assigned to APB 7. However, if vessel breach does not occur because injection is available after core damage and remains available after containment venting, then APB 9 is assigned.

23

TABLE4.2-5 PBAPS LEVEL 2 NODAL ASSUMPTIONS FOR APB ASSIGNMENTS ACCIDENT PBAPS PRA ASSUMPTION CLASS CONTAINMENT EVENT TREE NODE 2 or4 OP - Operator It is assumed that success on this branch results in RPV depressurizes the pressure below 200 psi.

RPV RX - Core Melt A success on this branch signifies that there is no vessel Arrested in Vessel breach. The sequences following this path are generally grouped in APB 9. However, there are cases in which combustible gas venting (GV) fails followed by containment failure (CZ); this is assumed to result in a high early release and is categorized as APB 4 event for low pressure and APB 3 for high pressure.

GV - Combustible If GV succeeds following success of RX, then APB 9 is Gas Venting assigned. If GV succeeds following failure of RX, then this is Initiated assumed to result in an early release and is categorized as a APB 4 event for low pressure and APB 3 for high pressure.

CZ/SI- Given that the core melt has not been contained in the RPV, Containment failure in node CZ is assumed to result in an un-scrubbed Intact/Mark I Shell release through the drywell. Failure in node SI is also Failure assumed to result in an un-scrubbed release due to fission product release through the gap between the liner and the concrete. The sequences with failures in these nodes are assigned to APB 3 or APB 4 depending on RPV pressure.

5 N/A No collapsed bin is available for containment bypass scenarios. The closest match to a bypass scenario is assumed to be a vessel breach with early drywell failure (bins 3 and 4). Bin 3 is assigned as it represents the largest release.

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 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 4.1-1 is divided into two sub-classes representing small and large leakage failures. These subclasses are defined as Class 3a and Class 3b, respectively.

24

The probability of the EPRI Class 3a failures may be determined, consistent with the latest EPRI guidance [3], as the mean failure estimated from the available data (i.e., 2 "small" failures that could only have been discovered by the ILRT in 217 tests leads to a 2/217=0.0092 mean value).

For Class 3b, consistent with latest available EPRI data, a non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5/(217+1) = 0.0023).

The EPRI methodology contains information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC regulatory guide 1.174. This information includes a discussion of conservatisms in the quantitative guidance for delta LERF. EPRI describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method.

The methodology 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 PBAPS (as detailed in Section 5) means that the Class 2, Class 7, and Class 8 LERF 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. Note that Class 2 events refer to sequences with a large pre-existing containment isolation failure that lead to LERF, a subset of Class 7 events are LERF sequences due to an early containment failure from energetic phenomena, and Class 8 event are containment bypass events that contribute to LERF.

Consistent with the EPRI methodology [3], the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection. For example, the average time that a leak could go undetected with a three-year test interval is 1.5 years (3 yr I 2), and the average time that a leak could exist without detection for a ten-year interval is 5 years (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, given a 10-year vs. a 3-yr 25

interval. Correspondingly, 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.

PB2 and PB3 Past ILRT Results The surveillance frequency for Type A testing in NEI 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e., two consecutive periodic Type A tests at least 24 months apart) where the calculated performance leakage rate was less than 1.0La, and in compliance with the performance factors in NEI 94-01, Section 11.3. Based on the successful completion of two consecutive ILRTs at PB2 and PB3, the current ILRT interval is once per ten years. Note that the probability of a pre-existing leakage due to extending the ILRT interval is based on the industry-wide historical results as noted in the EPRI guidance document [3].

EPRI Methodology This analysis uses the approach outlined in the EPRI Methodology [3]. The six steps of the methodology are:

1. Quantify the baseline (three-year ILRT frequency) risk in terms of frequency per reactor year for the EPRI accident classes of interest.

2. Develop the baseline population dose (person-rem, from the plant PRA or IPE, or calculated based on leakage) for the applicable accident classes.

3. Evaluate the risk impact (in terms of population dose rate and percentile change in population dose rate) for the interval extension cases.

4. Determine the risk impact in terms of the change in LERF and the change in CCFP.

5. Consider both internal and external events.

6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis.

The first three steps of the methodology deal with calculating the change in dose. The change in dose is the principal basis upon which the Type A ILRT interval extension was previously granted and is a reasonable basis for evaluating additional extensions. The fourth step in the methodology calculates the change in LERF and compares it to the guidelines in Regulatory Guide 1.174.

Because the change in CDF for PBAPS is minimal under EPU conditions, the change in LERF forms the quantitative basis for a risk informed decision per current NRC practice, namely Regulatory Guide 1.174. The fourth step of the methodology calculates the change in containment failure probability, referred to as the conditional containment failure probability, CCFP. The NRC has identified a CCFP of less than 1.5% as the acceptance criteria for extending the Type A ILRT test intervals as the basis for showing that the proposed change is consistent with the defense in 26

depth philosophy [7]. As such, this step suffices as the remaining basis for a risk informed decision per Regulatory Guide 1.174. Step 5 takes into consideration the additional risk due to external events, and Step 6 investigates the impact on results due to varying the assumptions associated with the liner corrosion rate and failure to visually identify pre-existing flaws.

4.4 IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is evaluated using the methodology from the Calvert Cliffs liner corrosion analysis [5]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner.

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

• Differences between the containment basemat and the containment cylinder and head

• The historical steel liner flaw likelihood due to concealed corrosion

• The impact of aging

• The corrosion leakage dependency on containment pressure

• The likelihood that visual inspections will be effective at detecting a flaw Assumptions

• Based on a review of industry events, an Oyster Creek incident is assumed to be applicable to Peach Bottom for a concealed shell failure in the floor. In the Calvert Cliffs analysis, this event was assumed not to be applicable and 0.5 failures were assumed (i.e. a typical PRA model when no failures have been identified) (See Table 4.4-1, Step 1.)

• The two corrosion events over a 5.5 year data period are used to estimate the liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the PBAPS containment analysis. These events, one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference [21]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Valley 1 containment 27

liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance (See Table 4.4-1, Step 1).

• Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed to double every five years. This is based solely on judgment and is included in this analysis to address the increased likelihood of corrosion as the steel liner ages (See Table 4.4-1, Steps 2 and 3). Sensitivity studies are included that address doubling this rate every two years and every ten years.

• In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated as 1.1 % for the cylinder and dome region, and 0.11 % (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the containment fragility curve versus the ILRT test pressure. For Peach Bottom the containment failure probabilities are conservatively assumed to be 10% for the drywell outer walls and 1% for the basemat. 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, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used for the containment cylinder and head. For the containment basemat, 100% is assumed unavailable for visual inspection. To date, all liner corrosion events have been detected through visual inspection (See Table 4.4-1, Step 5). Sensitivity studies are included that evaluate total detection failure likelihood of 5% and 15%,

respectively.

• Consistent with the Calvert Cliffs analysis, 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.

28

TABLE4.4-1 STEEL LINER CORROSION BASE CASE STEP DESCRIPTION CONTAINMENT CONTAINMENT BASEMAT CYLINDER AND HEAD 1 Historical Steel Liner Flaw Events: 2 Events: 1 Likelihood 1.0/(70

• 5.5) = 2.6E-3 Failure Data: Containment 2/(70

• 5.5) = 5.2E-3 location specific (consistent with Calvert Cliffs analysis).

2 Age Adjusted Steel Liner Year Failure Rate Year Failure Rate Flaw Likelihood 1 2.1E-3 1 1.0E-3 During 15-year interval, avg 5-10 5.2E-3 avg 5-10 2.6E-3 assume failure rate doubles 15 1.4E-2 15 7.0E-3 every five years (14.9%

increase per year). The 15 year average = 15 year average =

average for 5th to 1oth year 6.27E-3 3.14E-3 is set to the historical failure rate (consistent with Calvert Cliffs analysis).

3 Flaw Likelihood at 3, 10, 0.71% (1 to 3 years) 0.36% (1to3 years) and 15 years 4.06% (1 to 10 years) 2.03% (1 to 10 years)

Uses age adjusted liner 9.40% (1to15 years) 4.70% (1 to 15 years) flaw likelihood (Step 2), (Note that the Calvert Cliffs (Note that the Calvert Cliffs assuming failure rate analysis presents the delta analysis presents the delta doubles every five years between 3 and 15 years of between 3 and 15 years of (consistent with Calvert 8.7% to utilize in the 2.2% to utilize in the Cliffs analysis - See Table estimation of the delta-LERF estimation of the delta-6 of Reference [5]). value. For this analysis, the LERF value. For this values are calculated based analysis, twice that value is on the 3, 10, and 15 year utilized (since 1 failure is intervals.) assumed applicable instead of 0.5) and the values are calculated based on the 3, 10, and 15 year intervals.)

29

TABLE4.4-1 STEEL LINER CORROSION BASE CASE STEP DESCRIPTION CONTAINMENT CONTAINMENT BASEMAT CYLINDER AND HEAD 4 Likelihood of Breach in 10% 1%

Containment Given Steel Liner Flaw The failure probability of the containment cylinder and dome is assumed to be 10% (compared to 1.1% in the Calvert Cliffs analysis).

The basemat failure probability is assumed to be a factor of ten less, 1%

(compared to 0.11 % in the Calvert Cliffs analysis).

5 Visual Inspection 10% 100%

Detection Failure 5% failure to identify visual Cannot be visually Likelihood flaws plus 5% likelihood that inspected.

Utilize assumptions the flaw is not visible (not consistent with Calvert through-cylinder but could Cliffs analysis. be detected by ILRT)

All events have been detected through visual inspection. 5% visible failure detection is a conservative assumption.

6 Likelihood of Non- 0.0071% (at 3 years) 0.0036% (at 3 years)

Detected Containment =0.71%

• 10%

• 10% =0.36%

• 1%

• 100%

Leakage (Steps 3

• 4

• 5) 0.0406% (at 10 years) 0.0203% (at 10 years)

=4.06%

• 10%

• 10% =2.03%

• 1%

• 100%

0.0940% (at 15 years) 0.0470% (at 15 years)

=9.40%

• 10%

• 10% =4.70%

• 1%

• 100%

30

The total likelihood of the corrosion-induced, non-detected containment leakage that is subsequently added to the EPRI Class 3b contribution is the sum of Step 6 for the containment cylinder and dome, and the containment basemat:

At 3 years: 0.0071 % + 0.0036% = 0.0107%

At 1O years: 0.0406% + 0.0203% = 0.0609%

At 15 years: 0.094% + 0.0470% = 0.1410%

31

5.0 RESULTS The application of the approach based on EPRI Guidance [3] has led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes.

TABLE 5.0-1 ACCIDENT CLASSES ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE) DESCRIPTION 1 Containment Intact 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 analysis performed examined the PBAPS specific accident sequences in which the containment remains intact or the containment is impaired. Specifically, the categorization of the severe accidents contributing to risk was considered in the following manner:

• Core damage sequences in which the containment remains intact initially and in the long term (EPRI 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, if applicable. (EPRI Class 3 sequences).

• Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left "opened" following a plant post-maintenance test. (For example, a valve failing to close following a valve stroke test.

(EPRI Class 6 sequences). Consistent with the EPRI Guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.

32

• Accident sequences involving containment bypass (EPRI Class 8 sequences), large containment isolation failures (EPRI Class 2 sequences), and small containment isolation "failure-to-seal" events (EPRI Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change.

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

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 accident classes presented in Table 5.0-1.

Step 2 Develop plant-specific person-rem dose (population dose) per reactor year for each of the accident classes.

Step 3 Evaluate risk impact of extending Type A test interval from 3 to 15 and 1O to 15 years.

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

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

5.1 STEP 1 - QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR This step involves the review of the Peach Bottom containment event trees (CETs) and Level 2 accident sequence frequency results. The CETs characterize the response of the containment to important severe accident sequences. As described in Section 4.2, the Peach Bottom CETs were examined and each end state was applied to one of the Accident Progression Bins as defined in NUREG/CR-4551. The correlation between the NUREG/CR-4551 Accident Progression Bins to the EPRI containment release categories is shown in Table 5.1-1. This application combined with the Peach Bottom dose (person-rem) results determined from Table 4.2-4 forms the basis for estimating the population dose for Peach Bottom.

For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks is included in the model. (These events are represented by the Class 3 sequences in EPRI TR-104285). Two failure modes were considered for the Class 3 sequences. These are Class 3a (small breach) and Class 3b (large breach).

The frequencies for the severe accident classes defined in Table 5.0-1 were developed for Peach Bottom based on the assumptions shown in Table 4.2-5, 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 33

corrosion of the steel liner per the methodology described in Section 4.4. The eight containment release class frequencies were developed consistent with the definitions in Table 5.0-1 as described following Table 5.1-1.

TABLE 5.1-1 CONTAINMENT RELEASE TYPE ASSIGNMENT FROM THE NUREG/CR-4551 CONSEQUENCE MODEL EPRI TR-104285 CONTAINMENT NUREG/CR-4551 RELEASE SCENARIO DOSE ACCIDENT PEACH BOTTOM DOSE TYPE (PERSON-REM) PROGRESSION BIN (PERSON-REM) 1 1.22E+04 8 1.22E+04 (VB, No CF, No Vent) 10 O.OOE+OO (No core damage) 2 7.31E+06 3 (1) 7.31E+06 (Isolation Failure) 7 4.95E+Q6<2> 1 4.28E+06 (VB, Early WW, Hi Press) 2 2.68E+06 (VB, Early WW, Lo Press) 3 7.31 E+06 (VB, Early OW, Hi Press 4 5.54E+06 (VB, Early OW, Lo Press) 5 3.30E+06 (VB, Late WW) 6 5.61E+06 (VB, Late OW) 7 4.80E+06 (VB, No CF, Vent) 9 5.04E+05 (No VB, No CF, No Vent) 8 7.31 E+06 3 (1) 7.31 E+06 (ISLOCA)

1. No specific Release Bin for this category exists in NUREG/CR-4551. For simplicity, the large dose associated with APB 3 is used in this analysis to represent EPRI Class 2 and EPRI Class

8. This will not impact the calculated change for the proposed ILRT extension.

2. Given that multiple NUREG/CR-4551 discrete scenarios apply to the broader EPRI type, the EPRI type dose is based on a weighted average (weights based on Peach Bottom EPU PRA scenario frequencies) of the applicable NUREG/CR-4551 APB doses.

34

Class 1 Sequences This group consists of all core damage accident progression bins for which the containment remains intact (modeled as Technical Specification Leakage). The frequency per year for these sequences is 1.37E-06/yr and is determined by subtracting all containment failure end states including the EPRl/NEI Class 3a and 3b frequency calculated below, from the total CDF. For this analysis, the associated maximum containment leakage for this group is 1La, consistent with an intact containment evaluation.

Class 2 Sequences This group consists of large containment isolation failures. For PBAPS, all containment isolation failure sequences were assigned to APB 3. The sum of the frequencies of these scenarios is 6.09E-09/yr.

Class 3 Sequences This group represents pre-existing leakage in the containment structure (e.g., containment liner).

The containment leakage for these sequences can be either small or large. In this analysis, a value of 1Ola was used for small pre-existing flaws and 1OOLa for relatively large flaws.

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)

PROBc1ass_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 to those cases that are already considered LERF scenarios (i.e., the Class 2 and Class 8 contributions). Note that some portion of the EPRI Class 7 frequency also represents LERF scenarios, but these are conservatively not subtracted from that portion of CDF eligible for EPRI Class 3. The adjustment to exclude EPRI Class 2 and Class 8 is made on the frequency information as shown below.

Class_3a =0.0092 * [CDF - (Class 2 + Class 8)]

=0.0092 * [3.69E (6.09E-09 + 9.34E-08)]

=3.31 E-08/yr 35

Class_3b = 0.0023 * [CDF - (Class 2 + Class 8)]

= 0.0023 * [3.69E (6.09E-09 + 9.34E-08)]

=8.27E-09/yr For this analysis, the associated containment leakage for Class 3a is 1Ola and 1OOLa for Class 3b, which is consistent with the latest EPRI methodology [3] and the NRC SE [7].

Class 4 Sequences This group represents containment isolation failure-to-seal of Type B test components. 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 this analysis.

Class 5 Sequences This group represents containment isolation failure-to-seal of Type C test components. Because these 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 with a failure-to-seal containment leakage due to failure to isolate the containment. These sequences are dominated by misalignment of containment isolation valves following a test/maintenance evolution.

Consistent with the EPRI guidance, 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. For this analysis, the associated radionuclide releases are based on the application of the Level 2 end states to the Accident Progression Bins from NUREG/CR-4551 as described in Section 4.2. The Class 7 Sequences are divided into 8 categories which consists of Bins 1, 2, 3, (excluding the ISLOCA and isolation failure sequences assigned to this bin), 4, 5, 6, 7, and 9 from NUREG/CR-4551. The failure frequency and population dose for each specific APB is shown below in Table 5.1-2. The total release frequency and total dose are then used to determine a weighted average person-rem for use as the representative EPRI Class 7 dose in the subsequent analysis. Note that the total frequency and dose associated from this EPRI class does not change as part of the ILRT extension request.

36

TABLE 5.1-2 ACCIDENT CLASS 7 FAILURE FREQUENCIES AND POPULATION DOSES

{PEACH BOTTOM EPU BASE CASE LEVEL 2 MODEL)

POPULATION POPULATION DOSE (50 MILES) DOSE RISK (50 RELEASE PERSON-REM 11 > MILES)

ACCIDENT CLASS FREQUENCY/ (PERSON-REM I (APB NUMBER) YR YR) 12>

7a (APB 1) O.OOE+OO 4.28E+06 O.OOE+OO 7b (APB 2) O.OOE+OO 2.68E+06 O.OOE+OO 7c (APB 3, excluding ISLOCA and Isolation 2.35E-08 7.31E+06 1.71 E-01 failures) 7d (APB 4) 1.22E-06 5.54E+06 6.76E+OO 7e (APB 5) 2.37E-09 3.30E+06 7.82E-03 7f (APB 6) 4.67E-07 5.61E+06 2.62E+OO 7g (APB 7) 2.32E-07 4.80E+06 1.11E+OO 7h (APB 9) 2.34E-07 5.04E+05 1.18E-01 Class 7 Total 2.18E-06 4.95E+o5<3> 10.79 (1)

Population dose values obtained from Table 4.2-4 based on the Accident Progression Bin.

(2)

Obtained by multiplying the Release Frequency value from the second column of this table by the Population dose value from the third column of this table.

(3)

The weighted average population dose for Class 7 is obtained by dividing the total population dose risk by the total release frequency.

Class 8 Sequences This group represents sequences where containment bypass occurs (ISLOCA). For PBAPS, all containment bypass sequences were assigned to APB 3. The sum of the frequencies of these scenarios is 9.34E-08/yr.

Summary of Accident Class Frequencies In summary, the accident sequence frequencies that can lead to release of radionuclides to the public have been derived in a manner consistent with the definition of accident classes defined in EPRI 1O18243 [3] and are shown in Table 5.1-3 by accident class.

37

TABLE 5.1-3 RADIONUCLIDE RELEASE FREQUENCIES AS A FUNCTION OF ACCIDENT CLASS (PEACH BOTTOM BASE CASE)

ACCIDENT DESCRIPTION FREQUENCY CLASSES (PER RX-YR)

(CONTAINMENT RELEASE TYPE) 1 No Containment Failure 1.37E-06 2 Large Isolation Failures (Failure to Close) 6.09E-09 3a Small Isolation Failures (liner breach) 3.31E-08 3b Large Isolation Failures (liner breach) 8.27E-09 4 Small Isolation Failures (Failure to seal -Type 8) N/A 5 Small Isolation Failures (Failure to seal-Type C) N/A 6 Other Isolation Failures (e.g., dependent failures) NIA 7 Failures Induced by Phenomena (Early and Late) 2.18E-06 8 Bypass (Interfacing System LOCA) 9.34E-08 CDF All CET End states (including very low and no 3.69E-06 release) 38

5.2 STEP 2- DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE)

PER REACTOR YEAR Plant-specific release analyses were performed to estimate the person-rem doses to the population within a 50-mile radius from the plant. The releases are based on information provided by NUREG/CR-4551 with adjustments made for the site demographic differences compared to the reference plant at the time as described in Section 4.2, and summarized in Table 4.2-4. The results of applying these releases to the EPRl/NEI containment failure classification are as follows:

Class 1 = 1.22E+04 person-rem (at 1.0La)<1>

Class 2 = 7.31 E+06 person-rem( 2>

Class 3a = 1.22E+04 person-rem x 1Ola = 1.22E+05 person-rem(3>

Class 3b = 1.22E+04 person-rem x 100La = 1.22E+06 person-rem(3>

Class 4 = Not analyzed Class 5 = Not analyzed Class 6 = Not analyzed Class 7 = 4.95E+06 person-rem(4 >

Class 8 = 7.31 E+06 person-rem(5>

( 1> The Class 1, containment intact sequences, dose is assigned from the APB 8 (No CF, No Vent) from the NUREG/CR-4551 adjusted dose for Peach Bottom as shown in Table 4.2-4.

(Z) The Class 2, containment isolation failures, dose is approximated from APB 3 (VB, Early OW, Hi Press) from Table 4.2-4.

(3> The Class 3a and 3b dose are related to the leakage rate as shown. This is consistent with the accepted methodology.

(4> The Class 7 dose is assigned from the weighted average dose calculated from APBs #1, 2, 3, 4, 5, 6, 7, and 9 from Table 4.2-4 as detailed in Table 5.1-2 above.

(5> Class 8 sequences involve containment bypass failures; as a result, the person-rem dose is not based on normal containment leakage. As an approximation, the releases for this class are also assigned from APB 3 from Table 4.2-4.

In summary, the population dose estimates derived for use in the risk evaluation per the EPRI methodology [3] containment failure classifications are provided in Table 5.2-1.

39

TABLE 5.2-1 PEACH BOTTOM POPULATION DOSE ESTIMATES FOR POPULATION WITHIN 50 MILES ACCIDENT REPRESENTATIVE DESCRIPTION PERSON-CLASSES ACCIDENT REM (50 (CONTAINMENT PROGRESSION BIN MILES)

RELEASE TYPE) (APB) 1 8 No Containment Failure (1 La) 1.22E+04 2 3 Large Isolation Failures (Failure to 7.31E+06 Close) 3a 10La Small Isolation Failures (liner 1.22E+05 breach) 3b 100La Large Isolation Failures (liner 1.22E+06 breach) 4 N/A Small Isolation Failures (Failure to NA seal - Type 8) 5 N/A Small Isolation Failures (Failure to NA seal-Type C) 6 N/A Other Isolation Failures (e.g., NA dependent failures) 7 1, 2, 3 (except ISLOCA Failures Induced by Phenomena 4.95E+06 and isolation failures), 4, (Early and Late) 5,6, 7,9 8 3 Bypass (Interfacing System 7.31E+06 LOCA)

The above dose estimates, when combined with the frequency results presented in Table 5.1-3, yield the Peach Bottom baseline mean consequence measures for each accident class. These results are presented in Table 5.2-2.

40

TABLE 5.2-2 PBAPS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 3 IN 10 YEAR ILRT FREQUENCY ACCIDENT DESCRIPTION PERSON- EPRI METHODOLOGY EPRIMETHODOLOGY CHANGE DUE TO CLASSES REM PLUS CORROSION CORROSION (CONT. (0-50 (PERSON-FREQUENCY PERSON- FREQUENCY PERSON-RELEASE MILES) REMNR) <1l (1NR) REMNR (1NR} REMNR TYPE)

(0-50 MILES) (0-50 MILES) 1 Containment Intact <2l 1.22E+04 1.37E-06 1.67E-02 1.37E-06 1.67E-02 -4.65E-06 2 Large Isolation Failures 7.31 E+06 6.09E-09 4.45E-02 6.09E-09 4.45E-02 -

(Failure to Close) 3a Small Isolation Failures 1.22E+05 3.31 E-08 4.02E-03 3.31 E-08 4.02E-03 --

(liner breach) 3b Large Isolation Failures 1.22E+06 8.27E-09 1.00E-02 8.65E-09 1.05E-02 4.65E-04 (liner breach) 7 Failures Induced by 4.95E+06 2.18E-06 1.08E+01 2.18E-06 1.08E+01 -

Phenomena (Early and Late) 8 Containment Bypass 7.31E+06 9.34E-08 6.82E-01 9.34E-08 6.82E-01 -

(Interfacing System LOCA)

CDF All CET end states 3.69E-06 11.55 3.69E-06 11.55 4.61E-04 (1l Only release Classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.

The additional frequency added to Class 3b is subtracted from Class 1 and the population dose rates are recalculated. This results in a small reduction to the Class 1 dose rate and an increase to the Class 3b dose rate.

<2> Characterized as 1La 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.

41

5.3 STEP 3- EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS The next step is to evaluate the risk impact of extending the test interval from its current ten-year value to fifteen-years. To do this, an evaluation must first be made of the risk associated with the ten-year interval since the base case applies to a 3-year interval (i.e., a simplified representation of a 3-in-10 year interval).

Risk Impact Due to 10-year Test Interval As previously stated, Type A tests impact only Class 3 sequences. For Class 3 sequences, the release magnitude is not impacted by the change in test interval (a small or large breach remains the same, even though the probability of not detecting the breach increases). Thus, only the frequency of Class 3a and 3b sequences is impacted. The risk contribution is changed based on the EPRI guidance as described in Section 4.3 by a factor of 3.33 compared to the base case values. The results of the calculation for a 10-year interval are presented in Table 5.3-1.

Risk Impact Due to 15-YearTest Interval The risk contribution for a 15-year interval is calculated in a manner similar to the 10-year interval.

The difference is in the increase in probability of not detecting a leak in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the 3-year interval value, as described in Section 4.3. The results for this calculation are presented in Table 5.3-2.

42

TABLE 5.3-1 PBAPS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 1 IN 10 YEAR ILRT FREQUENCY ACCIDENT DESCRIPTION PERSON- EPRIMETHODOLOGY EPRIMETHODOLOGY CHANGE DUE TO CLASSES REM PLUS CORROSION CORROSION (CONT. (0-50 (PERSON-FREQUENCY PERSON- FREQUENCY PERSON-RELEASE MILES) REMNR) 111 (1NR) REMNR (1NR) REMNR TYPE)

(0-50 MILES) (0-50 MILES) 1 Containment Intact <2l 1.22E+04 1.28E-06 1.55E-02 1.27E-06 1.55E-02 -2.66E-05 2 Large Isolation Failures 7.31E+06 6.09E-09 4.45E-02 6.09E-09 4.45E-02 -

(Failure to Close) 3a Small Isolation Failures 1.22E+05 1.10E-07 1.34E-02 1.10E-07 1.34E-02 -

(liner breach) 3b Large Isolation Failures 1.22E+06 2.75E-08 3.35E-02 2.97E-08 3.61E-02 2.66E-03 (liner breach) 7 Failures Induced by 4.95E+06 2.18E-06 1.08E+01 2.18E-06 1.08E+01 -

Phenomena (Early and Late) 8 Containment Bypass 7.31 E+06 9.34E-08 6.82E-01 9.34E-08 6.82E-01 -

(Interfacing System LOCA)

CDF All CET end states 3.69E-06 11.58 3.69E-06 11.58 2.63E-03

<1> Only release Classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.

The additional frequency added to Class 3b is subtracted from Class 1 and the population dose rates are recalculated. This results in a small reduction to the Class 1 dose rate and an increase to the Class 3b dose rate.

<2> Characterized as 1La 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.

43

TABLE 5.3-2 PBAPS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 1 IN 15 YEAR ILRT FREQUENCY ACCIDENT DESCRIPTION PERSON- EPRIMETHODOLOGY EPRIMETHODOLOGY CHANGE DUE TO CLASSES REM PLUS CORROSION CORROSION (CONT. (0-50 (PERSON-FREQUENCY PERSON- FREQUENCY PERSON-RELEASE MILES) REMNR) 111 (1NR) REMNR (1NR) REMNR TYPE)

(0-50 MILES) (0-50 MILES) 1 Containment Intact <2l 1.22E+04 1.21 E-06 1.47E-02 1.20E-06 1.46E-02 -6.16E-05 2 Large Isolation Failures 7.31 E+06 6.09E-09 4.45E-02 6.09E-09 4.45E-02 -

(Failure to Close) 3a Small Isolation Failures 1.22E+05 1.65E-07 2.01E-02 1.65E-07 2.01E-02 -

(liner breach) 3b Large Isolation Failures 1.22E+06 4.13E-08 5.02E-02 4.64E-08 5.64E-02 6.16E-03 (liner breach) 7 Failures Induced by 4.95E+06 2.18E-06 1.08E+01 2.18E-06 1.08E+01 -

Phenomena(Earlyand Late) 8 Containment Bypass 7.31 E+06 9.34E-08 6.82E-01 9.34E-08 6.82E-01 -

(Interfacing System LOCA)

CDF All CET end states 3.69E-06 11.60 3.69E-06 11.61 6.10E-03

<1> Only release Classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.

The additional frequency added to Class 3b is subtracted from Class 1 and the population dose rates are recalculated. This results in a small reduction to the Class 1 dose rate and an increase to the Class 3b dose rate.

<2> Characterized as 1La 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.

44

5.4 STEP 4 - DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY Regulatory Guide 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of core damage frequency (CDF) below 1E-06/yr and increases in LERF below 1E-07/yr, and small changes in LERF as below 1E-06/yr. Because the ILRT for PBAPS has only a minor impact on CDF, the relevant metric is LERF.

For PBAPS, 100% of the frequency of Class 3b sequences can be used as a conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI guidance methodology and the NRC SE). Based on the original 3-in-10 year test interval assessment from Table 5.2-2, the Class 3b frequency is 8.65E-09/yr, which includes the corrosion effect of the containment liner. Based on a ten-year test interval from Table 5.3-1, the Class 3b frequency is 2.97E-08/yr; and, based on a fifteen-year test interval from Table 5.3-2, it is 4.64E-08/yr. Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years (including corrosion effects) is 3. 78E-08/yr. Similarly, the increase in LERF due to increasing the interval from 1O to 15 years (including corrosion effects) is 1.67E-08/yr. As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology), the estimated change in LERF is well within Region Ill of Figure 4 of Reference [4] (i.e., the acceptance criteria for very small changes in LERF) when comparing the 15 year results to the original 3-in-1 O year requirement.

5.5 STEP 5 - DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY Another parameter that 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 and, consistent with the EPRI guidance, the small isolation failures (Class 3a). The conditional part of the definition is conditional given a severe accident (i.e., core damage).

45

The change in CCFP can be calculated by using the method specified in the EPRI methodology

[3]. The NRC SE has noted a change in CCFP of <1.5% as the acceptance criterion to be used as the basis for showing that the proposed change is consistent with the defense-in-depth philosophy.

Table 5.5-1 shows the CCFP values that result from the assessment for the various testing intervals including corrosion effects in which the flaw rate is assumed to double every five years.

TABLE 5.5-1 PBAPS ILRT CONDITIONAL CONTAINMENT FAILURE PROBABILITIES CCFP CCFP CCFP 3IN10 YRS 1IN10YRS l'.'\CCFP1s-3 l'.'\CCFP1s-10 1IN15 YRS 61.94% 62.51% 62.97% 1.02% 0.45%

CCFP = [1 - (Class 1 frequency + Class 3a frequency)/CDF] x 100%

The change in CCFP of about 1% as a result of extending the test interval to 15 years from the original 3-in-10 year requirement is judged to be relatively insignificant, and is less than the NRC SE acceptance criteria of< 1.5%.

5.6

SUMMARY

OF INTERNAL EVENTS RESULTS Table 5.6-1 summarizes the internal events results of this ILRT extension risk assessment for PBAPS. The results between the 3-in-10 year interval and the 15 year interval compared to the acceptance criteria are then shown in Table 5.6-2, and it is demonstrated that the acceptance criteria are met.

46

TABLE5.6-1 PBAPS ILRT CASES:

BASE, 3 TO 10, AND 3 TO 15 YR EXTENSIONS (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD)

EPRI DOSE BASE CASE EXTEND TO EXTEND TO CLASS PER-REM 3IN10YEARS 1IN10 YEARS 1IN15 YEARS CDF PERSON- CDF PERSON- CDF PERSON-(1NR) REMNR (1NR) REMNR (1NR) REMNR 1 1.22E+04 1.37E-06 1.67E-02 1.27E-06 1.55E-02 1.20E-06 1.46E-02 2 7.31E+06 6.09E-09 4.45E-02 6.09E-09 4.45E-02 6.09E-09 4.45E-02 3a 1.22E+05 3.31E-08 4.02E-03 1.10E-07 1.34E-02 1.65E-07 2.01E-02 3b 1.22E+06 8.65E-09 1.05E-02 2.97E-08 3.61E-02 4.64E-08 5.64E-02 7 4.95E+06 2.18E-06 1.08E+01 2.18E-06 1.08E+01 2.18E-06 1.08E+01 8 7.31E+06 9.34E-08 6.82E-01 9.34E-08 6.82E-01 9.34E-08 6.82E-01 Total 3.69E-06 11.55 3.69E-06 11.58 3.69E-06 11.61 ILRT Dose Rate 1.45E-02 4.95E-02 7.65E-02 (person-rem/yr) from 3a and 3b Delta From 3 yr --- 3.38E-02 5.99E-02 Total Dose From 10 yr --- --- 2.61E-02 Rate<1>

3b Frequency (LERF) 8.65E-09 2.97E-08 4.64E-08 Delta 3b From 3 yr --- 2.11E-08 3.78E-08 LERF From 10 yr --- --- 1.67E-08 CCFP% 61.94% 62.51% 62.97%

Delta From 3 yr --- 0.57% 1.02%

CCFP%

From 10 yr --- --- 0.45%

<1> The overall difference in total dose rate is less than the difference of only the 3a and 3b categories between two testing intervals. This is due to the fact that the Class 1 person-rem/yr decreases when extending the ILRT frequency.

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TABLE 5.6-2 PBAPS ILRT EXTENSION COMPARISON TO ACCEPTANCE CRITERIA Figure of Merit-> .1LERF .1Person-rem/yr .1CCFP 3.78E-8/yr 5.99E-02/yr (0.52%) 1.02%

Acceptance <1.0E-6/yr <1.0 person-rem/yr <1.5%

Criteria or<1.0%

5.7 EXTERNAL EVENTS CONTRIBUTION Since the risk acceptance guidelines in RG 1.174 are intended for comparison with a full-scope assessment of risk, including internal and external events, a bounding analysis of the potential impact from external events is presented here.

External hazards were evaluated in the PBAPS Individual Plant Examination of External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20, Supplement 4)

[20]. The IPEEE Program was a one-time review of external hazard risk and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks.

The results of the PBAPS IPEEE study are documented in the PBAPS IPEEE Main Report [21]

and related correspondence. The primary areas of external event evaluation at PBAPS were internal fire and seismic. The internal fire events were addressed by using a modified version of the EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology [22] and the seismic evaluations were performed in accordance with the EPRI Seismic Margins Analysis (SMA) methodology [23]. As such, there are no comprehensive CDF and LERF values available from the IPEEE to support the EPU risk assessment.

However, since the performance of the IPEEE, a Fire PRA was performed. The EPRI FIVE Methodology [22] and Fire PRA Implementation Guide (FPRAIG) [24] screening approaches, EPRI Fire Events Database [25] and plant specific data were used in this 2002 study to develop the PBAPS Fire PRA. An update to that Fire PRA model was performed in 2007 that included explicit analysis of the main control room (MCR) and cable spreading room (CSR) that had previously not been included. The ignition frequencies for the MCR and CSR were developed using the guidance 48

in NUREG/CR-6850 [26]. The Fire PRA model was also integrated with the most recent internal events models as part of the 2007 update.

Additionally, bounding seismic CDF values from the NRC have been made public as part of the development of a generic issue report. Referencing the Risk Assessment for NRC Gl-199 [27],

Table D-1 lists the postulated core damage frequencies using the updated 2008 USGS Seismic Hazard Curves. The weakest link model using the curve for PBAPS resulted in a CDF of 2.40E-05/yr. This value is utilized for the bounding external events assessment provided here.

In addition to internal fires and seismic events, the PBAPS IPEEE analysis of high winds, floods, and other (HFO) external hazards was accomplished by reviewing the plant environs against regulatory requirements regarding these hazards. Since both PBAPS units were designed (with construction started) prior to the issuance of the 1975 Standard Review Plan (SRP) criteria, PECO

[now Exelon] performed a plant hazard and design information review for conformance with the SRP criteria. HFO events were screened out by compliance with the 1975 SRP criteria [28]. As such, these hazards were determined in the PBAPS IPEEE to be negligible contributors to overall plant risk.

5.7.1 PBAPS Fire Risk Discussion Although a quantifiable Fire PRA model exists for PBAPS, this model has not been approved for general use in quantified risk applications because there are several areas of conservatism in the current treatment that result in skewing the total reported CDF towards the upper bound.

While the fire analysis did yield a CDF, the intent of the analysis was to identify the most risk significant fire areas in the plant using a screening process and by calculating conservative core damage frequencies for fire scenarios. The screening attributes of the fire PRA are summarized below.

Attributes of Fire PRA Fire PRAs are useful tools to identify design or procedural items that could be clear areas of focus for improving the safety of the plant. Fire PRAs use a structure and quantification technique similar to that used in the internal events PRA.

Historically, since less attention has been paid to fire PRAs, conservative modeling is common in a number of areas of the fire analysis to provide a "bounding" methodology for fires. This concept is 49

contrary to the base internal events PRA which has had more analytical development and is closer to a realistic assessment (i.e., not conservative) of the plant.

There are a number of fire PRA topics involving technical inputs, data, and modeling that prevent the effective comparison of the calculated core damage frequency figure of merit between the internal events PRA and the fire PRA. These areas are identified as follows:

Initiating Events: The frequency of fires and their severity are generally conservatively overestimated. A revised NRC fire events database indicates the trend toward both lower frequency and less severe fires. This trend reflects the improved housekeeping, reduction in transient fire hazards, and other improved fire protection steps at nuclear utilities. The database used in the PBAPS fire assessment used significantly older data that is conservative compared to more current data.

System Response: Fire protection measures such as sprinklers, C02 , and fire brigades may be given minimal (conservative) credit in their ability to limit the spread of a fire. Therefore, the severity of the fire and its impact on requirements is exacerbated.

In addition, cable routings are typically characterized conservatively because of the lack of data regarding the routing of cables or the lack of the analytic modeling to represent the different routings. This leads to limited credit for balance of plant systems that are extremely important in CDF mitigation.

Sequences: Sequences may subsume a number of fire scenarios to reduce the analytic burden. The subsuming of initiators and sequences is done to envelope those sequences included.

This causes additional conservatism.

Fire Modeling: Fire damage and fire propagation are conservatively characterized. Fire modeling presents bounding approaches regarding the fire immediate effects (e.g., all cables in a tray are always failed for a cable tray fire) and fire propagation.

The fire PRA is subject to more modeling uncertainty than the internal events PRA evaluations.

While the fire PRA is generally self-consistent within its calculational framework, the fire PRA calculated quantitative risk metric does not compare well with internal events PRAs because of the number of conservatisms that have been included in the fire PRA process. Therefore, the use of the fire PRA figure of merit as a reflection of CDF may be inappropriate. Any use of fire PRA 50

results and insights should properly reflect consideration of the fact that the "state of the technology" in fire PRAs is less evolved than the internal events PRA.

Relative modeling uncertainty is expected to narrow substantially in the future as more experience is gained in the development and implementation of methods and techniques for modeling fire accident progression and the underlying data.

In any event, the reported fire PRA CDF value is 4.4E-5/yr or approximately a factor of 11.9 higher than the current internal events CDF values. The fire CDF is judged to be very conservative given the methods employed in developing the fire PRA for Peach Bottom when compared to the best estimate CDF and LERF values obtained from the internal events models. Given this, it is reasonable to assume that the total impact from fire risk is bounded by assuming a factor of 11.9 additional contribution to CDF compared to the internal events evaluation alone. A quantifiable LERF Fire PRA model is not available for PBAPS, therefore a LERF estimate must also be developed. The internal events LERF value for the PBAPS EPU model is 4.74E-7/yr. However, much of the contribution is from ISLOCA and ATWS scenarios which would not contribute as much to the Fire PRA results. In fact, the PBAPS Fire PRA excludes ATWS scenarios as do most Fire PRA models. This is consistent with the guidance provided in NUREG/CR-6850 [26].

Sequences associated with events that, while it is possible that the fire could cause the event, a low-frequency argument can be justified. For example, it can often be easily demonstrated that anticipated transient without scram (ATWS) sequences do not need to be treated in the Fire PRA because fire-induced failures will almost certainly remove power from the control rods (resulting in a trip), rather than cause a "failure-to-scram" condition. Additionally, fire frequencies multiplied by the independent failure-to-scram probability can usually be argued to be small contributors to fire risk.

From the PBAPS EPU internal events model, ATWS scenarios contribute 23.0% to the LERF total and ISLOCA scenarios contribute 19.7% to the LERF total. Therefore, a better estimate of the LERF from scenarios more applicable to the fire PRA results would be about 43% less than the total internal events value of 4.74E-7/yr, or 2.72E-07/yr. If the multiplier of 11.9 is used on this LERF value, then the total LERF estimate for the Fire PRA model is 3.22E-06/yr.

The assumptions regarding the CDF and LERF values provided above are used to provide insight into the impact of the total external hazard risk on the conclusions of this ILRT risk assessment.

5.7.2 PBAPS Seismic Risk Discussion A quantifiable seismic PRA model for PBAPS has not yet been approved for general use in risk applications. However, PBAPS was one of the reference plants in NUREG/CR-4550 [29], and in 51

that report the seismic CDF for PBAPS was reported to be 7.66E-05/yr using the LLNL hazard curve and 3.02E-06/yr using the EPRI hazard curve. However, more recent information is available from the NRC. Referencing the Risk Assessment for NRC Gl-199 [27], Table D-1 lists the postulated core damage frequencies using the updated 2008 USGS Seismic Hazard Curves.

The weakest link model using the curve for PBAPS resulted in a CDF of 2.40E-05/yr. Given this, it is reasonable to assume that the total impact from seismic risk can be approximated by assuming a factor of 6.5 additional contribution to CDF compared to the internal events evaluation alone.

Similarly, no LERF information is available, but using the same approach that was done for fire and using a base LERF value of 2. 72E-07/yr and multiplying by 6.5 for seismic, then the total LERF estimate for the seismic PRA model is 1. 76E-06/yr.

The assumptions regarding the CDF and LERF values provided above are used to provide insight into the impact of the total external hazard risk on the conclusions of this ILRT risk assessment.

5.7.3 Other External Events Discussion In addition to internal fires and seismic events, the PBAPS IPEEE Submittal analyzed a variety of other external hazards:

• High Winds/Tornadoes

• External Floods

• Transportation and Nearby Facility Accidents The PBAPS IPEEE analysis of high winds, tornadoes, external floods, transportation accidents, and nearby facility accidents was accomplished by reviewing the plant environs against regulatory requirements regarding these hazards. Based upon this review, it was concluded that PBAPS meets the applicable NRC Standard Review Plan requirements and therefore has an acceptably low risk with respect to these hazards.

Based on the other external events being low risk contributors and the fact that the ILRT extension would not significantly change the risk from these types of events, the increase in the PBAPS other external events risk due to the ILRT extension is much less than that calculated for internal events.

5.7.4 External Events Impact Summary In summary, the combination of the seismic and fire CDF values described above results in an external events bounding risk estimate of 6.8E-05/yr, which is 18.4 times higher than the internal 52

events CDF (3.69E-06/yr). Since the change in risk for the ILRT risk assessment is a function of CDF, then this multiplier will be used for the initial bounding assessment for the external events impact.

Table 5.7-1 summarizes the estimated bounding external events CDF contribution for PBAPS.

TABLE 5.7-1 PBAPS EXTERNAL EVENTS CONTRIBUTOR

SUMMARY

EXTERNAL EVENT INITIATOR GROUP CDF (1/yr)

Seismic 2.4E-05 Internal Fire 4.4E-05 High Winds Screened Other Hazards Screened Total (for initiators with CDF available) 6.8E-05 Internal Events CDF 3.7E-06 Bounding External Events Multiplier 18.4 From Table 5.7-1, the external events multiplier for PBAPS is conservatively estimated to be 18.4.

5.7.5 External Events Impact on ILRT Extension Assessment The EPRI Category 3b frequency for the 3-per-10 year, 1-per-10 year, and 1-per-15 year ILRT intervals are shown in Table 5.6-1 as 8.65E-09/yr, 2.97E-08/yr, and 4.64E-08/yr, respectively.

Using an external events multiplier of 18.4 for PBAPS, the change in the LERF risk measure due to extending the ILRT from 3-per-10 years to 1-per-15 years, including both internal and external hazards risk, is estimated as shown in Table 5.7-2.

53

TABLE 5.7-2 PBAPS 38 (LERF/YR) AS A FUNCTION OF ILRT FREQUENCY FOR INTERNAL AND EXTERNAL EVENTS (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD) 38 38 38 LERF FREQUENCY FREQUENCY FREQUENCY INCREASE111 (3-PER-10 YR (1-PER-10 (1-PER-15 ILRT) YEAR ILRT) YEAR ILRT)

Internal Events 8.65E-09 2.97E-08 4.64E-08 3.78E-08 Contribution External Events Contribution (Internal 1.59E-07 5.45E-07 8.52E-07 6.93E-07 Events x 18.4)

Combined (Internal +

1.67E-07 5.75E-07 8.98E-7 7.31E-07 External)

<1> Associated with the change from the baseline 3-per-10 year frequency to the proposed 1-per-15 year frequency.

The other acceptance criteria for the ILRT extension risk assessment can be similarly derived using the multiplier approach. The results between the 3-in-10 year interval and the 15 year interval compared to the acceptance criteria are shown in Table 5.7-3. As can be seen, the impact from including the external events contributors would not change the conclusion of the risk assessment. That is, the acceptance criteria are all met such that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years has been demonstrated to be small. Note that a bounding analysis for the total LERF contribution follows Table 5.7-3 to demonstrate that the total LERF value for PBAPS is less than 1.0E-05/yr consistent with the requirements for a "Small Change" in risk of the RG 1.174 acceptance guidelines.

54

TABLE 5.7-3 COMPARISON TO ACCEPTANCE CRITERIA INCLUDING EXTERNAL EVENTS CONTRIBUTION FOR PBAPS Contributor t.LERF t.Person-rem/yr t.CCFP Internal Events 3.78E-8/yr 5.99E-02/yr (0.52%) 1.02%

External Events 6.93E-7/yr 1.10E+OO/yr (0.52%) 1.02%

Total 7.31E-7/yr 1.16E+OO/yr (0.52%) 1.02%

Acceptance Criteria <1.0E-6/yr <1.0 person-rem/yr <1.5%

.Q! <1.0%

The 7.31 E-07/yr increase in LERF due to the combined internal and external events from extending the ILRT frequency from 3-per-10 years to 1-per-15 years falls within Region II between 1.0E-7 to 1.0E-6 per reactor year ("Small Change" in risk) of the RG 1.174 acceptance guidelines.

Per RG 1.174, when the calculated increase in LERF due to the proposed plant change is in the "Small Change" range, the risk assessment must also reasonably show that the total LERF is less than 1.0E-5/yr. Similar bounding assumptions regarding the external event contributions that were made above are used for the total LERF estimate.

From Table 4.2-1, the total LERF due to postulated internal event accidents is 4.74E-07/yr for PBAPS. As discussed in Sections 5.7.1, the total LERF estimate for the Fire PRA model is 3.22E-06/yr. As discussed in Sections 5.7.2, the total LERF estimate for the Seismic PRA model is 1.76E-06/yr. The total LERF values for PBAPS are then shown in Table 5.7-4.

55

TABLE 5.7-4 IMPACT OF 15-YR ILRT EXTENSION ON LERF FOR PBAPS LERF CONTRIBUTOR (1NR)

Internal Events LERF 4.74E-07 Fire LERF 3.22E-06 Seismic LERF 1.76E-06 Internal Events LERF due to 4.64E-08 ILRT (at 15 years) <1l External Events LERF due to 8.51E-07 ILRT (at 15 years) <1l [Internal Events LERF due to ILRT

• 18.4]

Total 6.36E-06/yr

<1> Including age adjusted steel liner corrosion likelihood as reported in Table 5.7-2.

As can be seen, the estimated upper bound LERF for PBAPS is estimated as 6.36E-06/yr. This value is less than the RG 1.174 requirement to demonstrate that the total LERF due to internal and external events is less than 1.0E-05/yr.

5.8 CONTAINMENT OVERPRESSURE IMPACTS ON CDF As indicated in the EPRI ILRT report [3], in general, CDF is not significantly impacted by an extension of the ILRT interval. However, plants that rely on containment overpressure for net positive suction head (NPSH) for emergency core coolant system (ECCS) injection for certain accident sequences may experience an increase in CDF.

For PBAPS, plant modifications made in support of the EPU effort eliminate reliance on containment accident pressure (CAP) credit to provide adequate net positive suction head (NPSH) margin. Rather than proposing an increased reliance on CAP credit, PBAPS has decided to make plant modifications and apply methodology changes that will increase NPSH margin for these pumps to the extent that reliance on CAP can be eliminated. The modifications include: (1) a residual heat removal (RHR) system heat exchanger cross-tie modification; (2) HPSW system cross-tie modification; and (3) condensate storage tank modifications. The EPU License Amendment Request has been approved by the NRC [30], and the proposed plant modifications will be in place on Unit 2 following the 2014 refueling outage, and on Unit 3 following the 2015 refueling outage.

56

However, since the modifications do rely on successful alignment of the cross-tie to reduce the need for CAP, the PBAPS EPU model does include scenarios where CDF could be impacted due to an increase in the likelihood for a loss of CAP resulting from .a pre-existing leak from containment and operators failing to align the RHR cross-tie in sufficient time for the scenarios of interest. The analysis of these scenarios was included in the EPU risk assessment as part of the License Amendment Request for EPU [31]. Per the EPRI guidance, as a first order estimate of the impact, it can be assumed that the EPRI Class 3b contribution would lead to loss of containment overpressure. For the PBAPS EPU model, applying that guidance would mean that the current containment isolation failure logic can be increased by the Class 3b frequency at 15 years (i.e.,

0.0023

• 5.0 =0.0115) to estimate a bounding increase in CDF. With this increase applied to the containment isolation failure probability in the PBAPS EPU PRA model, the CDF increases from 3.6946E-6/yr to 3.7023E-06/yr representing an increase of just 7.70E-09/yr. This is considered negligible, and as such the focus on the LERF figure of merit for this application is appropriate for PBAPS.

57

6.0 SENSITIVITIES 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS The results in Tables 5.2-2, 5.3-1, and 5.3-2 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. In any event, sensitivity cases were developed to gain an understanding of the sensitivity of the results to the key parameters in the corrosion risk analysis.

The time for the flaw likelihood to double was adjusted from every five years to every two and every ten years. The failure probabilities for the wall and basemat were increased and decreased by an order of magnitude. The total detection failure likelihood was adjusted from 10% to 15% and 5%. The results are presented in Table 6.1-1. In every case, the impact from including the corrosion effects is 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 1.43E-07/yr. The results indicate that even with very conservative assumptions, the conclusions from the base analysis would not significantly change.

TABLE 6.1-1 STEEL LINER CORROSION SENSITIVITY CASES FOR PBAPS AGE CONTAINMENT VISUAL INCREASE IN CLASS 3B FREQUENCY (STEP 3 IN BREACH INSPECTION & (LERF)

THE (STEP 4 IN THE NON-VISUAL FOR ILRT EXTENSION CORROSION CORROSION FLAWS FROM 3 IN 10 TO 1IN15 YEARS ANALYSIS) ANALYSIS) (STEP 5 IN (PER YEAR)

THE TOTAL INCREASE DUE TO CORROSION INCREASE CORROSION ANALYSIS)

Base Case Base Case Base Case 3.78E-08 4.69E-09 Doubles every (10% Wall, (10% Wall, 5 yrs 1% Basemat) 100% Basemat)

Doubles every Base Base 4.38E-08 1.0?E-08 2 yrs Doubles every Base Base 3.?0E-08 3.95E-09 10 yrs Base Base 15% Wall 3.93E-08 6.25E-09 Base Base 5%Wall 3.62E-08 3.12E-09 Base 100% Wall, Base 7.99E-08 4.69E-08 10% Basemat 58

TABLE 6.1-1 STEEL LINER CORROSION SENSITIVITY CASES FOR PBAPS AGE CONTAINMENT VISUAL INCREASE IN CLASS 3B FREQUENCY (STEP 3 IN BREACH INSPECTION & (LERF)

THE (STEP 4 IN THE NON-VISUAL FOR ILRT EXTENSION CORROSION CORROSION FLAWS FROM 3 IN 10 TO 1IN15 YEARS ANALYSIS) ANALYSIS) (STEP 5 IN (PER YEAR)

THE TOTAL INCREASE DUE TO CORROSION INCREASE CORROSION ANALYSIS)

Base 1.0% Wall, Base 3.35E-08 4.69E-10 0.1% Basemat LOWER BOUND Doubles every 1.0%Wall, 5%Wall, 3.33E-08 2.63E-10 10 yrs 0.1% Basemat 100% Basemat UPPER BOUND Doubles every 100% Wall, 15%Wall, 1.76E-07 1.43E-07 2 yrs 10% Basemat 100% Basemat 6.2 EPRI EXPERT ELICITATION SENSITIVITY An expert elicitation was performed to reduce excess conservatisms in the data associated with the probability of undetected leaks within containment [3]. Since the risk impact assessment of the extensions to the ILRT interval is sensitive to both the probability of the leakage as well as the magnitude, it was decided to perform the expert elicitation in a manner to solicit the probability of leakage as a function of leakage magnitude. In addition, the elicitation was performed for a range of failure modes which allowed experts to account for the range of failure mechanisms, the potential for undiscovered mechanisms, inaccessible areas of the containment as well as the potential for detection by alternate means. The expert elicitation process has the advantage of considering the available data for small leakage events, which have occurred in the data, and extrapolate those events and probabilities of occurrence to the potential for large magnitude leakage events.

The basic difference in the application of the ILRT interval methodology using the expert elicitation is a change in the probability of pre-existing leakage within containment. The base case methodology uses the Jeffrey's non-informative prior for the large leak size and the expert elicitation sensitivity study uses the results from the expert elicitation. In addition, given the 59

relationship between leakage magnitude and probability, larger leakage that is more representative of large early release frequency can be reflected. For the purposes of this sensitivity, the same leakage magnitudes that are used in the base case methodology (i.e., 10La for small and 100La for large) are used here. Table 6.2-1 illustrates the magnitudes and probabilities of a pre-existing leak in containment associated with the base case and the expert elicitation statistical treatments.

These values are used in the ILRT interval extension for the base methodology and in this sensitivity case. Details of the expert elicitation process, including the input to expert elicitation as well as the results of the expert elicitation, are available in the various appendices of EPRI 1018243 [3].

TABLE 6.2-1 EPRI EXPERT ELICITATION RESULTS LEAKAGE SIZE (LA) BASE CASE MEAN EXPERT ELICITATION PERCENT PROBABILITY OF MEAN PROBABILITY REDUCTION OCCURRENCE OF OCCURRENCE [3]

10 9.2E-03 3.88E-03 58%

100 2.3E-03 2.47E-04 89%

The summary of results using the expert elicitation values for probability of containment leakage is provided in Table 6.2-2. As mentioned previously, probability values are those associated with the magnitude of the leakage used in the base case evaluation (10La for small and 100La for large).

The expert elicitation process produces a relationship between probability and leakage magnitude in which it is possible to assess higher leakage magnitudes that are more reflective of large early releases; however, these evaluations are not performed in this particular study.

The net effect is that the reduction in the multipliers shown above also leads to a dramatic reduction on the calculated increases in the LERF values. As shown in Table 6.2-2, the increase in the overall value for LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3 to 15 years is just 8.24E-09/yr. Similarly, the increase due to increasing the interval from 1O to 15 years is just 4.36E-09/yr. As such, if the expert elicitation probabilities of occurrence are used instead of the non-informative prior estimates, the change in LERF is well within the range of a "very small" change in risk when compared to the current 1-in-10, or baseline 3-in-10 year requirement. Additionally, as shown in Table 6.2-2, the increase in dose rate and CCFP are similarly reduced to much smaller values. The results of this sensitivity study are judged to be more indicative of the actual risk associated with the ILRT extension than the results from the 60

assessment as dictated by the values from the EPRI methodology [3], and yet are still conservative given the assumption that all of the Class 3b contribution is considered to be LERF.

TABLE 6.2-2 PBAPS ILRT CASES:

3IN10 (BASE CASE), 1IN10, AND 1IN15 YR INTERVALS (BASED ON EPRI EXPERT ELICITATION LEAKAGE PROBABILITIES)

EPRI DOSE BASE CASE EXTEND TO EXTEND TO CLASS PER-REM 3IN10YEARS 1IN10YEARS 1IN15 YEARS CDF PERSON- CDF PERSON- CDF PERSON-(1NR) REMNR (1NR) REMNR (1NR) REMNR 1 1.22E+04 1.40E-06 1.70E-02 1.36E-06 1.66E-02 1.34E-06 1.62E-02 2 7.31 E+06 6.09E-09 4.45E-02 6.09E-09 4.45E-02 6.09E-09 4.45E-02 3a 1.22E+05 1.39E-08 1.70E-03 4.65E-08 5.64E-03 6.97E-08 8.48E-03 3b 1.22E+06 1.27E-09 1.54E-03 5.15E-09 6.25E-03 9.51E-09 1.16E-02 7 4.95E+06 2.18E-06 1.08E+01 2.18E-06 1.08E+01 2.18E-06 1.08E+01 8 7.31 E+06 9.34E-08 6.82E-01 9.34E-08 6.82E-01 9.34E-08 6.82E-01 Total 3.69E-06 11.54 3.69E-06 11.55 3.69E-06 11.55 ILRT Dose Rate from 3.24E-03 1.19E-02 2.00E-02 3a and 3b Delta From 3 yr --- 8.22E-03 1.60E-02 Total Dose From 10 yr --- --- 7.BOE-03 Rate<1>

3b Frequency (LERF) 1.27E-09 5.15E-09 9.51E-09 Delta 3b From 3 yr - 3.88E-09 8.24E-09 LERF From 10 yr --- --- 4.36E-09 CCFP% 61.74% 61.85% 61.97%

Delta From 3 yr --- 0.10% 0.22%

CCFP%

From 10 yr -- --- 0.12%

<1 > The overall difference in total dose rate is less than the difference of only the 3a and 3b categories between two testing intervals. This is due to the fact that the Class 1 person-rem/yr decreases when extending the ILRT frequency.

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7.0 CONCLUSION

S Based on the results from Section 5 and the sensitivity calculations presented in Section 6, the following conclusions regarding the assessment of the plant risk are associated with permanently extending the Type A ILRT test frequency to fifteen years:

• Reg. Guide 1.174 [4] provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Reg. Guide 1.174 defines "very small" changes in risk as resulting in increases of GDF below 1.0E-06/yr and increases in LERF below 1.0E-07/yr. "Small" changes in risk are defined as increases in GDF below 1.0E-05/yr and increases in LERF below 1.0E-06/yr. Since the ILRT extension was demonstrated to have negligible impact on GDF for PBAPS, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval for the base case with corrosion included is 3.78E-08/yr (see Table 5.6-1). In using the EPRI Expert Elicitation methodology, the change is estimated as 8.24E-09/yr (see Table 6.2-2). Both of these values fall within the very small change region of the acceptance guidelines in Reg. Guide 1.174.

• The change in dose risk for changing the Type A test frequency from three-per-ten years to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all internal events accident sequences for PBAPS, is 5.99E-02 person-rem/yr (0.52%) using the EPRI guidance with the base case corrosion included (Table 5.6-1). The change in dose risk drops to 1.60E-02 person-rem/yr (0.14%) when using the EPRI Expert Elicitation methodology (Table 6.2-2). The values calculated per the EPRI guidance are all lower than the acceptance criteria of ::>1.0 person-rem/yr or

<1.0% person-rem/yr defined in Section 1.3.

• The increase in the conditional containment failure frequency from the three in ten year interval to one in fifteen years including corrosion effects using the EPRI guidance (see Section 5.5) is 1.02%. This value drops to 0.22% using the EPRI Expert Elicitation methodology (see Table 6.2-2). Both of these values are below the acceptance criteria of less than 1.5% defined in Section 1.3.

• To determine the potential impact from external events, a bounding assessment from the risk associated with external events was performed utilizing available information.

As shown in Table 5.7-2, the total increase in LERF due to internal events and the bounding external events assessment is 7.31 E-07/yr. This value is in Region II of the Reg. Guide 1.174 acceptance guidelines.

• As shown in Table 5.7-4, the same bounding analysis indicates that the total LERF from both internal and external risks is 6.36E-06/yr which is less than the Reg. Guide 1.174 limit of 1. OE-05/yr given that the .b.LERF is in Region 11 (small change in risk).

• Including age-adjusted steel liner corrosion effects in the ILRT assessment was demonstrated to be a small contributor to the impact of extending the ILRT interval for PBAPS.

Therefore, increasing the ILRT interval on a permanent basis to a one-in-fifteen year frequency is not considered to be significant since it represents only a small change in the PBAPS risk profiles.

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Previous Assessments The NRC in NUREG-1493 [6] has previously concluded the following:

• Reducing the frequency of Type A tests (ILRTs) from three per 1O years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

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

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

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8.0 REFERENCES

[1] Nuclear Energy Institute, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, NE/ 94-01, Revision 3-A, July 2012.

[2] Electric Power Research Institute, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI TR-104285, August 1994.

[3] Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243.

[4] U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 2, May 2011.

[5] Letter from Mr. C. H. Cruse (Constellation Nuclear, Calvert Cliffs Nuclear Power Plant) to U.S. Nuclear Regulatory Commission, Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Accession Number ML020920100, March 27, 2002.

[6] U.S. Nuclear Regulatory Commission, Performance-Based Containment Leak-Test Program, NUREG-1493, September 1995.

[7] U.S. Nuclear Regulatory Commission, Final Safety Evaluation for Nuclear Energy Institute (NE/) 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), Accession Number ML081140105, June 25, 2008.

[8] Evaluation of Severe Accident Risks: Peach Bottom, Unit 2, Main Report NUREG/CR-4551, SAND86-1309, Volume4, Revision 1, Part 1, December 1990.

[9] ERIN Engineering and Research, Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAM', EPRI TR-105189, Final Report, May 1995.

[10] Oak Ridge National Laboratory, Impact of Containment Building Leakage on LWR Accident Risk, NUREG/CR-3539, ORNL/TM-8964, April 1984.

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

[12] U.S. Nuclear Regulatory Commission, Technical Findings and Regulatory Analysis for Generic Safety Issue 11.E.4.3 (Containment Integrity Check), NUREG-1273, April 1988.

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

[14] U.S. Nuclear Regulatory Commission, Reactor Safety Study, WASH-1400, October 1975.

[15] U.S. Nuclear Regulatory Commission, Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG-1150, December 1990.

[16] Exelon Risk Management Team, Peach Bottom PRA Summary Notebook, PB209A and PB309A Models, PB-PRA-013, Revision 3, July 2010.

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[17] Exelon Risk Management Team, Peach Bottom Application Specific Model for EPU, PB-ASM-001, June 2011.

[18] Exelon Risk Management Team, Peach Bottom 50 Mile Regional Population Estimate for 2030, PB-MISC-016, September 2014.

[19] Exelon Risk Management Team, Risk Assessment for Peach Bottom Unit 2 to Support ILRT (Type A) Interval Extension Request, PB-LAR-003, Revision 1, May 2009.

Attachment 4 to License Amendment Request - Type A Test Extension, August 28, 2009. ADAMS Accession Number ML092440053.

[20] NRC Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54({), Supplement 4, June 28, 1991.

[21] PECO Energy Co., Peach Bottom Atomic Power Station, Units 2 and 3, Individual Plant Examination for External Events, Main Report, May 1996.

[22] Professional Loss Control, Inc., Fire-Induced Vulnerability Evaluation (FIVE)

Methodology Plant Screening Guide, EPRI TR-100370, Electric Power Research Institute, Final Report, April 1992.

[23] NTS Engineering, et. al., A Method for Assessment of Nuclear Power Plant Seismic Margin, EPRI NP-6041, Electric Power Research Institute, Final Report, August 1991.

[24] W.J. Parkinson, et. al., Fire PRA Implementation Guide, EPRI TR-105928, Electric Power Research Institute, December 1995.

[25] NSAC/179L, Electric Power Research Institute, Fire Events Database for U.S. Nuclear Power Plants, Rev. 1, January, 1993.

[26] EPRl/NRC-RES, Fire PRA Methodology for Nuclear Power Facilities, EPRI 1011989, NUREG/CR-6850, Final Report, September 2005.

[27] U.S. Nuclear Regulatory Commission, Generic Issue 199 (Gl-199) Implications of Updated Probabilistic Seismic Hazard Estimates In Central And Eastern United States on Existing Plants Safety/Risk Assessment, August 2010.

[28] Letter from Bartholomew C. Buckley (USNRC) to James A. Hutton (PECO Energy Company), Review of Peach Bottom Atomic Power Station, Units 2 and 3, Individual Plant Examination of External Events Submittal (TAC Nos. M83657 and MA83658),

November 22, 1999 (Docket Nos. 50-277 and 50-278).

[29] Sandia National Laboratories, Analysis of Core Damage Frequency: Peach Bottom Unit 2 External Events, NUREG/CR-4550, Vol. 4, Rev. 1, Part 3, December 1990.

[30] U.S. Nuclear Regulatory Commission, Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendments RE: Extended Power Uprate (TAC Nos. ME9631 and ME9632), August 2014. ADAMS Accession Number ML14133A046.

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[31] Exelon Risk Management Team, Extended Power Uprate (EPU) Risk Assessment for Peach Bottom, PB-LAR-008, Revision 1, May 2012. Attachment 12 to License Amendment Request - Extended Power Uprate, September 28, 2012. ADAMS Accession Number ML12286A017.

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Appendix A PRA Technical Adequacy 67

A.1 OVERVIEW A technical Probabilistic Risk Assessment (PRA) analysis is presented in this report to help support an extension of the PB2 and PB3 containment Type A test integrated leak rate test (ILRT) interval to fifteen years.

The analysis follows the guidance provided in Regulatory Guide 1.200, Revision 2 [A.1 ], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities." The guidance in RG-1.200 indicates that the following steps should be followed to perform this study:

1. Identify the parts of the PRA used to support the application

• SSCs, operational characteristics affected by the application and how these are implemented in the PRA model.

• A definition of the acceptance criteria used for the application.

2. Identify the scope of risk contributors addressed by the PRA model

• If not full scope (i.e. internal and external), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the model.

3. Summarize the risk assessment methodology used to assess the risk of the application

• Include how the PRA model was modified to appropriately model the risk impact of the change request.

4. Demonstrate the Technical Adequacy of the PRA

• Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

• Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

11 Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide. Provide justification to show that where specific requirements in the standard are not met, it will not unduly impact the results.

• Identify key assumptions and approximations relevant to the results used in the decision-making process.

Items 1 through 3 are covered in the main body of this report. The purpose of this appendix is to address the requirements identified in item 4 above. Each of these items (plant changes not yet incorporated into the PRA model, relevant peer review findings, consistency with applicable PRA standards and the identification of key assumptions) are discussed in the following sections.

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The risk assessment performed for the ILRT extension request is based on the current Level 1 and Level 2 PRA model representing EPU conditions. Note that for this application, the accepted methodology involves a bounding approach to estimate the change in the LERF from extending the ILRT interval. Rather than exercising the PRA model itself, it involves the establishment of separate evaluations that are linearly related to the plant CDF contribution. Consequently, a reasonable representation of the plant CDF that does not result in a LERF does not require that Capability Category 11 be met in every aspect of the modeling if the Category I treatment is conservative or otherwise does not significantly impact the results.

A discussion of the Exelon model update process, the peer reviews performed on the PBAPS models, the results of those peer reviews and the potential impact of peer review findings on the ILRT extension risk assessment are provided in Section A.2. Section A.3 provides an assessment of key assumptions and approximations used in this assessment and Section A.4 briefly summarizes the results of the PRA technical adequacy assessment with respect to this application.

A.2 PRA MODEL EVOLUTION AND PEER REVIEW

SUMMARY

A.2.1 Introduction The 2009A versions of the PBAPS PRA models are the most recent evaluations of the Unit 2 and Unit 3 risk profile at PBAPS for internal event challenges. The PBAPS PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the PBAPS PRA is based on the event tree I fault tree methodology, which is a well-known methodology in the industry.

Exelon Generation Company, LLC (Exelon) employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating Exelon nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the PBAPS PRA.

PRA Maintenance and Update The Exelon risk management process ensures that the applicable PRA model is an accurate reflection of the as-built and as-operated plants. This process is defined in the Exelon Risk Management program, which consists of a governing procedure and subordinate implementation procedures. The PRA model update procedure delineates the responsibilities and guidelines for updating the full power internal events PRA models at all operating Exelon nuclear generation 69

sites. The overall Exelon Risk Management program defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, industry operating experience, etc.),

and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, the following activities are routinely performed:

• Design changes and procedure changes are reviewed for their impact on the PRA model.

• New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.

• Maintenance unavailabilities are captured, and their impact on CDF is trended.

• Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated approximately every four years.

In addition to these activities, Exelon risk management procedures provide the guidance for particular risk management maintenance activities. This guidance includes:

• Documentation of the PRA model, PRA products, and bases documents.

• The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.

• Guidelines for updating the full power, internal events PRA models for Exelon nuclear generation sites.

• Guidance for use of quantitative and qualitative risk models in support of the On-Line Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10 CFR 50.65(a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximately 4-year cycle; longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant. The 2009A models were completed in July of 2010.

As indicated previously, RG 1.200 also requires that additional information be provided as part of the LAR submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment. Each of these items (plant changes not yet incorporated into the PRA model, relevant peer review findings, and consistency with applicable PRA Standards) will be discussed in turn in this section.

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A.2.1 PLANT CHANGES NOT YET INCORPORATED INTO THE PRA MODEL A PRA updating requirements evaluation (URE- Exelon PRA model update tracking database) is created for all issues that are identified that could impact the PRA model. The URE database includes the identification of those plant changes that could impact the PRA model.

A review of the open UREs indicates that there are no plant changes that have not yet been incorporated into the PRA model that would affect this application. Note that the PRA model is also being updated in 2014 to incorporate changes into the PRA model. Preliminary results indicate that the base case CDF and LERF values are not significantly changing such that the conclusions for this risk assessment would not change upon completion of the updates.

A.2.2 Consistency with Applicable PRA Standards Several assessments of technical capability have been made for the PBAPS internal events PRA models. These assessments are as follows and further discussed in the paragraphs below.

• An independent PRA peer review was conducted under the auspices of the BWR Owners Group in 1998, following the Industry PRA Peer Review process [A.2]. This peer review included an assessment of the PRA model maintenance and update process.

• In 2004, a gap analysis was performed to assess gaps between the peer review scope/detail of the Industry PRA Peer Review results relative to the available version of the ASME PRA Standard [A.3] and the draft version of Regulatory Guide 1.200, DG-1122 [A.4]. In 2006, an assessment of the extent to which the previously defined gaps had been addressed was performed in conjunction with a PRA model update.

• During 2005 and 2006 the PBAPS Units 2 and 3 PRA model results were evaluated in the BWR Owners Group PRA cross-comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process [A.5].

• After the completion of the most recent PRA update, an industry peer review in accordance with the combined ASME/ANS PRA Standard [A.6] and Regulatory Guide 1.200, Revision 2 [A.1] was performed in November 2010. The results of that assessment are used as the basis for the capability assessment provided in Tables A-1 and A-2.

A summary of the disposition of the 1998 Industry PRA Peer Review facts and observations (F&Os) for the PBAPS Units 2 and 3 PRA models was documented as part of the statement of PRA capability for MSPI in the PBAPS MSPI Basis Document [A.5]. As noted in that document, there were no significance level A F&Os from the peer review, and all significance level B F&Os were addressed and closed out with the completion of the PB205C and PB305C models of record.

Also noted in that submittal was the fact that, after allowing for plant-specific features, there are no MSPI cross-comparison outliers for PBAPS (refer to the third bulleted item above).

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A Gap Analysis for the 2002 PBAPS, Units 2 and 3, PRA models (PB202 and PB302, respectively) was completed in January 2004. This Gap Analysis was performed against PRA Standard RA-S-2002 [A.3] and associated NRC comments in draft regulatory guide DG-1122 [A.4], the draft version of Regulatory Guide 1.200 Revision 0. This gap analysis defined a list of 83 supporting requirements from the Standard for which potential gaps to Capability Category II of the Standard were identified. For each such potential gap, a PRA URE was documented for resolution.

A PRA model update was completed in 2006, resulting in the PB205C and PB305C updated models. In updating the PRA, changes were made to the PRA to address most of the identified gaps, as well as to address other open UREs. Following the update, an assessment of the status of the gap analysis relative to the new model and the updated requirements in Addendum A of the ASME PRA Standard concluded that 59 of the gaps were fully resolved (i.e., are no longer gaps),

and another seven were partially resolved.

As indicated above, a PRA model update was completed in 2010, resulting in the PB209A and PB309A updated models. This model was subject to a peer review in November 2010 [A. 7]. In general, the peer review results supported the high quality of the PRA model as approximately 95% of all the supporting requirements were characterized as meeting Capability Category 11 or better. Those supporting requirements that were assessed as not meeting Capability Category II are described in Table A-1 with their impact on this application noted.

A.2.3 APPLICABILITY OF PEER REVIEW FINDINGS AND OBSERVATIONS The remaining set of findings from the 2010 peer review related to the current ANS/ASME PRA Standard for internal events and internal flood associated with supporting requirements that are otherwise met at Capability Category II are described in Table A-2 with their impact on this application noted.

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 2-2 Section 2.4 documented a number of special IE-AS Assessed as meeting Capability Not significant as the PBAPS initiators based on comparisons or review. Category I. PRA model includes a full range However, it's not evident that a structured of special initiators which are approach has been performed. consistent with many BWRs (e.g. loss of SW, loss of IA, loss of RBCCW, loss of TBCCW, loss of individual 4kV ac buses, and loss of individual 125V de buses). These are sufficient to determine the ILRT impacts.

6-2 The Initiating Event NB PB-PRA-001, Rev.2 IE-B3 Assessed as meeting Capability Not significant as the PBAPS addresses grouping in Section 2.5 and Category I. PRA model includes a full range summarizes the events in Table 2.6-2. Many of initiating events which are events have been subsumed into other events comparable with many BWRs.

as discussed in Section 2.5. The subsuming is These are sufficient to based on simple statements rather than a determine the ILRT impacts.

discussion of event progression, success criteria, timing and operator action. Certain items are not even discussed, but summarized in Table 2.6-2. For example, there is no discussion of Turbine Trip without Bypass, or Pressure Regulator Fails Open or Pressure Regulator Fails Closed (except for some foot notes).

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STA TUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 2-5 ISLOCA was analyzed and documented in the IE-C14 Assessed as not met. The Not significant given that the IE notebook, but it was based on IPE and no ISLOCA update has not yet current approach is reasonably particular consideration of protective been performed. However, the conservative, and ISLOCA interlocks, relevant surveillance test, check current ISLOCA values are scenarios would not be valve, etc. The newer failure data from conservative compared to other impacted by the ILRT.

NUREG/CR-6928 could be considered. In sites that have utilized the more addition, the RHR shutdown cooling discharge detailed methodology.

line appears missing in the analysis.

6-5 The SR calls for Peach Bottom's success SC-B5 Assessed as not met. Although Not significant given that the criteria to be compared with those for other a formally documented current success criteria have similar plants. comparison has not been been validated based on plant-There is no evidence such a comparison was performed, in practice this type specific MAAP runs or other performed. of comparison is done as the comparable generic sources.

results of the model are analyzed and reviewed.

3-1 Alignment pre-initiators are included for some HR-A1 Assessed as not met. Not significant given that risk significant systems (i.e., HPCI, RCIC, several pre-initiators are LPCS, and SLC), but these were not included included in the model, and in as a result of a review of procedures and any event, the pre-initiators practices. Refer to Sections 2.3.3, 4.3, 5.1, would not be impacted by the and Appendix B of the HRA Notebook (PB- ILRT.

PRA-004).

3-3 As described in Sections 2.3.3, 4.3, 5.1,and HR-A3 Assessed as not met. Not significant given that Appendix B of the HRA Notebook (PB-PRA- several pre-initiators are 004 }, the process for the identification of included in the model. These misalignment of modeled equipment does not are sufficient to determine the address common misalignment. ILRT impacts.

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 3-4 The process described in the HRA Notebook HR-81 Assessed as not met. Not significant given that (PB-PRA-004) does not establish any rules for several pre-initiators are screening individual activities. Some System included in the model. These Notebooks (PB-PRA-005) (e.g., HPCI, RCIC, are sufficient to determine the LPCS, SLC) include pre-initiators and identify ILRT impacts.

appropriate screening rules in Section 6.1.5 but do not identify activities which might have been screened.

5-8 Table 5.1-4 of the HRA Notebook (PB-PRA- HR-02 Assessed as meeting Capability Not significant given that 004) includes a number of pre-initiators types Category I. Not all significant several pre-initiators are (e.g., flow, delta-temperature, steam leak) that pre-initiators were evaluated included in the model. These are not documented in Table 5.1-2 or with an individual detailed HEP are sufficient to determine the Appendix B. analysis. Rather, the event was ILRT impacts.

assigned a 'type' based on the transmitter it is associated with, and the types were assigned an HEP value based on the limited set of detailed pre-initiator evaluations that were performed as described in Appendix B of the HRA notebook (PB-PRA-004).

1-4 No evidence was found for using plant- DA-C8 Assessed as meeting Capability Not significant given that the specific operational records to determine the Category I. The standby status estimates utilized are sufficient time that components were configured in their times are estimated based on for determining the ILRT standby status. the anticipated equipment impacts.

rotation moving forward. This provides an appropriate level of accuracy for the model.

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 6-11 The data from the maintenance Rule is used DA-C11 Assessed as not met. This Not significant given that the directly without checking to see if it includes level of refinement would have unavailability values utilized are only those maintenance or test activities that a very small impact on the sufficient for determining the could leave the component, train, or system actual unavailability values ILRT impacts.

unable to perform its function when demanded utilized in the model.

as required by the SR.

6-9 Inter-system unavailability, (e.g., HPCl/RCIC DA-C14 Assessed as not met. RHR, Not significant given that the systems) data was not evaluated and a value HPSW, and CS loop coincident unavailability values of 1.0E-5 was arbitrarily assigned. maintenance terms included for utilized are sufficient for intra-system unavailability determining the ILRT impacts.

terms. However, the SR is not met for inter-system unavailability terms as the model includes coincident outage times for a few pertinent combinations (e.g. HPCl/RCIC, RHR Loops), but since no known overlap existed for these combinations, an arbitrarily small value (1.0E-5) was assigned.

4-5 Per PB-PRA-015 RO "L2 PRA Analysis LE-04 Assessed as meeting Capability Not significant given that the Notebook", ISLOCA is classified as Class V Category I. current approach is reasonably "Unisolated LOCA outside containment" per conservative, and ISLOCA Table 4.3-2 of PB-PRA-015 RO "L2 PRA scenarios would not be Analysis Notebook" detailed assessment and impacted by the ILRT.

frequency analysis of the ISLOCA was not performed, but rather a simplified approach for determining the ISLOCA frequencies as discussed in section 3.3.3 of PB-PRA-001 R2 "Initiating Events Notebook".

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY 11 FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 2-14 No documentation is identified for model IFPP-83 Assessed as not met. The None.

uncertainty associated with the plant sources of model uncertainty partitioning. and related assumptions are documented based on the guidance provided in EPRI 1016737 (as endorsed in NUREG-1855). This assessment did address the items to consider per the EPRI guidance which did not include any specific items related to the IFPP plant partitioning category.

This indicates that there are no sources of model uncertainty for the IFPP category that need to be considered.

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 3-19 Plant-specific experience was gathered as IFEV-A6 Assessed as meeting Capability None.

shown in Appendix H of the Internal Flood Category I. It is clear that the Evaluation Summary Notebook (PB-PRA- available pipe failure data is 012). However, only generic flood frequencies extremely sparse and the were used. associated uncertainties are quite large. There is essentially no PBAPS specific evidence of internal flooding of the size comparable to that used in the EPRI analysis. As such, any Bayesian update of the generic data would not improve this already sparse data set. Specifically, it is further postulated that it is inappropriate to introduce the false rigor of the Bayesian update process given the unknowns introduced by the failure mechanisms, the generic uncertainty distribution size, and the age related effects. In other words, the past PBAPS specific evidence i.e., past 35+

years of operation is not necessarily characteristic of future performance of the piping systems. This exercise of judgment in the use of relevant data is allowed by the Bayesian update process.

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TABLEA-1 STATUS OF GAPS TO CAPABILITY CATEGORY II FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 1-7 Note: This SR is modified by the notes in the IFSN-A6 Assessed as meeting Capability Not significant given that the RG 1.200. Following those notes, this SR can Category I. This additional level overall impact would be minimal only be judged to be met at CC I. No of refinement would have and therefore would be very assessment was done relating to factors such minimal impact on the internal minimally impacted by ILRT.

as pipe whip, humidity, condensation, etc., as flooding analysis results.

required by the RG 1.200 notes.

6-15 Inter-area propagation has been addressed in IFSN-A8 Assessed as meeting Capability Not significant given that the the scenario development. However, flow path Category I. This additional level overall impact would be minimal via drain lines, and areas connected via of refinement would have and therefore would be very backflow through drain lines involving failed minimal impact on the internal minimally impacted by ILRT.

check valves, pipe and cable penetrations flooding analysis results.

(including cable trays) do not appear to be addressed.

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TABLEA-2 STATUS OF OPEN FINDINGS FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 3-6 No evidence was found that plant testing HR-C2 Open - However, the failure None.

procedures were used to define pre-initiator QU-D6 modes identified in the SR are activities that would cause system already included in the generic unavailability or plant trips. or plant-specific data utilized for each system, component, and initiating event modeled.

3-13 Random checks in Appendices B and H in the DA-DS Closed - A separate check was None.

Component Data Notebook (PB-PRA-004, performed on all of the CCF Volume 2) showed that in some cases the values utilized in the model.

CCF applied was not directly applied in the The few discrepancies were associated file. corrected in the models used for this assessment.

3-14 No confirmation that experience from the plant DA-D6 Assessed as meeting Capability None.

was used to confirm the applicability of the Category I. It is agreed that generic CCF alpha factors to the plant specific specific documentation related conditions. to the applicability of the use of generic alpha factors was not provided. However, a review of the plant-specific failures listed in Table 8-3 of the Component Data Notebook (PB-PRA-004, Volume 1) indicates that there is no evidence of significant common cause failure activity at PBAPS that would render the use of the generic alpha factors questionable.

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TABLEA-2 STATUS OF OPEN FINDINGS FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 4-4 Section 3.5.5 of PB-PRA-001, Revision 2 HR-G1 Open - Detailed analysis not Not significant given that the estimates value for recovery from 'loss of DC yet performed. A conservative current recovery value utilized bus' BUT without the detailed analysis. recovery value of 0.5 is applied of 0.5 is conservative and the in model. loss of DC bus initiators were not significant contributors to the delta risk assessment.

5-9 Of the four systems (i.e., RPS, ARI, RPT and SY-A1 Open - Further refinement Not significant given that the SLC) identified in Table 2.3-2 of the Event SY-A7 could be employed for these current treatment is adequate Tree Notebook (PB-PRA-002) as needed to systems but is not required for for the determination of the support the reactivity control function only every application of the model. ILRT impacts.

SLC has a System Notebook (PB-PRA-005).

Except for SLC, modeling for these systems is primarily point estimates in the Data Notebook (PB-PRA- 010).

Without more developed system modeling, system interactions may not be evident. (ARI typically uses RPT for an initiation signal and requires DC power for actuation of air pilot valves.) The inclusion of operator actions (e.g., scram the reactor, trip the recirculation pumps, or initiate ARI) may provide more realistic risk. Some BWRs have associated spurious operation of the reactor mode switch with a failure to scram.

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TABLEA-2 STATUS OF OPEN FINDINGS FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 6-3 There is adequate documentation to meet the IE-D2 Open - These comments are None.

SR. The treatment of four categories of LOOP either documentation issues or is an improvement. However, there is room for reference issues that are further improvement: addressed by other findings.

1. See F&O written in response to IE-83 to improve documentation.

2. There are a lot of pages written up to calculate the frequency of Large LOCA, but it does not look like the value is used in the PRA. The documentation can be simplified by just referring to the value used and eliminating the text relating to the unused value.

3. The steam LOCA and liquid LOCA seem be getting lumped together. It is not clear if these LOCAs are treated in the same manner (i.e.,

using the same success criteria).

4. The ISLOCA analysis has not been updated from the IPE days.

5. It might be useful to document why certain events such as the following are excluded from the PRA: Multiple IORV, Multiple SORV, Stuck-open safety valve.

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TABLEA-2 STATUS OF OPEN FINDINGS FROM THE 2010 PEER REVIEW FINDING DESCRIPTION OF FINDING APPLICABLE CURRENT STATUS I IMPORTANCE TO NO. SRs COMMENT APPLICATION 6-14 Plant walkdown was conducted to identify IFPP-A4 Open - This finding relates to None.

flood sources. No specific walkdown was IFSO-A6 providing additional detail in the conducted to identify the SSCs in the flood walkdown sheets which would IFSN-A17 areas or the pathways. These were identified enhance the fidelity of the through drawings, and verified by mini- model documentation.

walkdowns at the discretion of the PRA However, it is not expected to analysts. The walkdown documentation is change the results of the very sketchy. A lot more information needs to internal flood analysis.

be collected during walkdown to help flood scenario development. The location of drains, curbs, doors, sills need to be identified. The paths through stairwells need to be identified.

The flood pathways developed in the flood scenarios need to be verified by walkdown.

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A.2.4 EXTERNAL EVENTS Although EPRI report 1018243 [A.8] recommends a quantitative assessment of the contribution of external events (for example, fire and seismic) where a model of sufficient quality exists, it also recognizes that the external events assessment can be taken from existing, previously submitted and approved analyses or another alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval. Based on this, currently available information for external events models was referenced, and a multiplier was applied to the internal events results based on the available external events information. This is further discussed in Section 5. 7 of the risk assessment.

A.2.5 PRA QUALITY

SUMMARY

Based on the above, the PBAPS PRA is of sufficient quality and scope for this application. The modeling is detailed; including a comprehensive set of initiating events (transients, LOCAs, and support system failures) including internal flood, system modeling, human reliability analysis and common cause evaluations. The PBAPS PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that these PRA models are suitable for use in the risk-informed process used for this application.

A.3 IDENTIFICATION OF KEY ASSUMPTIONS The methodology employed in this risk assessment followed the EPRI guidance as previously approved by the NRC. The analysis included the incorporation of several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. None of the sensitivity studies or bounding analysis indicated any source of uncertainty or modeling assumption that would have resulted in exceeding the acceptance guidelines. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LERF, there are no identified key assumptions or sources of uncertainty for this application (i.e. those which would change the conclusions from the risk assessment results presented here).

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A.4

SUMMARY

A PRA technical adequacy evaluation was performed consistent with the requirements of RG-1.200, Revision 2. This evaluation combined with the details of the results of this analysis demonstrates with reasonable assurance that the proposed extension to the ILRT interval for PB2 and PB3 to fifteen years satisfies the risk acceptance guidelines in RG 1.174.

A.5 REFERENCES

[A.1] Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities, Revision 2, March 2009.

[A.2] Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997.

[A.3] American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, New York, New York, April 2002.

[A.4] U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Draft Regulatory Guide DG-1122, November 2002.

[A.5] Peach Bottom MSPI Basis Document, Rev. 2, March 27, 2007.

[A.6] ASME/American Nuclear Society, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, March 2009.

[A.7] Peach Bottom Atomic Power Station PRA Peer Review Report, BWROG Final Report, May2011.

[A.8] Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243.

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