LG-25-063, License Amendment Request for One-Time Extension of the Containment Type a Integrated Leakage Rate Test Frequency

License Amendment Request for One-Time Extension of the Containment Type a Integrated Leakage Rate Test Frequency

ML25227A183
Person / Time
Site:	Limerick
Issue date:	08/15/2025
From:	Para W Constellation Energy Generation
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML25227A216	List: LG-25-063, License Amendment Request for One-Time Extension of the Containment Type a Integrated Leakage Rate Test Frequency
References
LG-25-063R1
Download: ML25227A183 (1)

Text

200 Energy Way Kennett Square, PA 19348 www.constellation.com LG-25-063R1 10 CFR 50.90 August 15, 2025 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Subject:

License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency

Reference:

1.

Public Preapplication Meeting with Constellation Energy Generation, LLC (CEG) on June 26, 2025, to discuss a Planned License Amendment Request for a one time extension to the Integrated Leak Rate Test for Limerick Generating Station, Units 1 and 2 (ADAMS Accession No. ML25177B155).

Reference:

2.

CEG letter to the U.S. Nuclear Regulatory Commission (NRC), License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency, dated August 8, 2025 (ADAMS Accession No. ML25220A209).

In accordance with 10 CFR 50.90, Application for amendment of license, construction permit, or early site permit, Constellation Energy Generation, LLC (CEG) requests an amendment to Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2.

The proposed change would allow for a one-time extension to the 15-year frequency of the containment leakage rate test (i.e., integrated leakage rate test (ILRT) or Type A test). This test is required by Technical Specifications Section 6.8.4.g, "Primary Containment Leakage Rate Testing Program." The proposed one-time change to the TS would permit the current ILRT interval of 15 years to be extended by 13 months for LGS Unit 1 and 12 months for LGS Unit 2.

A preapplication meeting with the NRC was held on June 26, 2025, to discuss the one-time extension to the 15-year frequency of the ILRT for LGS Unit 1 and 2 (Reference 1).

The Reference 2 submittal contains personally identifiable information. This submittal provides a redacted version of that request. Constellation requests the NRC withhold the original Reference 2 submittal from public disclosure under 10 CFR 2.390.

This request is subdivided as follows.

provides a description and evaluation of the proposed change.

provides a markup of the affected TS pages.

provides an assessment of risk associated with the one-time extension.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency August 15, 2025 Page 2 The proposed change has been reviewed by the Plant Operations Review Committee in accordance with the requirements of the CEG Quality Assurance Program.

CEG requests approval of the proposed change by March 31, 2026. Once approved, the amendment will be implemented within 60 days. This implementation period will provide adequate time for the affected station documents to be revised using the appropriate change control mechanisms.

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation," paragraph (b),

CEG is notifying the State of Pennsylvania of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State Official.

There are no new regulatory commitments contained in this submittal.

Should you have any questions concerning this submittal, please contact Lane Oberembt at 267-533-5301.

I declare under the penalty of perjury that the foregoing is true and correct. Executed on the 15th day of August 2025.

Respectfully, Wendi Para Sr Manager - Licensing Constellation Energy Generation, LLC Attachments:

1. Evaluation of Proposed Change

2. Markup of Technical Specifications Page

3. Risk Assessment for LGS Regarding the ILRT (Type A) and DWBT One-Time Extension Request cc:

USNRC Region I, Regional Administrator w/attachments USNRC Senior Resident Inspector, LGS USNRC Project Manager, LGS Director, Bureau of Radiation Protection - Pennsylvania Department of Environmental Protection

ATTACHMENT 1 Evaluation of Proposed Changes Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Subject:

License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Testing Frequency 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Current and Proposed TS Wording 2.2 Current Surveillance Requirement (SR) Wording

3.0 TECHNICAL EVALUATION

3.1 ASME Class CC Concrete Components of the Containment 3.2 ASME Class MC Steel Components of the Containment 3.3 Chronology of Testing Requirements of 10 CFR 50, Appendix J 3.4 ILRT Requirements 3.5 Integrated Leakage Rate Testing History 3.6 Plant Specific Confirmatory Analysis 3.7 Non-Risk Based Assessment 3.8 Results of Recent Inspections 3.9 Drywell Bypass Leak Rate Test (DWBT) Assessment 3.10 NRC Regulatory Issue Summary (RIS) 2008-27

4.0 REGULATORY EVALUATION

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

6.0 REFERENCES

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Constellation Energy Generation, LLC (CEG), proposes changes to the Technical Specifications (TS), Appendix A of Renewed Facility Operating License Nos. NPF-39 and NPF-85 for Limerick Generating Station (LGS), Units 1 and 2, respectively.

The proposed change would allow for a one-time extension to the following:

15-year frequency of the LGS Units 1 and 2 containment leakage rate tests (i.e.,

integrated leakage rate test (ILRT) or Type A test) required by TS Section 6.8.4.g, "Primary Containment Leakage Rate Testing Program."

The drywell-to-suppression chamber bypass leak rate test (DWBT) conducted to coincide with the Type A test required by TS Section 4.6.2.1.e.

The proposed one-time change would permit the current interval of 15 years to be extended by 13 months for Unit 1 and 12 months for Unit 2.

The proposed change will also change the format of the Unit 1 Technical Specification (TS) 6.8.4.g, Primary Containment Leakage Rate Testing Program.

The last LGS Unit 1 ILRT and the DWBT were completed in March 2012. Based on the 15-year frequency, the next performance of the Unit 1 tests must be performed by March 2027. To perform the test during a regularly scheduled Unit 1 outage, the tests would have to be performed during refuel outage in spring 2026 (Li1R21). The last LGS Unit 2 ILRT and the DWBT were completed in April 2013. Based on the 15-year frequency, the next performance of the Unit 2 tests must be performed by April 2028. To perform the test during a regularly scheduled Unit 2 outage, the tests would have to be performed during refuel outage in spring 2027 (Li2R19).

LGS will be installing the Digital Modernization Project (DMP) in Li1R21 and Li2R19. This project will replace the existing analog control logic hardware of the Reactor Protection System (RPS) instrumentation, Nuclear Steam Supply Shutoff System (NSSSS) instrumentation, the Emergency Core Cooling System (ECCS) instrumentation, the Reactor Core Isolation Cooling (RCIC) System instrumentation, and the End-of-Cycle Recirculation Pump Trip (EOC-RPT) instrumentation with a new single digital control system.

The DMP was originally scheduled to be installed during Li1R20 (April 2024) and Li2R18 (April 2025), for Units 1 & 2, respectively, and there would not have been a conflict. However, with the DMP not obtaining approval for installation as originally scheduled, it is now planned for installation in the same refueling outages as the ILRTs.

The DMP is structured around key technical and regulatory advances that have come to fruition in recent years. This structure demonstrates that large scale modernization is a viable economic and technical alternative. Given the scale of the LGS Modernization Project, the public-facing research on which it is founded, and the demonstration of the multiple industry and Page 1 of 35

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 2 of 35 regulatory initiatives, this project has significant benefits for the industry and by extension the public in the form of demonstrating that modernization can be achieved efficiently and will preserve reliable and carbon-free generation. The successful installation strategy being employed with the support of this proposed License Amendment will facilitate a safe and error-free installation in a timely manner for such a large and significant undertaking. It will also eliminate the undue hardship of performing the ILRT while completing the acceptance testing required by the DMP.

2.0 DETAILED DESCRIPTION 2.1 Current and Proposed TS Wording LGS Units 1 and 2 TS 6.8.4.g, Primary Containment Leakage Rate Testing Program, currently states, in part:

Unit 1:

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008. The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

Unit 2:

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

The proposed change to LGS TS 6.8.4.g will add an exception to allow for the performance of the next Type A test no later than April 2028 for Unit 1 and April 2029 for Unit 2, which represents an extension of 13 months for Unit 1 and 12 months for Unit 2. In addition, the proposed change adds a second exception to allow the Type A test to be extended indefinitely if the test interval ends while primary containment integrity is not required (i.e., TS 3.6.1, "Primary Containment," does not require the primary containment to be operable in Modes 4 and 5). In this case, the second exception requires that the Type A test be performed prior to entering Mode 2.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 3 of 35 A format change would move the last sentence of the Unit 1 TS to a new paragraph to make the format the same format as the Unit 2 TS.

The proposed revised wording states:

Unit 1 A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01,"Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008 as modified by the following exceptions: (1) the next Type A test performed after the March 2012 Type A test shall be performed no later than April 30, 2028, and (2) if the Type A test has not been performed by April 30, 2028, and the unit is in Mode 4 or 5, the Type A test shall be performed prior to entering Mode 2.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

Unit 2 A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008 as modified by the following exceptions: (1) the next Type A test performed after the April 2013 Type A test shall be performed no later than April 30, 2029, and (2) if the Type A test has not been performed by April 30, 2029, and the unit is in Mode 4 or 5, the Type A test shall be performed prior to entering Mode 2.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

A TS page markup of the proposed change is provided in Attachment 2.

2.2 Current Surveillance Requirement (SR) Wording LGS, Units 1 and 2 SR 4.6.2.1.e currently states, Drywell-to-suppression chamber bypass leak tests shall be conducted to coincide with the Type A test at an initial differential pressure of 4 psi and verify that the A/k calculated from the measured leakage is within the specified limit. If any drywell-to-suppression chamber bypass leak test fails to meet the specified limit, the test schedule for subsequent tests shall be reviewed and approved by the Commission. If two consecutive tests fail to meet

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 4 of 35 the specified limit, a test shall be performed at least every 24 months until two consecutive tests meet the specified limit; at which time the test schedule may be resumed.

This LAR proposes extending the testing frequency for both the Type A test and the DWBT 13 months for Unit 1 and 12 months for Unit 2. The LAR does not propose any changes to the wording of SR 4.6.2.1.e as the current wording meets the intent of the change to the DWBT interval. The risk assessment for the extension of the DWBT is included in Attachment 3 of this submittal.

3.0 TECHNICAL EVALUATION

3.1 ASME Class CC Concrete Components of the Containment 3.1.1 Description of Primary Containment A horizontal diaphragm slab divides the primary containment into two major volumes: the drywell and the suppression chamber. The drywell encloses the reactor vessel, reactor recirculation system, and associated piping and valves. The suppression chamber stores a large volume of water.

The primary containment is in the form of a truncated cone over a cylindrical section, with the drywell being the upper conical section and the suppression chamber being the lower cylindrical section. These two sections comprise a structurally integrated, reinforced concrete pressure vessel, lined with welded steel plate and provided with a steel domed head for closure at the top of the drywell. The diaphragm slab is a reinforced concrete slab structurally connected to the containment wall.

The primary containment is structurally separated from the surrounding reactor enclosure.

The concrete dimensions of the primary containment are as follows:

1. Inside Diameter

a. Suppression chamber - 88'-0"

b. Base of drywell - 86'-4"

c. Top of drywell - 36'-4 1/2"

2. Height

a. Suppression chamber - 52'-6"

b. Drywell - 87'-9"

3. Thickness

a. Base foundation slab - 8'-0"

b. Containment wall - 6'-2" 3.1.2 Base Foundation Slab The containment base foundation slab is a reinforced concrete mat, the top of which is lined with carbon steel plate.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 5 of 35 3.1.3 Reinforcement The base foundation slab is reinforced with No. 18, Grade 60 steel reinforcement bars (rebar) at the top and bottom faces. The maximum rebar spacing is 18 inches. Shear reinforcement consists of No. 8 and No. 9 rebar as vertical and inclined ties. Cadweld splices are used for splicing all main reinforcement bars.

3.1.4 Liner Plate and Anchorages The steel liner plate is 1/4-inch thick and is anchored to the concrete slab by structural steel beams embedded in the concrete and welded to the plate.

3.1.5 Reactor Pedestal and Suppression Chamber Column, Base Liner Anchorage For the pedestal anchorage, Cadweld sleeves are welded to the top and bottom surfaces of the thickened base liner to permit anchoring of the pedestal vertical rebar into the base foundation slab. Metal studs are welded to the top and bottom surfaces of the thickened base liner to transfer radial and tangential shear forces from the pedestal to the base foundation slab. For the suppression chamber column anchorage, pipe caps are welded to the thickened base liner at the locations where the column anchor bolts penetrate the base liner, in order to ensure the leak-tight integrity of the base liner.

3.1.6 Containment Wall The containment wall is constructed of reinforced concrete 6 feet, 2 inches thick, and is lined with carbon steel plate on the inside surface.

3.1.7 Reinforcement The containment wall is reinforced with No. 18, Grade 60 rebar at the inner and outer faces.

The inner rebar curtain consists of two meridional layers and one hoop layer. The outer rebar curtain consists of one meridional layer, two hoop layers, and two helical layers. Radial shear reinforcement consists of No. 6 rebar as horizontal and inclined ties. Cadweld splices are used for splicing all main reinforcement bars.

3.1.8 Liner Plate and Anchorages The steel liner plate is 1/4-inch thick and is anchored to the concrete wall by vertical stiffeners, using structural tees spaced horizontally every 2 feet, or less. Horizontal plate stiffeners provide additional stiffening.

Loads from internal containment attachments, such as beam seats and pipe restraints, are transferred directly into the containment concrete wall. This is accomplished by thickening the liner plate and attaching structural weldments that transfer any type of load to the concrete, without relying on the liner plate or its anchorages. Where internal containment attachment loads are large, the structural weldments penetrate the liner plate, rather than being welded to opposite sides of the liner plate. This eliminates the possibility of lamellar tearing.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 6 of 35 3.1.9 Penetrations Services and communication between the inside and outside of the containment are performed through penetrations. Basic penetration types include pipe penetrations, electrical penetrations, and access hatches (equipment hatches, personnel lock, suppression chamber access hatches, and CRD removal hatch). Each penetration consists of a pipe sleeve with an annular ring welded to it. The ring is embedded in the concrete wall and provides an anchorage for the penetration to resist normal operating and accident loads. The pipe sleeve is also welded to the containment liner plate to provide a leak-tight penetration.

Meridional and hoop reinforcement is bent around typical penetrations. Additional local reinforcement in the hoop and diagonal directions is added at all large penetrations. Local thickening of the containment wall at penetrations is generally not required.

a. Pipe Penetrations There are two basic types of penetrations. For piping systems containing high temperature fluids, a sleeved penetration is furnished, providing an air gap between the containment concrete wall and the hot pipe. This air gap is large enough to maintain the concrete temperature below 200 degrees Fahrenheit in the penetration area. A flued head outside the containment connects the process pipe to the pipe sleeve. For piping systems containing low temperature fluid, a separate sleeve for the penetration is not furnished. For this type of penetration, the process pipe is welded directly to the two ends of the embedded pipe penetration.

b. Electrical Penetrations A typical electrical penetration assembly is used to extend electrical conductors through the containment. The penetrations are hermetically sealed and provide for leak testing at design pressure.

c. Equipment Hatches and Personnel Lock Two equipment hatches, with inside diameters of 12 feet, are furnished in the drywell wall. One of these equipment hatches includes a personnel lock. Additional meridional, hoop, helical, and shear reinforcement is used to accommodate local stress concentrations at the opening. The containment wall is thickened at the equipment hatches to accommodate the additional rebar.

d. Suppression Chamber Access Hatches Two access hatches, with internal diameters of 4 feet, 4 inches, are furnished in the suppression chamber wall.

e. Drywell Head Assembly The drywell head lower flange is anchored to the top of the drywell wall by rigid attachment to 108 meridional reinforcing bars in the inner curtain of the containment wall.

3.1.10 Internal Containment Attachments

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 7 of 35 The principal items attached to the containment wall from the interior are the diaphragm slab, beam seats, pipe restraints and the seismic truss.

a. Diaphragm Slab Embedments The diaphragm slab is attached to the containment wall by a structural weldment at the junction of the two components. Cadwelding the diaphragm slab rebar to the top and bottom flanges of the structural weldment, transfers radial force and bending moment, carried by the diaphragm slab main reinforcement, to the containment wall. The top and bottom flanges of the structural weldment are embedded in the containment concrete wall and are anchored using structural steel anchors. Flexural shear in the diaphragm slab is transferred to the containment wall through the web of the structural weldment, which is welded to opposite sides of the thickened containment liner plate.

b. Beam Seat Embedments Beam seats are provided to support the drywell platforms.

c. Pipe Restraint Embedments Pipe restraints are provided to prevent pipe whip caused by rupture of high-energy piping.

d. Seismic Truss Support Embedments The seismic truss provides lateral support for the reactor vessel and reactor shield.

3.1.11 External Containment Attachments There are no major external structural attachments to the primary containment wall, except brackets providing vertical support for some of the reactor enclosure floor beams. These floor beams support checkered plate blowout panels and are small enough to not cause any vertical interaction between the containment structure and the reactor enclosure. In addition, the beam-to-bracket connections are sliding connections, preventing horizontal interaction between the containment structure and the reactor enclosure.

3.2 ASME Class MC Steel Components of the Containment 3.2.1 Drywell Head Assembly The drywell head provides a removable closure at the top of the containment for reactor access during refueling operations. The drywell head assembly consists of a 2:1 hemi-ellipsoidal head and a cylindrical lower flange. The head is made of 1 1/2-inch thick plate and is secured with eighty 2-3/4 inch diameter bolts at the 4-inch-thick mating flange. The head-to-lower flange connection is made leak-tight by two replaceable gaskets. The space between the gaskets is provided with test connections to allow pneumatic testing from a remote location, outside the primary containment. The inside diameter of the drywell head at the mating flange is 37 feet, 7 1/2 inches. A double-gasketed manhole is provided in the drywell head.

3.2.2 Equipment Hatches and Personnel Lock

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 8 of 35 Two 12-foot diameter equipment hatches are furnished in the drywell wall to permit the transfer of equipment and components into and out of the drywell. One hatch consists of a double-gasketed flange and a bolted dished door. The outer hatch is furnished with a personnel lock welded to the removable door. The personnel lock is 8 feet, 7 inches diameter cylindrical pressure vessel, with inner and outer flat bulkheads. Interlocked doors 2-feet, 6-inch wide by 6 feet high, with double tongue-and-groove single element compression seals, are furnished in each bulkhead. A quick-acting, equalizing valve vents the personnel lock to the drywell to equalize the pressure in the two systems when the doors are opened and then closed. The two doors in the personnel lock are mechanically interlocked to prevent them from being opened simultaneously, and to ensure that one door is closed before the opposite door can be opened. The personnel lock has an ASME Code N-stamp.

3.2.3 Suppression Chamber Access Hatches Two 4 feet, 4-inch diameter access hatches are furnished in the suppression chamber wall to permit personnel access, and the transfer of equipment and components into and out of the suppression chamber. Each hatch consists of a double-gasketed flange and a bolted flat cover.

3.2.4 Control Rod Drive Removal Hatch One 3-foot diameter CRD removal hatch is furnished in the drywell wall to permit transfer of the CRD assemblies into and out of the drywell. The hatch is furnished with a double-gasketed flange and a bolted flat cover.

3.2.5 Piping and Electrical Penetrations A portion of each of the penetration sleeves extends beyond the containment wall and is not backed by concrete. Therefore, the entire length of any penetration sleeve is considered an MC component, and as such, is designed in accordance with ASME Section III, subsection B.

3.3 Chronology of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. 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 most potential containment leakage paths.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 9 of 35 Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

In 1995, 10 CFR 50, Appendix J, 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 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 2) 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 NRC risk assessment contained in NUREG-1493, (Reference 3) and Electric Power Research Institute (EPRI) TR-104285 (Reference 4) 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 extension of interval "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 5), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation (SE) on NEI 94-01 (Reference 8). NEI 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. 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.

On December 8, 2008, the NRC issued Regulatory Issue Summary (RIS) 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50" (Reference 6). The RIS clarifies the NRC position concerning licensee requests to extend Type A test intervals beyond 15 years, stating that a licensee can commence the test no later than the last day of the month in which it becomes due, without seeking NRC approval through a license amendment. The RIS also endorses the statement made in NEI 94-01, Revision 2-A, that if the test interval ends while primary containment integrity is not required, or is required solely for shutdown activities, the test interval may be extended indefinitely, but a Type A test shall be completed prior to entering the operating mode requiring primary containment integrity. In addition, the RIS states that any extension beyond the end of the month in which the test is due would require a license amendment request. Per RIS 2008-27, the license amendment request should demonstrate:

a sound technical justification and/or undue hardship or unusual difficulty;

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 10 of 35 the requested amendment poses minimal safety risk; acceptable plant-specific containment performance, including a plant-specific risk informed analysis; and that containment does not have a history of significant degradation issues.

In 2012, NEI 94-01, Revision 3-A (Reference 7), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SEs of June 25, 2008 (Reference 8) and June 8, 2012 (Reference 9) as an acceptable methodology for complying with the provisions of Option B in 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163 as modified by References 10 and 11 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 for extending test intervals is based on the performance history and risk insights.

The NRC has provided guidance concerning the use of test interval extensions in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRC SE Section 3.1.1.2 which states, in part:

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.

The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SE Section 4.0, Condition 2, which states, in part:

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.

3.4 ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements."

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 11 of 35 On March 11, 2020, the NRC issued Amendment 241 for LGS Unit 1 (Reference 10) and 204 for LGS Unit 2 (Reference 11). These amendments approved a permanent extension of the Type A ILRT frequency from once every 10 years to once every 15 years in accordance with NEI 94-01, Revision 3.A, and the conditions and limitations specified in NEI 94-01, Revision 2-A. These amendments also approved an extension of the containment isolation valve leakage rate testing frequency from 60 months to 75 months for Type C leakage rate testing of selected components in accordance with NEI 94-01, Revision 3-A. For further discussion of Type C testing, see Section 3.7.4.

With the issuance of Amendments 241 and 204 the due date for the LGS Unit 1 Type A test moved from March 2022 to March 2027 and the due date for the LGS Unit 2 Type A test moved from April 2023 to April 2028. This allows the Unit 1 test to be performed in the spring 2026 refueling outage and the Unit 2 test to be performed in the spring 2027 refueling outage. This request represents an extension of approximately 13 months for Unit 1 and 12 months for Unit

2. The intervals for the Type B and Type C tests remain unchanged at 120 months and 75 months, respectively. For further discussion of Type B and Type C testing, see Section 3.7.4.

3.5 Integrated Leakage Rate Testing History Previous LGS ILRT results have confirmed the containment is acceptable, with considerable margin, with respect to the TS acceptance criterion of 0.5% of primary containment air weight per day at the design basis loss-of-coolant accident pressure. Since the last two Type A test results meet the performance leakage rate criteria from NEI 94-01, Revision 3-A, a test frequency of 15 years would be acceptable. Table 3.5-1 lists the past periodic Type A ILRT results for LGS Unit 1. Table 3.5-2 lists the past periodic Type A ILRT results for LGS Unit 2.

Table 3.5 LGS Unit 1 Type A Testing History Test Date 95% UCL (wt.%/day)

Note 4 As-Found Leakage (wt.%/day)

Acceptance Criteria(wt.%/day)

As-Left Leakage (wt.%/day)

As-Found (La)

As-Left (75% La) 8/3/1984 0.213 Note 1 Note 1 0.375 0.1642 8/13/1987 0.131 Note 2 0.5 0.375 0.1469 11/23/1990 0.252 Note 5 0.5 0.375 0.287 5/13/1998 0.263 0.3751 0.5 0.375 0.307 3/17/2012 0.139 0.2688 0.5 0.375 0.2318 Table 3.5 LGS Unit 2 Type A Testing History Test Date 95% UCL (wt.%/day)

Note 4 As-Found Leakage (wt.%/day)

Acceptance Criteria(wt.%/day)

As-Left Leakage (wt.%/day)

As-Found (La)

As-Left (75% La) 5/6/1989 0.218 Note 1 Note 1 0.375 0.233 3/9/1993 Note 3 0.215 Note 5 0.5 0.375 0.2586 5/21/1999 0.2965 0.3584 0.5 0.375 0.3272 4/14/2013 0.252 0.3643 0.5 0.375 0.3643

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 12 of 35 Note 1: This was a pre-operational test; therefore, no AF leak rate calculated.

Note 2: The AF test results failed to meet the acceptance criteria of 0.500wt.%/day.

Note 3: The test method used was the Total Time Method, as described in ANSI N45.4-1972, "Leakage-Rate Testing of Containment Structures for Nuclear Reactors" and Bechtel Topical Report BN-TOP-1, Revision 1, "Testing Criteria for Integrated Leak Rate Testing of Primary Containment Structures for Nuclear Power Plants."

Note 4: The upper confidence limit (UCL) is a calculated value determined from test data that places a statistical upper bound on the true leakage rate. The UCL is calculated at a 95% confidence level in ANSI/ANS 56.8. From this 95% UCL leakage rate value, both the as-left (AL) and the as-found (AF) ILRT leakage rates are determined. Corrections are made to the 95% UCL leakage rate for changes in the net free volume due to changes in containment sub-volume water levels and valves not in accident positions (Types B and C penalties) during the test.

Note 5: LGS does not maintain records of Types B and C leak rate summations for RFOs earlier than 1996. Therefore, leakage savings are not known, and the AF leak rate cannot be calculated.

No modifications that require a Type A test are planned at LGS Units 1 and 2 prior to the Spring 2028 and 2029 refueling outages, when the next Type A test will be performed in accordance with this proposed change. Any unplanned modifications to containment prior to the next scheduled Type A test would be subject to the special testing requirements of Section IV.A of 10 CFR 50, Appendix J. There have been no pressure or temperature excursions in the LGS Units 1 and 2 containments which could have adversely affected containment integrity. There is no anticipated addition or removal of plant hardware within containment which could affect leak-tightness or air volume.

3.6 Plant Specific Confirmatory Analysis 3.6.1 Methodology An evaluation has been performed to provide an assessment of the risk associated with implementing a one-time extension of the LGS containment Type A ILRT interval by approximately fifteen months from the currently approved value of 15 years to 16.25 years. The 16.25 years conservatively envelopes this LAR for Unit 1 ILRT to be extended 13 months and Unit 2 ILRT to be extended 12 months. The risk assessment follows the guidelines from NEI 94-01, Revision 3-A, the methodology outlined in Electric Power Research Institute (EPRI)

Topical Report (TR) 104285 (Reference 4), as updated by the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (EPRI TR-1018243) (Reference 12), the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a change to a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 (Reference 13), and the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage going undetected during the extended test interval (Reference 14).

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 13 of 35 3.6.2 Summary of Plant-Specific Risk Assessment Results The risk assessment determined that increasing the ILRT interval on a one-time basis to a one-in-16.25-year frequency is not considered to be significant since it represents only a small change in the LGS risk profile. Details of the LGS risk assessment are contained in (LG-LAR-037, Rev. 0) to this letter. The plant-specific results for a one-time extension of the LGS ILRT surveillance interval from the current 15 years to 16.25 years are summarized below.

RG 1.174 provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines "very small" changes in risk as resulting in increases of core damage frequency (CDF) below 1E-06/yr and increases in large early release frequency (LERF) below 1E-07/yr. "Small" changes in risk are defined as increases in CDF below 1E-05/yr and increases in LERF below 1E-06/yr. Since the ILRT extension was demonstrated to have negligible impact on CDF for LGS, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years (analysis base case) to 16.25 years with corrosion included is 3.56E-08/yr, while the increase from the current 15-year interval to 16.25 years is only 3.66E-09/yr. 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 3-in-10 years to 16.25 years, measured as an increase to the total integrated dose risk for all internal events accident sequences for LGS, is 5.38E-02 person-rem/yr (0.37%) using the EPRI guidance with the base corrosion included. The change in dose risk drops to 5.43E-03 person-rem/yr (0.038%) for an extension from the current 15-year interval to 16.25 years. 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 Attachment 3, Section 1.3.

The increase in the conditional containment failure probability from the 3-in-10-year interval to 16.25 years including corrosion effects using the EPRI guidance (see, Section 5.5) is 1.13%. This value drops to 0.12% in view of an extension from the current 15-year interval to 16.25 years. Both 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 of the risk associated with external events was performed utilizing available information. As shown in Attachment 3, Table 5.7-4, the total increase in LERF due to internal events and the bounding external events assessment is 1.36E-07/yr for the 3-in-10-year interval extended to 16.25 years. This value is in Region II of the Reg. Guide 1.174 acceptance guidelines. For extension from the current 15 years to 16.25 years, the total increase in LERF is only 1.40E-08/yr, which is in Region III of Reg. Guide 1.174.

As shown in Attachment 3, Table 5.7-5, the same bounding analysis indicates that the total LERF from both internal and external risks is 2.29E-06/yr which is less than the Reg. Guide 1.174 limit of 1.0E-05/yr given that the LERF is in Region II (small change in risk) for the extension analysis case of 3-in-10 years to 16.25 years.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 14 of 35 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 LGS.

A Drywell Bypass Test (DWBT) risk analysis documented in Attachment 3, Appendix B, provides key metric values that, in combination with ILRT results, would not change the ILRT related conclusions described above. The DWBT values for an interval change from the original 3-in-10 years to 16.25 years are compared below to the ILRT base case with corrosion. These DWBT values are developed and reported in Attachment 3, Appendix B, Section B.5.

Delta CDF = 8.69E-10/yr (ILRT increase = 0.0)

Delta LERF = 2.59E-09/yr (ILRT increase = 3.56E-08/yr)

Delta Dose = 9.25E-03 p-rem/yr (ILRT increase = 5.38E-02 p-rem/yr)

Delta CCFP = 0.0029% (ILRT increase = 1.13%)

The DWBT CDF increase is less than 0.03% of base CDF (3.15E-06/yr). The DWBT values for change in LERF and CCFP are significantly below the ILRT values. Although the DWBT person-rem dose rate increase is about 17% of the ILRT dose rate increase, the total dose rate increase (DWBT and ILRT combined) is still less than 0.5% which is well less than the acceptance criteria of less than 1.0% increase. The change in DWBT risk metrics would be even smaller in view of the extension from the current 15-year interval to the proposed 16.25-year interval.

Therefore, increasing the ILRT (and associated DWBT) interval on a one-time basis up to a 16.25-year interval is not considered to be significant since it represents only a small change in the LGS risk profile.

3.7 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, LGS has assessed other non-risk-based considerations relevant to the proposed amendment. LGS 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.

3.7.1 Protective Coating Program LGS has a commitment to Regulatory Guide 1.54 "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants" Rev. 0. This RG describes a method to comply with requirements of Appendix B of 10 CFR 50 and invokes several ANSI Standards. Standards relevant to coatings are ANSI N101.2 "Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities," ANSI N101.4 "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and ANSI N5.12 "Protective Coatings for the Nuclear Industry." (ANSI N5.9, referenced in ANSI N101.2, was replaced by ANSI N5.12 in 1974)

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 15 of 35 In 1998, LGS changed its commitments from ANSI N101.4 to ASTM D3843-93 "Standard Practice for Quality Assurance for Protective Coatings Applied to Nuclear Facilities", with some exceptions. Because of this partial change LGS complies with ASTM D3843-93 for Service Level I protective coatings work with the following additional clarification, exception, and requirement:

For coating formulations developed prior to issuance of ASTM D3843-93, service level 1 qualification based on ANSI N5.9 (Revised as ANSI N5.12-1974) and ANSI N101.2 remains valid.

Section 10.1, last sentence - instead of references to ANSI 45.2 and NQA-1, inspections will be documented for record purposes as required by 10 CFR 50, Appendix B, and by this QA program description.

Limitations on use of coatings and cleaning materials which contain elements which could contribute to corrosion, inter-granular cracking, or stress corrosion cracking of safety-related stainless steel will be followed as described in Section C.4 of Regulatory Guide 1.54, June 1973.

A program to maintain containment coatings was developed to meet the requirements of RG 1.54 Rev. 0. This program is implemented in accordance with Constellation Procedure ER-AA-330-008 "Safety-Related (Service Level I) Protective Coatings". The inspection of containment coatings in the Drywell and vapor phase of the Wetwell is performed once per ASME period (40 months) in conjunction with the Containment Inservice Inspection. The immersed suppression pool lining receives a 100% visual inspection of accessible areas once per ASME IWE inspection period (i.e. 3 times in 10 years) and is managed under the ASME Code Section XI, Subsection IWE program.

The most recent inspections of the Drywell and Suppression Pool Vapor Space were performed during refueling outages, Unit 1 in April 2024 (Li1R20) and Unit 2 in May 2023 (Li2R17). These inspections covered the Liner Plate and Interior Surfaces at all elevations of the Drywell, and the non-immersed Liner Plate and Interior Surfaces of the Wetwell.

The most recent inspections of the immersed region of the Suppression Pool were performed on Unit 1 in April 2024 (Li1R20) and on Unit 2 in May 2023 (Li2R17).

There will be no change to the schedule for these inspections because of the extended ILRT interval.

Unqualified/Degraded Coatings in Containment In response to Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment, expanded coating condition assessments began at LGS with baseline inspections performed on Unit 1 in April 2000 and Unit 2 in April 2001. The results of these baseline inspections established the unqualified/degraded coatings logs for LGS Units 1 & 2.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 16 of 35 As of March 2025, there are 52.2 pounds of Degraded/Unqualified Coatings in LGS Unit 1 Containment. For LGS Unit 2, the evaluation of the initial inventory concluded that the quantity of unqualified coatings identified in the Unit 2 Containment and Suppression Pool are similar to the quantity found in Unit 1 and are certainly well under the design limits for the replacement ECCS suction strainers. In addition, the current condition of the Drywell and Suppression Chamber coatings between Unit 1 and Unit 2 is similar with the only major difference being approximately 16lbs of additional unqualified coatings in Unit 2 due to the installation of a pair of temporary skids, and an additional 0.24 lbs. from small damage identified during Li2R18. To account for Degraded/Unqualified coatings, 1000 pounds of additional operational debris loading is allowed in addition to the 1000-pound corrosion product and 2000 cubic feet of insulation limits per unit for the ECCS Suction Strainers as noted in calculation LM-0629 and summarized in License Amendment 128 for Unit 1 and License Amendment 99 for Unit 2.

As a result, the amounts of Degraded/Unqualified Coatings would not challenge the ECCS suction strainer limits to be of concern during a LOCA.

3.7.2 Containment Inservice Inspection Program (CISI)

LGS performs a comprehensive primary containment inspection to the requirements of American Society of Mechanical Engineers (ASME)Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," Subsection IWE, "Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants," and Subsection IWL, "Requirements for Class CC Concrete Components of Light-Water Cooled Plants." The LGS Containment Inservice Inspection Program began development in 1996, and the initial inspections were completed in April of 2000 (Unit 1) and April of 2001 (Unit 2). The components subject to Subsection IWE and IWL requirements are those which make up the containment structure, its leak-tight barrier (including integral attachments), and those that contribute to its structural integrity. Specifically included are Class MC pressure retaining components, including metallic shell and penetration liners of Class CC pressure retaining components, and their integral attachments. The initial ASME Code Inspection Plan was developed in accordance with the requirements of the 1992 Edition with the 1992 Addenda of ASME Boiler and Pressure Vessel Code,Section XI, Division 1, Subsections IWE and IWL, as modified by the NRC final rulemaking to 10 CFR 50.55a published in the Federal Register on August 8, 1996.

The initial inspections of the LGS metal/concrete containment have been completed. No significant conditions were found in the First CISI Interval; however, conditions were identified in the Second and Third CISI Interval, requiring application of additional augmented examination requirements under paragraph IWE-1240. During the Second and Third CISI Intervals, containment surfaces were identified by LGS and were designated as Examination Category E-C, per paragraph IWE-1240. The submerged portion of the suppression pool is required to receive a Subsection IWE examination during each ISI period not to exceed a maximum interval of 4 years (two refueling cycles).

As a result of license renewal, the ASME Section XI, Subsection IWE aging management program was enhanced to:

1. Manage the suppression pool liner and coating system to:

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 17 of 35

a. Remove any accumulated sludge in the suppression pool every refueling outage. *De-sludging in 1R18 was not performed due to the COVID-19 pandemic.

b. Perform an ASME IWE examination of the submerged portion of the suppression pool each ISI period. *The ASME IWE examination in 1R18 was not performed due to the COVID-19 pandemic. This is a one-time exception to the 4-year LR SER inspection interval.

c. Use the results of the ASME IWE examination to implement a coating maintenance plan to perform the following prior to the period of extended operation (Unit 1: 10/26/2024; Unit 2: 6/22/2029):

i. Local areas (less than 2.5 inches in diameter) of general corrosion that are greater than 100 mils plate thickness loss will be recoated in the outage they are identified. This plate thickness loss criterion for local areas will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME XI, Subsection IWE, Category E-C.

ii. Areas of general corrosion greater than 65 mils average plate thickness loss will be recoated-based on ranking of affected surface area, high to low. This plate thickness loss criterion for areas of general corrosion will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

d. Use the results of the ASME IWE examination to implement a coating maintenance plan to perform the following during the period of extended operation:

i. Local areas (less than 2.5 inches in diameter) of general corrosion that are greater than 100 mils plate thickness loss will be recoated in the outage they are identified. This plate thickness loss criterion for local areas will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

ii. Areas of general corrosion greater than 65 mils average plate thickness loss will be recoated in the outage they are identified. This plate thickness loss criterion for areas of general corrosion will also be used to determine when the submerged portions of the liner require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 18 of 35 The coating maintenance plan was initiated in the 2012 refueling outage for Unit 1 and the 2013 refueling outage for Unit 2. The coating maintenance plan will continue through the period of extended operation to ensure the coating protects the liner to avoid significant material loss.

2. Use the results of ASME IWE inspection of the submerged portions of the suppression pool downcomers to perform the following:

a. Local areas (less than or equal to 5.5 inches in any direction) that have 40 mils or more metal thickness loss will be recoated. This downcomer metal thickness loss criteria for local areas will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

b. Areas of general corrosion (greater than 5.5 inches in any direction) that have 30 mils or more metal thickness loss will be recoated. This downcomer metal thickness loss criteria for areas of general corrosion will also be used to determine when the submerged portions of the downcomers require augmented inspection in accordance with ASME Section XI, Subsection IWE, Category E-C.

The downcomer recoat and augmented inspection criteria will be implemented prior to receipt of the renewed licenses.

3. When IWE examinations are conducted, perform ultrasonic thickness measurements on four areas of submerged suppression pool liner affected by general corrosion. The ultrasonic thickness measurement requirements will be implemented prior to receipt of the renewed licenses.

4. Provide guidance for proper specification of bolting material, lubricant and sealants, and installation torque or tension to prevent or mitigate degradation and failure of structural bolting.

There will be no change to the schedule for these inspections as a result of the extended ILRT interval. Inspection period dates for the 3rd CISI inspection interval and projected period dates for the 4th CISI inspection interval are displayed in Table 3.7.2-1 and 3.7.2-2, respectively.

Table 3.7.2-1 LGS Unit 1 and 2 IWE Examination Schedule 3rd and 4th Inspection Interval LGS Unit 1 Interval/Period LGS Unit 2 2/1/2017 to 1/31/2021 Li1R17 Li1R18 3rd Interval 1st Period 2/1/2017 to 1/31/2020 Li2R14 Li2R15 2/1/2021 to 1/31/2024 Li1R19 3rd Interval 2nd Period 2/1/2020 to 1/31/2023 Li2R16 2/1/2024 to 1/31/2027 Li1R20 3rd Interval 3rd Period 2/1/2023 to 1/31/2027 Li2R17

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 19 of 35 Table 3.7.2-1 LGS Unit 1 and 2 IWE Examination Schedule 3rd and 4th Inspection Interval Li1R21 Li2R18 2/1/2027 to 1/31/2031 Li1R22 Li1R23 4th Interval 1st Period 2/1/2027 to 1/31/2031 Li2R19 Li2R20 2/1/2031 to 1/31/2035 Li1R24 Li1R25 4th Interval 2nd Period 2/1/2031 to 1/31/2035 Li2R21 Li2R22 2/1/2035 to 1/31/2039 Li1R26 Li1R27 4th Interval 3rd Period 2/1/2035 to 1/31/2039 Li2R23 Li2R24 Table 3.7.2-2 LGS Unit 1 and 2 IWL Examination Schedule 3rd and 4th Inspection Interval LGS Unit 1 LGS Unit 2 Li1R18 - 2020 Li2R16 - 2021 Li1R20 - 2024 Li2R18 - 2025 Li1R24 - 2030 Li2R21 - 2031 Li1R25 - 2034 Li2R23 - 2035 Edition and Addenda of the ASME Section XI Code LGS is currently committed to the following Editions and Addenda of the ASME Section XI Code.

American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, 2007 Edition with 2008 Addenda.

The applicable requirements of Subsection IWA (General Requirements), Subsection IWE (Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants), and Subsection IWL (Requirements of Class CC Concrete Components of Light-Water Cooled Plants) of the 2007 Edition with 2008 Addenda and the ASME Section XI Code shall apply to components and items classified as ASME Code Class MC or ASME Code Class CC.

In addition to the requirements of the ASME Section XI Code, the applicable modifications and limitations outlined in 10 CFR 50.55a(b)(2)(viii) and 50.55a(b)(2)(ix) shall also be implemented.

Code Cases Applicable ASME Section XI Code Cases are implemented in accordance with 10 CFR 50.55a(a)(3) and Regulatory Guide 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.

Relief Requests There are no Relief Requests implemented for the CISI program at this time.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 20 of 35 Identification of Class MC and/or CC Exempt Components Table 3.7.2-3, Class MC and/or CC Exempt Components Exam Category Item Number Description Applicability to LGS 1 & 2 E-A E1.30 Moisture Barriers Not Applicable L-B L2.10 Tendon Not Applicable L2.20 Wire or Strand Not Applicable L2.30 Anchorage Hardware and Surrounding Concrete Not Applicable L2.40 Corrosion Protection Medium Not Applicable L2.50 Free Water Not Applicable Augmented Inspections Table 3.7.2-4, Augmented Inspections Exam Category Item Number Description Total Number of Components1 E-C E4.11 Visible Surfaces Unit 1: 4 Unit 2: 0 E4.12 Surface Area Grid Minimum Wall Thickness Location Unit 1: 0 Unit 2: 0 L-A L1.12 Suspect Areas Unit 1: 0 Unit 2: 0 Note 1: There are currently 4 Unit 1 suppression pool downcomers that exceed the thickness loss criterion of the Subsection IWE Aging Management Program and are designated Category E-C, Item Number E4.11 components. There are currently no Unit 2 components that exceed the thickness loss criterion of the Subsection IWE Aging Management Program, therefore there are no Category E-C, Item Number E4.11 components for Unit 2.

Inaccessible Areas For Class MC applications, LGS shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, LGS shall provide the following in the ISI summary report as required by 10 CFR 50.55a(b)(2)(ix)(A):

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

2) An evaluation of each area, and the result of the evaluation; and

3) A description of necessary corrective actions.

In addition, for Class CC applications, LGS shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, LGS shall provide the following in the ISI summary report as required by 10 CFR 50.55a(b)(2)(viii)(E):

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 21 of 35

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

2) An evaluation of each area, and the result of the evaluation; and

3) A description of necessary corrective actions.

For Class MC applications LGS has performed evaluations for the acceptability of inaccessible areas in the suppression pool. These evaluations have been submitted with the ISI summary report for the outage in which the conditions were identified as required by 10 CFR 50.55a(b)(2)(ix)(A). For Class CC applications, LGS has not identified any conditions in the accessible areas that could indicate the presence of or result in degradation to inaccessible concrete surfaces that would require evaluation in accordance with 10 CFR 50.55a(b)(2)(viii)(E).

3.7.3 Supplemental Inspection Requirements TS 6.8.4.g requires, in part, that a primary containment leakage rate testing program be established in accordance with the guidelines contained in NEI 94-01, Revision 3-A. This requires 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 (3) other outages before the next Type A test if 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" In addition to the inspections performed by the IWE/IWL Containment Inspection Program, procedure ST-4-060-970-1, "Containment Structures Inservice Inspection," is performed for Unit 1 and ST-4-060-970-2, "Containment Structures Inservice Inspection," is performed for Unit 2.

These procedures inspect the structural integrity of the exposed accessible interior and exterior surfaces of the drywell and the containment, including the liner plate, shall be determined by a visual inspection of those surfaces prior to the Type A Containment Leak Rate Test. This inspection also fulfills the surveillance requirement of TS SR 4.6.1.2 and NEI 94-01.

3.7.4 Type B and Type C Testing Programs A significant number of Type B and Type C containment penetrations are local leak-rate tested (LLRTd) during each refueling outage in accordance with the performance-based testing requirements of 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. As stated in LGS Plant Technical Specification 6.8.4.g for Unit 1 and Unit 2, this testing is in accordance with the guidelines contained in NEI 94-01, Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

Type C testing is performed on Containment Isolation Valves in those piping systems which could become a potential leakage pathway from inside the Primary Containment to the outside environs following various accident scenarios up to and including the Design Basis Accident (DBA). Type B testing is performed on Primary Containment penetrations which do not

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 22 of 35 normally see flow, such as personnel and equipment air locks, equipment hatches, and electrical penetrations. All Primary Containment penetrations are tested at a pressure greater than or equal to the peak calculated internal pressure for the design basis accident, Pa (44.0 psig), unless otherwise specifically stated in the Primary Containment Leakage Rate Testing Program.

The Type B and C acceptance criteria are based on running totals of the cumulative leakage rates for all Type B and C penetrations. Acceptance criteria for Type B and C penetrations is less than or equal to 0.60 La, (94,964 sccm) min path, when the Primary Containment is required to be operable and 0.60 La max path, prior to entering a mode requiring the Primary Containment to be operable following testing in accordance with this Program. The testing frequency of Type B and C components is based on performance and may be extended from the base frequency of 30 months to a frequency of 120 months for Type B tests and 75 months for Type C tests. Certain components, such as MSIVs, Feedwater check valves, and Primary Containment Vent and Purge Valves are excluded from performance-based consideration and must be tested on the base 30-month frequency. LGS Technical Specification 3.6.1.2.c limits MSIV total leakage not to exceed 200 SCFH (94,389.5 sccm) for all four main steam lines, when tested at 22.0 psig.

Table 3.7.4-1: Unit 1 Types B & C Performance History OUTAGE MSIV AS-FOUND MIN PATH MSIV AS-LEFT MAX PATH TYPES B&C AS-FOUND MIN-PATH TYPE B&C AS-LEFT MAX-PATH Li1R20 (2024) 26.12 SCFH 121.58 SCFH 91,564.1 sccm 51,153.8 sccm Li1R19 (2022) 87.77 SCFH 102.97 SCFH 47,188.2 sccm 70,384.2 sccm Li1R18 (2020) 96.40 SCFH 146.63 SCFH 25,447.0 sccm 57,058.1 sccm Table 3.7.4-2: Unit 2 Types B & C Performance History OUTAGE MSIV AS-FOUND MIN PATH MSIV AS-LEFT MAX PATH TYPES B&C AS-FOUND MIN-PATH TYPE B&C AS-LEFT MAX-PATH Li2R18 (2025) 88.15 SCFH 176.29 SCFH 27,770.3 sccm 40,172.6 sccm Li2R17 (2023) 45.69 SCFH 60.59 SCFH 19,510.9 sccm 32,554.2 sccm Li2R16 (2021) 93.41 SCFH 186.81 SCFH 36,034.1 sccm 41,624.9 sccm Li2R15 (2019) 86.57 SCFH 150.62 SCFH 22,906.5 sccm 37,527.8 sccm The above tables demonstrate that the Type B and Type C primary containment leakage rate testing program is well maintained and has a reasonably large margin with regard to the overall Primary Containment Leakage Rate Testing Program.

Installation of the DMP will require the affected components scheduled for Type B/C testing to have their test procedures revised to account for the new digital control system being installed versus the existing analog system. There will be no changes to the actual valve or penetration configurations in the plant, or test methodology. LGS does not foresee any instances where the DMP will affect our ability to comply with the requirements of ANSI/ANS 56.8 Section 3.3.3.

3.8 Results of Recent Inspections

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 23 of 35 3.8.1 Drywell and Wetwell Coatings 3.8.1.1 LGS Unit 1 - Li1R20 - 2024 3.8.1.1.1 Drywell The overall condition of the protective coatings inside the Drywell including on the Drywell Liner, Biological Shield Wall, Drywell Floor, Subpile Room, and installed steel are good with no new indications of degradation or damage reported in Li1R20. Previously identified and evaluated indications are as follows: Coating chips due to mechanical damage on the Drywell Liner and Biological Shield wall on all elevations of the Drywell. Locations of missing coating due to mechanical surface preparation around installed and previously removed piping hangers on all elevations on the Drywell liner. Chipped coating and light surface corrosion (237 11 elevation around 180-270 degrees AZ) on the Subpile Room floor. Small <1" diameter coating chips with light surface corrosion on the inside of the Drywell Head. These previously identified indications have remained largely unchanged with no change in condition noted in subsequent inspection reports.

3.8.1.1.2 Suppression Pool The coatings in the vapor space of the suppression pool (SP) including the SP wall liner, RPV pedestal liner, Main Steam Relief Valve (MSRV) discharge downcomers, and installed steel are in overall good condition with no new damage or degradation identified. The SP roof does show a loss of coating and surface corrosion; however, this condition has been previously evaluated and was deemed acceptable.

The conditions of the coatings on the immersed portion of the suppression pool varies depending upon the panel/region. The suppression pool liner was originally coated in a sacrificial inorganic zinc coating, Dimetcote 6N. After nearly 30 years of operation, with the IOZ coating having reached depletion, a Large Area recoating/repair project began in Li1R15. This project spanning multiple outages, replaces the depleted inorganic zinc coating with a new qualified epoxy lining, BIO-DUR 560BLUE. As of Li1R20 4128ft2 of liner has been recoated.

Additional information on the coating condition is discussed in Section 3.8.2.4, Containment Liner, IWE - Wetted Surfaces of Submerged Areas and BWR Vent System.

3.8.1.2 LGS Unit 2 - Li2R18 - 2025 3.8.1.2.1 Drywell The overall condition of the protective coatings inside the Drywell including on the Drywell Liner, Biological Shield Wall, Drywell Floor, Subpile Room, and installed steel are good with some indications of degradation or damage reported in Li2R18. Previously identified and evaluated indications are as follows: Coating chips due to mechanical damage on the Drywell Liner and Biological Shield wall on all elevations of the Drywell. Small areas of missing coating (approx.

0.5in2) between the 210 and 260 degree AZ on the inside of the Drywell Head. These previously identified indications have remained largely unchanged with no change in condition noted in subsequent inspection reports. There are approximately 50 new locations of damage

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 24 of 35 identified by the Site Coatings Engineer during Li2R18, conservatively estimated to be 2ft2 of damage. These areas included some small damage across EL238-285, and more significant damage to the Biological Shield Liner on EL 296 and 303. In all identified locations, the damage was to the liner coating only, not to the steel liner plate.

3.8.1.2.2 Suppression Pool The coatings in the vapor space of the suppression pool including the SP pool wall liner, RPV pedestal liner, MSRV Discharge downcomers, and installed steel are in overall good condition with no new damage or degradation identified. The suppression pool roof does show surface corrosion; however, this condition has been previously evaluated and deemed acceptable.

The conditions of the coatings on the immersed area of the suppression pool varies depending upon the panel/region. The suppression pool liner was originally coated in a sacrificial inorganic zinc coating, Dimetcote 6N. After 25 years of operation, with the inorganic zinc coating having reached depletion, a Large Area recoating/repair project began in Li2R13. This project spanning multiple outages, replaces the depleted inorganic zinc coating with a new qualified epoxy lining, BIO-DUR 560BLUE. As of Li2R17, 4945ft2 of liner has been recoated. Recoating of the liner continued in Li2R18. However, LGS is awaiting the final report from the vendor to update this total. Additional information on the coating condition is discussed in Section 3.8.2.4, Containment Liner, IWE - Wetted Surfaces of Submerged Areas and BWR Vent System.

3.8.1.3 Conclusion The current condition of the containment coatings does not adversely impact structural integrity, plant operations, or the safe shutdown of the plant. The Protective Coating Monitoring and Maintenance Program provides for coating system inspection, assessment, and repair for any condition that could adversely affect the ability of Service Level I coatings to function as intended. The routine coating assessment during outages will continue to be performed.

3.8.2 CISI Program Inspection Results The LGS CISI program is based on the examination methods and frequencies identified in ASME Section XI Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants, and Subsection IWL, Requirement for Class CC Concrete Components of Light-Water Cooled Plants as enhanced by the LGS aging management program. The program consists of periodic inspection of the primary containment liner plate surfaces, components, penetrations inside and outside containment, and concrete surfaces to identify loss of leak-tightness or areas of deterioration. Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME Section XI, Subsection IWE or IWL requirements, as applicable, or corrected in accordance with the corrective action program.

3.8.2.1 CISI on Containment Liner CISI of the Unit 1 containment liner was last performed during Li1R20 (2024) for ASME Section XI IWE inspection requirements. The following observations were documented.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 25 of 35 Visual examination of the subpile room interior walls and floor identified coatings degradation due to chipped paint, discoloration, blistering, and rust buildup on the floor.

This indication was previously identified, evaluated as acceptable, and determined to be essentially unchanged. No additional actions were necessary.

Visual examination of the drywell head noted an area of mechanical damage on the drywell head flange between bolt location #51 and #52. Additionally, areas of chipped coatings were identified between bolt holes and various areas around the ID and OD of the drywell head. These indications were previously identified, evaluated as acceptable, and determined to be essentially unchanged. No additional actions were necessary.

CISI of the Unit 2 containment liner was last performed during Li2R17 (2023) for ASME Section XI IWE inspection requirements. The following observations were documented.

Visual examination of the containment head manway (penetration X-4) bolted connection identified degradation of the gasket sealing surface. This containment bolted connection is leak rate tested every outage. Previous exam history was reviewed and determined to be acceptable. The leak rate test was also performed in Li2R18 and determined to be acceptable. No additional actions were necessary.

3.8.2.2 CISI on Concrete Containment CISI of the Unit 1 concrete containment was last performed during Li1R20 (2024) for ASME Section XI IWL inspection requirements. The following observations were documented.

Visual examination of the bio-shield identified a white, crystalline deposit around the outside of the bio-shield. This indication was previously identified. The source of the deposits was previously determined to be from the grout that is inside the bio-shield.

Previous chemical analysis determined that the deposits were not corrosive to the carbon steel liner unless the deposits were exposed to standing water. The identified areas are located on the bio-shield in the upper elevations of the drywell and are not subject to standing water. The condition was determined essentially unchanged, and no additional actions were necessary.

Light surface rusting with no apparent material loss of the diaphragm slab form work (Q-decking) was noted. This condition was previously identified, evaluated as acceptable, and determined to be essentially unchanged. No additional actions were necessary.

General visual examination of the outside containment concrete surfaces noted previously identified conditions that were determined to be unchanged. The conditions consisted of flaking paint, hairline surface cracks, and a small popouts. These indications were previously evaluated as acceptable, and no additional actions were necessary. These indications are described in more detail in Amendment 241 for LGS Unit 1 (Reference 10).

General visual examination of the outside containment concrete surfaces noted previously identified conditions in the area of penetration X-8, X-14, and X-59A. The conditions consisted of missing grout and linear concrete indications extending from the base plate of penetration X-59A. These indications were previously evaluated as

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 26 of 35 acceptable, and no additional actions were necessary. These indications are described in more detail in Amendment 241 for LGS Unit 1 (Reference 10).

CISI of the Unit 2 concrete containment was last performed during Li2R18 (2025) for ASME Section XI IWL inspection requirements. The following observations were documented.

Light surface rusting with no apparent material loss of the diaphragm slab form work (Q-decking) was noted. This condition was previously identified, evaluated as acceptable, and determined to be essentially unchanged. No additional actions were necessary.

A surface crack that runs the length of Room 184 and 184A was noted. This indication was determined to be a crack in the wall coating and appeared to have been previously repaired. No additional actions were necessary.

A previously identified surface crack that runs the length of Room 174 was noted. This indication was determined to be a crack in the wall coating and appeared to have been previously repaired. No additional actions were necessary.

A previously identified concrete pop out in Room 479 was noted. This condition was previously identified, evaluated as acceptable, and determined to be essentially unchanged. No additional actions were necessary.

3.8.2.3 CISI on Penetrations for Inside and Outside Containment All containment penetrations are inspected from inside and outside containment as part of the periodic visual examinations of the containment liner required by ASME XI, Subsection IWE.

No unacceptable conditions were identified on the containment penetrations during the last IWE examinations which were performed in Li1R20 (2024) for Unit 1 and Li2R17 (2023) for Unit 2.

3.8.2.4 Containment Liner, IWE - Wetted Surfaces of Submerged Areas and BWR Vent System As part of license renewal, the LGS Subsection IWE program was enhanced to require that the submerged portion of the suppression pool receive a Subsection IWE examination during each ISI period not to exceed a maximum interval of 4 years (two refueling cycles).

Subsection IWE examination of the submerged portion of the Unit 1 suppression pool liner and vent system was last performed during Li1R20 (2024). The activities performed are summarized below:

During Li1R20, underwater desludging, ASME XI, Subsection IWE inspections, and large area coating repairs were performed.

o Removal of any accumulated sludge was performed to improve water clarity for ASME Section XI, Subsection IWE inspections, coating repairs, general water quality, and to remove any foreign material that might affect ECCS strainer operation. Sludge accumulations on the floor and components were consistent with previous outage results.

o ASME Section XI, Subsection IWE inspection activities including visual examination of all accessible floor and wall liner plates, integral attachments,

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 27 of 35 and downcomers were performed. Coatings and base metal deficiencies found on the liner plates were consistent with previous inspections and include evidence of random spot corrosion, general corrosion, and tiger striping. No indications were identified exceeding the corrosion allowance of the ASME Section XI, Subsection IWE aging management program.

o ASME Section XI, Subsection IWE visual examinations included examination of the four suppression pool downcomers that previously exceeded the metal thickness loss criteria of the IWE aging management program. These Category E-C components received a VT-1 examination, and it was determined that the condition was essentially unchanged from the previous inspection.

o ASME Section XI, Subsection IWE visual examinations were also performed in the normally inaccessible areas behind the "D" residual heat removal (RHR) suction strainers which were removed from their penetrations to provide access.

The overall condition of the existing coating system and liner plates in these areas was described as "similar to" or "more degraded than" the adjacent accessible areas for each adjacent panel. Following visual examination, the inaccessible areas behind the "D" RHR suction strainers were recoated with a qualified coating system.

o Large area coating repairs were performed as required by the ASME Section XI, Subsection IWE aging management program. Repairs were performed to floor and wall liner panels throughout the Unit 1 suppression pool. Repairs were also performed in the previous inaccessible areas behind the "D" RHR suction strainers.

During desludging of the suppression pool, in preparation for visual inspections, a small hole (approx. 3/64-inch diameter) was identified in the top of the inner leak chase channel in the northwest corner of the "m" tee-quencher. The presence of a hole in the leak chase channel allows for suppression pool water to fill the volume of the leak chase channel and contact the underlying liner plate and weld. Li1R20 is the first outage this condition has been identified in either unit. The condition was evaluated and determined acceptable until the next required ASME Section XI, Subsection IWE inspection which will occur no later than 2028. Additionally, the impact to the inaccessible area was evaluated as required by 10 CFR 50.55a(b)(2)(ix)(A) and submitted with the Li1R20 Outage Summary Report.

During Li1R20 ASME Section XI, Subsection IWE inspections, two liner plate bulges were reported. These areas were described as areas where the liner plate had an upward deflection from the normal plane of the plate. Similar bulge indications have been previously identified in the Unit 1 and Unit 2 suppression pool. The bulge areas were ultrasonically examined, and it was determined that there was no material loss and significant margin existed to all established repair criteria. Therefore, these locations were accepted with no additional action required.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 28 of 35 Subsection IWE examination of the submerged portion of the Unit 2 suppression pool liner and vent system was last performed during Li2R17 (2023). The activities performed are summarized below:

During Li2R17, underwater desludging, ASME XI, Subsection IWE inspection, and large-area coating repairs were performed.

o Removal of any accumulated sludge was performed to improve water clarity for ASME Section XI, Subsection IWE inspections, coating repairs, general water quality, and to remove any foreign material that might affect ECCS strainer operation. Sludge accumulations on the floor and components were consistent with previous outage results.

o ASME Section XI, Subsection IWE inspection activities including visual examination of all accessible floor and wall liner plates, integral attachments, and downcomers were performed. Coatings and base metal deficiencies found on the liner plates were consistent with previous inspections and include evidence of random spot corrosion, general corrosion, and tiger striping. No indications were identified exceeding the corrosion allowance of the ASME Section XI, Subsection IWE aging management program.

o ASME Section XI, Subsection IWE visual examinations were also performed in the normally inaccessible areas behind the "B" residual heat removal (RHR) suction strainers which were removed from their penetrations to provide access.

The overall condition of the existing coating system and liner plates in these areas was consistent with accessible areas of the surrounding panels.

o Large area coating repairs were performed as required by the ASME Section XI, Subsection IWE aging management program. Repairs were performed to floor and wall liner panels throughout the Unit 2 suppression pool. Repairs were also performed in the previously inaccessible areas behind the "B" RHR suction strainers.

During Li2R18, underwater desludging, a limited ASME XI, Subsection IWE inspection, and large area coating repairs were performed.

o Removal of any accumulated sludge was performed to improve water clarity for limited ASME Section XI, Subsection IWE inspections, coating repairs, general water quality, and to remove any foreign material that might affect ECCS strainer operation. Sludge accumulations on the floor and components were consistent with previous outage results.

o ASME Section XI, Subsection IWE visual examinations were limited to the normally inaccessible areas behind the C residual heat removal (RHR) and C core spray (CS) suction strainers which were removed from their penetrations to provide access. The overall condition of the existing coating system and liner plates in these areas was consistent with accessible areas of the surrounding panels.

o Large area coating repairs were performed as required by the ASME Section XI, Subsection IWE aging management program. Repairs were performed on the

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 29 of 35 floor and wall liner panels throughout the Unit 2 suppression pool. Repairs were also performed in the previously inaccessible areas behind the C RHR and C CS suction strainers.

During Li2R18 suppression pool diving activities, three leak chase channel test plugs were found to be loose or missing. This condition allows for suppression pool water to fill the volume of the leak chase channel and contact the underlying liner plate and weld.

Li2R18 is the first outage this condition has been identified in Unit 2. The condition was evaluated and determined acceptable until the next required ASME XI, Subsection IWE inspection which will occur in Li2R19 (2027). Additionally, the impact to the inaccessible area was evaluated as required by 10 CFR 50.55a(b)(2)(ix)(A) and submitted with the Li2R18 Outage Summary Report.

3.8.2.5 Conclusion The above observations identified through CISI inspections on the containment liner plate surfaces, components, penetrations inside and outside containment, and concrete surfaces were evaluated and determined to be acceptable. There is no adverse effect on the metallic liner with respect to the design intent and the overall structural integrity of the containment system is maintained. Continued inspections in accordance with the ASME Section XI CISI program and the ASME Section XI, Subsection IWE and IWL aging management programs will allow for timely identification and resolution of any adverse conditions that could impact the containment system.

3.9 Drywell Bypass Leak Rate Test (DWBT) Assessment As described in TS Bases 3/4.6.2 Depressurization Systems, during a LOCA, potential leak paths between the drywell and suppression chamber airspace could result in excessive containment pressures, since the steam flow into the airspace would bypass the heat sink capabilities of the chamber. Potential sources of bypass leakage are the suppression chamber-to-drywell vacuum breakers (VBs), penetrations in the diaphragm floor, and cracks in the diaphragm floor and/or liner plate and downcomers located in the suppression chamber airspace. The containment pressure response to the postulated bypass leakage can be mitigated by manually actuating the suppression chamber sprays. An analysis was performed for a design bypass leakage area of 0.0500 ft² to verify that the operator has sufficient time to initiate the sprays prior to exceeding the containment design pressure of 55 psig. The Technical Specification limit of 10% of the design value of 0.0500 ft² ensures that the design basis for the steam bypass analysis is met.

As previously mentioned in Amendments 241 (Unit 1) and 204 (Unit 2) (ML19351E376), a review of the past test history for the DWBT contained no failures. See Tables 3.9-1 and 3.9-2 below for historical DWBT test results at LGS, Units 1 and 2:

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 30 of 35 Table 3.9 Unit 1 DWBT Historical Results Year Measured Leakage (ft2)

Acceptance Criteria (ft2) 1984 0.00026 0.005 1987 0.00005133 0.005 1990 0.000278 0.005 1998 0.000075 0.005 2012 0.000151 0.005 Table 3.9 Unit 2 DWBT Historical Results Year Measured Leakage (ft2)

Acceptance Criteria (ft2) 1989 0.000069 0.005 1993 0.000076 0.005 1999 0.000012 0.005 2013 0.000137 0.005 The history of test results indicates that the typical leakage is about an order of magnitude or more below the acceptance criteria (which is set at an order of magnitude below the design basis limit).

In addition to the inspections outlined in Sections 3.7 & 3.8 of the LAR, which cover most of the potential leak paths described above, TS 4.6.2.1.f requires the suppression chamber-to-drywell vacuum breakers to be tested every refueling outage for which the drywell bypass leak rate test is not performed. Therefore, the most likely largest contributor to the bypass leakage will still be monitored each RFO and, thus, will continue to be managed and controlled to assure TS leakage is maintained.

The vacuum breaker leakage test and stringent acceptance criteria, combined with the historical negligible non-vacuum breaker leakage, and thorough periodic visual inspection provide an equivalent level of assurance as the DWBT that the drywell to suppression chamber bypass leakage can be measured, and any adverse condition detected prior to a LOCA.

3.10 Regulatory Issue Summary (RIS) 2008-27 In RIS 2008-27 (Reference 6), the NRC has established its position on the extension of the containment Type A test interval beyond 15 years under 10 CFR Part 50, Appendix J, Option B.

The NRC will consider such extensions only under compelling circumstances. As stated earlier, the license amendment request should demonstrate:

a sound technical justification and/or undue hardship or unusual difficulty; the requested amendment poses minimal safety risk; acceptable plant-specific containment performance, including a plant-specific risk informed analysis; and that containment does not have a history of significant degradation issues.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 31 of 35 In the framework of the Digital Modernization project, around 1800 safety-related components are being replaced with software functionalities. This transition will require approximately 2100 changes to operational procedures and about 900 revisions to instrumentation and control procedures. During the modification process, the station will perform a Modification Acceptance Test (MAT), which will entail evaluating the new platform's logic as it interfaces with the plant components through the software. The MAT test will require the station to maneuver the plant into numerous configurations which will require every affected component to be stroked/started/etc. (approx. 500 iterations), and each system will need to be tested for full functionality to ensure OPERABILITY. The majority of this testing will be performed in OPERATIONAL CONDITION (OPCON) 5 (i.e., MODE 5) with additional testing in OPCON 2.

As stated earlier, the DMP was originally scheduled for installation in the prior refueling outages and there would not have been a conflict with the currently scheduled ILRTs, but regulatory approval was not obtained. With the ILRT being performed in OPCON 4, the first-in-the-industry MAT of the large scale digital instrumentation upgrade cannot be completed without a multi-day interruption. Additionally, the ILRT will require a major re-write as many of its components will now be controlled/manipulated digitally rather than via the original analog means. This constitutes a hardship and deferral of the ILRT will minimize the potential risk caused by this interruption.

Based on the results of previous Type A (and associated DWBT), Type B, and Type C tests performed at LGS Units 1 & 2, along with recent IWE and IWL examinations, the LGS Unit 1 and Unit 2 containments do not have a history of significant degradation issues (Sec. 3.5 & 3.7 thru 3.9). The plant-specific risk analysis demonstrates that the increased risk due to an extension of approximately thirteen months to the containment Type A tests is minimal (Sec. 3.6 and Attachment 3) and this request satisfies the concerns raised in RIS 2008-27.

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(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." 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 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.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 32 of 35 The one-time extension of the frequency of the containment Type A test will not affect the design, fabrication, or construction of the containment structure, and the design will continue to account for the effects of natural phenomena. The containment Type A test will continue to be done in accordance with 10 CFR 50 Appendix J using 10 CFR 50 Appendix B quality standards.

The frequency of the containment Type A test is being changed in accordance with standards reviewed and approved as compliant with Appendix J. Therefore, there will be no instances where the applicable regulatory criteria are not met.

CEG has determined that the proposed change does not require any exemptions or relief from regulatory requirements, other than the TS, and does not affect conformance with any regulatory requirements/criteria.

4.2 Precedent The proposed amendment incorporates into the LGS Unit 1 and 2 Technical Specifications a change that is similar (i.e., an ILRT interval greater than 15 years), to the following license amendments previously approved by the NRC to extend the Type A test frequency:

September 3, 2020 (ML20213C704), for Donald C. Cook Nuclear Plant, Unit 1

• December 20, 2018 (ML18337A422), for Indian Point Nuclear Generating Station, Unit 3 April 27, 2009 (ML090570892), for Kewaunee Power Station, Unit 1 March 24, 2006 (ML060520032), for Seabrook Station, Unit 1 February 9, 2006 (ML060410310), for River Bend Station Unit 1

• - A number of plants besides D.C. Cook requested extensions in 2020-2021 due to the Covid-19 virus.

4.3 No Significant Hazards Consideration In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Constellation Energy Generation, LLC (CEG) requests an amendment to Facility Operating License No. NPF-39 and NPF-85 for Limerick Generating Station (LGS),

Units 1 and 2. The proposed change would allow for a one-time extension to the 15-year frequency of the containment leakage rate test (i.e., integrated leakage rate test (ILRT) or Type A test). This test is required by Technical Specifications (TS) Section 6.8.4.g, "Primary Containment Leakage Rate Testing Program." The proposed one-time change to the TS would permit the current ILRT interval of 15 years to be extended by 13 months for LGS Unit 1 and 12 months for LGS Unit 2.

CEG has evaluated whether a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:

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

Response: No

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 33 of 35 The proposed change involves changes to the LGS Unit 1 and 2 containment leakage rate testing programs. The proposed change does not involve a physical change to the plants or a change in the manner in which the plants are operated or controlled. The primary containment function is to provide an essentially leak-tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment itself, and the testing requirements to periodically demonstrate the integrity of containment, exist to ensure the plant's ability to mitigate the consequences of an accident and do not involve any accident precursors or initiators.

The proposed change modifies 6.8.4.g, to allow for a one-time extension to the containment Type A test interval. The potential consequences of extending the containment Type A test interval one-time by 13 months for Unit 1 and 12 months for Unit 2 have been evaluated by analyzing the resulting changes in risk. The increase in risk in terms of person-rem per year within 50 miles resulting from design basis accidents was estimated to be acceptably small and determined to be within the guidelines published in the NRC Final Safety Evaluation for NEI Topical Report (TR) 94-01, Revision 3-A. Additionally, the proposed change maintains defense-in-depth by preserving a reasonable balance among prevention of core damage, prevention of containment failure, and consequence mitigation. CEG has determined that the increase in conditional containment failure probability due to the proposed change would be very small. Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No The proposed change modifies TS 6.8.4.g, to allow for a one-time extension to the containment Type A test interval. Containment, and the testing requirements to periodically demonstrate the integrity of containment, exist to ensure the plant's ability to mitigate the consequences of an accident and do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plants (i.e.,

no new or different type of equipment will be installed) or a change to the manner in which the plants are operated or controlled.

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

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

Response: No The proposed change modifies TS 6.8.4.g, to allow for a one-time extension to the containment Type A test interval. The proposed change does not alter the manner in which safety limits, limiting safety system setpoints, or limiting conditions for operation are determined. The specific requirements and conditions of the containment leakage

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 34 of 35 rate testing program, as defined in the TS, ensure that the degree of primary containment structural integrity and leak-tightness that is considered in the plant's safety analysis is maintained. Containment inspections performed in accordance with other plant programs serve to provide a high degree of assurance that containment would not degrade in a manner that is not detectable by an ILRT. A risk assessment concluded that extending the ILRT test interval one-time by 13 months for Unit 1 and 12 months for Unit 2 results in a very small change to the risk profile (Attachment 3).

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above evaluation, CEG concludes that the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92, paragraph (c), and accordingly, a finding of no significant hazards consideration is justified.

4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will 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 the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

CEG 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, "Standards for Protection Against Radiation." 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, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," paragraph (c)(9). Therefore, pursuant to 10 CFR 51.22, paragraph (b), no environmental impact statement or environmental assessment needs to be prepared in connection with the proposed amendment

6.0 REFERENCES

1. US NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, Revision 0, September 1995.

2. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, July 21, 1995.

3. NUREG-1493, Performance-Based Containment Leak-Test Program, Final Report, September 1995.

U.S. Nuclear Regulatory Commission License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency Docket Nos. 50-352 and 50-353 : Evaluation of Proposed Changes Page 35 of 35

4. Electric Power Research Institute (EPRI) TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994.

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

6. Regulatory Issue Summary (RIS) 2008-27, "Staff Position on Extension of the Containment Type A Test Interval Beyond 15 Years Under Option B of Appendix J to 10 CFR Part 50," dated December 8, 2008.

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

8. NRC Safety Evaluation Report, Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (TAC No. MC9663),

June 25,2008.

9. NRC Safety Evaluation Report, Safety Evaluation by the Office of Nuclear Reactor Regulation Nuclear Energy Institute Topical Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J Nuclear Energy Institute Project No. 689, June 8, 2012.

10. Amendment 241 for LGS Unit 1.

11. Amendment 204 for LGS Unit 2.

12. Electric Power Research Institute (EPRI) TR-1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, October 2008.

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

14. Methodology for Calvert Cliffs to Estimate the Likelihood and Risk Implications of Corrosion-Induced Leakage Going Undetected During the Extended Test Interval.

ATTACHMENT 2 Markup of Technical Specifications Page Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353 UNIT 1 REVISED TECHNICAL SPECIFICATIONS PAGE 6-14c UNIT 2 REVISED TECHNICAL SPECIFICATIONS PAGE 6-14c

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued) g.

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 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008. The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.5%

of primary containment air weight per day.

Leakage rate acceptance criteria are:

a.

Primary Containment leakage rate acceptance criterion is less than or equal to 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are less than or equal to 0.60 La for the Type B and Type C tests and less than or equal to 0.75 La for Type A tests; b.

Air lock testing acceptance criteria are:

1)

Overall airlock leakage rate is less than or equal to 0.05 La when tested at greater than or equal to Pa.

2)

Seal leakage rate is less than or equal to 5 scf per hour when the gap between the door seals is pressurized to 10 psig.

The provisions of Specification 4.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program.

The provisions of Specification 4.0.3 are applicable to the tests described in the Primary Containment Leakage Rate Testing Program.

h.

Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

A change in the TS incorporated in the license; or A change to the UFSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d.

Proposed changes that meet the criteria of b. above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

LIMERICK - UNIT 1 6-14c Amendment No. 118, 162, 190, 241 Insert A Start new paragraph

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued) g.

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 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, dated July 2012, and the Limitations and Conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 44.0 psig.

The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.5% of primary containment air weight per day.

Leakage rate acceptance criteria are:

a.

Primary Containment leakage rate acceptance criterion is less than or equal to 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are less than or equal to 0.60 La for the Type B and Type C tests and less than or equal to 0.75 La for Type A tests; b.

Air lock testing acceptance criteria are:

1) Overall airlock leakage rate is less than or equal to 0.05 La when tested at greater than or equal to Pa.

2) Seal leakage rate is less than or equal to 5 scf per hour when the gap between the door seals is pressurized to 10 psig.

The provisions of Specification 4.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program.

The provisions of Specification 4.0.3 are applicable to the tests described in the Primary Containment Leakage Rate Testing Program.

h.

Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

A change in the TS incorporated in the license; or A change to the UFSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d.

Proposed changes that meet the criteria of b. above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

LIMERICK - UNIT 2 6-14c Amendment No. 81, 124, 151, 204 Insert B

TS 6.8.4.g TS change Insert A as modi"ed by the following exceptions: (1) the next Type A test performed after the March 2012 Type A test shall be performed no later than April 30, 2028, and (2) if the Type A test has not been performed by April 30, 2028, and the unit is in Mode 4 or 5, the Type A test shall be performed prior to entering Mode 2 Insert B as modi"ed by the following exceptions: (1) the next Type A test performed after the April 2013 Type A test shall be performed no later than April 30, 2029, and (2) if the Type A test has not been performed by April 30, 2029, and the unit is in Mode 4 or 5, the Type A test shall be performed prior to entering Mode 2

ATTACHMENT 3 Risk Assessment for LGS Regarding the ILRT (Type A) and DWBT One-Time Extension Request Limerick Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-39 and NPF-85 NRC Docket Nos. 50-352 and 50-353

Risk Impact Assessment of Extending the LGS ILRT/DWBT Interval LG-LAR-037 RM DOCUMENTATION NO. LG-LAR-037 REV: 0 PAGE NO.

1 STATION: Limerick Generating Station (LGS)

UNIT(s) AFFECTED: 1 & 2 TITLE: Risk Assessment for LGS Regarding the ILRT (Type A) and DWBT One-Time Extension Request

SUMMARY

LGS is pursuing a License Amendment Request (LAR) for a one-time extension of the Type A Integrated Leak Rate Test (ILRT) and Drywell Bypass Test (DWBT) to approximately 16 years and one month.

The purpose of this document is to provide an assessment of the risk associated with implementing a one-time extension of the LGS Unit 1 and Unit 2 containment ILRT and DWBT interval to 16.25 years.

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

[ ] Review required after periodic update

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

Microsoft Excel LGS-16yr-ILRT-Base-Final.xlsx, 02/28/2025, 12:09 PM 804 KB Microsoft Excel LGS-16yr-ILRT-Sens-Final.xlsx, 02/28/2025, 12:14 PM 805 KB Method of Review: [ X ] Detailed [ ] Alternate [ ] Review of External Document This RM documentation supersedes: N/A Prepared by:

Grant Teagarden

/

See attached email for approval

/

2/28/2025 Print Sign Date Reviewed by:

Don Vanover

/

See attached email for approval

/

2/28/2025 Print Sign Date Approved by:

Suzanne Loyd

/

See attached email for approval

/

2/28/2025 Print Sign Date Docket Nos. 50-352 and 50-353 ATTACHMENT 3 1 of 108

TABLE OF CONTENTS Section Page 1.0 OVERVIEW....................................................................................................... 1-1 1.1 PURPOSE.............................................................................................. 1-1

1.2 BACKGROUND

...................................................................................... 1-2 1.3 ACCEPTANCE CRITERIA...................................................................... 1-4 2.0 METHODOLOGY.............................................................................................. 2-1 3.0 GROUND RULES.............................................................................................. 3-1 4.0 INPUTS.......................................................................................................... 4-1 4.1 GENERAL RESOURCES AVAILABLE................................................... 4-1 4.2 PLANT-SPECIFIC INPUTS.................................................................... 4-7 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE).............................. 4-18 4.4 IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE......................................... 4-21 5.0 RESULTS.......................................................................................................... 5-1 5.1 STEP 1 - QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR........................................................................... 5-3 5.2 STEP 2

DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR...................................... 5-9 5.3 STEP 3 - EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL............................................................................................ 5-12 5.4 STEP 4 - DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY......................................................... 5-15 5.5 STEP 5 - DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY........................................... 5-15 5.6

SUMMARY

OF INTERNAL EVENTS RESULTS.................................. 5-16 5.7 EXTERNAL EVENTS CONTRIBUTION............................................... 5-18 5.7.1 Fire Risk................................................................................ 5-18 5.7.2 Seismic Risk......................................................................... 5-19 5.7.3 Other External Event Risk..................................................... 5-19 5.7.4 External Events Impact Summary......................................... 5-20 5.7.5 External Events Impact on ILRT Extension Assessment...... 5-21 5.8 CONTAINMENT OVERPRESSURE IMPACTS ON CDF..................... 5-24 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 2 of 108

6.0 SENSITIVITIES................................................................................................. 6-1 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS................... 6-1 6.2 EPRI EXPERT ELICITATION SENSITIVITY.......................................... 6-2 6.3 MODEL CHANGES SENSITIVITY......................................................... 6-4

7.0 CONCLUSION

S................................................................................................ 7-1

8.0 REFERENCES

.................................................................................................. 8-1 A

PRA TECHNICAL ACCEPTABILITY B

BYPASS LEAK RATE TEST RISK ASSESSMENT Docket Nos. 50-352 and 50-353 ATTACHMENT 3 3 of 108

Risk Impact Assessment of Extending the LGS ILRT/DWBT Interval 1-1 LG-LAR-037 1.0 OVERVIEW The risk assessment associated with implementing a one-time extension of the Limerick Generating Station (LGS) Unit 1 and Unit 2 Type A Integrated Leak Rate Test (ILRT) and Drywell Bypass Test (DWBT) interval to 16.25 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 one-time extension of the LGS Units 1 and 2 containment Type A ILRT interval by approximately 15 months, i.e., from 15 years to 16.25 years (a value of 16.25 years is used in this analysis) to permit focus on digital control upgrades during the prior refueling outage for each unit. The extension interval requested is anticipated to be 16 years 1 month for Unit 1 (16.08 yr frequency) and 16 years for Unit 2 (16.0 yr frequency).

The use of a 16.25 year frequency (16 years 3 months) in the risk assessment therefore provides conservative analytical margin.

The risk assessment follows the guidelines from NEI 94-01 [1], the methodology outlined in Electric Power Research Institute (EPRI) TR-104285 [2] as updated by the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (EPRI TR-1018243) [3], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plants 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 EPRI TR-1018243 [3].

This analysis also provides a risk assessment of extending the plants Drywell to Suppression Chamber Bypass Leak Test (also referred to as the Drywell Bypass Test -

DWBT) interval from 15 years to 16.25 years. Technical specification 4.6.2.1.e specifies that the DWBT be conducted to coincide with the Type A ILRT. The change to the DWBT Docket Nos. 50-352 and 50-353 ATTACHMENT 3 4 of 108

interval can impact the ILRT dose metrics because bypass leakage above nominal through the drywell to the outer wetwell airspace would bypass potential fission product scrubbing in the suppression pool. The DWBT risk assessment is performed in Appendix B separate from the Type A Test assessment in the main body of the calculation. The DWBT risk assessment is performed consistent with the guidelines set forth in NEI 94-01

[1], the methodology used in EPRI TR-1018243 [3], and the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a licensee request for changes to a plants licensing basis, Reg. Guide 1.174 [4]. The DWBT risk assessment is also performed consistently with the permanent extension request to 15 years [29].

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 NRCs rulemaking basis, NEI undertook a similar study. The results of that study are documented in EPRI 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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 5 of 108

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 LGS. The current analysis is being performed to confirm these conclusions based on LGS 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 LGS U1 and U2 employs the EPRI 1018243 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary. The methodology to evaluate the impact of concurrently extending the DWBT interval is performed consistent with previous one-time ILRT/DWBT extensions for BWR Mark II containment types including the Limerick one-time assessment [27], and Columbia [28], which were approved by the NRC. Additionally, the methodology is similar to that used for the LGS 15-year ILRT risk assessment supporting the LGS ILRT permanent extension LAR [29] approved by the NRC [30], and the Clinton Power Station (CPS) risk assessment for a one-time ILRT extension to 15.7 years [31] approved by the NRC [32].

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1.3 ACCEPTANCE CRITERIA The acceptance guidelines in RG 1.174 [4] are used to assess the acceptability of this one-time 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 of this risk assessment confirms that the CDF is not impacted by the proposed ILRT interval change for LGS.

Therefore, since the Type A test has no measurable impact on CDF for LGS, 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-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 regards to population dose, examinations of NUREG-1493 [6] and Safety Evaluation Reports (SERs) for one-time interval extension (summarized in Appendix G of EPRI TR-1018243 [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 0.01 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 SE on this issue [7] defines a small increase in population dose as an increase of 1.0 person-rem per year, or 1 % of the total population dose (when compared against the baseline interval of 3 tests per 10 years), whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This definition has been adopted for the LGS analysis.

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

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 7 of 108

The acceptance criteria are summarized below.

1. The estimated risk increase associated with temporarily extending the ILRT/DWBT surveillance interval to 16.25 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 LGS, 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/yr.

2. The increase in population dose must be small. Per the NRC SE [7], a small increase in population dose is defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1% of the total population dose, whichever is less restrictive.

3. In addition, the NRC 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% (i.e., marginally greater than 1.2%) as indicated in the EPRI methodology [3].

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 8 of 108

2.0 METHODOLOGY A simplified bounding analysis approach consistent with the EPRI methodology [3] is used for evaluating the change in risk associated with increasing the test interval to 16.25 years. The analysis uses results from a Level 2 analysis of core damage scenarios from the current LGS PRA models of record [16] 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/DWBT interval to 16.25 years.

4. Determine the change in risk in terms of 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 CCFP.

6. Evaluate the impact of external events.1 Furthermore,

• Consistent with the previous industry containment leak risk assessments, the LGS assessment uses population dose as one of the risk measures.

The other risk measures used in the LGS assessment are the CCFP for defense-in-depth considerations, and change in LERF to demonstrate that the acceptance guidelines from RG 1.174 are met.

1 The EPRI methodology [3] also outlines sensitivity cases associated with the assumptions used for the liner corrosion analysis. These sensitivities were conducted in the recent LGS permanent 15-year ILRT risk assessment [29] approved by the NRC [30] and were found to have only small to negligible impacts on the results of interest. Given the previous demonstration of the minimal impacts, these sensitivity cases are not repeated for this one-time 16.25 year ILRT risk assessment, consistent with the CPS one-time 15.7-year ILRT risk assessment [31] approved by the NRC [32]. See Section 6 for further discussion.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 9 of 108

• This evaluation for LGS 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].

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 10 of 108

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

• The LGS 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. The technical acceptability of the PRA models is consistent with the requirements of Regulatory Guide 1.200 Rev. 3 [26] as relevant to this ILRT risk assessment. PRA acceptability is discussed in Appendix A of this document.

• It is appropriate to use the LGS internal events PRA model as a gauge to effectively describe the risk change attributable to the ILRT/DWBT extension. It is reasonable to assume that the impact from the ILRT/DWBT 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 LGS.

• Dose results for the containment failures modeled in the PRA can be characterized by information provided in NUREG/CR-4551 [8]. They are estimated by scaling the NUREG/CR-4551 results by population and power level differences for Limerick compared to the NUREG/CR-4551 reference plant.

• 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 10La and for Class 3b sequences is 100La, based on the recommendations in the latest EPRI report [3] and as recommended in the NRC SE [7] on this topic. It should be noted that this is more conservative than earlier 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 LERF metric.

• The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension, but is accounted for in the 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.

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• 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 2050 population data [17] 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].

• The methodology to evaluate the impact of concurrently extending the DWBT interval is performed consistent with previous one-time ILRT/DWBT extensions for BWR Mark II containment types including the Limerick one-time assessment [27], and Columbia [28], which have been approved by the NRC.

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4.0 INPUTS This section summarizes the following:

• Section 4.1 - General resources available as input

• Section 4.2 - Plant specific inputs

• Section 4.3 - Impact of extension on detection of component failures that lead to leakage (small and large)

• Section 4.4 - impact of extension on detection of steel liner corrosion that leads to leakage 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here:

1. NUREG/CR-3539 [10]

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 of NEI Topical Report 94-01 [7]

11. NUREG/CR-4551 [8]

The first study (NUREG/CR-3539) 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 (NUREG/CR-4220) 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 (NUREG-1273) is applicable because it is a subsequent study to NUREG/CR-4220 that Docket Nos. 50-352 and 50-353 ATTACHMENT 3 13 of 108

undertook a more extensive evaluation of the same database. The fourth study (NUREG/CR-4330) provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study (EPRI TR-105189) provides an assessment of the impact on shutdown risk from ILRT test interval extension. The sixth study (NUREG-1493) is the NRCs 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 (EPRI TR-104285) is an EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study (Calvert Cliffs Liner Corrosion Analysis) addresses the impact of age-related degradation of the containment liners on ILRT evaluations. The ninth study (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. The tenth study (NRC SE) documents the acceptance by the NRC of the proposed methodology with a few exceptions. These exceptions (associated with the ILRT Type A tests) were addressed in 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. Finally, the eleventh study (NUREG/CR-4551) provides ex-plant consequence analysis for a 50-mile radius surrounding a plant that may be used on a surrogate basis for ILRT interval extension risk assessment.

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 [11]

NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related Docket Nos. 50-352 and 50-353 ATTACHMENT 3 14 of 108

records to calculate the unavailability of containment due to leakage. It assessed the large containment leak probability to be in the range of 1.0E-3 to 1.0E-2, with 5.0E-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 [13]

NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies:

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

EPRI TR-105189 [9]

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.

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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 in 10 years to 1 in 10 years.

NUREG-1493 [6]

NUREG-1493 is the NRCs 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 in 10 years to 1 in 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 [2]

Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined Individual Plant Examination (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

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5. Type C (LLRT) related containment isolation failures

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 The EPRI methodology [2,3] defines the accident classes that may be used in the ILRT extension evaluation. These containment failure classes, reproduced in Table 4.1-1, 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 EPRI [2] 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 B-tested components that have isolated but exhibit excessive leakage.

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TABLE 4.1-1 EPRI [2] CONTAINMENT FAILURE CLASSIFICATIONS CLASS DESCRIPTION 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 (ISI/IST) program.

7 Accidents involving containment failure induced by severe accident phenomena. Changes in Appendix J testing requirements do not impact these accidents.

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

Calvert Cliffs Liner Corrosion Analysis [5]

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

EPRI 1018243 [3]

This report presents a risk impact assessment for extending ILRT surveillance intervals to 15 years. This risk impact assessment complements the previous EPRI report, TR-104285 [2]. The earlier report considered changes to local leak rate testing intervals as well as changes to ILRT testing intervals. The original risk impact assessment [2]

considers the change in risk based on population dose, whereas the revision [3] considers dose as well as LERF and 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.

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The risk impact assessment using the Jeffreys 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 were used as a separate sensitivity investigation for the 15-year permanent ILRT interval LGS analysis [29] as a means of considering conservatism in the EPRI methodology and is not reproduced in this risk assessment.

The expert sensitivity demonstrated that use of the expert elicitation values would result in a significant decrease in the risk metrics of interest.

NRC Safety Evaluation Report [7]

This SE documents the NRC staffs evaluation and acceptance of NEI TR 94-01, Revision 2, and EPRI 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 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 at the end of Section 1.3.

4.2 PLANT-SPECIFIC INPUTS The LGS Unit 1 and Unit 2 specific information used to perform this ILRT interval extension risk assessment includes the following:

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

• Population dose within a 50-mile radius for various release categories [17]

LGS Unit 1 and Unit 2 Internal Events Core Damage Frequencies The current LGS Unit 1 and Unit 2 Internal Events PRA models of record (MOR) are based on an event tree / 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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 19 of 108

core damage frequency (CDF) is 3.01E-06/yr for Unit 1 (at a 1E-11/yr truncation). Note that Unit 2 is very similar at 3.03E-06/yr. Table 4.2-1 provides the CDF results by accident class from the PRA Model Summary report [16] for Unit 1. As discussed below, the Level 2 MOR is quantified at a lower truncation of 1E-12/yr. Since the EPRI methodology involves calculations involving both Level 1 and Level 2 frequency results, the Unit 1 CDF of 3.15E-06/yr at 1E-12/yr truncation is used for consistency with the Level 2 MOR frequency results.

No substantive differences exist between the LGS Unit 1 and Unit 2 PRA models that are judged to affect the conclusions of the PRA. As such, no separate PRA quantification is conducted for Unit 2. Since the LGS PRA Unit 1 PRA results are judged representative of both Unit 1 and Unit 2, the ILRT/DWBT extension evaluation is considered applicable to both Unit 1 and Unit 2.

TABLE 4.2-1

SUMMARY

OF LG121A CDF BY ACCIDENT SEQUENCE SUBCLASS ACCIDENT CLASS DESIGNATOR SUBCLASS DEFINITION LG121A MODEL (PER YR)(1)

Class I A

Accident sequences involving loss of inventory makeup in which the reactor pressure remains high.

8.02E-07 B

Accident sequences involving a loss of offsite power and loss of coolant inventory makeup.

9.58E-07 C

Accident sequences involving a loss of coolant inventory induced by an ATWS sequence with containment intact.

1.38E-09 D

Accident sequences involving a loss of coolant inventory makeup in which reactor pressure has been successfully reduced to 200 psi.

1.32E-07 E

Accident sequences involving loss of inventory makeup in which the reactor pressure remains high and DC power is unavailable.

2.43E-09 Class II A

Accident sequences involving a loss of containment heat removal with the RPV initially intact; core damage; core damage induced post containment failure.

9.41E-07 F

Class IIA and IIL except that the vent operates as designed; loss of makeup occurs at some time following vent initiation. Suppression pool saturated but intact.

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TABLE 4.2-1

SUMMARY

OF LG121A CDF BY ACCIDENT SEQUENCE SUBCLASS ACCIDENT CLASS DESIGNATOR SUBCLASS DEFINITION LG121A MODEL (PER YR)(1)

Class II L

Accident sequences involving a loss of containment heat removal with the RPV breached but no initial core damage; core damage induced post containment failure.

(Note that this is grouped with Class IIA for transfer to the Level 2 model.)

Class III (LOCA)

A Accident sequences leading to core damage conditions initiated by vessel rupture where the containment integrity is not breached in the initial time phase of the accident.

8.68E-09 B

Accident sequences initiated or resulting in small or medium LOCAs for which the reactor cannot be depressurized prior to core damage occurring.

3.62E-08 C

Accident sequences initiated or resulting in medium or large LOCAs for which the reactor is a low pressure and no effective injection is available.

7.07E-09 D

Accident sequences which are initiated by a LOCA or RPV failure and for which the vapor suppression system is inadequate, challenging the containment integrity with subsequent failure of makeup systems.

3.23E-09 Class IV (ATWS)

A Accident sequences involving failure of adequate shutdown reactivity with the RPV initially intact; core damage induced post containment failure.

7.48E-08 L

Accident sequences involving failure of adequate shutdown reactivity with the RPV initially breached; core damage induced post containment failure. (Note that this is grouped with Class IVA for transfer to the Level 2 model.)

Class V Unisolated LOCA outside containment.

3.22E-08(2)

Total 3.01E-06(3)

Notes to Table 4.2-1:

(1)

Frequency values are based on 1E-11 truncation.

(2)

Class V frequency @ 1E-12 truncation is 3.25E-08/yr. This slightly higher value is used in the risk assessment.

(3)

Total CDF @ 1E-12 truncation is 3.15E-06/yr. This slightly higher value is used in the risk assessment.

LGS Internal Events Release Category Frequencies The Level 2 Model that is used for LGS was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. Thirteen (13) different release categories were developed in the LGS Level 2 PRA. These release categories Docket Nos. 50-352 and 50-353 ATTACHMENT 3 21 of 108

represent radionuclide release severity and timing classification scheme shown in Table 4.2-2.

TABLE 4.2-2 LEVEL 2 END STATE BINS: RADIONUCLIDE RELEASE SEVERITY AND TIMING CLASSIFICATION SCHEME (SEVERITY, TIMING)(1)

RADIONUCLIDE RELEASE SEVERITY RADIONUCLIDE RELEASE TIMING CLASSIFICATION CATEGORY CS IODIDE % IN RELEASE CLASSIFICATION CATEGORY TIME OF INITIAL RELEASE(2)

RELATIVE TO DECLARATION OF A GENERAL EMERGENCY High (H)(4)

Moderate (M)

Low (L)

Low-low (LL)

No iodine (OK, Intact Containment)

Greater than 10(4) 1 to 10 0.1 to 1 Less than 0.1 Negligible Late (L)

Intermediate (I)

Early (E)

Greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> E(3) to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Less than E(3), (4) hours Notes to Table 4.2-2:

(1)

Thirteen (13) Level 2 End State Bins: H/E, H/I, H/L, M/E, M/I, M/L, L/E, L/I, L/L, LL/E, LL/I, LL/L, OK.

(2)

The General Emergency declaration is accident sequence dependent and occurs when EALs are exceeded.

(3)

Where E hours is less than the time when evacuation is effective (6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) for LGS.

(4)

Consistent with NUREG/CR-6595 [23].

Table 4.2-3 summarizes the pertinent LGS Unit 1 results in terms of release category (timing and magnitude). The total LERF, which corresponds to the H/E release category in Table 4.2-3, was found to be 1.78E-07/yr (at 1E-12/yr truncation). The total release frequency is 2.82E-06/yr. With a total CDF of 3.15E-06/yr (at 1E-12/yr truncation), this corresponds to an OK release limited to normal leakage of 3.29E-07/yr (after round-off).

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TABLE 4.2-3 LGS LEVEL 2 PRA MODEL RELEASE CATEGORIES AND FREQUENCIES CATEGORY FREQUENCY/YR Intact 3.29E-07 H/E - High Early (LERF) 1.78E-07 M/E - Medium Early 3.09E-07 L/E - Low Early 1.50E-08 LL/E - Low Low Early 0.00E+00 H/I - High Intermediate 1.94E-06 M/I - Medium Intermediate 1.16E-07 L/I - Low Intermediate 2.50E-07 LL/I - Low Low Intermediate 1.31E-08 H/L - High Late 0.00E+00 M/L - Medium Late 0.00E+00 L/L - Low Late 0.00E+00 LL/L - Low Low Late 0.00E+00 Total Release Frequency (Cont. Intact Frequency not included) 2.82E-06 Core Damage Frequency 3.15E-06(1)

Notes to Table 4.2-3:

(1)

CDF @ 1E-12 truncation.

LGS Population Dose Information The population dose is calculated by using data provided in NUREG/CR-4551 [8] and adjusting the results for Limerick, as outlined in the EPRI methodology [3]. Three adjustments are considered based on differences between the surrogate NUREG/CR-4551 plant and Limerick, those differences being the 50-mile population, reactor power level, and allowable containment leak rate.

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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 23 of 108

result in a set of 10 bins that are relevant to the analysis. The definitions of the 10 collapsed APBs are provided in NUREG/CR-4551 and are reproduced in Table 4.2-4 for references purposes. Table 4.2-5 summarizes the calculated population dose associated with each APB from NUREG/CR-4551 for the Peach Bottom Atomic Power Station (PBAPS) reference plant.

Table 4.2-4 Collapsed Accident Progression Bin (APB) Descriptions [8]

Collapsed APB Number Description 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 (DCH) 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 DCH is not possible).

3 CD, VB, Early CF, DW 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 DCH is possible).

4 CD, VB, Early CF, DW 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 DCH 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 DCH occurred, it did not fail containment at the time it occurred.

6 CD, VB, Late CF, DW 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 DCH occurred, it did not fail containment at the time it occurred.

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Table 4.2-4 Collapsed Accident Progression Bin (APB) Descriptions [8]

Collapsed APB Number Description 7

CD, VB, No CF, Vent, N/A 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, DCH does not significantly affect the source term as the containment does not fail and the vent limits its effect.

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 N/A) since, even if it occurred, DCH 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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Table 4.2-5 Calculation of PBAPS Population Dose at 50 Miles [8]

Collapsed Bin #

Fractional APB Contributions to Risk (MFCR) (1)

NUREG/CR-4551 Population Dose Risk at 50 miles (From a total of 7.9 person-rem/yr, mean) (2)

NUREG/CR-4551 Collapsed Bin Frequencies (per year) (3)

NUREG/CR-4551 Population Dose at 50 miles (Person-rem) (4) 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-06 Notes to Table 4.2-5:

(1)

Mean Fractional Contribution to Risk 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 PDR50 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.

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Population Dose Estimate Methodology The person-rem results in Table 4.2-5 can be used as an approximation of the dose for Limerick if it is adjusted for the population surrounding Limerick, differences in reactor power levels, and differences in allowable containment leakage. Differences in population and reactor power level would apply to all APBs, but differences in allowable containment leakage would only apply to intact containment end states.

The total population within a 50-mile radius of Limerick is projected to be 9.51E+06 by the year 2050 [17]. The use of the 2050 estimate is judged to be sufficient to perform the one-time extension assessment.

This population value is compared to the population value used in NUREG/CR-4551 in order to develop a Population Factor that can be applied to the APBs to get dose estimates for Limerick.

Total Limerick Population50miles = 9.51E+06 Peach Bottom Population from NUREG/CR-4551 = 4.36E+061 Population Factor = 9.51E+06 / 4.36E+06 = 2.18 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 each site. This does not take into account differences in meteorology data, detailed environmental factors or detailed differences in containment designs, but does provide a first-order approximation for Limerick 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.

1 The Peach Bottom 50-mile population is developed by summing the population data documented in the MACCS SITE input file listed in Appendix A of NUREG/CR-4551 Vol. 2 Part 7 [35] as was also performed for the Plant Hatch ILRT risk assessment [25].

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With regards to reactor power level, the current Limerick licensed power level of 3,515 MWth is greater than that used in the NUREG/CR-4551 study for PBAPS (3,293 MWth),

and an adjustment factor can be applied to the APBs as follows:

Rx Power Factor = LGS 3,515 MWth / PBAPS 3,293 MWth = 1.07 With regards to allowable containment leakage, Limerick has a technical specification value of 0.5% air weight per day, which is the same as that used in the NUREG/CR-4551 study for the PBAPS. Since the two values are the same, no adjustment is needed.

Table 4.2-6 shows the results of applying the population and reactor power level adjustment factors to the NUREG/CR-4551 population dose results at 50 miles to obtain the adjusted population dose at 50 miles for Limerick for use in this ILRT risk assessment.

Table 4.2-6 Calculation of Limerick Population Dose Risk at 50 Miles Accident Progression Bin #

NUREG/CR-4551 Population Dose at 50 miles (Person-rem)

Population Adjustment Factor Rx Power Adjustment Factor Limerick Adjusted Population Dose at 50 miles (Person-rem) 1 1.74E+06 2.18 1.07 4.06E+06 2

1.09E+06 2.18 1.07 2.54E+06 3

2.97E+06 2.18 1.07 6.93E+06 4

2.25E+06 2.18 1.07 5.25E+06 5

1.34E+06 2.18 1.07 3.13E+06 6

2.28E+06 2.18 1.07 5.32E+06 7

1.95E+06 2.18 1.07 4.55E+06 8

4.94E+03 2.18 1.07 1.15E+04 9

2.05E+05 2.18 1.07 4.78E+05 10 0

2.18 1.07 0.00E+00 Application of Limerick PRA Model Results to NUREG/CR-4551 Level 3 Output The results of the Limerick PRA Level 2 model end states (i.e., release categories) are not defined in the same manner as the collapsed APBs reported in NUREG/CR-4551. In Docket Nos. 50-352 and 50-353 ATTACHMENT 3 28 of 108

order to apply the adjusted PBAPS doses to the Limerick PRA Level 2 frequency results a mapping process was needed. Consequently, the end state characteristics of the Limerick Level 2 model were reviewed and assigned into one of the collapsed APBs from NUREG/CR-4551, based on the timing and magnitude summarized as follows:

• APB 3 had the highest dose with early containment failure. The LGS H/E release frequency was therefore assigned.

• APBs 1 & 4 with early containment failure had the next highest doses. The LGS M/E frequency was therefore split between these two APBs, assuming 50% to each.

• APB 2 had the lowest dose associated with early containment failure. The LGS L/E frequency was therefore assigned.

• APB 6 had the highest dose with late containment failure. The LGS H/I release frequency was therefore assigned.

• APB 7 with containment venting had the next highest dose in the non-early time frame. The LGS M/I frequency was therefore assigned.

• APB 5 had the lowest dose associated with late containment failure. The LGS L/I frequency was therefore assigned.

• APB 9 had the lowest dose other than APB 8. The LGS LL/I frequency was therefore assigned.

• APB 8 reflects no containment failure. The LGS Intact frequency was therefore assigned.

• APB 10 reflects non-core damage scenarios which are not applicable to this ILRT risk assessment and APB 10 was therefore assigned no frequency.

The frequency results from the thirteen release categories were previously shown in Table 4.2-3. The results of the frequency assignments to the APBs are shown in Table 4.2-7.

Table 4.2-7 Assignments of Limerick Level 2 Results to APBs Accident Progression Bin #

Brief Description (Refer to Table 4.2-3)

Limerick Adjusted Population Dose at 50 miles (Person-rem)

Assigned Limerick Level 2 Release Category 1

CD, VB, Early CF, WW Failure, RPV Pressure >

200 psi at VB 4.06E+06 50% of M/E Release (1.55E-07/yr)

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Table 4.2-7 Assignments of Limerick Level 2 Results to APBs Accident Progression Bin #

Brief Description (Refer to Table 4.2-3)

Limerick Adjusted Population Dose at 50 miles (Person-rem)

Assigned Limerick Level 2 Release Category 2

CD, VB, Early CF, WW Failure, RPV Pressure <

200 psi at VB 2.54E+06 100% of L/E Release (1.50E-08/yr) 3 CD, VB, Early CF, DW Failure, RPV Pressure >

200 psi at VB 6.93E+06 100% of H/E Release (1.78E-07/yr) 4 CD, VB, Early CF, DW Failure, RPV Pressure <

200 psi at VB 5.25E+06 50% of M/E Release (1.55E-07/yr) 5 CD, VB, Late CF, WW Failure, N/A 3.13E+06 100% of L/I Rlease (2.50E-07/yr) 6 CD, VB, Late CF, DW Failure, N/A 5.32E+06 100% of H/I Release (1.94E-06/yr) 7 CD, VB, No CF, Vent, N/A 4.55E+06 100% of M/I Release (1.16E-07/yr) 8 CD, VB, No CF, N/A, N/A 1.15E+04 100% of Intact Release (3.29E-07/yr) 9 CD, No VB, N/A, N/A, N/A 4.78E+05 100% of LL/I Release (1.31E-08/yr) 10 No CD, N/A, N/A, N/A, N/A 0.00E+00 N/A 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.

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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 EPRI methodology [3] 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 Limerick, as detailed in Section 5, means that the Class 2 and Class 8 sequences are subtracted from the CDF that is applied to Class 3b. To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Class 2 and Class 8 events refer to sequences with either large pre-existing containment isolation failures or containment bypass events. These sequences are already considered to contribute to LERF in the Limerick Level 2 PRA analysis.

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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 / 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 interval. Correspondingly, an extension of the ILRT interval to 15 years can be estimated to lead to about a factor of 5.0 (7.5/1.5) increase in the non-detection probability of a leak, and that of a 16.25 year interval leads to a factor of 5.42 (8.125/1.5).

LGS 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. Limerick has successfully completed two consecutive ILRTs at Unit 1 and Unit 2. Additionally, Limerick received approval [34] of an extension of the ILRT interval to once per 15 years on a permanent basis.

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 per reactor year) 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.

5. Determine the impact on the CCFP.

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6. Evaluate the impact of external events.

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 [4]. Because Limerick does not rely upon containment overpressure for mitigation of design basis accidents (see Section 5.8 for further discussion), the change in LERF forms the quantitative basis for a risk informed decision per the EPRI methodology and current NRC practice, namely Regulatory Guide 1.174. The fifth 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 depth philosophy [7]. As such, this step suffices as the remaining basis for a risk informed decision per Regulatory Guide 1.174. Step 6 takes into consideration the additional risk due to external events.

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 Limerick primary containment is a pressure-suppression BWR/Mark II containment type that also includes a steel-lined reinforced concrete structure.

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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 33 of 108

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 walls

• 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

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

2. 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 LGS 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 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).

3. 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 on this assumption were evaluated in the LGS 15-year permenant ILRT risk assessment [29] and were found to have a very small impact.

4. 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 LGS the containment failure probabilities are conservatively assumed to be 10% for the drywell and wetwall outer walls and 1% for the basemat.

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(See Table 4.4-1, Step 4.) It is noted that since the basemat for the LGS Mark II containment is in the suppression pool, it is judged that failure of this area would not lead to LERF. Therefore the 1% probability is conservative.

Sensitivity studies on these values were evaluated in the LGS 15-year permenant ILRT risk assessment [29] and were found to have a very small impact.

5. 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. To date, all liner corrosion events have been detected through visual inspection (See Table 4.4-1, Step 5). Sensitivity studies on these values were evaluated in the LGS 15-year permanent ILRT risk assessment [29] and were found to have a very small impact. Note that 100% of the basemat failures are assumed to be undetectable.

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

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TABLE 4.4-1 STEEL LINER CORROSION BASE CASE STEP DESCRIPTION CONTAINMENT CYLINDER, CONE AND HEAD CONTAINMENT BASEMAT 1

Historical Steel Liner Flaw Likelihood Failure Data: Containment location specific (consistent with Calvert Cliffs analysis).

Events: 2 2/(70

• 5.5) = 5.2E-3 Events: 0 (assume 0.5 failure) 0.5/(70

• 5.5) = 1.3E-3 2

Age Adjusted Steel Liner Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9%

increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis).

Year 1

avg 5-10 15 16.25 Failure Rate 2.1E-3 5.2E-3 1.4E-2 1.7E-2 Year 1

avg 5-10 15 16.25 Failure Rate 5.1E-4 1.3E-3 3.6E-3 4.3E-3 15 year average = 6.27E-3 15 year average = 1.57E-3 3

Flaw Likelihood at 3, 10, 15, and 16.25 years Uses age adjusted liner flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis - See Table 6 of Reference [5]).

0.71% (1 to 3 years) 4.06% (1 to 10 years) 9.40% (1 to 15 years) 11.1% (1 to 16.25 years)

(Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 8.7% to utilize in the estimation of the delta-LERF value. For this analysis, the values are calculated based on the 3, 10, 15, and 16.25 year intervals.)

0.18% (1 to 3 years) 1.02% (1 to 10 years) 2.35% (1 to 15 years) 2.78% (1 to 16.25 years)

(Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 2.2% to utilize in the estimation of the delta-LERF value. For this analysis, the values are calculated based on the 3, 10, 15, and 16.25 year intervals.)

4 Likelihood of Breach in 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).

10%

1%

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TABLE 4.4-1 STEEL LINER CORROSION BASE CASE STEP DESCRIPTION CONTAINMENT CYLINDER, CONE AND HEAD CONTAINMENT BASEMAT 5

Visual Inspection Detection Failure Likelihood Utilize assumptions consistent with Calvert Cliffs analysis.

10%

5% failure to identify visual flaws plus 5% likelihood that the flaw is not visible (not through-cylinder but could be detected by ILRT)

All events have been detected through visual inspection. 5%

visible failure detection is a conservative assumption.

100%

Cannot be visually inspected.

6 Likelihood of Non-Detected Containment Leakage (Steps 3

• 4

• 5) 0.0071% (at 3 years)

=0.71%

• 10%

• 10%

0.0406% (at 10 years)

=4.06%

• 10%

• 10%

0.0940% (at 15 years)

=9.40%

• 10%

• 10%

0.1111% (at 16.25 years)

=11.11%

• 10%

• 10%

0.0018% (at 3 years)

=0.18%

• 1%

• 100%

0.0102% (at 10 years)

=1.02%

• 1%

• 100%

0.0235% (at 15 years)

=2.35%

• 1%

• 100%

0.0278% (at 16.25 years)

=2.78%

• 1%

• 100%

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% + 0.0018% = 0.0089%

• At 10 years: 0.0406% + 0.0102% = 0.0508%

• At 15 years: 0.0940% + 0.0235% = 0.1175%

• At 16.25 years: 0.1111% + 0.0278% = 0.1389%

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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 sealType 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 LGS 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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 38 of 108

post-maintenance test (e.g., a valve failing to close following a valve stroke test.) (EPRI Class 6 sequences). Consistent with the EPRI Guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.

• Accident sequences involving containment 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 in Sections 5.1 through 5.5:

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 16.25 years and 15 to 16.25 years.

Step 4 Determine the change in risk in terms of LERF in accordance with RG 1.174.

Step 5 Determine the impact on CCFP.

Following Step 5, the results are summarized in Section 5.6, external events are considered in Section 5.7 and the impact of containment overpressure is assessed in Section 5.8.

It is noted that the calculations were generally performed using an electronic spreadsheet such that the presented numerical results may differ slightly as compared to values calculated by hand.

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5.1 STEP 1 - QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR This step involves the review and assignment of the LGS Level 2 accident sequence frequency results to the EPRI classes defined in the EPRI methodology [3]. Table 5.1-1 relates EPRI class containment release scenarios to the various accident sequence categories. This mapping combined with the LGS dose (person-rem) results documented in Table 4.2-6 forms the basis for estimating the population dose for LGS.

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-1018243 [3]). 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 LGS based on Level 2 PRA inputs found in Section 4, determining the frequencies for Classes 3a and 3b, and then determining the remaining frequency for Class 1.

Furthermore, adjustments were made to the Class 3b and hence Class 1 frequencies to account for the impact of undetected corrosion of the steel liner per the methodology described in Section 4.4. 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 provides dose values for each EPRI scenario class. The dose values were developed in Section 4.2. The Level 2 Accident sequence bin(s) assigned to each EPRI Class are described under each containment release class discussion following Table 5.1-1. The methodology for determining the dose applied to EPRI Class 7 is further described under the paragraph heading Class 7 Sequences.

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TABLE 5.1-1 EPRI CLASS DOSE ASSIGNMENT FOR LGS EPRI SCENARIO CLASS ACCIDENT PROGRESSION BIN RELEASE CATEGORY DOSE (PERSON-REM) 1 APB-8 Intact 1.15E+04 2

APB-3 HE (non-ISLOCA) 6.93E+06 7

Weighted Average Miscellaneous(1) 5.06E+06 APB-1 0.5*ME 4.06E+06 Individual Contributors to Class 7 Weighted Average APB-2 LE 2.54E+06 APB-3 HE - EPRI 2 - EPRI 8 6.93E+06 APB-4 0.5*ME 5.25E+06 APB-5 LI 3.13E+06 APB-6 HI 5.32E+06 APB-7 MI 4.55E+06 APB-9 LLI 4.78E+05 8

APB-3 HE (ISLOCA) 6.93E+06 Notes to Table 5.1-1:

(1) Given that multiple LGS discrete scenarios apply to the broader EPRI Class 7, the EPRI dose is based on a weighted average of the various release catgeory frequencies. The weighted average dose is developed in Table 5.1-2.

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 2.93E-07/yr and is determined by subtracting all containment failure end states including the EPRI/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.

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Class 1

= CDF - (EPRI Classes)

= 3.15E (1.11E-08 (Class 2) + 2.86E-08 (Class 3a) + 7.14E-09 (Class 3b) +

2.78E-06 (Class 7) + 3.25E-08 (Class 8))

= 2.93E-07/yr.

Class 2 Sequences This group consists of large containment isolation failures. For LGS, containment isolation failure sequences resulting in a large early release are the following: IA-084, IBE-084, IBL-084, IC-084, ID-084, IIIB-043, and IIIC-043. The sum of the frequencies of these scenarios is 1.11E-08/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 10La was used for small pre-existing flaws and 100La for relatively large flaws.

The respective frequencies per year are determined as follows:

PROBClass 3a

= probability of small pre-existing containment liner leakage

= 0.0092 (see Section 4.3)

PROBClass 3b

= probability of large pre-existing containment liner leakage

= 0.0023 (see Section 4.3)

As described in Section 4.3, additional consideration is made to not apply these failure probabilities to those cases that are already considered LERF scenarios (i.e., the Class 2 and Class 8 contributions). Note that a 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)]

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= 0.0092 * [3.15E (1.11E-08 + 3.25E-08)]

= 2.86E-08/yr Class 3b

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

= 0.0023 * [3.15E (1.11E-08 + 3.25E-08)]

= 7.14E-09/yr For this analysis, the associated containment leakage for Class 3a is 10La and 100La 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. Note that containment failure is Docket Nos. 50-352 and 50-353 ATTACHMENT 3 43 of 108

not induced for containment bypass (BOC and ISLOCA) (EPRI Class 8) and isolation failure (EPRI Class 2) sequences as these are either the initiating event or a plant condition, existing at the time of the initiating event. For this analysis, the associated radionuclide releases are based on the application of the Level 2 end states from the LGS release category evaluation as described in Section 4.2. The Class 7 Sequences are all Level 2 release categories except containment intact EPRI Class 1, containment bypass (EPRI Class 8), and isolation failure (EPRI Class 2) sequences leading to a large early release. The failure frequency and population dose for each specific release category 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. The resulting weighted average person-rem is the representative EPRI Class 7 dose in the subsequent analysis. Note that the total frequency and dose associated with this EPRI class does not change as part of the ILRT extension request.

TABLE 5.1-2 ACCIDENT CLASS 7 FAILURE FREQUENCIES AND POPULATION DOSES (LGS BASE CASE LEVEL 2 MODEL)

ACCIDENT PROGRESSION BIN RELEASE CATEGORY RELEASE FREQUENCY / YR(1)

POPULATION DOSE (50 MILES)

PERSON-REM(2)

POPULATION DOSE RISK (50 MILES)

(PERSON-REM / YR)(3)

APB-1 50% of ME 1.55E-07 4.06E+06 6.27E-01 APB-2 LE 1.50E-08 2.54E+06 3.82E-02 APB-3 HE - (Class 2 +

Class 8) 1.34E-07 6.93E+06 9.32E-01 APB-4 50% of ME 1.55E-07 5.25E+06 8.11E-01 APB-5 LI 2.50E-07 3.13E+06 7.82E-01 APB-6 HI 1.94E-06 5.32E+06 1.03E+01 APB-7 MI 1.16E-07 4.55E+06 5.28E-01 APB-9 LLI 1.31E-08 4.78E+05 6.27E-03 Class 7 Total 2.78E-06 5.06E+06(4) 1.40E+01 Notes to Table 5.1-2:

(1)

Release Frequency values obtained from Table 4.2-3.

(2)

Population dose values obtained from Table 4.2-7.

(3)

Obtained by multiplying the Release Frequency per year by the Population Dose Person-Rem value. Calculations were performed using more than 3 significant figures. Therefore, figures may differ in the 3rd digit if multiplying the figures shown above.

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(4)

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. For this analysis, the frequency is determined from release categories Break Outside Containment (BOC) and ISLOCA Level 2 results. The sum of each of these contributions as quantified by the model is 3.25E-08/yr (listed in Table 4.2-1 for Accident Class V sequences).

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 1018243 [3] and are shown in Table 5.1-3 by accident class.

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

ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE)

DESCRIPTION FREQUENCY (PER RX-YR) 1 No Containment Failure 2.93E-07 2

Large Isolation Failures (Failure to Close) 1.11E-08 3a Small Isolation Failures (liner breach) 2.86E-08 3b Large Isolation Failures (liner breach) 7.14E-09 4

Small Isolation Failures (Failure to seal -Type B)

N/A 5

Small Isolation Failures (Failure to sealType C)

N/A 6

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

N/A 7

Failures Induced by Phenomena (Early and Late) 2.78E-06 8

Bypass (Interfacing System LOCA) 3.25E-08 CDF All CET End states (including very low and no release) 3.15E-06 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 45 of 108

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 of 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 as described in Section 4.2 and summarized in Table 4.2-7. The results of applying these releases to the EPRI/NEI containment failure classification defined in Table 4.1-1 are as follows:

Class 1

=

1.15E+04 person-rem (at 1.0La) (1)

Class 2

=

6.93E+06(2)

Class 3a

=

1.15E+04 person-rem x 10La = 1.15E+05 person-rem (3)

Class 3b

=

1.15E+04 person-rem x 100La = 1.15E+06 person-rem (3)

Class 4

=

Not analyzed Class 5

=

Not analyzed Class 6

=

Not analyzed Class 7

=

5.06E+06 person-rem (4)

Class 8

=

6.93E+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 Limerick as shown in Table 4.2-6.

(2)

The Class 2, containment isolation failures, dose is approximated from APB #3 (VB, Early DW, Hi Press) from Table 4.2-7.

(3) The Class 3a and 3b dose are related to the leakage rate as shown.

(4)

The Class 7 dose is assigned from the weighted average dose calculated from the APBs from Table 4.2-7 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 assigned from APB #3 from Table 4.2-7 which is the largest dose.

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.

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TABLE 5.2-1 LGS POPULATION DOSE ESTIMATES FOR POPULATION WITHIN 50 MILES ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE)

REPRESENTATIVE ACCIDENT SEQUENCE DESCRIPTION PERSON-REM (50 MILES) 1 Containment Intact No Containment Failure (1 La) 1.15E+04 2

H/E Large Isolation Failures (Failure to Close) 6.93E+06 3a 10La Small Isolation Failures (liner breach) 1.15E+05 3b 100La Large Isolation Failures (liner breach) 1.15E+06 4

N/A Small Isolation Failures (Failure to seal -Type B)

NA 5

N/A Small Isolation Failures (Failure to sealType C)

NA 6

N/A Other Isolation Failures (e.g., dependent failures)

NA 7

See Table 5.1-2 (All releases except isolation, and bypass sequences)

Failures Induced by Phenomena (Early and Late) 5.06E+06 8

H/E Bypass (BOC and Interfacing System LOCA) 6.93E+06 The above dose estimates, when combined with the frequency results presented in Table 5.1-3, yield the LGS baseline mean consequence measures for each accident class.

These results are presented in Table 5.2-2.

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TABLE 5.2-2 LGS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 3 IN 10 YEAR ILRT FREQUENCY ACCIDENT CLASSES (CONT.

RELEASE TYPE)

DESCRIPTION PERSON-REM (0-50 MILES)

EPRI METHODOLOGY EPRI METHODOLOGY PLUS CORROSION CHANGE DUE TO CORROSION (PERSON-REM/YR) (1)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES) 1 Containment Intact (2) 1.15E+04 2.93E-07 3.38E-03 2.93E-07 3.38E-03

-3.19E-06 2

Large Isolation Failures (Failure to Close) 6.93E+06 1.11E-08 7.71E-02 1.11E-08 7.71E-02 3a Small Isolation Failures (liner breach) 1.15E+05 2.86E-08 3.30E-03 2.86E-08 3.30E-03 3b Large Isolation Failures (liner breach) 1.15E+06 7.14E-09 8.24E-03 7.42E-09 8.56E-03 3.19E-04 7

Failures Induced by Phenomena (Early and Late) 5.06E+06 2.78E-06 1.40E+01 2.78E-06 1.40E+01 8

Containment Bypass (Interfacing System LOCA) 6.93E+06 3.25E-08 2.25E-01 3.25E-08 2.25E-01 CDF All CET end states 3.15E-06 14.366 3.15E-06 14.366 3.16E-04 Notes to Table 5.2-2:

(1)

Only release Classes 1 and 3b are affected by the corrosion analysis. During the ILRT 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.

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5.3 STEP 3 - EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL The next step is to evaluate the risk impact of extending the test interval from its current fifteen-years and the proposed 16.25 years.

Risk Impact Due to 15-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 5.0 compared to the base case values. The results of the calculation for a 15-year interval are presented in Table 5.3-1.

Risk Impact Due to 16.25-Year Test Interval The risk contribution for a 16.25-year interval is calculated in a manner similar to the 15-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 5.42 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.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 49 of 108

TABLE 5.3-1 LGS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 1 IN 15 YEAR ILRT FREQUENCY ACCIDENT CLASSES (CONT.

RELEASE TYPE)

DESCRIPTION PERSON-REM (0-50 MILES)

EPRI METHODOLOGY EPRI METHODOLOGY PLUS CORROSION CHANGE DUE TO CORROSION (PERSON-REM/YR)(1)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES) 1 Containment Intact (2) 1.15E+04 1.50E-07 1.73E-03 1.47E-07 1.69E-03

-4.21E-05 2

Large Isolation Failures (Failure to Close) 6.93E+06 1.11E-08 7.71E-02 1.11E-08 7.71E-02 3a Small Isolation Failures (liner breach) 1.15E+05 1.43E-07 1.65E-02 1.43E-07 1.65E-02 3b Large Isolation Failures (liner breach) 1.15E+06 3.57E-08 4.12E-02 3.94E-08 4.54E-02 4.21E-03 7

Failures Induced by Phenomena (Early and Late) 5.06E+06 2.78E-06 1.40E+01 2.78E-06 1.40E+01 8

Containment Bypass (Interfacing System LOCA) 6.93E+06 3.25E-08 2.25E-01 3.25E-08 2.25E-01 CDF All CET end states 3.15E-06 14.410 3.15E-06 14.415 4.17E-03 Notes to Table 5.3-1:

(1)

Only release Classes 1 and 3b are affected by the corrosion analysis. During the ILRT 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.

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TABLE 5.3-2 LGS ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR 1 IN 16.25 YEAR ILRT FREQUENCY ACCIDENT CLASSES (CONT.

RELEASE TYPE)

DESCRIPTION PERSON-REM (0-50 MILES)

EPRI METHODOLOGY EPRI METHODOLOGY PLUS CORROSION CHANGE DUE TO CORROSION (PERSON-REM/YR) (1)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES)

FREQUENCY (1/YR)

PERSON-REM/YR (0-50 MILES) 1 Containment Intact (2) 1.15E+04 1.35E-07 1.56E-03 1.31E-07 1.51E-03

-4.97E-05 2

Large Isolation Failures (Failure to Close) 6.93E+06 1.11E-08 7.71E-02 1.11E-08 7.71E-02 3a Small Isolation Failures (liner breach) 1.15E+05 1.55E-07 1.79E-02 1.55E-07 1.79E-02 3b Large Isolation Failures (liner breach) 1.15E+06 3.87E-08 4.46E-02 4.30E-08 4.96E-02 4.97E-03 7

Failures Induced by Phenomena (Early and Late) 5.06E+06 2.78E-06 1.40E+01 2.78E-06 1.40E+01 8

Containment Bypass (Interfacing System LOCA) 6.93E+06 3.25E-08 2.25E-01 3.25E-08 2.25E-01 CDF All CET end states 3.15E-06 14.415 3.15E-06 14.420 4.92E-03 Notes to Table 5.3-2:

(1)

Only release Classes 1 and 3b are affected by the corrosion analysis. During the ILRT 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.

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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 interval for LGS does not impact CDF, the relevant metric is LERF.

For LGS, 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 7.42E-09/yr, which includes the corrosion effect of the containment liner.

Based on a 15-year test interval from Table 5.3-1, the Class 3b frequency is 3.94E-08/yr; and, based on a 16.25-year test interval from Table 5.3-2, it is 4.30E-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 16.25 years (including corrosion effects) is 3.56E-08/yr. Similarly, the increase in LERF due to increasing the interval from 15 to 16.25 years (including corrosion effects) is 3.66E-09/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 III of Figure 4 of Reference [4] (i.e., less than 1E-07/yr, the acceptance criteria for very small changes in LERF) when comparing the 16.25 year results to the original 3-in-10 year requirement or the current 15 year interval.

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 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 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 52 of 108

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).

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 LGS ILRT CONDITIONAL CONTAINMENT FAILURE PROBABILITIES CCFP 3 IN 10 YRS CCFP 1 IN 15 YRS CCFP 1 IN 16.25 YRS CCFP16.25-3 CCFP16.25-15 89.79%

90.81%

90.93%

1.13%

0.12%

Note to Table 5.5-1:

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

The change in CCFP of about 1.1% as a result of extending the test interval to 16.25 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%. The change in CCFP for 16.25 years compared to the current 15 year interval is about 0.12% and is considered very small.

5.6

SUMMARY

OF INTERNAL EVENTS RESULTS Table 5.6-1 summarizes the internal events results of this ILRT extension risk assessment for LGS. The results between the different intervals as compared against the acceptance criteria are then shown in Table 5.6-2, and it is demonstrated that the acceptance criteria are met.

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TABLE 5.6-1 LGS ILRT CASES: BASE, CURRENT, AND 16.25 YR EXTENSION (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD)

EPRI CLASS DOSE PER-REM BASE CASE 3 IN 10 YEARS CURRENT 1 IN 15 YEARS EXTEND TO 1 IN 16.25 YEARS CDF (1/YR)

PERSON-REM/YR CDF (1/YR)

PERSON-REM/YR CDF (1/YR)

PERSON-REM/YR 1

1.15E+04 2.93E-07 3.38E-03 1.47E-07 1.69E-03 1.31E-07 1.51E-03 2

6.93E+06 1.11E-08 7.71E-02 1.11E-08 7.71E-02 1.11E-08 7.71E-02 3a 1.15E+05 2.86E-08 3.30E-03 1.43E-07 1.65E-02 1.55E-07 1.79E-02 3b 1.15E+06 7.42E-09 8.56E-03 3.94E-08 4.54E-02 4.30E-08 4.96E-02 7

5.06E+06 2.78E-06 1.40E+01 2.78E-06 1.40E+01 2.78E-06 1.40E+01 8

6.93E+06 3.25E-08 2.25E-01 3.25E-08 2.25E-01 3.25E-08 2.25E-01 Total 3.15E-06 14.366 3.15E-06 14.415 3.15E-06 14.420 ILRT Dose Rate (person-rem/yr) from 3a and 3b 1.19E-02 6.19E-02 6.75E-02 Delta Total Dose Rate(1)

From 3 yr 4.83E-02 5.38E-02 From 15 yr 5.43E-03 3b Frequency (LERF) 7.42E-09 3.94E-08 4.30E-08 Delta 3b LERF From 3 yr 3.20E-08 3.56E-08 From 15 yr 3.66E-09 CCFP %

89.79%

90.81%

90.93%

Delta CCFP %

From 3 yr 1.01%

1.13%

From 15 yr 0.12%

Note to Table 5.6-1:

(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 LGS ILRT EXTENSION COMPARISON TO ACCEPTANCE CRITERIA Interval Change LERF Person-rem/yr CCFP 3/10yrs to 16.25yrs 3.56E-08/yr 5.38E-02 (0.37%)

1.13%

15yrs to 16.25yrs 3.66E-09/yr 5.43E-03 (0.038%)

0.12%

Acceptance Criteria per NRC SE [7]

<1.0E-6/yr

<1.0 person-rem/yr or

<1.0%

<1.5%

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. This analysis is performed consistent with the Limerick 15-year permanent extension risk assessment [29] approved by the NRC [34], except using the most recent Fire PRA model and refined seismic values.

5.7.1 Fire Risk The potential impact associated with fire risk is evaluated in a manner consistent with the Limerick 15-year permanent extension risk assessment [29] approved by the NRC [34],

using the most recent Fire PRA (FPRA) model (LG121AF/LG221AF) [19]. The technical acceptability of the Limerick Fire PRA model has been previously documented in the Limerick Risk-Informed Completion Time (RICT) LAR [33] which was reviewed and approved by the NRC [34]. Further discussion of the technical acceptability of the Limerick PRA models is provided in Appendix A.

The Unit 1 Fire CDF is 4.99E-06/yr and Fire LERF is 8.66E-08/yr. The Unit 2 results are similar but slightly higher than Unit 1. The Unit 2 Fire CDF is 5.15E-06/yr and the Fire LERF is 1.01E-07/yr. Since the Unit 2 Fire CDF and Fire LERF are higher than those of Unit 1, the Unit 2 results are used for the ILRT risk evaluation, as was done for the 15-year permanent extension risk assessment [29]. It is noted that the Unit 2 Fire CDF Docket Nos. 50-352 and 50-353 ATTACHMENT 3 55 of 108

(5.15E-6/yr, at 1E-12/yr truncation) is approximately a factor of 1.63 higher than the internal events CDF value of 3.15E-06/yr used in this risk assessment.

5.7.2 Seismic Risk For the Limerick 15-year permanent extension risk assessment [29] approved by the NRC

[30], seismic risk was assessed starting with a bounding seismic CDF value as developed by the NRC risk assessment for generic issue report GI-199 [24] using the updated 2008 USGS Seismic Hazard curves and reduced by 50% based on pga considerations. For the more recent Limerick RICT LAR [33], which was reviewed and approved by the NRC

[34], a seismic CDF of 3.70E-06/yr and seismic LERF of 1.85E-06/yr were developed to support the seismic penalty approach for RICT. These seismic CDF and LERF values from the RICT application are applied in this ILRT risk assessment evaluation of external events. It is noted that the Seismic CDF (3.70E-06/yr) is approximately a factor of 1.17 higher than the internal events CDF value of 3.15E-06/yr.

5.7.3 Other External Event Risk External hazards were evaluated in the LGS Individual Plant Examination of External Events (IPEEE) submittal [22] 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.

In addition to internal fires and seismic events, the LGS IPEEE Submittal analyzed a variety of other external hazards including, but not limited to:

• Aircraft impact

• External flooding

• Pipeline accidents

• Military and industrial facilities accidents

• Transportation accidents

• Release of chemicals in onsite storage Docket Nos. 50-352 and 50-353 ATTACHMENT 3 56 of 108

• High winds and tornadoes The IPEEE analysis concluded that the other external hazards were insignificant contributors to plant risk. The more recent RICT risk assessment [33] has confirmed that conclusion for Limerick.

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 other external events risk due to the ILRT extension is much less than that calculated for internal events, and is considered to be bounded by conservatism in the EPRI methodology.

5.7.4 External Events Impact Summary In summary, the combination of the fire and seismic CDF values described above results in an external events risk estimates of 5.15E-06/yr (fire) and 3.70E-06/yr (seismic). This compares to the Unit 1 internal events CDF of 3.15E-06/yr. Since the change in risk for the ILRT risk impact is a function of CDF, a multiplier will be used for the assessment for the external events impact. Table 5.7-1 summarizes the estimated external events CDF and LERF contribution for LGS.

TABLE 5.7-1 LGS EXTERNAL EVENTS CONTRIBUTOR

SUMMARY

EXTERNAL EVENT INITIATOR GROUP CDF (1/YR)

LERF (1/YR)

Seismic 3.70E-06 1.85E-06 Internal Fire (Unit 2) (1) 5.15E-06 1.01E-07 High Winds Screened Screened Other Hazards Screened Screened Total For External Events 8.85E-06 1.95E-06 Internal Events Values (for comparison) 3.15E-06 1.78E-07 Notes to Table 5.7-1:

(1)

The Unit 2 Fire PRA values are utilized since they are slightly higher than the Unit 1 values.

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As noted earlier, the EPRI Class 3b contribution is approximately proportional to CDF. An increase in CDF would likely lead to higher 3b frequency and assumed LERF. To determine a suitable multiplier of external CDF to internal event CDF, a multiplier is developed for each external event group (i.e., fire and seismic) and then added together to address both contributors, as shown in Table 5.7-2.

TABLE 5.7-2 LGS EXTERNAL EVENTS TO INTERNAL EVENTS CDF COMPARISON EXTERNAL EVENT INITIATOR GROUP CDF (1/YR)

RATIO TO FPIE CDF Seismic 3.70E-06 1.17 Internal Fire (Unit 2) 5.15E-06 1.63 Total For External Events 8.85E-06 2.81 Internal Events CDF 3.15E-06 1.00 5.7.5 External Events Impact on ILRT Extension Assessment The EPRI Category 3b frequency for the 3-in-10 year, 15 year, and 16.25 year ILRT intervals are shown in Table 5.6-1 as 7.42E-09/yr, 3.94E-08/yr, and 4.30E-08/yr, respectively. Using an external events multiplier of 2.81 for LGS, the change in the LERF risk measure due to extending the ILRT from 3-in-10 years to 1-in-15 years, including both internal and external hazards risk, is estimated as shown in Table 5.7-3.

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TABLE 5.7-3 LGS 3B (LERF/YR) AS A FUNCTION OF ILRT FREQUENCY FOR INTERNAL AND EXTERNAL EVENTS (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD) 3B FREQ.

(3-IN-10 YR) 3B FREQ.

(15 YEAR) 3B FREQ.

(16.25 YEAR)

LERF INCREASE (3/10 TO 16.25 YEAR)

LERF INCREASE (15 TO 16.25 YEAR)

Internal Events Contribution 7.42E-09 3.94E-08 4.30E-08 3.56E-08 3.66E-09 External Events Contribution (Internal Events x 2.81) 2.08E-08 1.11E-07 1.21E-07 1.00E-07 1.03E-08 Combined (Internal +

External) 2.83E-08 1.50E-07 1.64E-07 1.36E-07 1.40E-08 The other figures of merit can be similarly derived using the multiplier approach and compared to the acceptance criteria for the ILRT extension risk assessment. The results between the 3-in-10 year interval and the 16.25 year interval, and the current 15 year interval and the 16.25 year interval compared to the acceptance criteria are shown in Table 5.7-4. 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 a one-time extension of the ILRT surveillance interval to 16.25 years has been demonstrated to be small when compared to the EPRI baseline of 3-in-10 year frequency (e.g., change in LERF < 1E-06/yr), and very small when compared to the current 15 year frequency (e.g., change in LERF < 1E-07/yr).

A bounding analysis for the total LERF contribution follows Table 5.7-4 to demonstrate that the total LERF value for LGS is less than 1.0E-05/yr consistent with the requirements for a small change in risk of the RG 1.174 acceptance guidelines.

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TABLE 5.7-4 COMPARISON TO ACCEPTANCE CRITERIA INCLUDING EXTERNAL EVENTS CONTRIBUTION FOR LGS CONTRIBUTOR LERF (/YR) 3 TO 16.25 LERF (/YR) 15 TO 16.25 PERSON-REM/YR 3 TO 16.25 PERSON-REM/YR 15 TO 16.25 CCFP 3 TO 16.25 CCFP 15 TO 16.25 Internal Events 3.56E-08 3.66E-09 5.38E-02 (0.37%)

5.43E-03 (0.038%)

1.13%

0.12%

External Events 1.00E-07 1.03E-08 1.51E-01 (0.37%)

1.53E-02 (0.038%)

1.13%

0.12%

Total 1.36E-07 1.40E-08 0.205 (0.37%)

0.021 (0.038%)

1.13%

0.12%

Acceptance Criteria

<1.0E-6/yr small change

<1.0E-7/yr very small change

<1.0 person-rem/yr or

<1.0%

<1.5%

The 1.40E-08/yr increase in LERF due to the combined internal and external events from extending the ILRT frequency from the current 15 year interval to the proposed 16.25 year interval falls within Region III being less than 1.0E-7 per reactor year and represents a very small change in risk per the RG 1.174 acceptance guidelines. The 1.36E-07/yr increase in LERF due to the combined internal and external events from extending the ILRT frequency from 3-in-10 years to the proposed 16.25 year interval falls within Region II being 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 4.2-3, the total LERF due to postulated internal event accidents is 1.78E-07/yr for LGS. As discussed in Section 5.7.2, the total LERF estimate for the Fire PRA model (Unit 2) is 1.01E-07/yr. As discussed in Section 5.7.3, the total LERF estimate for the Seismic PRA model is 1.85E-06/yr. The total LERF values for LGS are shown in Table 5.7-5.

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TABLE 5.7-5 IMPACT OF 16.25-YR ILRT EXTENSION ON LERF FOR LGS LERF CONTRIBUTOR (1/YR)

Internal Events LERF 1.78E-07 Fire LERF (Unit 2) 1.01E-07 Seismic LERF 1.85E-06 Internal Events LERF due to ILRT (at 16.25 years) (1) 4.30E-08 External Events LERF due to ILRT (at 16.25 years) (1) 1.21E-07

[Internal Events LERF due to ILRT

• 2.81]

Total 2.29E-06/yr Note to Table 5.7-5:

(1)

Including age adjusted steel liner corrosion likelihood as reported in Table 5.7-3.

As can be seen, the estimated bounding LERF for LGS is estimated as 2.29E-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.

LGS does not credit containment overpressure for the mitigation of design basis accidents. The LGS ECCS pumps are designed to have available NPSH based on minimum postaccident suppression pool level, maximum suppression pool temperature, partial plugging of strainers, and no credit for wetwell pressurization (see UFSAR [18]

Section 6.3.3.4). As such, the LGS PRA does not require containment pressurization above atmospheric conditions for successful ECCS injection. Therefore, an increase in the containment leakage (e.g., EPRI Class 3b) that prevents containment overpressurization would have no effect on successful ECCS injection.

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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.

For the Limerick permanent 15-year interval extension risk assessment [29] eight 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 containment 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%. Upper bound and lower bound cases were also performed varying the key parameters together. In each case the impact from including the corrosion effects was found to be small to negligible with regards to LERF. Even the upper bound estimate with very conservative assumptions for all of the key parameters yielded an increase in LERF due to corrosion of only 1.09E-7/yr for an extension of the ILRT interval from 3-in-10 years to 15 years. The upper bound results indicate that even with multiple very conservative assumptions, the conclusions from the base analysis did not change.

In view of these insights from the permanent 15-year interval risk assessment [29], these eight sensitivity cases are not repeated for this one-time 16.25 year interval risk assessment. The potential corrosion impacts associated with a one-time extension from the current 15-year interval to 16.25 years would be less than those identified in the corrosion sensitivities for the 3-in-10 years to 15-year interval evaluated for the permanent extension [29]. Including a LERF increase due to corrosion of the upper bound estimate of this previous LGS ILRT risk assessment (i.e., to 1.09E-07/yr) would not change the conclusions of the base analysis for this one-time 16.25 interval extension request.

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6.2 EPRI EXPERT ELICITATION SENSITIVITY An industry expert elicitation was performed to evaluate and 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. 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].

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 Jeffreys non-informative prior (i.e., assumed one half failure) for the large leak size while the expert elicitation sensitivity study uses the results from the expert elicitation. In addition, given the relationship between leakage magnitude and probability, larger leakage that is more representative of large early release frequency can be reflected. For the purposes of sensitivity, the same leakage magnitudes that are used in the base case methodology (i.e., 10La for small and 100La for large) would be used in the sensitivity case. 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. As shown, the mean probability of leakage for a given size is significantly reduced for the expert elicitation values, reflecting expected conservatism in the base case values.

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TABLE 6.2-1 EPRI EXPERT ELICITATION RESULTS LEAKAGE SIZE (LA)

BASE CASE MEAN PROBABILITY OF OCCURRENCE EXPERT ELICITATION MEAN PROBABILITY OF OCCURRENCE [3]

PERCENT REDUCTION 10 (Class 3a) 9.2E-03 3.88E-03 58%

100 (Class 3b) 2.3E-03 2.47E-04 89%

For the Limerick permanent 15-year interval extension risk assessment [29] a sensitivity case was conducted using the EPRI expert elicitation probability values for Class 3a and 3b in lieu of the base case values. The net effect of the reduction in the multipliers shown above led to a dramatic reduction on the calculated increase in the LERF values. The increase in the overall value for LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3-in-10 years to 15 years was reduced approximately an order of magnitude, from 3.23E-08/yr to 3.11E-09/yr [29]. A similar reduction of approximately an order of magnitude occurred for the change in CCFP (from 1.02% for the base case to 0.10% for the expert elicitation values). The change in total dose rate also significantly decreased from 6.60E-02 per-rem/yr to 1.16E-02 per-rem/yr (more than 80% reduction) using the expert elicitation 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 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.

This sensitivity case is not repeated for this one-time 16.25 year interval risk assessment; however, in view of these insights from the permanent 15-year interval risk assessment

[29], the change in metrics of interest associated with the one-time 16.25 year interval would be significantly less using the EPRI expert elicitation values than those calculated using the EPRI base case values. Particularly, the change in LERF even including external events impacts would be expected to be in the very small change region of RG.

1.174.

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6.3 MODEL CHANGES SENSITIVITY As discussed in more detail in Appendix A, Constellation employs a multi-faceted approach to establishing and maintaining the technical acceptability and plant fidelity of the PRA models for all operating Constellation nuclear generation sites. This approach includes a proceduralized PRA maintenance and update process. The Constellation risk management process ensures that the applicable PRA model is an accurate reflection of the as-built and as-operated plants.

The Constellation 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.). A PRA Updating Requirements Evaluation (URE-Constellation PRA model update tracking database) is created for all issues that are identified (e.g., plant changes, new industry data) that could impact the PRA model.

To examine the sensitivity of the ILRT risk assessment to the primary methodology inputs of CDF and LERF, a sensitivity was examined where the internal events CDF, LERF and other Level 2 release categories were all arbitrarily increased by 50% to bound the potential impact of any pending changes. Table 6.3-1 presents the key results as compared to the acceptance criteria for a change in ILRT interval from 3-in-10 years to 16.25 years and from 15 years to 16.25 years, including the corrosion effect of the containment liner.

TABLE 6.3-1 LGS ILRT EXTENSION COMPARISON TO ACCEPTANCE CRITERIA Interval Change LERF Person-rem/yr CCFP 3/10yrs to 16.25yrs 5.34E-08/yr 8.06E-02 (0.37%)

1.13%

15yrs to 16.25yrs 5.50E-09/yr 8.14E-03 (0.038%)

0.12%

Acceptance Criteria per NRC SE [7]

<1.0E-6/yr

<1.0 person-rem/yr or

<1.0%

<1.5%

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When compared against the base case results presented in Table 5.6-2 it is evident that the change in LERF and dose risk are effectively proportional to the CDF and Level 2 releases (i.e., an increase of 50% for the CDF and Level 2 releases result in an increase of approximately 50% to the change in LERF and dose risk). The change to CCFP is essentially not impacted by the CDF and Level 2 release increases given that its calculation involves the ratio of the Class 1 plus Class 3a frequencies divided by total CDF (i.e., the 50% frequency increases effectively cancel out). Even with a 50% increase in CDF and Level 2 releases, there is substantial margin to the acceptance criteria.

It is recognized that an increase of 50% in the internal events results would generally be expected to result in a meaningful increase in external event risk. To examine this potential, the external event risk for fire and seismic (i.e., estimated CDF and LERF) were also arbitrarily increased by 50% for sensitivity purposes. Table 6.3-2 presents the results for external events, also combined with internal events, as compared to the acceptance criteria for a change in ILRT interval from 3-in-10 years to 16.25 years and from 15 years to 16.25 years, including the corrosion effect of the containment liner.

TABLE 6.3-2 COMPARISON TO ACCEPTANCE CRITERIA INCLUDING EXTERNAL EVENTS CONTRIBUTION FOR LGS CONTRIBUTOR LERF (/YR) 3 TO 16.25 LERF (/YR) 15 TO 16.25 PERSON-REM/YR 3 TO 16.25 PERSON-REM/YR 15 TO 16.25 CCFP 3 TO 16.25 CCFP 15 TO 16.25 Internal Events 5.34E-08 5.50E-09 8.06E-02 (0.37%)

8.14E-03r (0.038%)

1.13%

0.12%

External Events 1.50E-07 1.54E-08 2.27E-01 (0.37%)

2.29E-02 (0.038%)

1.13%

0.12%

Total 2.04E-07 2.09E-08 0.307 (0.37%)

0.310 (0.038%)

1.13%

0.12%

Acceptance Criteria

<1.0E-6/yr small change

<1.0E-7/yr very small change

<1.0 person-rem/yr or

<1.0%

<1.5%

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When compared against the base case results presented in Table 5.7-4 it is evident that the change in LERF and dose risk due to external event risk are effectively proportional to the CDF and LERF, and the change to CCFP is essentially not impacted, similar to the results for internal event risk. Even with a 50% increase in fire and seismic CDF and LERF, there is substantial margin to the acceptance criteria.

Per RG 1.174, when the calculated increase in LERF due to the proposed plant change is in the small change range (i.e., Region II being between 1.0E-7 to 1.0E-6 per reactor year), the risk assessment must also reasonably show that the total LERF is less than 1.0E-5/yr. Table 6.3-3 presents the total LERF for this sensitivity case, demonstrating that total LERF has significant margin to the acceptance criterion.

TABLE 6.3-3 IMPACT OF 16.25-YR ILRT EXTENSION ON LERF FOR LGS LERF CONTRIBUTOR (1/YR)

Internal Events LERF 2.67E-07 Fire LERF (Unit 2) 1.52E-07 Seismic LERF 2.78E-06 Internal Events LERF due to ILRT (at 16.25 years) (1) 6.46E-08 External Events LERF due to ILRT (at 16.25 years) (1) 1.81E-07

[Internal Events LERF due to ILRT

• 2.81]

Total 3.44E-06/yr Acceptance Criterion

<1E-05/yr Note to Table 6.3-3:

(1)

Including age adjusted steel liner corrosion likelihood.

This sensitivity case demonstrates that due to the inherent margin in the ILRT risk assessment results for Limerick, the conclusion of the risk assessment would not change given even significant changes to the overall risk profile (e.g., CDF and LERF increasing by 50%).

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It is noted that in preparation for digital controls upgrades at Limerick, Constellation has been evaluating the potential impact of digital controls upon plant risk metrics. The digital controls modeling presently includes conservatisms with respect to inputs given that the modifications are not yet installed, generic failure data are used for the digital systems given that there are no plant specific failure data, and there is limited industry data on common cause failure for digital systems. Despite these present modeling conservatisms, the evaluation model projects that the incorporation of digital controls is expected to have a very small impact upon the PRA risk metrics, well below the bounds of this sensitivity case. Similarly, all of the PRA model changes currently being tracked in the URE database are well bounded by this sensitivity case. Therefore, the upgrade to digital controls or other projected model changes at the next PRA update would not have a meaningful impact upon this ILRT/DWBT risk assessment.

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7.0 CONCLUSION

S Based on the results from Section 5 and the sensitivity considerations presented in Section 6, and the DWBT analysis shown in Appendix B, the following conclusions regarding the assessment of the plant risk are associated with a one-time extension of the Type A ILRT test interval to 16.25 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 CDF below 1.0E-06/yr and increases in LERF below 1.0E-07/yr. Small changes in risk are defined as increases in CDF 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 CDF for LGS, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years (analysis base case) to 16.25 years with corrosion included is 3.56E-08/yr, while the increase from the current 15-year interval to 16.25 years is only 3.66E-09/yr (see Table 5.6-1). 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 3-in-10 years to 16.25 years, measured as an increase to the total integrated dose risk for all internal events accident sequences for LGS, is 5.38E-02 person-rem/yr (0.37%) using the EPRI guidance with the base case corrosion included (Table 5.6-1). The change in dose risk drops to 5.43E-03 person-rem/yr (0.038%) for an extension from the current 15-year interval to 16.25 years. 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 probability from the 3-in-10 year interval to 16.25 years including corrosion effects using the EPRI guidance (see Section 5.5) is 1.13%. This value drops to 0.12%

in view of an extension from the current 15-year interval to 16.25 years.

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 of the risk associated with external events was performed utilizing available information. As shown in Table 5.7-4, the total increase in LERF due to internal events and the bounding external events assessment is 1.36E-07/yr for the 3-in-10 year interval extended to 16.25 years. This value is in Region II of the Reg. Guide 1.174 acceptance guidelines. For extension from the current 15 years to 16.25 Docket Nos. 50-352 and 50-353 ATTACHMENT 3 69 of 108

years, the total increase in LERF is only 1.40E-08/yr, which is in Region III of Reg. Guide 1.174.

As shown in Table 5.7-5, the same bounding analysis indicates that the total LERF from both internal and external risks is 2.29E-06/yr which is less than the Reg. Guide 1.174 limit of 1.0E-05/yr given that the LERF is in Region II (small change in risk) for the extension analysis case of 3-in-10 years to 16.25 years.

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 LGS.

A DWBT risk analysis documented in Appendix B provides key metric values that, in combination with ILRT results, would not change the ILRT related conclusions described above. The DWBT values for an interval change from the original 3-in-10 years to 16.25 years are compared below to the ILRT base case with corrosion. These DWBT values are developed in Appendix B and reported in Appendix B, Section B.5.

Delta CDF = 8.69E-10/yr (ILRT increase = 0.0)

Delta LERF = 2.59E-09/yr (ILRT increase = 3.56E-08/yr)

Delta Dose = 9.25E-03 p-rem/yr (ILRT increase = 5.38E-02 p-rem/yr)

Delta CCFP = 0.0029%

(ILRT increase = 1.13%)

The DWBT CDF increase is less than 0.03% of base CDF (3.15E-06/yr). The DWBT values for change in LERF and CCFP are significantly below the ILRT values. Although the DWBT person-rem dose rate increase is about 17% of the ILRT dose rate increase, the total dose rate increase (DWBT and ILRT combined) is still less than 0.5% which is well less than the acceptance criteria of less than 1.0% increase. The change in DWBT risk metrics would be even smaller in view of the extension from the current 15 year interval to the proposed 16.25 year interval.

Therefore, increasing the ILRT (and associated DWBT) interval on a one-time basis to a 16.25 year interval is not considered to be significant since it represents only a small change in the LGS risk profile.

Previous Assessments The NRC in NUREG-1493 [6] has previously concluded the following:

• Reducing the frequency of Type A tests (ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk.

The estimated increase in risk is small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and Docket Nos. 50-352 and 50-353 ATTACHMENT 3 70 of 108

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

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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, NEI 94-01, Revision 3-A, July 2012.

[2]

Electric Power Research Institute, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI TR-104285, August 1994.

[3]

Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. EPRI TR-1018243, October 2008.

[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 3, January 2018.

[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 (NEI) Topical Report (TR) 94-01, Revision 2, Industry Guideline for Implementing Performance-Based Option Of 10 CFR Part 50, Appendix J and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, Risk Impact Assessment Of Extended Integrated Leak Rate Testing Intervals (TAC No. MC9663), Accession Number ML081140105, June 25, 2008.

[8]

Evaluation of Severe Accident Risks: Peach Bottom, Unit 2, Main Report NUREG/CR-4551, SAND86-1309, Volume 4, Revision 1, Part 1, December 1990.

[9]

ERIN Engineering and Research, Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMTM, 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.

[11]

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

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[12]

U.S. Nuclear Regulatory Commission, Technical Findings and Regulatory Analysis for Generic Safety Issue II.E.4.3 (Containment Integrity Check), NUREG-1273, April 1988.

[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]

Constellation Risk Management Team, Limerick Generating Station PRA Summary Notebook LG121A and LB221A Models, LG-PRA-013, Revision 5, May 2022.

[17]

Exelon Risk Management Team, Limerick 50-Mile Population Projection for Year 2050, LG-MISC-026, January 2018.

[18]

Limerick Generating Station, Updated Final Safety Analysis Report, UFSAR, Revision 22, September 2024.

[19]

Constellation Risk Management Team, Limerick Generating Station Fire PRA Summary & Quantification Notebook, LG-PRA-021.11, Revision 2, June 2022.

[20]

U.S. Nuclear Regulatory Commission, NRC Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4, June 28, 1991.

[21]

Letter from P. B. Cowan (Exelon Nuclear, Peach Bottom) to U.S. Nuclear Regulatory Commission, Response to Request for Additional Information - License Amendment Request for Type A Test Extension, Accession Number ML100560433, February 25, 2010.

[22]

Philadelphia Electric Company, Individual Plant Examination for External Events, Limerick Generating Station, Units 1 and 2, IPEEE Submittal, June 1995.

[23]

An Approach for Estimating the Frequencies of Various Containment Failure Modes and Bypass Events (NUREG/CR-6595, BNL-NUREG-52539, Revision 1),

October, 2004.

[24]

U.S. Nuclear Regulatory Commission, Generic Issue 199 (GI-199) Implications of Updated Probabilistic Seismic Hazard Estimates In Central And Eastern United States on Existing Plants Safety/Risk Assessment, ML100270756 - Appendix D:

Seismic Core-Damage Frequencies, August 2010.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 73 of 108

[25]

Letter from Justin Wheat, Southern Nuclear Operating Company, to U.S. NRC, subject Edwin I Hatch Plant Units 1 and 2, License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies, Correction to Attachment 3, ML16238A477, August 24, 2016.

[26]

U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 3, December 2020.

[27] Letter from Pamela B. Cowan, Exelon Generation Company, LLC to US NRC, subject: Limerick Generating Station Response to Request for Additional Information Technical Specifications Change Request - Type A Test Extension, ML072600355, September 2007.

[28]

Columbia Generating Station Risk Assessment to Support ILRT (Type A) Interval Extension Request. ERIN Report No. C106-04-0001-5801, ML042230388, June 2004.

[29]

Letter from James Barstow, Limerick Generating Stations, Exelon Generation Company, LLC, to US NRC, subject: Revise the Technical Specifications for Permanent Extension of Types A and C Leak Rate Test Frequencies and Permanently Extend the Drywell Bypass Leakage Test Frequency, ML19099A367, April 9, 2019.

[30]

U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 241 and 204 to Revise Technical Specification 6.8.4.g, Primary Containment Leakage Rate Testing Program, to Extend Containment Integrated Leak Rate Test Frequency (EPIK-L-2019-LLA-0073),

ML19351E376, March 11, 2020.

[31]

Letter from Patrick Simpson, Clinton Power Station, Exelon Generation Company, LLC to US NRC, subject: License Amendment Request for One-Time Extension of the Containment Type A Integrated Leakage Rate Test Frequency, ML21055A822, February 24, 2021.

[32]

U.S. Nuclear Regulatory Commission, Clinton Power Station, Units No. 1 -

Issuance of Amendment No. 239 Re: One-Time Extension of Containment Type A Integrated Leakage Rate Test Frequency (EPID L-2021LLA-0031 [COVID-19]),

ML21188A020, August 11, 2021.

[33]

Letter from James Barstow, Limerick Generating Station, Exelon Generation Company, LLC, to U.S. NRC, subject License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Docket Nos. 50-352 and 50-353 ATTACHMENT 3 74 of 108

Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, ML18347B366, December 13, 2018.

[34]

U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 240 and 203 to Implement TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, (EPID L-2018-LLA-0567), ML20034F637, February 28, 2020.

[35] Evaluation of Severe Accident Risks: Quantification of Major Input Parameters, MACCS Input, NUREG/CR-4551, SAND86-1309, Volume 2, Revision 1, Part 7, December 1990.

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APPENDIX A PRA TECHNICAL ACCEPTABILITY Docket Nos. 50-352 and 50-353 ATTACHMENT 3 76 of 108

A PRA TECHNICAL ACCEPTABILITY A.1 OVERVIEW Discussion of the Probabilistic Risk Assessment (PRA) analysis is presented in this appendix to support the risk assessment for the one-time extension of the LGS Unit 1 and Unit 2 containment Type A Integrated Leak Rate Test (ILRT) to a 16.25 year interval.

The discussion follows the guidance provided in Regulatory Guide 1.200, Revision 3 [A-1], Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities.

The guidance in RG-1.200 indicates that the following aspects should be included in the application:

1. Identify the parts of the PRA used to support the application

a. SSCs, operational characteristics affected by the application and how these are implemented in the PRA model.

b. A definition of the acceptance criteria used for the application.

2. Identify the scope of risk contributors addressed by the PRA model

a. 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

a. Include how the PRA model was modified to appropriately model the risk impact of the change request.

4. Demonstrate the Technical Acceptability of the PRA

a. 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.

b. 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.

c. 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.

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d. 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 risk assessment 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. It is noted that Limerick has submitted two LARs for risk applications in recent years (i.e., 50.69 [A-9] and RICT [A-11]) which were reviewed and approved by the NRC (via [A-10] for 50.69 and [A-12] for RICT). Both the 50.69 and RICT applications require higher PRA capability requirements than the ILRT risk application such that the previous NRC review of the technical adequacy and acceptability of the Limerick PRA models supports their use for this ILRT assessment.

The risk assessment performed for the ILRT extension request is based on the current Level 1 and Level 2 PRA models as discussed in the main document. The accepted industry methodology for this ILRT risk assessment involves a bounding approach to estimate the change in the LERF from extending the ILRT (and Drywell Bypass Test (DWBT)) interval. Rather than exercising the PRA model itself, the assessment 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 II 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 Constellation model update process, the peer reviews performed on the LGS models, the results of those peer reviews and the current consistency with applicable standards in view of the ILRT/DWBT extension risk assessment are provided in Section A.2. Section A.3 provides an assessment of key assumptions and approximations used in this risk evaluation. Finally, Section A.4 briefly summarizes the results of the PRA technical acceptability assessment with respect to this application.

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A.2 PRA MODEL EVOLUTION AND PEER REVIEW

SUMMARY

A.2.1 Introduction The 2021 versions of the LGS PRA models are the most recent model of record evaluations of the Unit 1 and Unit 2 risk profile at LGS for internal event challenges. The LGS 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 LGS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.

Constellation employs a multi-faceted approach to establishing and maintaining the technical acceptability and plant fidelity of the PRA models for all operating Constellation 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 LGS PRA.

PRA Maintenance and Update The Constellation 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 Constellation 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 Constellation nuclear generation sites. The overall Constellation 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:

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• Design changes and procedure changes 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 at least once every two refueling cycles.

In addition to these activities, Constellation risk management procedures provide 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 the 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)).

As indicated previously, RG 1.200 also requires that additional information be provided as part of the LAR submittal to demonstrate the technical acceptability 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.

A.2.2 Plant Changes Not Yet Incorporated into the PRA Model A PRA Updating Requirements Evaluation (URE - Constellation PRA model update tracking database) is created for all issues that are identified (e.g., plant changes, new industry data) that could impact the PRA model.

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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 impact the conclusions of this ILRT/DWBT risk assessment.

A.2.3 Consistency with Applicable PRA Standards Several assessments (e.g., industry peer reviews) of technical capability have been made for the LGS internal events PRA models during their evolution. These assessments are briefly summarized as follows, with more detailed information provided in the RICT LAR

[A-11] which was reviewed and approved by the NRC [A-12]:

• Industry peer review in November 1998, followed by a model update in 2001 to address the significant findings from that review.

• An NRC RG 1.200 pilot assessment in July 2004, followed by a PRA update in 2005 to strategically address the identified gaps.

• An industry peer review against draft Addendum B of the ASME PRA Standard [A-2] was performed in October 2005, finding that 97% of the SRs evaluated Met Capability Category II or better.

• A focused scope peer review against Addendum B of the ASME PRA Standard of the updated Internal Flooding (IF) analysis was performed in May 2008.

• A PRA update was performed in to address findings from the 2005 and 2008 peer reviews.

• In July 2016 a review of the peer review resolutions was performed by an independent review team [A-5].

As part of NRC review and approval of the RICT LAR, the NRC staff reviewed the resolution of the peer review findings concluding that they had been adequately addressed. In summary, the NRC in the LGS RICT Safety Evaluation [A-12] states:

The NRC staff concludes that the Limerick internal events PRA, including internal flooding, has been appropriately peer reviewed or assessed against the requirements of the ASME/ANS PRA Standard RA-Sa-2009 and in accordance with RG 1.200, Revision 2, and that the licensee has adequately dispositioned the F&Os to support the technical acceptability of the internal events PRA for the RICT program detailed in that LAR technical adequacy of the internal events PRA.

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As noted previously, the RICT application requires higher PRA capability requirements than the ILRT risk application such that the NRC review of the technical adqequacy and acceptability of the Limerick internal events (and included internal flooding) PRA models supports the PRAs acceptability for this ILRT risk assessment.

A.2.5 External Events Although EPRI report 1018243 [A-8] recommends a quantitative assessment of the contribution of external events (e.g., fire, 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 discussion of the unscreened external events contributors (i.e., internal fire hazards and seismic hazards) follows.

Internal Fire Hazards Several assessments (e.g., industry peer reviews) of technical capability have been made for the LGS Fire PRA models during their evolution. These assessments are briefly summarized as follows, with more detailed information provided in the RICT LAR [A-11]

which was reviewed and approved by the NRC [A-12]:

• A Fire PRA peer review was performed November 2011 using the NEI 07-12 Fire PRA peer review process [A-7], the ASME PRA Standard, ASME/ANS RA-Sa-2009 [A-6] and Regulatory Guide 1.200, Rev. 2 [A-3].

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• The Fire PRA was updated to address peer review findings and in July 2016 an independent review team performed a review of the 2011 peer review findings and the resolutions [A-5].

• Focused scope peer reviews were conducted in 2017 and 2018 on select technical areas and quantification.

As part of NRC review and approval of the RICT LAR, the NRC staff reviewed the resolution of the peer review findings concluding that they had been adequately addressed. In summary, the NRC in the LGS RICT Safety Evaluation [A-12] states:

The NRC staff concludes that the Limerick Fire PRA has been appropriately peer reviewed against the ASME/ANS PRA Standard RA-Sa-2009 and RG 1.200, Revision 2, and that the licensee has adequately dispositioned the F&Os to support the technical acceptability of the Fire PRA for the RICT program.

As noted previously, the RICT application requires higher PRA capability requirements than the ILRT risk application such that the NRC review of the technical adqequacy and acceptability of the Limerick Fire PRA models supports the PRAs acceptability for this ILRT risk assessment.

Seismic Hazards A seismic CDF PRA model is not maintained for Limerick. As noted in Section 5.7.2 of the main body of the LGS ILRT risk assessment, for the Limerick RICT LAR [A-11] which was reviewed and approved by the NRC [A-12], a seismic CDF of 3.70E-06/yr and seismic LERF of 1.85E-06/yr were developed to support the seismic penalty approach for RICT. With regards to the basis of the seismic CDF and LERF valus, the NRC Safety Evaluation [A-12] noted that:

• the licensee used the most current site-specific seismic hazard information for Limerick

• the licensee used an acceptably low plant HCLPF value of 0.3g consistent with the information for Limerick in the GI-199 evaluation Docket Nos. 50-352 and 50-353 ATTACHMENT 3 83 of 108

These seismic CDF and LERF values from the RICT application are applied in this ILRT risk assessment as they satisfactorily support an order of magnitude LGS ILRT external events risk impact assessment.

A.2.6 PRA Quality Summary Based on the above, the LGS FPIE 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.

Similarly, the Fire PRA Model results and the seismic CDF and LERF estimates are judged to be adequate for performing a bounding order of magnitude assessment of ILRT impact.

Additionally, Limerick has submitted two LARs for risk applications in recent years (i.e.,

50.69 [A-9] and RICT [A-11]) which were reviewed and approved by the NRC (via [A-10]

for 50.69 and [A-12] for RICT). Both the 50.69 and RICT applications require higher PRA capability requirements than the ILRT risk application such that the previous NRC review of the technical adqequacy and acceptability of the Limerick PRA models also supports their use for this ILRT assessment.

The LGS 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.

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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 consideration of sensitivity studies (e.g., those performed for the Limerick 15-year permanent extension LAR [A-13]

approved by the NRC [A-14]) 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. The accepted process utilizes a bounding analysis approach, mostly driven by that CDF contribution which does not already lead to LERF. Therefore, there are no key assumptions or sources of uncertainty identified for this application (i.e.

those which would change the conclusions from the risk assessment results presented here).

A.4 TECHNICAL ACCEPTABILITY

SUMMARY

A PRA technical acceptability evaluation was performed consistent with the requirements of RG-1.200, Revision 3 [A-1]. This evaluation combined with the details of the results of this analysis demonstrates with reasonable assurance that the proposed one-time extension to the ILRT interval for LGS Unit 1 and Unit 2 to 16.25 years satisfies the risk acceptance guidelines in RG 1.174 [A-4].

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A.5 REFERENCES

[A-1] Regulatory Guide 1.200, Acceptability of Probabilistic Risk Assessment Results for Risk Informed Activities, Revision 3, December 2020.

[A-2] ASME, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, Draft Addendum B to ASME RA-Sa-2003, June 2005.

[A-3] 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-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 3, January 2018.

[A-5] Jensen Hughes, Limerick Generating Station PRA Finding Level Fact and Observation Technical Review, Report 032156-RPT-001, August 2016.

[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] NEI, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines, NEI 07-12, Revision 1, June 2010.

[A-8] Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325, EPRI TR-1018243, October 2008.

[A-9] Letter from James Barstow, Limerick Generating Stations, Exelon Generation Company, LLC, to US NRC, subject: Application to Adopt 10 CFR 50.69, Risk-Informed Categorization and Treatment of Structures, Systems, and Components (SSCs) for Nuclear Power Plants, ML17179A161, June 28, 2017.

[A-10] U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 230 and 193 to Adopt Title 10 of the Code of Federal Regulations Section 50.69, Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors (CAC Nos MF9873 and MF9874; EPID L-2017-LLA-0275), ML18165A162, July 31, 2018.

[A-11] Letter from James Barstow, Limerick Generating Station, Exelon Generation Company, LLC, to U.S. NRC, subject: License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, ML18347B366, December 13, 2018.

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[A-12] U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 2401 and 203 to Implement TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, (EPID L-2018-LLA-0567), ML20034F637, February 28, 2020.

[A-13] Letter from James Barstow, Limerick Generating Stations, Exelon Generation Company, LLC, to US NRC, subject: Revise the Technical Specifications for Permanent Extension of Types A and C Leak Rate Test Frequencies and Permanently Extend the Drywell Bypass Leakage Test Frequency, ML19099A367, April 9, 2019.

[A-14] U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 241 and 204 to Revise Technical Specification 6.8.4.g, Primary Containment Leakage Rate Testing Program, to Extend Containment Integrated Leak Rate Test Frequency (EPIK-L-2019-LLA-0073),

ML19351E376, March 11, 2020.

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Appendix B BYPASS LEAK RATE TEST RISK ASSESSMENT Docket Nos. 50-352 and 50-353 ATTACHMENT 3 88 of 108

B BYPASS LEAK RATE TEST RISK ASSESSMENT The methodology to evaluate the impact of concurrently extending the DWBT interval to 16.25 years on a one-time basis is performed consistent with the LGS permanent 15-year ILRT/DWBT extension risk assessment [B-1] which was approved by the NRC [B-8].

=

Background===

The following steps are used to perform the analysis for the DWBT interval extension:

• Review the design basis

• Review historical test results

• Develop qualitative technical justification of change

• Perform deterministic calculations

• Perform risk assessment of interval change B.1 LGS MARK II PRESSURE SUPPRESSION CONTAINMENT DESIGN LGS incorporates a Mark II containment with the drywell located over the suppression chamber and separated by a diaphragm slab. The suppression chamber contains a pool of water having a depth that varies between 22 and 24-3 during normal operation.

Eighty-seven downcomers and 14 main steam safety/relief valve (SRV) discharge lines penetrate the diaphragm slab and terminate at a pre-designed submergence within the pool. During a loss of coolant accident (LOCA) inside containment, the containment design directs steam from the drywell to the suppression pool via the downcomers through the pool of water to limit the maximum containment pressure response to less than the design pressure of 55 psig. The effectiveness of the LGS pressure suppression containment requires that the leak path from the drywell to the suppression chamber airspace be minimized. Steam that enters the suppression pool airspace through the leak paths will bypass the suppression pool and can result in a rapid post-LOCA increase in containment pressure depending on the size of the bypass flow area.

The design value for leakage area is determined by analyzing a spectrum of LOCA break sizes. For each break size there is a limiting leakage area. In determining the limiting Docket Nos. 50-352 and 50-353 ATTACHMENT 3 89 of 108

leakage area, credit is taken for the capability of operators to initiate drywell and suppression pool sprays after a period of time sufficient for them to realize that there is a significant bypass leakage flow. The effect of suppression pool bypass on containment pressure response is greatest with small breaks. The design value of 0.0500 ft² for LGS represents the maximum leakage area that can be tolerated for that break size that is most limiting with respect to suppression pool bypass.

Limerick Tech Spec (TS) requirements conservatively specify a maximum allowable bypass area of 10% of the design value of 0.0500 ft². The TS limit provides an additional factor of 10 safety margin above the conservatisms taken in the steam bypass analysis.

The drywell-to-suppression chamber bypass test verifies that the actual bypass flow area is less than or equal to the TS limit.

B.2 HISTORICAL TEST RESULTS A review of the past test history for the drywell-to-suppression chamber bypass leakage test has identified no failures. The following are the test results [B-1, B-6]:

Unit 1 (Acceptance - 0.005 sq. ft.)

Unit 2 (Acceptance - 0.005 sq. ft.)

1984 - 0.00026 1989 - 0.000069 1987 - 0.00005133 1993 - 0.000076 1990 - 0.000278 1999 - 0.000012 1998 - 0.000075 2013 - 0.000137 2012 - 0.000151 The history of test results indicates that the typical leakage is about an order of magnitude or more below the acceptance criteria (which is set at an order of magnitude below the design basis limit). This excellent history combined with the conservatism included in the allowable leakage rate helps to support the qualitative justification provided below, and also helps support the low likelihood of a large undetected bypass leakage in the risk assessment.

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B.3 QUALITATIVE JUSTIFICATION FOR DWBT INTERVAL EXTENSION Several potential bypass leakage pathways exist:

• Leakage through the diaphragm floor penetrations (SRV discharge line downcomers),

• Cracks in the diaphragm floor/liner plate,

• Cracks in the downcomers that pass through the suppression pool airspace,

• Valve seat leakage in the four sets of drywell-to-suppression chamber containment vacuum breakers, and

• Seat leakage of isolation valves in piping connecting the drywell and the suppression chamber air space.

A previous assessment [B-2] demonstrated that the most likely source of potential bypass leakage is the four sets of drywell-to-suppression chamber vacuum breakers. Each set consists of two vacuum breakers in series, flange mounted to a tee off the downcomers in the suppression chamber airspace. The drywell-to-suppression chamber bypass leak test is currently performed on a schedule consistent with the ILRT. However, TS 4.6.2.1.f requires that the vacuum breaker leakage tests on all four sets of vacuum breakers be performed on all non-ILRT outages. Therefore, the most likely largest contributor to the bypass leakage will still be monitored each refueling outage and therefore will continue to be managed and controlled to assure Tech Spec leakage is maintained.

The vacuum breaker leakage test and stringent acceptance criteria, combined with the historical negligible non-vacuum breaker leakage, and thorough periodic visual inspection provide an equivalent level of assurance as the DWBT that the drywell to suppression chamber bypass leakage can be measured and any adverse condition detected prior to a LOCA.

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B.4 DETERMINISTIC CALCULATIONS As part of the risk assessment of the for the 15-year permanent DWBT interval extension

[B-1], a set of deterministic thermal hydraulic analyses were performed to identify the impact of increased drywell to suppression chamber leakage on the risk spectrum [B-5].

These same calculations are applicable to this 16.25 year interval risk assessment.

Table B-2 summarizes the results of the deterministic thermal hydraulic analyses using the LGS specific plant model (i.e., MAAP model). The results in Tables B-2 focus on the response of containment pressurization to water and steam LOCA events as a function of the drywell to suppression chamber bypass leakage.

Tables B-2 displays the following key results from this analysis and the impact of increased drywell to suppression chamber bypass leakage:

As shown in the table, steam LOCAs are a greater challenge than water LOCAs.

Medium and large steam LOCA events challenge the ultimate containment pressure (~140 psig) capability for a leakage size of 100x Tech Spec leakage. The steam events have the potential to result in core damage and a Large Early Release (LERF) event. The time to drywell failure ranges from 2.0 to 2.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Small steam LOCA events do not exceed the ultimate containment pressure (~140 psig) capability for a leakage size of 100x Tech Spec leakage for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time. However, it is noted that some additional mitigation measures would be required to achieve a safe and stable state for the small steam LOCA initiators.

A water LOCA event with a concurrent drywell bypass leakage of size 100x TS leakage does not challenge the ultimate containment pressure limit. Therefore, CDF associated with water break LOCAs and bypass leakage up to 100x TS leakage is not affected because adequate vapor suppression is present.

The vacuum breaker failure-to-close bypass cases (600x TS leakage) are run for information.

It should be noted that there are simple crew actions that can successfully mitigate the containment pressurization observed in the LOCA cases:

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Use of drywell sprays Emergency depressurization Both actions are called for by the LGS TRIPs and neither system is adversely impacted by the small LOCA initiating event. As can be seen in Table B-2, the large and medium steam LOCA events would reach the ultimate containment pressure in about two hours.

This would provide operators ample time to provide mitigation measures. For the small steam LOCAs, even more time would be available such that the TSC is operational and actions according to the EOPs will be taken with a high degree of certainty, comparable to the certainty applied to the initiation of RHR.

In conclusion, for a full range of water LOCAs, variations in the drywell to suppression chamber bypass leakage, from zero to many times Tech Spec leakage, do not impact the vapor suppression capability of the LGS containment and therefore do not significantly impact the calculated CDF or radionuclide release frequency for these accident scenarios. For the medium and large steam LOCAs the results indicate that the containment pressure exceeds the ultimate containment pressure within a few hours. For small steam LOCAs, the containment pressure approaches the ultimate containment pressure within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time. For simplicity, an operator action to initiate containment sprays or perform an emergency depressurization is assumed to be required to prevent containment overpressure failure for a leakage of this magnitude. These conclusions regarding the impact of the potential for increased drywell to suppression chamber leakage are factored into the risk assessment.

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TABLE B-2 CONTAINMENT PRESSURE RESPONSE FOR LOCA INITIATORS AS A FUNCTION OF DRYWELL TO WETWELL BYPASS LEAKAGE MAAP Case(1) (2)

DRYWELL PRESSURE (PSIG)

TIME TO DRYWELL FAILURE AT 140 PSIG (HOURS)

INITIAL PEAK AT 5 HRS AT 24 HRS STEAM WATER STEAM WATER STEAM WATER STEAM WATER SLOCA-0L 35.4 33.4 50.8 44.6 N/A N/A SLOCA-10L 45.5 42.4 66.4 45.8 N/A N/A SLOCA-100L 102.7 40.9 121.6 45.5 N/A N/A SLOCA-600L(3) 103.2 40.9 121.2 45.2 N/A N/A MLOCA-0L 30.1 29.6 33.3 13.6 42.5 25.2 N/A N/A MLOCA-10L 33.2 32.0 43.8 13.7 66.9 23.0 N/A N/A MLOCA-100L 72.8 59.4 15.5 22.5 2.0 hrs N/A MLOCA-600L(3)

>140 132.0 21.3 20.4 0.9 hrs N/A LLOCA-0L 27.0 22.5 32.5 10.4 46.9 16.6 N/A N/A LLOCA-10L 29.4 22.7 42.5 10.6 66.0 16.7 N/A N/A LLOCA-100L

>140 25.2 10.8 16.8 2.2 Hrs N/A LLOCA-600L(3)

>140 37.2 12.4 16.9 1.8 hrs N/A Notes to Table B-2:

(1)

MAAP cases run with RHR in suppression pool cooling mode and no containment sprays actuated.

(2)

Case IDs: 0L cases indicate no DW to SP bypass, 10L and 100L run with 10x and 100x Tech Spec leakage from DW to WW, respectively.

(3)

LOCA with ECCS available and stuck open vacuum breaker (600x Tech Spec leakage from DW to WW).

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B.5 RISK ASSESSMENT The Drywell to Suppression Chamber leakage can lead to the following perturbations on risk metrics:

• The increase in leakage could result in an increase in the failure probability of the vapor suppression function and consequential failure of containment. This could lead to pool bypass and core damage.

• The bypass leakage would result in an increase in the radionuclides in the suppression chamber airspace following an RPV breach if drywell sprays were unavailable. This could result in increased radionuclide release for suppression chamber breach cases or suppression chamber (wetwell) vent cases with core damage and no drywell failure or other pool bypass mechanisms.

The following steps are used for the risk assessment:

1. Determine sequences that are impacted by changes in bypass area.

2. Calculate probability of large bypass area.

3. Calculate risk metrics for original bypass test interval.

4. Calculate risk metrics for 15 year bypass test interval.

5. Calculate the risk metrics for the 16.25 year bypass test interval.

6. Summarize the changes in the calculated risk metrics.

Step 1 - Determine Sequences Impacted by Changes in Bypass Area As shown in the deterministic calculations, the only accident sequences that are impacted by the DWBT interval extension are those severe accidents induced by a loss of containment integrity due to overpressure failure. Additionally, it was shown that the only potential contributors to this situation are small, medium, and large steam LOCAs that have sufficiently high bypass leakage to allow continual containment pressurization coupled with no mitigating actions.

Loss of containment from over pressurization with adequate vessel inventory make-up prior to failure, has the potential to cause loss of inventory make-up upon containment failure leading to core damage. This assessment will conservatively assume that all Docket Nos. 50-352 and 50-353 ATTACHMENT 3 95 of 108

injection is lost if containment failure occurs due to over pressurization afforded by drywell bypass leakage.

Additionally, it is acknowledged that some accident scenarios that are currently classified as early wetwell region failures have the potential to be re-categorized as LERF due to the presence of a large bypass area that would render the fission product scrubbing capabilities of the suppression pool ineffective in reducing the source term below LERF threshold values. These potential scenario changes will also be accounted for in this analysis.

Finally, it is noted that the potential exists for increased drywell to suppression chamber bypass leakage to have an impact on the likelihood that early containment failure occurs.

For example, in an SBO scenario (i.e., loss of all injection), molten debris in contact with significant volumes of water shortly after vessel failure could maximize the amount of steam generation resulting in a deleterious impact of the bypass leakage. The LGS Mark II containment design incorporates a pedestal directly below the RPV. This pedestal area would be expected to be dry unless containment sprays were operating prior to the time of vessel failure. The pedestal floor has drain pipes that are estimated to fail by core interaction shortly after vessel failure resulting (i.e., within 7 minutes) in a drywell to wetwell airspace pathway. The drain pipe pathway failure would exceed the postulated DWBT drywell to wetwell leakage area and would render a pre-existing drywell to wetwell leakage moot. As such, the risk assessment assumes that there is no increase in LERF from this potential accident scenario (i.e. LERF due to early containment failure from drywell bypass vapor suppression failure near the time of vessel failure) due to changing the DWBT interval.

Step 2 - Calculate Probability of Large Bypass Area Industry and LGS experience with the results of the DWBT has been quite good.

However, for simplicity and for consistency with the ILRT analysis for LGS, it will be Docket Nos. 50-352 and 50-353 ATTACHMENT 3 96 of 108

assumed that the base case potential for a large drywell to suppression chamber bypass leak (100La) is the same as was utilized for the ILRT analysis (i.e. 0.0023).

Additionally, consistent with the EPRI Guidance [B-3], the change in the probability of a large undetected bypass increases by a factor of 3.33 for a ten-year interval, by a factor of 5.0 for a 15-year interval, and an extension to a 16.25 year interval can be estimated to lead to a factor increase of 5.42 in the non-detection probability of a leak.

Step 3 - Calculate the Risk for the 3 in 10 Year Bypass Leak Rate Test Interval The LGS base case did not include DW to WW bypass failure. Therefore the frequency of the Base Case model is adjusted to incorporate the severe accident frequency.

As described in Step 2, the probability of a large bypass given the original DWBT interval and excellent historical test experience is assumed to be 0.0023. Thus, the CDF to be added to the base model is:

CDF = (Small Steam LOCA) (Large Bypass Leak Probability)

(DW Spray Failure Probability Emergency Depressurization)SLOCA +

(Medium Steam LOCA) (Large Bypass Leak Probability)

(DW Spray Failure Probability Emergency Depressurization)MLOCA +

(Large Steam LOCA) (Large Bypass Leak Probability)

(DW Spray Failure Probability Emergency Depressurization)LLOCA Where the applicable LOCA(1) initiating event frequencies are taken from the current LGS PRA model [B-7]. Addtionally, given the extremely long time avaialble to take mitigative measures in the small steam LOCA case, a bounding value of 1E-4 is utilized to represent the combined fialure probabililty of the DW spray failure probability and emergency depressurization actions. This bounding value accounts for both operator action dependencies and hardware failures. Given the approximate two-hour time frame available in the medium and large steam LOCA scenarios, a factor of ten higher value is (1) LOCA frequencies are as follows:

Small Steam LOCA (2.04E-04/yr)

Medium Steam LOCA (5.76E-05/yr)

Large Steam LOCA (7.45E-06/yr)

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utilized (i.e., 1E-3 combined failure probability). Thus, the calculated increase in CDF is as follows.

CDFSLOCA = 2.04E-04/yr 0.0023 1.0E-04 = 4.69E-11/yr CDFMLOCA = 5.76E-05/yr 0.0023 1.0E-03 = 1.32E-10/yr CDFLLOCA

= 7.45E-06/yr 0.0023 1.0E-03 = 1.71E-11/yr CDF = 4.69E-11/yr + 1.32E-10/yr + 1.71E-11/yr = 1.97E-10/yr Assuming all of this increase also leads to a large and early release, adjustments can also be made to EPRI Category 2 for the new LERF contribution from these small, medium and large steam LOCAs. However, as can be easily seen, the new contributors to CDF and LERF are negligible compared with the previously assessed base case, and will not have any measurable impact on the results.

Change in LERF for Existing Sequences The potential change in LERF is limited to those accident scenarios that were previously classified as early wetwell region failures in Category 7. This contribution can be conservatively represented by the Low-Early (L/E) and Medium-Early (M/E) contributions assigned to APB#1 and APB#2. That is, it will be conservatively assumed that all previous L/E and M/E contributions from APB#1 and APB#2 would be H/E release given a DWBT leakage of 100La.

Medium-Early (M/E) = (M/EOriginal from APB#1)

• Large Bypass Leak Probability

= (1.55E-07/yr)

• 0.0023 = 3.55E-10/yr Low-Early (L/E) = (L/EOriginal from APB#2)

• Large Bypass Leak Probability

= (1.50E-08/yr)

• 0.0023 = 3.45E-11/yr These L/E and M/E will be assumed to represent a change in LERF and the contributions will be removed from Category 7 contributions and moved to Category 2 (Isolation Bypass Failure).

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EPRI Class 2

=

Medium-Early (M/E) + Low-Early (L/E)

=

3.55E-10/yr + 3.45E-11/yr = 3.90E-10/yr For the purposes of this assessment, the changes to EPRI Classes 3a and 3b from the ILRT interval extension will be ignored so as to isolate the potential impact of the changes on the DWBT interval extension. With the population dose information derived for LGS as shown in Table 5.2-2 of the ILRT portion of the LGS submittal, with the initial EPRI Class 2, and 7 frequency information obtained from the detailed information that was used to support the development of that table, and with EPRI Class 1 assigned the remaining CDF from the total, the revised base case results showing the adjustments to Class 2, and 7 as described above are shown in Table B-3.

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TABLE B-3 QUANTITATIVE RESULTS AS A FUNCTION OF ORIGINAL DWBT INTERVAL FOR 3 IN 10 YEARS FREQUENCY ORIGINAL DWBT INTERVAL EPRI CLASS DOSE (PERSON-REM WITHIN 50 MILES)

ACCIDENT FREQUENCY (PER YEAR)

POPULATION DOSE RATE (PERSON-REM/YEAR WITHIN 50 MILES) 1 1.15E+04 3.29E-07(2) 3.79E-03 2

6.93E+06 1.11E-08

+ 1.97E-10(3)

+ 3.90E-10(4)

= 1.17E-08 8.11E-02 3a 1.15E+05 3b 1.15E+06 4

N/A N/A N/A 5

N/A N/A N/A 6

N/A N/A N/A 7

5.06E+06 2.78E-06

- 3.90E-10

= 2.78E-06 1.40E+01 8

6.93E+06 3.25E-08 2.25E-01 TOTALS CDF CCFP(1) 3.15E-06 89.559%

14.357 Notes to Table B-3:

(1)

Determined from (Class 2 + Class 7 + Class 8) / (Total CDF)

(2)

Intact containment CDF w/o subtracting class 3a and 3b contributors.

(3)

Represents new CDF from small, medium, and large LOCA sequences.

(4)

Represents non-large releases from Class 7 that now become large early releases (moved to Class 2).

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 100 of 108

Step 4 - Calculate the Risk for 15 Year Bypass Leak Rate Test Interval The risk metrics for the 15 year DWBT interval are the same as the base case from Step 3, except the impact of the bypass leakage is increased by a factor of 5.00 consistent with the ILRT assessment. The revised results are shown in Table B-4.

TABLE B-4 QUANTITATIVE RESULTS AS A FUNCTION OF 15 YEAR DWBT INTERVAL 15 YEAR DWBT INTERVAL EPRI CLASS DOSE (PERSON-REM WITHIN 50 MILES)

ACCIDENT FREQUENCY (PER YEAR)

POPULATION DOSE RATE (PERSON-REM/YEAR WITHIN 50 MILES) 1 1.15E+04 3.29E-07(2) 3.79E-03 2

6.93E+06 1.11E-08

+ 9.83E-10(3)

+ 1.95E-09(4)

= 1.40E-08 9.74E-02 3a 1.15E+05 3b 1.15E+06 4

N/A N/A N/A 5

N/A N/A N/A 6

N/A N/A N/A 7

5.06E+06 2.78E-06

- 1.95E-09

= 2.78E-06 1.40E+01 8

6.93E+06 3.25E-08 2.25E-01 TOTALS CDF CCFP(1) 3.15E-06 89.562%

14.365 Notes to Table B-4:

(1)

Determined from (Class 2 + Class 7 + Class 8) / (Total CDF)

(2)

Intact containment CDF w/o subtracting class 3a and 3b contributors.

(3)

Represents new CDF from small, medium, and large LOCA sequences.

(4)

Represents non-large releases from Class 7 that now become large early releases (moved to Class 2).

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 101 of 108

Step 5 - Calculate the Risk for 16.25 Year Bypass Leak Rate Test Interval The risk metrics for the 15 year DWBT interval are the same as the base case from Step 3, except the impact of the bypass leakage is increased by a factor of 5.42 consistent with the ILRT assessment. The revised results are shown in Table B-5.

TABLE B-5 QUANTITATIVE RESULTS AS A FUNCTION OF 16.25 YEAR DWBT INTERVAL 16.25 YEAR DWBT INTERVAL EPRI CLASS DOSE (PERSON-REM WITHIN 50 MILES)

ACCIDENT FREQUENCY (PER YEAR)

POPULATION DOSE RATE (PERSON-REM/YEAR WITHIN 50 MILES) 1 1.15E+04 3.29E-07(2) 3.79E-03 2

6.93E+06 1.11E-08

+ 1.07E-09(3)

+ 2.11E-09(4)

= 1.43E-08 9.91E-02 3a 1.15E+05 3b 1.15E+06 4

N/A N/A N/A 5

N/A N/A N/A 6

N/A N/A N/A 7

5.06E+06 2.78E-06

- 2.11E-09

= 2.78E-06 1.40E+01 8

6.93E+06 3.25E-08 2.25E-01 TOTALS CDF CCFP(1) 3.15E-06 89.562%

14.366 Notes to Table B-5:

(1)

Determined from (Class 2 + Class 7 + Class 8) / (Total CDF)

(2)

Intact containment CDF w/o subtracting class 3a and 3b contributors.

(3)

Represents new CDF from small, medium, and large LOCA sequences.

(4)

Represents non-large releases from Class 7 that now become large early releases (moved to Class 2).

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 102 of 108

Step 6 - Summarize the Changes in the Calculated Risk Metrics Consistent with the ILRT assessment, the relevant figures of merit are change in LERF, population dose, and CCFP. Additionally, the DWBT extension will also lead to a change in CDF as previously described. The results for these figures of merit from the DWBT interval extension are shown below in Table B-6.

Table B-6

SUMMARY

OF QUANTITATIVE RESULTS FOR DWBT INTERVAL EXTENSION FIGURE OF MERIT 3-IN-10 YR DWBT INTERVAL 15 YR DWBT INTERVAL 16.25 YR DWBT INTERVAL CDF

(/yr) 3.150E-06 3.151E-06 3.151E-06 LERF (Class 2)

(/yr) 1.17E-08 1.40E-08 1.43E-08 Dose (person-rem/yr) 14.357 14.365 14.366 CCFP

(%)

89.559%

89.562%

89.562%

Changes from 3 in 10 yr. interval Increase in CDF (/yr) 7.86E-10 8.69E-10 Increase in LERF (/yr) 2.35E-09 2.59E-09 Increase in Dose (person-rem/yr) 8.37E-03 (0.058%)

9.25E-03 (0.064%)

Increase in CCFP (%)

0.0026%

0.0029%

Based on the results of the deterministic studies and their probabilistic risk assessment implications, the following can be defined:

• Increasing the DWBT interval is assumed to increase the probability of increased bypass leakage.

• There is a change in CDF associated with the possibility that a steam LOCA occurs with the increased DW to WW bypass leakage and the containment pressurization is not mitigated. This is conservatively assumed to lead to containment failure and consequential loss of RPV makeup resulting in core damage.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 103 of 108

• There is also a change in the LERF associated with the possibility that previous early WW region failures that were not considered LERF due to the fission product scrubbing effects of the suppression pool would be LERF if sufficient bypass leakage area exists.

• The change in population dose associated with the changes above, as provided in Table B-6, is very small (<0.07%).

• There is also a change in the CCFP with an increase in CDF. It is also noted that the increase in LERF is only from cases that were already containment failure cases (albeit shifted to a LERF release).

The risk metric changes associated with a one-time extension of the DWBT to 16.25 year interval compared to a base case interval of 3-in-10 years are then:

CDF

= 8.69E-10/yr LERF

= 2.59E-09/yr Person-rem dose rate = 9.25E-03 person-rem/yr (0.064%)

CCFP

= 0.0029%

The risk metric changes associated with a 16.25 year interval as compared to the current 15 year interval are approximately an order of magnitude smaller:

CDF

= 8.25E-11/yr LERF

= 2.46E-10/yr Person-rem dose rate = 8.79E-04 person-rem/yr (0.0061%)

CCFP

= 0.00027%

The changes in CDF and LERF meet the Regulatory Guide 1.174 [B-4] acceptance guidelines for very small risk change. The change in population dose rate is well below the acceptance criteria of 1.0 person-rem/yr or <1.0% person-rem/yr defined in the EPRI guidance document [B-3]. Change in CCFP of 0.0029% is over two orders of magnitude below the EPRI guidance document acceptance criteria of less than 1.5%.

The change in the risk metrics associated with the DWBT interval extension calculated above are based on internal events. The changes are very small and would not significantly change even if the potential impact from external events as calculated in Docket Nos. 50-352 and 50-353 ATTACHMENT 3 104 of 108

Section 5.7.5 of the main body were to be incorporated. That is, the change in CDF is negligible, the change in LERF from the DWBT is about 7% of the change in LERF from the ILRT, the change in person-rem from the DWBT is about 17% of the change in person-rem from the ILRT extension, and the change in CCFP is just about 0.25% of the change in CCFP from the ILRT. Given the substantial margin that exists to the acceptance criteria even when external events are factored in, including the DWBT results into the external events assessment would not change the conclusions of the analysis. In summary, the change in the DWBT interval extension from 3 in 10 years to 1 in 16.25 years is found to result in an acceptable change in risk.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 105 of 108

B.6 REFERENCES

[B-1]

Letter from James Barstow, Limerick Generating Stations, Exelon Generation Company, LLC, to US NRC, subject: Revise the Technical Specifications for Permanent Extension of Types A and C Leak Rate Test Frequencies and Permanently Extend the Drywell Bypass Leakage Test Frequency, ML19099A367, April 9, 2019.

[B-2] Letter from G.A. Hunger, Jr. (Philadelphia Electric Company) to U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2 Technical Specifications Change Request, Dockets No. 50-352 and 50-353, November 30, 1993.

[B-3] Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325, EPRI TR-1018243, October 2008.

[B-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 3, January 2018.

[B-5] Exelon Risk Management Team, MAAP Analysis to Support the DWBT Interval Extension Assessment, LG-MISC-027, January 2018.

[B-6] E-Mail from Brian Tracy (Exelon) to Arthur Holtz (Jensen Hughes), RE: Limerick PRA, (Provided most recent DWBT results), July 30, 2018.

[B-7] Constellation Risk Management Team, Limerick Generating Station PRA Summary Notebook LG121A and LB221A Models, LG-PRA-013, Revision 5, May 2022.

[B-8] U.S. Nuclear Regulatory Commission, Limerick Generating Station, Units 1 and 2

- Issuance of Amendment Nos 241 and 204 to Revise Technical Specification 6.8.4.g, Primary Containment Leakage Rate Testing Program, to Extend Containment Integrated Leak Rate Test Frequency (EPIK-L-2019-LLA-0073),

ML19351E376, March 11, 2020.

Docket Nos. 50-352 and 50-353 ATTACHMENT 3 106 of 108

1 Teagarden, Grant From:

Loyd, Suzanne: (Constellation Nuclear)

Sent:

Friday, February 28, 2025 9:12 AM To:

Vanover, Donald; Teagarden, Grant Cc:

Richards, Connelly:

Holtz, Arthur

Subject:

Re: [EXTERNAL]RE: LG-LAR-037 ILRT DWBT Risk Assessment R0 Signatures

[CAUTION - EXTERNAL SENDER] Warning this email comes from an external source.

I, Suzanne Loyd, Constellation Senior Manager, approve LG-LAR-037, Revision 0.

Nice work everyone.

Thanks, Suzanne Loyd Senior Manager, Nuclear Risk Management From: Vanover, Donald Sent: Friday, February 28, 2025 8:57 AM To: Teagarden, Grant Cc: Loyd, Suzanne: (Constellation Nuclear)

Richards, Connelly

Holtz, Arthur

Subject:

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2 From: Teagarden, Grant Sent: Friday, February 28, 2025 8:54 AM To: Vanover, Donald Cc:

Richards, Connelly:

Holtz, Arthur

Subject:

LG-LAR-037 ILRT DWBT Risk Assessment R0 Signatures I, Grant Teagarden, Jensen Hughes Risk Management Engineer, sign LG-LAR-037 Revision 0 as preparer.

Grant Teagarden Contractor, Risk Informed Engineering jensenhughes.com This Email message and any attachment may contain information that is proprietary, legally privileged, confidential and/or subject to copyright belonging to Constellation Energy Corporation or its affiliates

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