DCL-24-070, License Amendment Request 24-03 Revision to Technical Specification 5.5.16 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

License Amendment Request 24-03 Revision to Technical Specification 5.5.16 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML24213A331
Person / Time
Site:	Diablo Canyon
Issue date:	07/31/2024
From:	Rogers J Pacific Gas & Electric Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
DCL-24-070
Download: ML24213A331 (1)

Text

Justin E. Rogers Station Director Diablo Canyon Power Plant Mail code 104/5/502 P.O. Box 56 Avila Beach, CA 93424 805.545.3088 Justin.Rogers@pge.com A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Diablo Canyon

• Palo Verde

• Wolf Creek 10 CFR 50.90 PG&E Letter DCL-24-070 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Diablo Canyon Units 1 and 2 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 License Amendment Request 24-03 Revision to Technical Specification 5.5.16 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies

References:

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

2. Regulatory Guide 1.163, Revision 1, Performance-Based Containment Leak-Test Program, dated June 2023 (ADAMS Accession No. ML23073A154)

Dear Commissioners and Staff:

Pursuant to 10 CFR 50.90, Pacific Gas and Electric Company (PG&E) hereby requests approval of the enclosed proposed amendment to Facility Operating License Nos. DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP), respectively. The enclosed license amendment request (LAR) proposes to revise Technical Specification (TS) 5.5.16, Containment Leakage Rate Testing Program.

The proposed change to the TS revises Specification 5.5.16 by replacing the reference to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program to Revision 1 of RG 1.163 and 10 CFR 50, Appendix J, Option B -

Performance-Based Requirements, with a reference to NEI 94-01, Revision 3-A, dated July 2012, as the documents used by PG&E for DCPP to implement a performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. Also, this LAR proposes to remove the third exception under TS 5.5.16 for the 15-year Type A test interval beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2.

m PacHic Gas and Electric Company*

Document Control Desk PG&E Letter DCL-24-070 Page 2 A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Diablo Canyon

• Palo Verde

• Wolf Creek The changes in this LAR are consistent with NRC-endorsed guidance and have been similarly approved for other licensees. PG&E requests approval of this LAR within 12 months of completion of the NRCs acceptance review. PG&E requests the license amendment be made effective upon NRC issuance, to be implemented within 180 days from the date of issuance.

PG&E makes no regulatory commitments (as defined by NEI 99-04) in this letter.

This letter includes no revisions to existing regulatory commitments.

The enclosure to this letter contains the evaluation of the proposed change.

In accordance with site administrative procedures and the Quality Assurance Program, the proposed amendment has been reviewed by the Plant Staff Review Committee.

Pursuant to 10 CFR 50.91, PG&E is notifying the State of California of this LAR by transmitting a copy of this letter and enclosure to the California Department of Public Health.

If you have any questions or require additional information, please contact James Morris, Manager, Regulatory Services, at 805-545-4609.

I state under penalty of perjury that the foregoing is true and correct.

Sincerely, Justin E. Rogers Station Director Date misf/51230373 Enclosure cc:

Diablo Distribution cc/enc: Anthony Chu, Branch Chief, California Dept of Public Health Mahdi O. Hayes, NRC Senior Resident Inspector Samson S. Lee, NRR Project Manager John D. Monninger, NRC Region IV Administrator 07/31/2024

Enclosure PG&E Letter DCL-24-070 1

Evaluation of the Proposed Change License Amendment Request 24-03 Revision to Technical Specification 5.5.16, Containment Leakage Rate Testing Program for Permanent Extension of Type A and Type C Leak Rate Test Frequencies

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION 2.1 Current Containment Leakage Rate Testing Program 2.2 Proposed TS Changes Description

3. TECHNICAL EVALUATION 3.1 Primary Containment System 3.2 Justification for the Proposed Technical Specification Change 3.3 Plant Specific Confirmatory Analysis 3.4 Non-Risk Based Assessment 3.5 Operating Experience 3.6 License Renewal Aging Management 3.7 NRC Staff Regulatory Guidance and SER Limitations and Conditions 3.8 Conclusion

4. REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 Significant Hazards Consideration 4.4 Conclusions

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES ATTACHMENTS:

1. Proposed Technical Specification Page Markup

2. Proposed Retyped Technical Specification Page

Enclosure PG&E Letter DCL-24-070 2

1.

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.90, Pacific Gas and Electric Company (PG&E) requests an amendment to the Diablo Canyon Power Plant (DCPP) Technical Specifications (TS) to revise Specification 5.5.16, Containment Leakage Rate Testing Program to allow the following:

• Increase the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A (Reference 32), and the regulatory guidance specified in Regulatory Guide (RG) 1.163, Revision 1, Performance-Based Containment Leak-Test Program (Reference 48).

• Adopt an extension of the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, per RG 1.163, Performance-Based Containment Leak-Test Program (Reference 43), to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.

• Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2020, Containment System Leakage Testing Requirements (Reference 29).

• Adopt a more conservative allowable test interval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A.

The proposed change to the TS revises Specification 5.5.16 by replacing the references to RG 1.163 with a reference to NEI 94-01, Revision 3-A, and the regulatory guidance specified in Regulatory Guide (RG) 1.163, Revision 1, dated June 2023. These documents will be used by DCPP to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors. Also, this license amendment request (LAR) proposes to remove the third exception under Technical Specification 5.5.16 for the 15-year Type A test interval beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2.

Enclosure PG&E Letter DCL-24-070 3

2.

DETAILED DESCRIPTION 2.1 Current Containment Leakage Rate Testing Program DCPP Technical Specification 5.5.16, Containment Leakage Rate Testing Program, currently states, in part:

a.

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 RG 1.163, Performance-Based Containment Leak-Test Program, dated September 1995, as modified by the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements and frequency specified by ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

3.

The ten-year interval between performance of the integrated leakage rate (Type A) test, beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, has been extended to 15 years.

2.2 Proposed TS Changes Description The proposed changes to DCPP TS 5.5.16, will be (1) the administrative change to delete the information regarding the 15-year Type A test interval beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, and (2) to include the addition of references to RG 1.163 Revision 1 and the guidelines contained in NEI Topical Report, NEI 94-01, Revision 3-A for Type A, B and Type C leakage rate testing.

The proposed change revises the DCPP TS 5.5.16 to read as follows in part (with recommended changes using strike-out for deleted text and bold-type for added text for clarification purposes):

a.

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 RG 1.163, Revision 1, Performance-Based Containment Leak-Test Program, dated September 1995 June 2023, and NEI 94-

Enclosure PG&E Letter DCL-24-070 4

01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, dated July 2012, as modified by the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements and frequency specified by ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

3.

The ten-year interval between performance of the integrated leakage rate (Type A) test, beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, has been extended to 15 years.

Therefore, the retyped (clean) version of DCPP TS 5.5.16 will appear as follows:

a.

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 RG 1.163, Revision 1, Performance-Based Containment Leak-Test Program, dated June 2023, and NEI 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, dated July 2012, as modified by the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements and frequency specified by ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

A markup of Specification 5.5.16 is provided in Attachment 1. Proposed Retyped Technical Specification 5.5.16 is provided in Attachment 2.

Enclosure PG&E Letter DCL-24-070 5

Reference 64 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment follows the guidelines of NRC RG 1.174, Revision 3 (Reference 4) and NRC RG 1.200, Revision 2 (Reference 45). The risk assessment concluded that increasing the ILRT required performance interval from 10 to 15 years is considered insignificant since it represents a small change in the DCPP risk profile.

3.

TECHNICAL EVALUATION 3.1 Primary Containment System 3.1.1 Description of Primary Containment System The reactor containment building for each unit is a steel-lined, reinforced concrete cylindrical building with a dome roof that completely encloses the reactor and reactor coolant system (RCS). It ensures that essentially no leakage of radioactive materials to the environment would result even if gross failure of the RCS were to occur simultaneously with a design basis earthquake.

The exterior shell consists of a 142 feet (ft) high cylinder, topped with a hemispherical dome. The thickness of the concrete cylindrical walls is 3 ft, 8 inches and the thickness of the concrete roof is 2 ft, 6 inches. Both Units containments have a nominal inside diameter of 140 ft. The concrete floor pad is 153 ft in diameter with a thickness of 14 ft, 6 inches, with the reactor cavity near the center of the floor pad.

A continuous welded steel liner plate is provided on the entire inside face of the containment which prevents the release of radioactive materials to the environment under any postulated accident condition. The wall liner is 3/8 inches thick, except for the bottom section (approximately 4 ft high) next to the basemat where the thickness is 3/4 inches.

The dome liner is 3/8 inches thick. The thickness of the basemat liner is 1/4 inches and this liner is covered with a 24-inch-thick concrete floor slab for protection of the liner. The top of the concrete floor slab is at an elevation of 91.0 ft.

An anchorage system is provided to prevent instability of the liner during an earthquake.

The bottom of the wall liner is attached to the basemat by an anchorage system that consists of reinforcing bars attached to the wall liner. The wall liner and dome liner are anchored to the concrete with L-shaped welded studs placed in approximately an equilateral triangle pattern. The basemat liner is anchored to the basemat concrete through steel T-shaped sections anchored in the basemat.

Most of the reinforcement bars in the concrete shell are placed near the outside face of the shell to minimize temperature stresses; diagonal bars are also provided for seismic loads in the bottom portion of the shell and inside layer reinforcing is provided elsewhere to assure liner anchorage. Diagonal bars inclined at 60 degrees are used to resist both membrane shear and vertical tension in the cylindrical walls. The concrete dome

Enclosure PG&E Letter DCL-24-070 6

reinforcing bars are placed in a geodesic pattern matching the wall reinforcing. Diagonal bars from the cylindrical wall become a part of the geodesic pattern of the dome, forming continuous loops with both ends anchored in the basemat.

The equipment hatch is an 18 ft 6 inches nominal diameter opening for transportation of equipment through the containment wall. The opening is bound by a 3-inch thick, 24-inch wide, 18 ft 6 inches inside-diameter steel band, welded to the liner plate. An approximately 21 ft, 10-inch square area of the liner around the steel band is thickened to 1-1/2 inches.

The personnel hatch provides access to the inside of containment through a 9 ft diameter 17 ft 6 inches long penetration sleeve with bulkheads and sealed access doors at both ends. The penetration sleeve is made of 3/4-inch and 3/8-inch steel plate, welded to a 13 ft diameter liner insert plate. The bulkheads are made of 1-1/8-inch steel plate stiffeners.

The emergency hatch is similar to the personnel hatch except that it is smaller. The access door is 30 inches in diameter. The penetration sleeve is 5 ft in diameter and is constructed of a 1/2-inch plate which is welded to a 110-inch diameter, 1-inch thick liner insert plate.

Typically, penetrations consist of a sleeve embedded in concrete and welded to the liner.

A portion of the liner adjacent to the sleeve is made of a thicker plate thickness of 1-1/8 inches to replace the material displaced by the penetration and to reduce local stress concentrations.

The DCPP containment isolation system does not contain any stainless-steel bellows that are credited as a containment pressure boundary. Therefore, the concerns of Information Notice 92-20 are not applicable to DCPP and no inservice inspections of stainless-steel bellows are required.

3.1.2 Containment Overpressure on ECCS Performance The Emergency Core Cooling System (ECCS) is designed so that adequate Net Positive Suction Head (NPSH) is provided to system pumps. In addition to considering the static head and suction line pressure drop, the calculation of available NPSH in the recirculation mode for the Residual Heat Removal (RHR) pumps assumes that the vapor pressure of the liquid in the sump equals containment pressure. This assumption ensures that the actual available NPSH is always greater than the calculated NPSH.

Adequate NPSH is shown to be available for all ECCS pumps as follows:

RHR Pumps:

The NPSH of the RHR Pumps was evaluated for normal plant shutdown operation, and for both the injection and recirculation modes of operation for the design basis accident.

Enclosure PG&E Letter DCL-24-070 7

Recirculation operation gives the limiting NPSH requirement. The NPSH evaluation was based on all pumps (i.e., both RHR pumps, Centrifugal Charging Pump 1 (CCP1) and Centrifugal Charging Pump 2 (CCP2), both Safety Injection (SI) pumps, and both Containment Spray System (CSS) pumps) operating at the maximum design (run out) flow rates.

Safety Injection and Centrifugal Charging Pumps 1 and 2:

The NPSH for the SI pumps and CCP1 and CCP2 was evaluated for both the injection and recirculation modes of operation for the design basis accident. The end of the injection mode of operation gives the limiting NPSH available. The limiting NPSH was determined from the elevation head and vapor pressure of the water in the refueling water storage tank, which is at atmospheric pressure, and the pressure drop in the suction piping from the tank to the pumps. The NPSH evaluation is based on all pumps operating at the maximum design flow rates. Following switchover to the recirculation mode, adequate NPSH is supplied from the containment recirculation sump by the booster action of the RHR pumps.

3.1.3 Steam Generator Replacements (SGRP)

The SGRPs did not have to cut an opening in the containment. The ILRT post-work test confirmed the integrity of the closed system inside containment. Post SGRP ILRTs were performed in March 2009 for Unit 1 and April 2008 for Unit 2.

3.2 Justification for the Proposed Technical Specification Change 3.2.1 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. 10 CFR 50, Appendix J also ensures that periodic surveillances of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and of 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 CIV leakage rates.

Enclosure PG&E Letter DCL-24-070 8

Types B and C tests identify the vast majority of potential containment leakage paths.

Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types 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 43) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference 30) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allowed 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 change was based on an NRC risk assessment contained in NUREG-1493, (Reference 41) and Electric Power Research Institute (EPRI) TR 104285 (Reference 16), 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 were 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 31), 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) report (SER) on NEI 94-01. 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 (Reference 43). The document also 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 SER Section 3.1.1.2, which states, in part:

As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history. However, Section

Enclosure PG&E Letter DCL-24-070 9

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.

In 2012, NEI 94-01, Revision 3-A (for Reference 32), 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 SERs of June 25, 2008 (for Reference 31), and June 8, 2012 (for Reference 32), 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 7 and 8, 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.

Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensees allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

NEI 94-01, Revision 3-A, Section 10.1, Introduction, concerning the use of test interval extensions in the deferral of Type B and Type C local leakage rate tests (LLRT), based on performance, states, in part:

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

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

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine-month extension) does not apply to valves that are restricted and/or limited

Enclosure PG&E Letter DCL-24-070 10 to 30-month intervals in Section 10.2 (such as BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance.

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

The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time.

In 2023, RG 1.163 Revision 1 (Reference 48) was issued:

This revision of the guide (Revision 1) endorses the guidance in NEI 94-01, Revision 3-A, issued July 2012 [Reference 32], for implementing Option B of Appendix J to 10 CFR Part 50, subject to the regulatory positions listed in Section C of this RG. This guidance includes (1) extending Type A test intervals up to 15 years and (2) extending Type C test intervals up to 75 months.

This RG endorses Electric Power Research Institute (EPRI) Report No. 1009325, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, Revision 2-A, subject to the applicable regulatory positions listed in Section C of this RG. EPRI Report No. 1009325, Revision 2-A provides a generic assessment of the risks associated with a permanent extension of the integrated leakage rate test (ILRT) surveillance interval to 15

years, and a

risk-informed methodology/template to be used to confirm the risk impact of the ILRT extension on a plant-specific basis.

This revision also endorses American National Standards Institute (ANSI)/American Nuclear Society (ANS) 56.8-2020, Containment System Leakage Testing Requirements [Reference 29], for acceptable industry standards on technical methods and techniques for performing Type A, B, and C tests. The staff has reviewed ANSI/ANS 56.8-2020 and found it to be technically consistent with the 2002 edition.

Licensees wishing to implement the methods, procedures, or analyses in this RG, will need to submit a license amendment request (LAR) to amend the Technical Specifications (TS) to reflect incorporation of this RG. Also, 10 CFR Part 50, Appendix J, Option B, Paragraph V.B.3, states, in part, that, [t]he submittal for technical specification revisions must contain justification, including supporting analysis, if the licensee chooses to deviate from methods approved by the Commission and endorsed in a regulatory guide.

Enclosure PG&E Letter DCL-24-070 11 3.2.2 DCPP 10 CFR 50, Appendix J, Option B Licensing History March 1, 1996 - License Amendments No. 109 and 110 (Reference 27)

This amendment revised the DCPP Unit 1 (Amendment 110) and Unit 2 (Amendment 109) TS to allow use of 10 CFR 50, Appendix J, Option B, for Type A, B, and C containment leak rate testing implementing the performance-based leakage rate testing program as permitted by 10 CFR 50, Appendix J.

April 22, 2002 - License Amendments No. 150 and 150 (Reference 21)

This amendment revised the DCPP Unit 1 and Unit 2 TS 5.5.16.a.3, Containment Leakage Rate Testing Program, to allow a one-time, 5-year extension to the 10-year interval for performing the next Type A test at DCPP. The change allowed Type A testing within 15 years from the last Type A test, which was performed in May 1994, at Unit 1 and April 1993, at Unit 2.

June 26, 2007 - License Amendments No. 197 and 198 (Reference 18)

This amendment revised the DCPP Unit 1 (Amendment 197) and Unit 2 (Amendment 198) TS 5.5.16, Containment Leakage Rate Testing Program, to comply with the requirements of 10 CFR 50.55a(g)(4) for components classified as ASME Section Ill, Code Class CC consistent with TSTF-343, Containment Structural Integrity, (Reference 11). The revision allows the performance of visual examinations of the containment pursuant to ASME Section XI, Subsections IWE and IWL, in lieu of the visual examinations performed pursuant to RG 1.163.

January 15, 2009 - License Amendments No. 203 and 204 (Reference 19)

This amendment revised the DCPP Unit 1 (Amendment 203) and Unit 2 (Amendment 204) TS 5.5.16, Containment Leakage Rate Testing Program, to specify a lower peak calculated containment internal pressure following a large break loss of coolant accident (LOCA)s and the containment design pressure at DCPP. This revision specifies a new lower peak calculated containment internal pressure following SGRP, which contains adequate margin to the Updated Final Safety Analysis Report (UFSAR) containment internal pressure analysis values.

April 27, 2017 - License Amendments No. 230 and 232 (References 61 and 62)

This amendment revised the DCPP Unit 1 (Amendment 230) and Unit 2 (Amendment 232) revised the licensing bases to adopt alternative source term and approve the methodology for evaluating radiological consequences of design-basis accidents. The amendments revise TS 1.1, Definitions; TS 3.4.16, RCS [Reactor Coolant System]

Specific Activity; TS 3.6.3, Containment Isolation Valves; TS 5.5.11, Ventilation Filter Testing Program (VFTP); and TS 5.5.19, Control Room Envelope Habitability Program, in support of the revised licensing bases.

Enclosure PG&E Letter DCL-24-070 12 3.2.3 Continued Acceptability of TS Amendments 197 (Unit 1) and 198 (Unit 2)

By application dated December 29, 2006 (Reference 11), PG&E requested changes to the TSs for DCPP, Units 1 and 2.

The proposed amendments revised TS 5.5.16, Containment Leakage Rate Testing Program, to comply with the requirements of 10 CFR 50.55a(g)(4) for components classified as Code Class CC consistent with TSTF-343, Containment Structural Integrity. This regulation requires licensees to update their containment inservice inspection requirements in accordance with subsections IWE and IWL of ASME Section XI, Division I, of the ASME Boiler and Pressure Vessel Code as limited by 10 CFR 50.55a(b)(2)(vi) and modified by 10 CFR 50.55a(b)(2)(viii) and 10 CFR 50.55a(b)(2)(ix).

Amendments 197 and 198 revised TS 5.5.16.a by adding the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

NEI 94-01, Revision 3-A, Section 1.1 states (in part), generally, a FSAR describes plant testing requirements, including containment testing. In some cases, FSAR testing requirements differ from those of Appendix J. In many cases, Technical Specifications were approved that incorporated exemptions to provisions of Appendix J. Additionally, some licensees have requested and received exemptions after their Technical Specifications were issued. The alternate performance-based testing requirements contained in Option B of Appendix J will not invalidate such exemptions. However, any exemptions to the provisions of 10 CFR 50, Appendix J to be maintained in force as part of the Containment Leakage Testing Program should be clearly identified as part of the plant's program documentation.

By letter dated May 8, 2012, the NRC issued the final SER for NEI 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, and EPRI Report No. 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, (Reference 15).

==

Conclusion:==

DCPP will continue to implement the provisions of TS 5.5.16.a.1 and TS 5.5.16.a.2.

Enclosure PG&E Letter DCL-24-070 13 3.2.4 Integrated Leakage Rate Testing (ILRT) History As noted previously, TS 5.5.16 currently requires Type A, B, and C testing to be performed in accordance with RG 1.163, which endorses the methodology for complying with Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Revision 0, Section 9.1.1 for Type A testing.

Tables 3.2.4-1 and 3.2.4-2 list the past periodic Type A ILRT results for DCPP Units 1 and 2. As shown in the tables, Type A ILRT test results were well below the acceptance criteria of 0.1 percent weight per day.

Table 3.2.4-1, DCPP Unit 1 Type A ILRT History Test Date Measured Rate (Percent Weight per Day)

December, 1975 (Pre-Operational) 0.0466 November 1978 0.0219 February, 1982(1) 0.0156 April, 1985 (1) 0.0530 May, 1988 0.0230 April, 1994 0.0429 March, 2009 (SGRP)(2) 0.0355 February, 2019 0.0366 Notes:

(1) Test performed at reduced pressure (2) The 2009 ILRT was scheduled following the Steam Generator Replacement Project (SGRP)

Table 3.2.4-2, DCPP Unit 2 Type A ILRT History Test Date Measured Rate (Percent Weight per Day)

November, 1977 (Pre-Operational) 0.0165 August, 1984 0.0430 April, 1990 0.0340 November, 1993 0.0251 April, 2008 (SGRP)(1) 0.0171 April, 2018 0.0206 Notes:

(1) The 2008 ILRT was scheduled following the SGRP 3.2.5 Performance Leakage Rate Determination The current ILRT test interval for DCPP Units 1 and 2 is ten years. Verification of this interval is presented in Table 3.2.5-1. The acceptance criteria used for this verification is contained in NEI 94-01, Revision 3-A, Section 5.0, Definitions, and is as follows:

Enclosure PG&E Letter DCL-24-070 14 The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test. In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0La.

Table 3.2.5-1, DCPP ILRT Test Results Verification of Current Extended ILRT Interval Test Date Upper 95%

Confidence Limit (wt.%/day)

(Test Pressure)

Level Corrections (Leakage Savings)

(wt.%/day)

As Left Min Pathway Penalty for Isolated Pathways (wt.%/day)

Adjusted As Left Leak Rate (wt.%/day)

ILRT Acceptance Criteria (wt.%/day)

Test Method /

Data Analysis Techniques Unit 1 March 2009 0.0337 (44.144 psig) 0.0 0.00176 0.03546 0.1 Absolute /

ANSI/ANS 56.8-1994 Mass Point February 2019 0.0314 (43.8 psig) 0.0007 0.0045 0.0366 0.1 Absolute /

ANSI/ANS 56.8-1994 Mass Point Unit 2 April 2008 0.0144 (45.969 psig) 0.00087 0.001813 0.0171 0.1 Absolute /

ANSI/ANS 56.8-1994 Mass Point April 2018 001649 (44.9 psig) 0.0005 0.0036 0.0206 0.1 Absolute /

ANSI/ANS 56.8-1994 Mass Point 3.3 Plant Specific Confirmatory Analysis 3.3.1 Methodology An analysis was performed to provide a risk assessment of permanently extending the DCPP, Units 1 & 2 containment Type A integrated leak rate test (ILRT) interval from ten years to fifteen years. The risk assessment follows the guidelines from the following:

• NEI 94-01, Revision 3-A and 2-A (References 32 and 31),

• Methodology used in EPRI TR-104285 (Reference 16),

Enclosure PG&E Letter DCL-24-070 15

• NEI Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals from November 2001 (Reference 17),

• NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200, Revision 3 (Reference 59) as applied to ILRT interval extensions, risk insights in support of a request for a plants licensing basis as outlined in Regulatory Guide (RG) 1.174 (Reference 4),

• Methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 20),

• Methodology used in EPRI 1018243, Revision 2-A of EPRI 1009325 (Reference 14).

The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0 (Reference 30), and established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493, Performance-Based Containment Leak Test Program, September 1995 (Reference 41), 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 assessment of the risk impact 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 Research Project TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals.

The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry), containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for DCPP.

NEI 94-01 Revision 3-A supports using EPRI Report No. 1009325 Revision 2-A (EPRI 1018243), Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, for performing risk impact assessments in support of ILRT extensions. The Guidance provided in Appendix H of EPRI Report No. 1009325 Revision 2-A builds on the EPRI Risk Assessment methodology, EPRI TR-104285. This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.

It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the ASME Boiler and Pressure Vessel Code Section XI. More specifically, Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining

Enclosure PG&E Letter DCL-24-070 16 components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. The associated change to NEI 94-01 requires that visual examinations be conducted during at least three other outages, and in the outage during which the ILRT is being conducted. These requirements are not changed as a result of the extended ILRT interval. In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.

The acceptance guidelines in RG 1.174 are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in Core Damage Frequency (CDF) less than 10-6 per reactor year and increases in Large Early Release Frequency (LERF) less than 10-7 per reactor year. Since the Type A test does not impact CDF, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 10-6 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the Conditional Containment Failure Probability (CCFP), which helps ensure the defense-in-depth philosophy is maintained, is also calculated.

Regarding CCFP, changes of up to 1.1 percent have been accepted by the NRC for the one-time requests for extension of ILRT intervals. In context, it is noted that a CCFP of 1/10 (10 percent) has been approved for application to evolutionary light water designs.

Given these perspectives, a change in the CCFP of up to 1.5 percent is assumed to be small.

In addition, the total annual risk (person-rem/yr population dose) is examined to demonstrate the relative change in this parameter. While no acceptance guidelines for these additional figures of merit are published, examinations of NUREG-1493 and SEs for one-time interval extension (summarized in Appendix G of Reference 15) indicate a range of incremental increases in population dose that have been accepted by the NRC.

The range of incremental population dose increases is from 0.01 to 0.2 person-rem/yr and/or 0.002 percent to 0.46 percent of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493, Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of 1.0 person-rem per year or 1 percent of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.

For those plants that credit containment overpressure for the mitigation of design basis accidents, a brief description of whether overpressure is required should be included in

Enclosure PG&E Letter DCL-24-070 17 this section. In addition, if overpressure is included in the assessment, other risk metrics such as CDF should be described and reported. Containment overpressure is not required in support of ECCS performance to mitigate design basis accidents at DCPP.

Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

7. When using the methodology in EPRI Report No. 1009325, Revision 2-A to permanently extend the ILRT interval to 15 years, the licensee should submit documentation indicating that the technical adequacy of the PRA used to support its performance-based Appendix J program is consistent with the guidance in RG 1.200, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, (Ref. 20), relevant to the ILRT extension application. RG 1.200 describes one acceptable approach for determining whether a base PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision-making for light-water reactors. A minimum of Capability Category I of the ASME PRA standard should be applied as the standard for assessing PRA quality for ILRT extension applications, since approximate values of core damage frequency (CDF) and large early release frequency (LERF) and their distribution among release categories are sufficient to support the evaluation of changes to ILRT frequencies.

The assessment of external events may be taken from existing analyses, previously submitted to, and approved by the NRC staff, or from another alternate method of assessing an order of magnitude estimate for the contribution of the external event to the impact of the changed interval.

For the use of the methodology in EPRI Report No. 1009325, Revision 2-A to permanently extend the ILRT interval to 15 years, DCPP has documented the technical adequacy of the PRA used to support its performance-based Appendix J program in Section 3.3.2 below and Reference 64, Attachment 1, PRA Model Technical Adequacy for Permanent 15-Year ILRT Extension.

Enclosure PG&E Letter DCL-24-070 18 Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

8. When using the methodology in EPRI Report No. 1009325, Revision 2-A to permanently extend the ILRT interval to 15 years, the licensee should submit documentation indicating that the estimated risk increase associated with extending the ILRT surveillance interval to 15 years is small. The methodology should quantitatively evaluate the risk impact of the ILRT extension. The most relevant risk metric is LERF, since the Type A test does not generally impact CDF.

RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, (Ref. 21) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Additional risk metrics including the increase in population dose and the increase in conditional containment failure probabilityare also evaluated in EPRI Report No. 1009325, Revision 2-A to help ensure that the key safety principles in RG 1.174 are met.

The increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 1.12E-7/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included), and baseline LERF is 2.71E-7/year. As such, the estimated change in LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.174 (Reference 4). When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 7.36E-7/year using the EPRI guidance, and baseline LERF is 7.55E-6/year. As such, the estimated change in LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.174.

The effect resulting from changing the Type A test frequency to 1-per-15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.040 person-rem/year. EPRI Report No.

1009325, Revision 2-A (Reference 14) states that a very small population dose is defined as an increase of 1.0 person-rem per year, or 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

(Refer to Reference 64, Section 7.0 Conclusion and Recommendations, 1st and 2nd bullets)

9. The methodology in EPRI Report No.

1009325, Revision 2-A, is acceptable, except for the calculation of the increase in expected population dose (per year of reactor operation). To make the methodology acceptable, the average leak rate for the pre-existing containment large leak rate accident case (accident case 3b) used by the licensees should be 100 La [wt%/24-hour] instead of 35 La.

The representative containment leakage for Class 3b sequences used is 100La based on the guidance provided in EPRI Report No. 1009325, Revision 2-A. (Refer to Reference 64, Section 4.0 Assumptions and Limitations, 7th bullet)

Enclosure PG&E Letter DCL-24-070 19 Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

10. As part of the LAR submittal, the licensee should provide an evaluation if containment overpressure is relied upon for net positive suction head (NPSH) for emergency core cooling system (ECCS) injection for certain accident sequences. If the plant relies on containment overpressure for NPSH for ECCS injection for certain accident sequences, the plant may experience an increase in CDF as a result of the proposed change in the ILRT interval. For these plants, the ILRT evaluation should consider the impacts on both CDF and LERF and compare them with the risk acceptance guidelines in RG 1.174. RG 1.174 gives guidance for determining the risk impact of plant-specific changes to the licensing basis. EPRI Report No. 1009325, Revision 2-A, provides that in the case where containment overpressure may be a consideration, that licensees should (1) examine their NPSH requirements to determine whether containment overpressure is required (and assumed to be available) in various accident scenarios and (2) adjust the PRA model to account for this requirement if accident scenarios could be impacted by a large containment failure that eliminates the necessary containment overpressure. The combined impacts on CDF and LERF will be considered by the NRC staff in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174.

Containment overpressure is not required in support of ECCS performance to mitigate design basis accidents at DCPP, the ILRT extension does not impact CDF. Therefore, the relevant risk-impact metric is LERF. (Refer to Section 3.1.2 of this submittal and Reference 64, Section 5.2.4, Determine the Change in Risk in Terms of LERF.)

3.3.2 PRA Technical Adequacy PRA Model Technical Adequacy for Permanent 15-Year ILRT Extension PG&E employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA model for the operating PG&E nuclear power plant.

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 DCPP PRA.

PRA Maintenance and Update The PG&E risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated plants. This process is defined in the PG&E risk management program, which consists of a governing procedure PRA Model

Enclosure PG&E Letter DCL-24-070 20 Maintenance and Upgrades. This procedure delineates the responsibilities and guidelines for updating the full power internal events PRA models at DCPP. The overall PG&E 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, errors or limitations identified in the model, and industry operational experience), 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 plant, the following activities are routinely performed:

• Design changes are reviewed for their impact on the PRA model.

• New procedures and procedure changes are reviewed for their impact on the PRA model.

• New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.

• Equipment unavailabilities are captured, and their impact on CDF is trended.

• Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities for equipment that can have a significant impact on the PRA model are updated approximately every 3 years. The last update was completed in April 2023.

In addition to these activities, PG&E risk management procedures provide the guidance for specific risk management activities during power operation, and PRA quality and PRA 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 and external events PRA models for DCPP.

• 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 within the scope of the Maintenance Rule (10 CFR 50.65 (a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on a 3-year cycle; longer intervals may be justified if it can be shown that the PRA

Enclosure PG&E Letter DCL-24-070 21 continues to adequately represent the as-built, as-operated plant. PRA model updates were also performed in shorter intervals in the past to incorporate design changes, procedure changes and/or newly developed industry data and models that had a significant impact on the plant risk results. The DC05A Application Model was completed in June of 2023 (Reference 26).

PRA Self-Assessment and Peer Review Several assessments of technical capability have been made, and continue to be planned, for the DCPP PRA models. The summary of these assessments are as follows:

Internal Events and Internal Flooding Model In December 2012, the Pressurized Water Reactor Owners Group (PWROG) performed a full scope peer review of the DCPP Internal Events Model. All the findings were resolved, a formal F&O closure review was completed in July of 2023 per the NEI 05-04 Appendix X process, and a final report from the closure review was issued stating that all F&Os have been closed and meet Capability Category II or higher [Reference 44].

Internal Fire Events Model In January 2008, the PWROG performed a full scope peer review of the DCPP Internal Fire PRA model to pilot the fire PRA Peer Review process as defined in the NEI document NEI 07-12 [Reference 33]. The 2008 Peer Review was conducted against the requirements of the ANS Standard (Fire PRA Methodology ANSI/ANS-58, 23-2007).

The 2010 Fire PRA Peer Review was conducted against the requirements of Section 4 of the 2009 ASME/ANS Combined PRA Standard (Reference 50).

In December 2010, the PWROG performed a follow-on peer review of the DCPP Internal Fire Model (Reference 51). As stated in Section 1.3 of Reference 51, the follow-on Peer Review included only those technical elements that were not reviewed in 2008 and those supporting requirements (SR) which were judged to not meet the Standard, and the SRs associated with Findings-category F&O issued in the 2008 review.

The ASME/ANS Combined Standard is essentially the same as the previous ANS Standard, except that certain SRs are deleted and certain new ones added. The new SRs in the identified scope were also reviewed as part of the follow-on peer review.

In September 2018, the resolution/disposition of the 2010 Fire PRA Peer Review F&O items was reviewed per the NEI 05-04 Appendix X process (Reference 52) and closed out.

Upon incorporation of new guidance from NUREG-2178 (Reference 53) for treatment of obstructed plumes, NUREG-2180 (Reference 54) for crediting incipient detection, and NUREG-7150 (Reference 55) for addressing ground fault equivalent hot shorts, it was determined that incorporation of guidance from these NUREGs represented an upgrade

Enclosure PG&E Letter DCL-24-070 22 to the Fire PRA such that a focused scope peer review was needed. The focused peer review was performed using the general process defined in NEI 07-12 and covered Technical Elements Fire Scenario Selection and Circuit Failures per ASME/ANS RS-Sa-2009 Standard and RG 1.200 Revision 2 (Reference 45). All associated SRs were met at Capability Category II or better. No F&O items were identified (Reference 56).

Seismic Events Model In January 2013, the PWROG performed a full scope peer review of the DCPP Seismic Model (Reference 57). This review was performed against the 2009 version of the ASME/ANS PRA Standard.

In June of 2017, a second SPRA peer review (Reference 42) was performed using the updated 2013 version of the ASME/ANS Standard.

In February 2018, the resolution/disposition of the 2017 Seismic PRA Peer Review F&O items were reviewed per the guidance of Appendix X of the NEI 12-13 peer review process (Reference 46) and closed out (Reference 28).

Other External Events Model The original external event analysis was performed in 1988. A number of external hazard sources were analyzed, and the following hazard sources were selected for more detailed analysis.

• Aircraft crash and other falling objects

• External Fires

• Turbine Missiles

• Ship Impact

• Hazardous Chemicals

• Hurricane Winds and Tornados

• External Flooding The Other External Event analysis was updated in November of 2016 (Reference 40).

The analysis concluded that at the DCPP site all the hazard sources mentioned above were negligible contributors to the core damage frequency.

General Conclusion Regarding PRA Capability The DCPP PRA maintenance and update processes and technical capability evaluations described above provide a robust basis for concluding that the PRA is suitable for use in the ILRT analysis.

Enclosure PG&E Letter DCL-24-070 23 3.3.3 Summary of Plant-Specific Risk Assessment Results The findings of the DCPP Risk Assessment, contained in Reference 64, confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in ten years to one in 15 years is small.

Based on the results from Reference 64, Section 5.2 and the sensitivity calculations presented in Section 5.3, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to 15 years:

• Regulatory Guide 1.174 (Reference 4) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Regulatory Guide 1.174 defines small changes in risk as resulting in increases of CDF greater than 1.0E-6/year and less than 1.0E-5/year and increases in LERF greater than 1.0E-7/year and less than 1.0E-6/year. Since the ILRT does not impact CDF, the relevant criterion is LERF. The increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 1.12E-7/year using the EPRI guidance (this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included), and baseline LERF is 2.71E-7/year.

As such, the estimated change in LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.174. When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 7.36E-7/year using the EPRI guidance, and baseline LERF is 7.55E-6/year. As such, the estimated change in LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.174.

• The effect resulting from changing the Type A test frequency to 1-per-15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.040 person-rem/year. EPRI Report No. 1009325, Revision 2-A (Reference 14) states that a very small population dose is defined as an increase of 1.0 person-rem per year, or 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria.

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

• The increase in the conditional containment failure probability from the 3 in 10-year interval to 1 in 15-year interval is 0.906 percent. EPRI Report No. 1009325, Revision 2-A (Reference 14) states that increases in CCFP of 1.5 percent is small. Therefore, this increase is judged to be small.

Therefore, increasing the ILRT interval to 15 years is considered to be insignificant since it represents a small change to the DCPP risk profile.

Enclosure PG&E Letter DCL-24-070 24 3.3.4 Previous Assessments The NRC in NUREG-1493 (Reference 41) has previously concluded that:

• Reducing the frequency of Type A tests (ILRTs) from 3 per 10 years to 1 per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type 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 1 in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test integrity of the containment structure.

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

Details of the DCPP, Units 1 and 2, risk assessment are contained in Reference 64.

3.3.5 RG 1.174 Revision 3 Defense in Depth Evaluation RG 1.174, Revision 3 (Reference 4), describes an approach that is acceptable for developing riskinformed applications for a licensing basis change that considers engineering issues and applies risk insights. One of the considerations included in RG 1.174 is Defense in Depth. Defense in Depth is a safety philosophy that employs successive compensatory measures to prevent accidents or mitigate damage if a malfunction, accident, or naturally caused event occurs at a nuclear facility. The following seven considerations, as presented in RG 1.174, Revision 3, Section C.2.1.1.2, Considerations for Evaluating the Impact of the Proposed Licensing Basis Change on Defense in Depth, will serve to evaluate the proposed licensing basis change for overall impact on Defense in Depth for DCPP.

1.

Preserve a reasonable balance among the layers of defense.

A reasonable balance of the layers of defense (i.e., minimizing challenges to the plant, preventing any events from progressing to core damage, containing the radioactive source term, and emergency preparedness) helps to ensure an apportionment of the plants capabilities between limiting disturbances to the plant and mitigating their consequences. The term reasonable balance is not meant

Enclosure PG&E Letter DCL-24-070 25 to imply an equal apportionment of capabilities. The NRC recognizes that aspects of a plants design or operation might cause one or more of the layers of defense to be adversely affected. For these situations, the balance between the other layers of defense becomes especially important when evaluating the impact of the proposed licensing basis change and its effect on defense in depth.

Response

Several layers of defense are in place to ensure the DCPP containment structure(s); penetrations, isolation valves and mechanical seal systems; continue(s) to perform their intended safety function. The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and Type C LLRTs for selected components from 60-months to 75-months.

As shown in NUREG-1493, Performance-Based Containment Leak-Test Program (Reference 41), increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Finally, the study concluded that Types B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.

Several programmatic factors can also be cited as layers of defense ensuring the continued safety function of the DCPP containment pressure boundary. NEI 94-01 Revisions 2-A and 3-A require sites adopting the 15-year extended ILRT interval perform visual examinations of the accessible interior and exterior surfaces of the containment structure for structural degradation that may affect the containment leak-tight integrity at the frequency prescribed by the guidance or, if approved through a TS amendment, at the frequencies prescribed by ASME Section XI, which is the case for DCPP Units 1 and 2. Additionally, several measures are put in place to ensure integrity of the Types B and C tested components. NEI 94-01 limits large containment penetrations such as airlocks, purge and vent valves, to a maximum 30-month testing interval. For those valves that meet the performance standards defined in NEI 94-01, Revision 3-A and are selected for test intervals greater than 60 months, a leakage understatement penalty is added to the MNPLR prior to the frequency being extended beyond 60-months. Finally, identification of adverse trends in the overall Types B and C leakage rate summations and available margin between the Type B and Type C leakage rate summation and its regulatory limit are required by NEI 94-01, Revision 3-A to be shown in the DCPP post-outage report(s). Therefore, the proposed change does not challenge or limit the layers of defense available to assess the ability of the DCPP containment structure to perform its safety function.

Enclosure PG&E Letter DCL-24-070 26 PRA Response:

The use of the risk metrics of LERF, population dose, and conditional containment failure probability collectively ensures the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. The change in LERF is small for internal events and when including external events per RG 1.174, and the change in population dose and CCFP are small as defined in this analysis and consistent with NEI 94-01, Revision 3-A.

2.

Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.

Nuclear power plant licensees implement a number of programmatic activities, including programs for quality assurance, testing and inspection, maintenance, control of transient combustible material, foreign material exclusion, containment cleanliness, and training. In some cases, activities that are part of these programs are used as compensatory measures; that is, they are measures taken to compensate for some reduced functionality, availability, reliability, redundancy, or other feature of the plants design to ensure safety functions (e.g., reactor vessel inspections that provide assurance that reactor vessel failure is unlikely). NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, (Reference 60), defines safety function as those functions needed to shut down the reactor, remove the residual heat, and contain any radioactive material release.

A proposed licensing basis change might involve or require compensatory measures. Examples include hardware (e.g., skid-mounted temporary power supplies); human actions (e.g., manual system actuation); or some combination of these measures. Such compensatory measures are often associated with temporary plant configurations. The preferred approach for accomplishing safety functions is through engineered systems. Therefore, when the proposed licensing basis change necessitates reliance on programmatic activities as compensatory measures, the licensee should justify that this reliance is not excessive (i.e., not overly reliant). The intent of this consideration is not to preclude the use of such programs as compensatory measures but to ensure that the use of such measures does not significantly reduce the capability of the design features (e.g., hardware).

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. Several programmatic factors were described in the response to Question 1 above, which are required when adopting NEI 94-01, Revision 3-A and RG 1.163, Revision 1. These factors are conservative in nature and are designed to generate corrective actions if the required testing or inspections are deemed

Enclosure PG&E Letter DCL-24-070 27 unsatisfactory well in advance to ensure the continued safety function of the containment is maintained. The programmatic factors are designed to provide differing ways to test and/or examine the containment pressure boundary in a manner that verifies the DCPP containment pressure boundary will perform its intended safety function. Since the proposed change does not alter the configuration of the DCPP containment pressure boundary, continued performance of the tests and inspections associated with NEI 94-01 will only serve to ensure the continued safety function of the containment without affecting any margin of safety.

PRA Response:

The adequacy of the design feature (the containment boundary subject to Type A testing) is preserved as evidenced by the overall small change in risk associated with the Type A test frequency change.

3.

Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.

As stated in RG 1.174, Revision 3, Section C.2.1.1.1, Background, the defense-in-depth philosophy has traditionally been applied in plant design and operation to provide multiple means to accomplish safety functions. System redundancy, independence, and diversity result in high availability and reliability of the function and also help ensure that system functions are not reliant on any single feature of the design. Redundancy provides for duplicate equipment that enables the failure or unavailability of at least one set of equipment to be tolerated without loss of function. Independence of equipment implies that the redundant equipment is separate such that it does not rely on the same supports to function. This independence can sometimes be achieved by the use of physical separation or physical protection. Diversity is accomplished by having equipment that performs the same function rely on different attributes such as different principles of operation, different physical variables, different conditions of operation, or production by different manufacturers which helps reduce common-cause failure (CCF).

A proposed change might reduce the redundancy, independence, or diversity of systems. The intent of this consideration is to ensure that the ability to provide the system function is commensurate with the risk of scenarios that could be mitigated by that function. The consideration of uncertainty, including the uncertainty inherent in the PRA, implies that the use of redundancy, independence, or diversity provides high reliability and availability and also results in the ability to tolerate failures or unanticipated events.

Enclosure PG&E Letter DCL-24-070 28

Response

The proposed change to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months does not reduce the redundancy, independence, or diversity of systems. As shown in NUREG-1493, increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Additionally, the study concluded that Type B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.

Despite the change in test interval, containment isolation diversity remains unaffected and will continue to provide the inherent isolation, as designed. In addition, NEI 94-01, Revision 3-A, Section 11.3.2 requires a schedule of tests be developed, for components on a test interval greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. Therefore, the proposed change preserves system redundancy, independence, and diversity and ensures a high reliability and availability of the containment structure to perform its safety function in the event of unanticipated events.

PRA Response:

The redundancy, independence, and diversity of the containment subject to the Type A test is preserved, commensurate with the expected frequency and consequences of challenges to the system, as evidenced by the overall small change in risk associated with the Type A test frequency change.

4.

Preserve adequate defense against potential common-cause failures (CCFs).

An important aspect of ensuring defense in depth is to guard against CCF. Multiple components may fail to function because of a single specific cause or event that could simultaneously affect several components important to risk. The cause or event may include an installation or construction deficiency, accidental human action, extreme external environment, or an unintended cascading effect from any other operation or failure within the plant. CCFs can also result from poor design, manufacturing, or maintenance practices.

Defenses can prevent the occurrence of failures from the causes and events that could allow simultaneous multiple component failures. Another aspect of guarding

Enclosure PG&E Letter DCL-24-070 29 against CCF is to ensure that an existing defense put in place to minimize the impact of CCF is not significantly reduced; however, a reduction in one defense can be compensated for by adding another.

Response

As part of the proposed change, DCPP will be required to adopt the performance-based testing standards outlined in RG 1.163 Revision 1, NEI 94-01, Revision 3-A along with ANSI/ANS 56.8-2020. NEI 94-01, Revision 3-A, Section 11.3.2 requires a schedule of tests be developed, for components on test intervals greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. In addition, components considered to be risk-significant from a PRA standpoint are required to be limited to a testing interval less than the maximum allowable limit of 75-months. For those components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and should allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revision 3-A, requires cause determinations be performed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. The proposed change also imposes a requirement to address margin management (i.e., margin between the current containment leakage rate and its pre-established limit). As a result, adoption of the performance-based testing standards proposed by this change ensures adequate barriers exist to preclude failure of the containment pressure boundary due to common-mode failures and therefore continues to guard against CCF.

PRA Response:

Adequate defense against CCFs is preserved. The Type A test detects problems in the containment which may or may not be the result of a CCF; such a CCF may affect failure of another portion of containment (i.e., local penetrations) due to the same phenomena. Adequate defense against CCFs is preserved via the continued performance of the Type B and C tests and the performance of inspections. The change to the Type A test, which bounds the risk associated with containment failure modes including those involving CCFs, does not degrade adequate defense as evidenced by the overall small change in risk associated with the Type A test frequency change.

Enclosure PG&E Letter DCL-24-070 30

5.

Maintain multiple fission product barriers.

Fission product barriers include the physical barriers themselves (e.g., the fuel cladding, reactor coolant system pressure boundary, and containment) and any equipment relied on to protect the barriers (e.g., containment spray). In general, these barriers are designed to perform independently so that a complete failure of one barrier does not disable the next subsequent barrier. For example, one barrier, the containment, is designed to withstand a double-ended guillotine break of the largest pipe in the reactor coolant system, another barrier.

A plants licensing basis might contain events that, by their very nature, challenge multiple barriers simultaneously. Examples include interfacing-system loss-of-coolant accidents, steam generator tube rupture, or crediting containment accident pressure. Therefore, complete independence of barriers, while a goal, might not be achievable for all possible scenarios.

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. As part of the proposed change, DCPP will be required to adopt the performance-based testing standards outlined in RG 1.163, Revision 1, NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2020. The overall containment leakage rate calculations associated with the testing standards contain inherent conservatisms through the use of margin. Plant TS require the overall primary containment leakage rate to be less than or equal to 1.0 La. NEI 94-01 requires the as-found Type A test leakage rate must be less than the acceptance criterion of 1.0 La given in the plant TS. Prior to entering a mode where containment integrity is required, the as-left Type A leakage rate shall not exceed 0.75 La. The as-found and as-left values are as determined by the appropriate testing methodology specifically described in ANSI/ANS 56.8-2020. Additionally, the combined leakage rate for all Type B and Type C tested penetrations shall be less than or equal to 0.6 La, determined on a maximum pathway basis from the as-left LLRT results prior to entering a mode where containment integrity is required. This regulatory approach results in a 25 percent and 40 percent margin, respectively, to the 1.0 La requirements. For those local leak rate tested components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revision 3-A requires cause determinations be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. Therefore, the proposed change adopts requirements with inherent conservatisms to ensure the margin to

Enclosure PG&E Letter DCL-24-070 31 safety limit is maintained, thereby, preserving the containment fission product barrier.

PRA Response:

Multiple Fission Product barriers are maintained. The portion of the containment affected by the Type A test extension is still maintained as an independent fission product barrier, albeit with an overall small change in the reliability of the barrier.

6.

Preserve sufficient defense against human errors.

Human errors include the failure of operators to correctly and promptly perform the actions necessary to operate the plant or respond to off-normal conditions and accidents, errors committed during test and maintenance, and incorrect actions by other plant staff. Human errors can result in the degradation or failure of a system to perform its function, thereby significantly reducing the effectiveness of one of the layers of defense or one of the fission product barriers. The plant design and operation include defenses to prevent the occurrence of such errors and events.

These defenses generally involve the use of procedures, training, and human engineering; however, other considerations (e.g., communication protocols) might also be important.

Response

Sufficient defense against human errors is preserved. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A, Type B and Type C tests (less opportunity for errors to occur).

PRA Response:

Sufficient defense against human errors is preserved. The probability of a human error to operate the plant, or to respond to off-normal conditions and accidents is not significantly affected by the change to the Type A testing frequency. Errors committed during test and maintenance may be reduced by the less frequent performance of the Type A test (less opportunity for errors to occur).

7.

Continue to meet the intent of the plants design criteria.

For plants licensed under 10 CFR Part 50 or 10 CFR Part 52, the plants design criteria are set forth in the current licensing basis of the plant. The plants design criteria define minimum requirements that achieve aspects of the defense-in-depth philosophy; as a consequence, even a compromise of the intent of those design criteria can directly result in a significant reduction in the effectiveness of one or more of the layers of defense. When evaluating the effect of the proposed licensing basis change, the licensee should demonstrate that it continues to meet

Enclosure PG&E Letter DCL-24-070 32 the intent of the plants design criteria.

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. The proposed extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled.

As part of the proposed change, DCPP will be required to adopt the performance-based testing standards outlined in RG 1.163, Revision 1, NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2020. The leakage limits imposed by plant TS remain unchanged when adopting the performance-based testing standards outlined in NEI 94-01, Revision 3-A, and ANSI/ANS 56.8-2020. Plant design limits imposed by the UFSAR also remain unchanged as a result of the proposed change.

Therefore, the proposed change continues to meet the intent of the plants design criteria to ensure the integrity of the DCPP containment pressure boundary.

PRA Response:

The intent of the plants design criteria continues to be met. The extension of the Type A test does not change the configuration of the plant or the way the plant is operated.

==

Conclusion:==

The responses to the seven Defense in Depth questions above conclude that the existing Defense in Depth has not been diminished; rather, in some instances has been increased. Therefore, the proposed change does not comprise a reduction in safety.

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

DCPP has multiple inspections and testing programs that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

3.4.1 Coating Quality Monitoring Program The Coating Quality Monitoring Program is designed to provide added assurance of continued acceptable performance of coatings inside the containments.

In September 1984, following the Unit 2 Type A test, PG&E undertook a comprehensive review of the paint systems in containment. As a result of the investigation and analysis associated with this review, PG&E implemented a formal Coating Quality Monitoring

Enclosure PG&E Letter DCL-24-070 33 Program to provide added assurance of continued acceptable paint system performance to address all containment coatings (previous NRC commitment contained in References 9 and 10). The program required a walkdown of containment during scheduled refueling outages (RFOs) to verify the general paint condition by thorough visual inspection. This walkdown is to be conducted by individuals qualified in coatings and coating systems. In addition, paint adhesion testing was conducted; special attention was given to the Unit 2 areas where blistering was previously discovered to monitor the general paint system condition, the adhesion of the primer, and its hardness. This special inspection was conducted until adequate data was collected to ensure that unqualified coatings inside containment were in good condition and did not show degradation. The results of this special inspection of Unit 2 after three RFOs provided sufficient information to conclude that these coatings performed adequately. Therefore, based on the good performance of the coatings, the special inspection portion of the Coating Quality Monitoring Program was discontinued after completion of the third RFO for Unit 2.

In accordance with the Coating Quality Monitoring Program, PG&E continues the general inspections of the containment coatings scheduled each RFO, which include inspection of all quality and non-quality coatings. The general inspection is part of surveillance activities to assure continued acceptable performance of quality-related coatings inside containment.

Specifically, the general inspection provides a survey of the condition of coatings inside containment. Deficient coatings identified are documented describing locations, types, quantities, and modes of failure. These are repaired within a reasonable time and are evaluated to assure that there are no safety concerns. If significant failures are observed during the general inspection, the special monitoring and testing can be reinstated and expanded, as deemed necessary by the coatings inspector. An overall report is issued after each RFO to document the condition and assessment of the coatings.

Results of Recent Coatings Inspections The Unit 1 1R22, 1R23, and 1R24 reports were reviewed and PG&E confirmed that the majority of coatings inside the Unit 1 containment were in good condition. Coatings with potential to become a source of debris were either removed or included in the unqualified coatings log, which tracks the margin of coating debris allowable for safe operation of the ECCS. The total quantity of unqualified coatings remained within the bounds required by design basis, with considerable margin remaining.

The Unit 2 2R21, 2R22, and 2R23 reports were reviewed and PG&E confirmed that the majority of coatings inside the Unit 2 containment were in good condition. Coatings with potential to become a source of debris were either removed or included in the unqualified coatings log, which tracks the margin of coating debris allowable for safe operation of the ECCS. The total quantity of unqualified coatings remained within the bounds required by design basis, with considerable margin remaining.

Enclosure PG&E Letter DCL-24-070 34 3.4.2 Containment Inservice Inspection Plan The incorporation into 10 CFR 50.55a of Section XI Subsections IWL and IWE, 1992 Edition with 1992 Addenda, for the inservice inspection of containment concrete and metal liner, became effective September 9, 1996. The September 9, 1996, effective date established the beginning of the DCPP Containment Inservice Inspection Program. The guidance contained in NRC IN 97-29 Containment Inspection Rule requires that all repair and replacement activities are in accordance with IWE and IWL requirements effective September 9, 1996, with the completion of 1st inspection period exams no later than September 9, 2001. As required, expedited containment concrete and liner exams were completed successfully by September 9, 2001.

The Containment Inservice Inspection (CISI) Program Plan for DCPP, Units 1 and 2, includes the Containment concrete shell (ASME Code Class CC) and containment metallic liner (ASME Code Class MC). The Containment Inspection Program Plan supplements the DCPP Units 1 and 2 ISI Program Plan for Class 1, 2, and 3 pressure retaining components and their supports, and together these two separate plans comprise the Inservice Inspection (ISI) Program Plan.

The ISI boundary for the DCPP containment concrete shell and liner is defined as shown on PG&E drawings. Additionally, ISI drawings for the containment concrete shell and liner have been prepared to document areas subject to examination and facilitate recording of the examination results. Areas of the shell and liner which are accessible for direct or qualified remote examination are subject to these requirements.

This third interval Containment Inspection Program Plan implements ASME Code Section XI, Subsections IWE and IWL, 2007 Edition with 2008 Addenda (Reference 49), within the limits and modifications of 10 CFR 50.55a. IWE exams of the metallic containment liner are performed on 40-month periods within the 10-year interval starting May 9, 2018.

Concrete shell exams occur on a 5-year frequency as specified by IWL-2410(a), starting November 2000 and August 2001, for Unit-1 and Unit-2 respectively.

The proper performance of concrete shell exams in accordance with the requirements and frequency of Section XI, Subsection IWL is required to satisfy DCPP Technical Specification 5.5.16.a.1, Containment Leakage Rate Testing Program. These examinations supersede those required by 10 CFR 50, Appendix J.

The proper performance of metallic liner exams in accordance with the requirements and frequency of Section XI, Subsection IWE is required to satisfy DCPP Technical Specification 5.5.16.a.2, Containment Leakage Rate Testing Program. These examinations supersede those required by 10 CFR 50, Appendix J.

Examiners performing General Visual and Detailed Visual examinations of concrete are qualified and certified to Level II in the VT-3C method by examination every 3 years.

Examiners performing General Visual examinations of the containment liner are qualified and certified to Level II in the VT-1 and/or VT-3 method by examination every 3 years.

Enclosure PG&E Letter DCL-24-070 35 Examiners performing VT-1 examinations of the containment liner are qualified and certified to Level II in the VT-1 method by examination every 3 years. Alternatively, Level III examiners in the Visual method, qualified and certified by examination every 5 years, may perform all referenced examinations.

Examinations of the concrete shell are carried out in accordance with the recommendations of ACI 201.1 and use a 2-tier acceptance process similar to that described in ACI 349.3R (Reference 1).

Repairs and replacement to the containment shell are conducted in accordance with IWL-4000. Repairs and replacement of the metallic liner are in accordance with IWE-3124.

The incorporation into 10 CFR 50.55a of Section XI Subsections IWL and IWE, 1992 Edition with 1992 Addenda, for the inservice inspection of containment concrete and metal liner, became effective September 9, 1996. The September 9, 1996, effective date established the beginning of the DCPP Containment Inservice Inspection Program. The guidance contained in NRC IN 97-29, Containment Inspection Rule requires that all repair/replacements activities are in accordance with IWE and IWL requirements effective September 9, 1996, with the completion of 1st inspection period exams no later than September 9, 2001. As required, expedited containment concrete and liner exams were completed successfully by September 9, 2001.

Remaining first interval examinations of the containment liners were completed successfully as required.

Remaining first interval examinations of the Unit 2 containment concrete shell were completed successfully by August 2006 as required.

The second interval IWE/IWL program was written to the requirements of ASME Code Section XI, Subsections IWE and IWL, 2001 Edition with 2003 Addenda (Reference 7),

within the limits and modifications of 10 CFR 50.55a. The second interval was completed successfully for both units IWL by September 9, 2016, and both units IWE by May 9, 2018.

Exemptions Concrete areas inaccessible due to adjacent structures or components, or due to coverage of foundation material, backfill or embedment are not required to be examined per IWL-1220(b). Embedded or inaccessible areas of the containment liner are not required to be examined per IWE-1220.

Code Cases Use of Code Cases which may apply to this Program Plan are governed by relief requests subject to NRC review and approval until such time as they are incorporated into

Enclosure PG&E Letter DCL-24-070 36 Regulatory Guide 1.147, or otherwise approved for use by the NRC.

Pressure Tests Pressure tests of containment, which includes both ILRTs and LLRTs, are scheduled in accordance with the Surveillance Test Program.

Enclosure PG&E Letter DCL-24-070 37 Containment Liner Examination Table 3.4.2-1, Examination Category E-A, Containment Liner Surfaces Item No.

Item Description Code Exam Requirement Exam Method Acceptance Standard Number of Components in Item Interval Exam Requirement Number of Exams During Interval Exam Frequency Number Exams

/ Period 1st 2nd 3rd Unit-1 Containment Liner (Containment Vessel Pressure Retaining Boundary)

E1.11 Accessible Surface Areas IWE-2310 General Visual IWE-3510 1

100% x 3 3

Each Inspection Period 1

1 1

E1.12 Wetted Surfaces of Submerged Areas IWE-2310 None*

• Note: DCPP sump design precludes wetted/submerged surfaces of the metallic liner. E1.12 does not apply.

E1.30 Moisture Barriers IWE-2310 / Fig IWE-2500-1 None**

N/A N/A N/A N/A N/A

• • Note: DCPP Unit 1 liner design does not use moisture barriers or caulking. E1.30 does not apply.

Enclosure PG&E Letter DCL-24-070 38 Table 3.4.2-2, Examination Category E-A, Containment Liner Surfaces Item No.

Item Description Code Exam Requirement Exam Method Acceptance Standard Number of Components in Item Interval Exam Requirement Number of Exams During Interval Exam Frequency Number of Exams / Period 1st 2nd 3rd Unit-2 Containment Liner (Containment Vessel Pressure Retaining Boundary)

E1.11 Accessible Surface Areas IWE-2310 General Visual IWE-3510 1

100% x 3 3

Each Inspection Period 1

1 1

E1.12 Wetted Surfaces of Submerged Areas IWE-2310 None*

• Note: DCPP sump design precludes wetted/submerged surfaces of the metallic liner. E1.12 does not apply.

E1.30 Moisture Barriers IWE-2310 / Fig IWE-2500-1 General Visual IWE-3510 1**

100% x 3 3

Each Inspection Period 1

1 1

• • Unit 2 caulking installed in intermittent portions of containment at two locations at 230° and seven locations from 275° to 305° azimuth.

Enclosure PG&E Letter DCL-24-070 39 Table 3.4.2-3, Examination Category E-C, Containment Liner Surfaces Requiring Augmented Examination Item No.

Item Descripti on Code Exam Requirement Exam Method Acceptance Standard Number of Components in Item Interval Exam Requirement Number of Exams During Interval Exam Frequency Number Exams/Period 1st 2nd 3rd Unit-1 Containment Liner (Containment Vessel Pressure Retaining Boundary)

E4.11 Visible Surfaces IWE-2310 IWE-2500(b)(1)

VT-1 IWE-3520 Note-1 Note-1 & -2 Note-2 Note-2 E4.12 Surface Area Grid

-Minimum Wall Thickness Location IWE-2500(b)(2)

IWE-2500(b)(3)

IWE-2500(b)(4)

Ultrasonic Thickness IWE-3520 Note-1 Note-1 & -2 Note-2 Note-2 Unit-2 Containment Liner (Containment Vessel Pressure Retaining Boundary)

E4.11 Visible Surfaces IWE-2310 IWE-2500(b)(1)

VT-1 IWE-3520 Note-1 Note-1 & -2 Note-2 Note-2 E4.12 Surface Area Grid

-Minimum Wall Thickness Location IWE-2500(b)(2)

IWE-2500(b)(3)

IWE-2500(b)(4)

Ultrasonic Thickness IWE-3520 Note-1 Note-1 & -2 Note-2 Note-2 Note-1: Containment surface areas requiring augmented examination are those identified in IWE-1240. Currently no surface areas meeting the requirements of IWE-1240 are identified. The recirc sump wall adjacent to the self-contained sump structure is no longer a thickness grid area.

Note-2: The extent of examination shall be 100% for each inspection period until the areas examined remain essentially unchanged for the next inspection period. Such areas then no longer require augmented examination in accordance with IWE-2420(c).

Enclosure PG&E Letter DCL-24-070 40 1QOTTC is Quick Opening Transfer Tube Cover Table 3.4.2-4, Examination Category E-G, Pressure Retaining Bolting Item No.

Item Description Code Exam Requirement Exam Method Acceptance Standard Number of Components in Item Interval Exam Requirement Number of Exams During Interval Exam Frequency Number of Exams / Period 1st 2nd 3rd Unit-1 Containment Liner Pressure Retaining Bolting E8.10 Penetration

1. 58 (Mini Equipment)

IWE-2310 VT-1 IWE-3530 12 Studs, 24 Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 60 (Mini Equipment)

IWE-2310 VT-1 IWE-3530 12 Studs, 24 Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 63 (Vacuum Pressure Relief)

IWE-2310 VT-1 IWE-3530 12 Bolts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 64 (Fuel Transfer Tube)

IWE-2310 VT-1 IWE-3530 Bolts not normally removed due to QOTTC1 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Equipment Hatch (Always Disassembled)

IWE-2310 VT-1 IWE-3530 48 Eye Bolts And Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Note 1: Examination shall include bolts, studs, nuts, bushings, washers, and threads in base material and flange, ligaments between fastener holes.

Note 2: Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.

Enclosure PG&E Letter DCL-24-070 41 Table 3.4.2-5, Examination Category E-G, Pressure Retaining Bolting Item No.

Item Description Code Exam Requirement Exam Method Acceptance Standard Number of Components in Item Interval Exam Requirement Number of Exams During Interval Exam Frequency Number of Exams / Period 1st 2nd 3rd Unit-2 Containment Liner Pressure Retaining Bolting E8.10 Penetration

1. 58 (Mini Equipment)

IWE-2310 VT-1 IWE-3530 12 Studs, 24 Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 60 (Mini Equipment)

IWE-2310 VT-1 IWE-3530 12 Studs, 24 Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 63 (Vacuum Pressure Relief)

IWE-2310 VT-1 IWE-3530 12 Bolts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Penetration

1. 64 (Fuel Transfer Tube)

IWE-2310 VT-1 IWE-3530 Bolts not normally removed due to QOTTC 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Equipment Hatch (Always Disassembled)

IWE-2310 VT-1 IWE-3530 48 Eye Bolts And Nuts 100% When Disassembled

- See Note 2 1

Once per Interval -

See Note 2 0-1 0-1 0-1 Note 1: Examination shall include bolts, studs, nuts, bushings, washers, and threads in base material and flange, ligaments between fastener holes.

Note 2: Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.

Enclosure PG&E Letter DCL-24-070 42 Containment Concrete Shell Examination Table 3.4.2-6, Examination Category L-A, Containment Concrete Shell Item No.

Description Examination Requirements /

Fig. No.

Examination Method Acceptance Standard Number of Components In Item Extent of Examination Number of Exams During Interval Exam Frequency Unit-1 Containment Concrete Shell L1.11 All Accessible Surface Areas IWL-2510 General Visual IWL-3210 1

IWL-2510 Accessible Surfaces 100% x 2 Every 5 Years L1.12 Suspect Areas IWL-2510 Detailed Visual IWL-3210 Any Areas Identified During General Visual IWL-2510 Suspect Areas Note-1 Note-1 Unit-2 Containment Concrete Shell L1.11 All Accessible Surface Areas IWL-2510 General Visual IWL-3210 1

IWL-2510 Accessible Surfaces 100% x 2 Every 5 Years L1.12 Suspect Areas IWL-2510 Detailed Visual IWL-3210 Any Areas Identified During General Visual IWL-2510 Suspect Areas Note-1 Note-1 Note-1: Any suspect areas identified during the General Visual exam must receive a Detailed Visual exam. The number of items and frequency of examination for the Detailed Visual exam depend on results of the General Visual exam. All examination results are reviewed and evaluated by the responsible Registered Professional Civil Engineer.

Enclosure PG&E Letter DCL-24-070 43 10 CFR 50.55a (b)(2)(i) Limitations and Modifications Table 3.4.2-7, General Limitations and Modifications 10 CFR 50.55a Section 10 CFR 50.55a Requirement 10 CFR 50.55a(b)(2)

Conditions on ASME BPV Code,Section XI As used in this section, references to Section XI refer to Section XI, Division 1, of the ASME Boiler and Pressure Vessel Code, and include the 1970 Edition through the 1976 Winter Addenda, and the 1977 Edition through the 2007 Edition with the 2008 Addenda, subject to the following conditions:

10 CFR 50.55a(b)(2)(vi)

Effective edition and addenda of Subsection IWE and IWL,Section XI.

Successive 120-month interval updates must be implemented in accordance with paragraph (g)(4)(ii) of this section 10 CFR 50.55a(g)(4)(ii)

Inservice examination of components and system pressure tests conducted during successive 120-month inspection intervals must comply with the requirements of the latest edition and addenda of the Code incorporated by reference in paragraph (b) of this section 12 months before the start of the 120-month inspection interval (or the optional ASME Code cases listed in NRC Regulatory Guide 1.147, Revision 16, when using Section XI; or Regulatory Guide 1.192 when using the OM Code, that are incorporated by reference in paragraph (b) of this section), subject to the conditions listed in paragraph (b) of this section. However, a licensee whose inservice inspection interval commences during the 12 through 18-month period after July 21, 2011, may delay the update of their Appendix VIII program by up to 18 months after July 21, 2011.

Enclosure PG&E Letter DCL-24-070 44 Table 3.4.2-8, Examination of Concrete Containments 10 CFR 50.55a(b)(2)(viii)

Examination of Concrete Containments.

Licensees applying Subsection IWL, 2007 Edition through the latest edition and addenda incorporated by reference in paragraph (b)(2) of this section, shall apply paragraph (b)(2)(viii)(E) of this section.

10 CFR 50.55a(b)(2)(viii)(E)

Class CC Inaccessible Areas Licensee 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, the license shall provide the following in the ISI Summary Report required by IWA-6000:

(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 action.

Table 3.4.2-9, Examination of Metallic Liners 10 CFR 50.55a(b)(2)(ix)

Examination of metal containments and the liners of concrete containments Licensees applying Subsection IWE, 2007 Edition. through the latest addenda incorporated by reference in paragraph (b)(2) of this section, shall satisfy the requirements of paragraphs (b)(2)(ix)(A)(2), (b)(2)(ix)(B) and (b)(2)(ix)(J) of this section.

10 CFR 50.55a(b)(2)(ix)(B)

Remote Visual Examination Requirements When performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2210-1 may be extended and the minimum illumination requirements specified in Table IWA-2210-1 may be decreased provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.

Enclosure PG&E Letter DCL-24-070 45 Table 3.4.2-9, Examination of Metallic Liners 10 CFR 50.55a(b)(2)(ix)(J)

Major Containment Modifications & R/R In general, a repair/replacement activity such as replacing a large containment penetration, cutting a large construction opening in the containment pressure boundary to replace steam generators, reactor vessel heads, pressurizers, or other major equipment; or other similar modification is considered a major containment modification. When applying IWE-5000 to Class MC pressure-retaining components, any major containment modification or repair/replacement, must be followed by a Type A test to provide assurance of both containment structural integrity and leaktight integrity prior to returning to service, in accordance with 10 CFR part 50, Appendix J, Option A or Option B on which the applicant's or licensee's Containment Leak-Rate Testing Program is based. When applying IWE-5000, if a Type A, B, or C Test is performed, the test pressure and acceptance standard for the test must be in accordance with 10 CFR part 50, Appendix J.

Inspection Intervals The inspection intervals for each ISI program shall conform to Inspection Program of IWA-2431 of Section XI as follows:

a.

1st Inspection Interval - 10 years following initial start of the unit into commercial operation. For containment, 10 years following the established date indicated in the Final Rule that became effective September 9, 1996

b.

2nd Inspection Interval - 10 years following the first inspection interval.

c.

3rd Inspection Interval - 10 years following the second inspection interval.

d.

4th Inspection Interval - 10 years following the third inspection interval.

e.

Inspection Period - 1/3 of each inspection interval (i.e., 3-1/3 years or 40 months). Not applicable for containment concrete (IWL).

f.

Containment concrete is examined once every 5 years as specified in IWL-2410.T36940

g.

Each inspection period or interval, or containment concrete five-year inspection cycle, may be decreased or extended (but not cumulatively) by as much as one year as allowed by ASME Section XI IWA-2430 or IWL-2410(c), to conform the inspections to scheduled plant outages; however, every effort should be made to

Enclosure PG&E Letter DCL-24-070 46 assure completion of the examinations within the base period, interval, or inspection cycle.

1.

If an examination must run over into the allowed extension following the last refueling outage of the interval, it shall be included on the forced outage list and completed at the earliest opportunity.

2.

All such extensions shall be brought to the attention of the engineering director.

Containment liner shall be examined per schedules conforming to IWE-2411, IWE-2420, and Table IWE-2500-1 of Section XI and approved requests for alternative as stated in the Containment ISI Program Plan.

Containment concrete shell shall be examined per schedules conforming to IWL-2410, and Table IWL-2500-1 of Section XI and approved alternative requests as stated in the Containment ISI Program Plan.

Table 3.4.2-10, DCPP Unit 1 IWE Examination Schedule 3rd Interval Period 1 5/9/2018 - 9/8/2021 Planned Outages 1R21 1R22 3rd Interval Period 2 9/9/2021 - 1/8/2025 Planned Outages 1R23 1R24 3rd Interval Period 3 1/9/2025 - 5/8/2028 Planned Outages 1R25 1R26

Enclosure PG&E Letter DCL-24-070 47 Table 3.4.2-11, DCPP Unit 1 IWE Examination Schedule 4th Interval Period 1 5/9/2028 - 9/8/2031 Planned Outages 1R27 1R28 1R29 4th Interval Period 2 9/9/2031 - 1/8/2035 Planned Outages 1R30 1R31 4th Interval Period 3 1/9/2035 - 5/8/2038 Planned Outages 1R32 1R33 Table 3.4.2-12 DCPP Unit 2 IWE Examination Schedule 3rd Interval Period 1 5/9/2018 - 9/8/2021 Planned Outages 2R21 2R22 3rd Interval Period 2 9/9/2021 - 1/8/2025 Planned Outages 2R23 2R24 3rd Interval Period 3 1/9/2025 - 5/8/2028 Planned Outages 2R25 2R26

Enclosure PG&E Letter DCL-24-070 48 Table 3.4.2-13 DCPP Unit 2 IWE Examination Schedule 4th Interval Period 1 5/9/2028 - 9/8/2031 Planned Outages 2R27 2R28 4th Interval Period 2 9/9/2031 - 1/8/2035 Planned Outages 2R29 2R30 2R31 4th Interval Period 3 1/9/2035 - 5/8/2038 Planned Outages 2R32 2R33 Table 3.4.2-14, DCPP Unit 1 and 2 IWL Examination Schedule Unit 1 Unit 2 2020 2021 2025 2026 2030 2031 2035 2036 2040 2041

Enclosure PG&E Letter DCL-24-070 49 Results of Recent IWE Inspections NRI - No Reportable Indications RI - Reportable Indications Pacific Gas and Electric Company DIABLO CANYON POWER PLANT -

UNIT 1

• SECOND INTERVAL, THIRD PERIOD, SECOND REFUELING OUTAGE REPORT (1R20)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS PAGE 1 of 1 CATEGORY COMPONENT WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS E-A E1.11 Liner Liner Liner General Visual 5/23/17

• IWE 2nd Interval, 3rd Period exam.

NRI Equip Hatch U1 48 Studs, 48 Nuts VT-3 5/22/17 Disassembled - Bolt #41 RI RI Pen 58 12 Studs, 24 Nuts VT-3 4/29/17 Disassembled NRI Pen 60 12 Studs, 24 Nuts VT-3 4/29/17 Disassembled NRI Pen 63 12 Bolts VT-3 5/22/17 Disassembled NRI Pen 64 (QOTTC)

VT-3 4/26/17 Two bolts removed NRI

Enclosure PG&E Letter DCL-24-070 50 Bolt #41 RI During ISI inspection of containment hatch bolting, distorted threads and excessive play between nut and eyebolt were observed on location #41 bolting. Bolt threads appear to be displaced and nut threads appear to be flattened. Two attempts to hand thread the #41 nut onto other eyebolts were unsuccessful.

The eyebolt is located at the 2 o'clock position on the hatch.

Affected bolt #41 and nut replaced in 1R20.

Need for additional examinations to verify degradation does not exist in similar components: All equipment hatch bolts and three of the other four penetrations' bolting was examined disassembled with no indications and the fourth was examined in place with no indications.

Enclosure PG&E Letter DCL-24-070 51 Pacific Gas and Electric Company DIABLO CANYON POWER PLANT -

UNIT 1 THIRD INTERVAL, FIRST PERIOD, SECOND REFUELING OUTAGE REPORT (1R22)* *(IWE/IWL PROGRAM PLAN)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS PAGE 1 of 1 CATEGORY COMPONENT

/

WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS E-A E1.11 Unit-1 Containment Liner Unit-1 Containment Liner Accessible Surface Areas GV 10/29/20 General Visual NRI E-G E8.10 Penetration

1. 58 Penetration

1. 58 Mini Equipment VT-1 10/18/20 NRI Penetration

1. 60 Penetration

1. 60 Mini Equipment VT-1 10/18/20 NRI Equipment Hatch Equipment Hatch Equipment Hatch VT-1 10/23/20 NRI

Enclosure PG&E Letter DCL-24-070 52 Pacific Gas and Electric Company DIABLO CANYON POWER PLANT -

UNIT 1 THIRD INTERVAL, SECOND PERIOD, SECOND REFUELING OUTAGE REPORT (1R24) (IWE/IWL PROGRAM PLAN)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS PAGE 1 of 1 CATEGORY COMPONENT

/

WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS E-A E1.11 Accessible Surface Areas Containment Liner Containment Liner General Visual 10/20/23 NRI

Enclosure PG&E Letter DCL-24-070 53 PG&E DIABLO CANYON POWER PLANT -

UNIT 2 OUTAGE REPORT (2R20)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS, CONTAINMENT SECOND INTERVAL, THIRD PERIOD, SECOND REFUELING OUTAGE REPORT PAGE 1 of 1 CATEGORY COMPONENT /

WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS IWE E-A Containment Liner Containment Liner Containment Liner GV 3-8-18 NRI Assembled penetrations Penetration #63 (Vacuum Pressure Relief) 12 Bolts VT-3 2/27/18 NRI Penetration #64 (Fuel Transfer Tube)

VT-3 3/10/18 Two bolts removed and examined.

18 of 20 examined in place.

NRI Disassembled penetrations Penetration #58 (Mini E

i t) 12 Studs, 24 Nuts VT-3 2/27/18 NRI Penetration #60 (Mini E

i t) 12 Studs, 24 Nuts VT-3 3/13/18 NRI Equipment Hatch bolting 48 Eye Bolts and Nuts VT-3 2/27/18 NRI

Enclosure PG&E Letter DCL-24-070 54 PG&E DIABLO CANYON POWER PLANT - UNIT 2 OUTAGE REPORT (2R21)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS, CONTAINMENT THIRD INTERVAL, FIRST PERIOD, FIRST REFUELING OUTAGE REPORT PAGE 1 of 1 CATEGORY COMPONENT WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS IWE EA E1.11 Accessible Surface Areas Containment Liner Containment Liner GV 10/18/1 9

Partial exam.

Remainder to be performed during 2R22.

NRI E-G E8.10 Bolted Connections Equipment Hatch Equipment Hatch VT-1 10/14/1 9

NRI Penetration

1. 58 (Mini Equipment)

Penetration #58 (Mini Equipment)

VT-1 09/23/1 9

NRI Penetration

1. 63 (Vac Relief)

Penetration #63 (Vac Pressure Relief)

VT-1 09/23/1 9

NRI Penetration

1. 64 (Fuel Xfer Tube)

Penetration #64 (Fuel Transfer Tube)

VT-1 09/24/1 9

NRI

Enclosure PG&E Letter DCL-24-070 55 PG&E DIABLO CANYON POWER PLANT -

UNIT 2 OUTAGE REPORT (2R22)

MAJOR ITEM: CONTAINMENT ASME SECTION XI SYSTEMS, CONTAINMENT THIRD INTERVAL, FIRST PERIOD, SECOND REFUELING OUTAGE REPORT PAGE 1 of 1 CATEGORY COMPONENT WELD OR EXAM EXAM ITEM DESCRIPTION LINE COMPONENT NO.

TYPE DATE COMMENTS RESULTS IWE EA E1.11 Accessible Surface Areas Containment Liner Containment Liner GV 03/30/21 Completes exam started in 2R21 outage NRI E-G E8.10 Bolted Connections Penetration

1. 60 (Mini Equipment)

Penetration #60 (Mini Equipment)

VT-1 03/22/21 NRI

Enclosure PG&E Letter DCL-24-070 56 Results of Recent IWL Examinations Unit 1 2021 Examination A concrete examination was performed to meet ISI requirements and evaluate the engineering properties of the concrete for the Unit 1 Containment Structure at DCPP. The examinations were conducted from March 2021 to December 2021. The examinations consisted of a visual examination of 100 percent of the accessible exterior concrete surface of the Unit 1 Containment Structure. The Unit 1 Containment Structure exterior surface consists of approximately 98,800 sq. ft. of concrete.

Acceptance Criteria VT-3C examination of the containment concrete employs a three-tiered hierarchy similar to that described in ACI 349.3R-96 (Reference 1).

Inspection Results The condition of the Unit 1 Containment concrete was assessed to be structurally sound.

There was no apparent loss of structural capacity, and based on the results of this examination, no repairs were required. The Containment Exterior Structure (concrete shell) continues to remain capable of performing its design functions.

Unit 2 2021 Examination A concrete examination was performed to meet ISI requirements and evaluate the engineering properties of the concrete for the Unit 2 Containment Structure at DCPP. The examination was conducted from March 2021 to December 2021. The examination consisted of a visual examination of 100 percent of the accessible exterior concrete surface of the Unit 2 Containment Structure. The Unit 2 Containment Structure exterior surface consists of approximately 98,800 sq. ft. of concrete.

Acceptance Criteria VT-3C examination of the containment concrete employs a three-tiered hierarchy similar to that described in ACI 349.3R-96 (Reference 1).

Inspection Results The condition of the Unit 2 Containment concrete was assessed to be structurally sound. There was no apparent loss of structural capacity, and based on the results of this examination, no repairs were required. The Containment Exterior Structure (concrete shell) continues to remain capable of performing its design functions.

Enclosure PG&E Letter DCL-24-070 57 3.4.3 Supplemental Inspection Requirements DCPP License Amendments 197 and 198 (Reference 18) were approved on June 26, 2007 to allow the performance of the visual examinations of the containment pursuant to ASME Code Section XI, Subsections IWE and IWL, in lieu of the visual examinations performed pursuant to RG 1.163. The containment visual examination for the DCPP is implemented by the Containment Inservice Inspection Program (ASME XI, Subsections IWE and IWL) procedure. This procedure fulfills the surveillance requirements of the DCPP Containment ISI Program Plan (IWE / IWL Plan), as all areas of the shell and liner which are accessible for direct or qualified remote examination are subject to these requirements. Supplemental inspections will not be required.

3.4.4 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program The reactor containment leakage test program includes performance of LLRTs, also known as either Type B or Type C tests, in accordance with 10 CFR 50, Appendix J, Option B and RG 1.163. Type B tests are intended to detect leakage paths and measure leakage for certain primary reactor containment penetrations such as airlocks, hatches flanges and electrical penetrations. Type C tests are intended to measure containment isolation valve leakage rates. The Type B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with Specification 5.5.16, the allowable maximum pathway total Type B and C leakage is 0.6 La, 119,149 sccm, and where La equals 198,581 sccm.

Tables 3.4.4-1 and 3.4.4-2 provide LLRT data trend summaries for DCPP Units 1 and 2 inclusive of the Unit 1 2019 and Unit 2 2018 ILRTs.

Table 3.4.4-1 DCPP Unit 1 Type B and C LLRT Combined As-Found / As-Left Trend Summary RFO 2015 2017 2019 2020 2022 2023 1R19 1R20 1R21 1R22 1R23 1R24 AF Min Path (sccm) 14899 16958 12749 11442 13849 9249 Fraction of La (percent) 7.5 8.54 6.42 5.76 6.97 4.66 AL Max Path (sccm) 19036 16864 18706 18160 16647 15445 Fraction of La (percent) 9.59 8.49 9.42 9.14 8.38 7.78

Enclosure PG&E Letter DCL-24-070 58 Table 3.4.4-1 DCPP Unit 1 Type B and C LLRT Combined As-Found / As-Left Trend Summary RFO 2015 2017 2019 2020 2022 2023 1R19 1R20 1R21 1R22 1R23 1R24 AL Min Path (sccm) 14699 13229 14761 13682 11751 9928 Fraction of La (percent) 7.4 6.66 7.43 6.89 5.92 5.00 Table 3.4.4-2 DCPP Unit 2 Type B and C LLRT Combined As-Found / As-Left Trend Summary RFO 2014 2016 2018 2019 2021 2022 2R18 2R19 2R20 2R21 2R22 2R23 AF Min Path (sccm) 7942 8682 11718 12943 17562 34541 Fraction of La (percent) 4.0 4.37 5.90 6.52 8.84 17.39 AL Max Path (sccm) 17241 12598 15349 15930 17079 15361 Fraction of La (percent) 8.68 6.34 7.73 8.02 8.60 7.74 AL Min Path (sccm) 7880 7297 11284 14180 13145 10315 Fraction of La (percent) 3.97 3.67 5.68 7.14 6.62 5.19 As discussed in NUREG-1493 (Reference 41), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the Type B and Type C test results from 2014 through 2023 for DCPP has shown margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements as described below:

Enclosure PG&E Letter DCL-24-070 59 Unit 1:

• The As-Found minimum pathway leak rate average for DCPP Unit 1 shows an average of 6.64 percent of La with a high of 8.54 percent La.

• The As-Left maximum pathway leak rate average for DCPP Unit 1 shows an average of 8.80 percent of La with a high of 9.59 percent La.

Unit 2:

• The As-Found minimum pathway leak rate average for DCPP Unit 2 shows an average of 7.84 percent of La with a high of 17.39 percent La.

• The As-Left maximum pathway leak rate average for DCPP Unit 2 shows an average of 7.85 percent of La with a high of 8.68 percent La.

Statistics on Number of Components on Extended Intervals Number of Components in Type B and Type C Test Program:

Personnel airlock (1), Personnel airlock seals (2), Emergency airlock (1), Emergency airlock seals (2), Equipment hatch seals (1), Mini equipment hatch (Pen 58) seals (1),

Mini equipment hatch (Pen 60) seals (1), Fuel transfer tube seals (1), Electrical penetrations (42), Containment isolation valves (105). 157 Total Components per Unit.

Components not eligible for extended intervals due to Technical Specification limitations and refueling outage use - 17 components per Unit.

Components not eligible for extended intervals due to performance: Unit 1 - 2 components, Unit 2 - 3 components.

3.4.5 Type B and Type C LLRT Program Implementation Review Tables 3.4.5-1 and 3.4.5-2 identifies the components that were on extended LLRT intervals and have not demonstrated acceptable performance during the previous two outages for DCPP Units 1 and 2:

Enclosure PG&E Letter DCL-24-070 60 Table 3.4.5-1, DCPP Unit 1 Type B and C LLRT Program Implementation Review 1R23 - 2022 Component As-Found SCCM Admin Limit SCCM As-Left SCCM Cause Corrective Action Scheduled Interval None 1R24 - 2023 Component As-Found SCCM Admin Limit SCCM As-Left SCCM Cause Corrective Action Scheduled Interval NSS-9355B 1000 300 693 Seat leakage Accept as is, rebuild in 1R25 30 months CCW-585 26932 3500 1523 Gross Leakage Clean &

Inspect Removed and Reinstalled 30 months Table 3.4.5-2, DCPP Unit 2 Type B and C LLRT Program Implementation Review 2R22 - 2021 Component As-Found SCCM Admin Limit SCCM As-Left SCCM Cause Corrective Action Scheduled Interval None 2R23 - 2022 Component As-Found SCCM Admin Limit SCCM As-Left SCCM Cause Corrective Action Scheduled Interval CS-9011B 24,593 5,100 1,208 boric acid (dry) found in bottom of valve body Clean &

Inspect 30 months CCW-585 26932 3500 1523 Gross Leakage Clean &

Inspect Removed and Reinstalled 30 months 8368B 23365 2120 51 Gross Leakage Valve Replaced 30 months 3.4.6 Repeat Exceedance of LLRT Administrative Limit CS-2-9011B CS-2-9011B is a containment isolation valve located inside Unit 2 Containment on Containment Spray Header B. CS-2-9011B was unable to meet its acceptance criteria during the 2R23 performance of LLRT. The allowable leakage value is 5100 sccm, but

Enclosure PG&E Letter DCL-24-070 61 the leakage was measured at 24593 sccm. The redundant containment isolation valves outside Containment on CS Header B met their leakage criteria without issues, and there was no impact to CIV function.

When valve inspection was performed, Maintenance documented no internal issues with the valve. Dried Boric Acid (DBA) deposits on the seat and disk were observed. This was similar to the condition of the valve when LLRT acceptance criteria were not met in 2016 and 2008. This line is kept dry during the operating cycle, and only pressurized during outage CS Header testing. Boric acid crystals may form as valve seating surfaces dry over time.

The valve was partially disassembled for cleaning and inspection. DBA on disk and seat areas were cleaned. The LLRT was re-performed, and the acceptance criteria was satisfied (1208 sccm).

VAC-2-21 During performance of the 2R18 LLRT, VAC-2-21 failed to meet its acceptance criteria.

The leak rate during this LLRT was found to be in excess of 50,000 standard cubic centimeters per minute (sccm).

The valve was inspected and found with deposits of carbon dust. No wear was found on any parts of the valve. The valve was cleaned, and the upstream and downstream pipe was cleaned as far as reasonable. LLRT was re-performed, and the acceptance criteria were met with satisfactory results of 22 sccm.

A similar condition was documented in 2013 and 2011.

Under Appendix J, Operability is based on a penetration basis (not a 'by valve' basis).

Each penetration must provide closure integrity. Although testing of VAC-2-21 was unable to quantify flow at a minimum test pressure of 46 psig, thus exceeding its penetration 69 administrative leakrate of 500 sccm, the Outside Containment valve VAC-2-FCV-681 exhibited minimal leakage (12 sccm), well under the administrative limit. Therefore, penetration 69 remained operable.

An extent of condition evaluation was performed on VAC-2-21. There are a total of seven Mission (style), duo-check valves in service:

• CCW-585

• VAC-200 I 201

• CCW-695

• VAC-21

• AIR-587

• AIR-114

Enclosure PG&E Letter DCL-24-070 62 With the exception of VAC-21, and the recent failures of CCW-585, all other Mission style duo-check valves have performed sufficiently well under option B of the 10 CFR Appendix J program such that they have an extended test frequency of 3R.

Only VAC-21 is subject to a carbon dust effluent (from the sample pump of Radiation Monitor-11) and consequently is now tested on a 1R frequency. Unit 1 uses the same valve in the same function and is also monitored and tested per the Appendix J. Unit 1 history on VAC-21 shows satisfactory as-found results during 1R16, 1R17 & 1R18. Based on this repeatability, no actions required.

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

The following site specific and industry events have been evaluated for impact on containment:

• NRC IN 1989-79, Degraded Coatings and Corrosion of Steel Containment Vessels (Reference 34)

• NRC IN 1992-20, Inadequate Local Leak Rate Testing (Reference 35)

• NRC IN 1997-10, Liner Plate Corrosion in Concrete Containments (Reference

36)

• NRC IN 2004-09, Corrosion of Steel Containment and Containment Liner (Reference 37)

• NRC IN 2010-12, Containment Liner Corrosion (Reference 38)

• NRC IN 2014-07, Degradation of Leak Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner (Reference

39)

• RIS 2016-07, Containment Shell or Liner Moisture Barrier Inspection (Reference

47)

• Diablo Canyon Power Plant, Unit 1 - NRC Inspection Report 05000275/2023011 (Reference 6)

Each of these areas is discussed in detail in Sections 3.5.1 through 3.5.8, respectively.

Enclosure PG&E Letter DCL-24-070 63 3.5.1 NRC IN 1989-79, Degraded Coatings and Corrosion of Steel Containment Vessels The NRC issued IN 1989-79, dated December 1, 1989, to alert addressees of the discovery of severely degraded coatings and the corrosion of steel ice condenser containment vessels that are caused by boric acid and collected condensation in the annular space between the steel shell and the surrounding concrete shield building.

On August 24, 1989, Duke Power Company reported significant coating damage and base metal corrosion on the outer surface of the steel shell of the McGuire Unit 2 containment which was discovered during a pre-integrated leak rate test inspection (as required by Appendix J to 10 CFR Part 50). Subsequently, Duke Power identified similar degradation of the McGuire Unit 1 containment, which is essentially identical to the Unit 2 structure.

Both units have ice condenser-type containments consisting of a freestanding steel shell surrounded by a concrete shield building. Between the shell and the shield building is a 6-foot-wide annular space. The steel shells have a nominal thickness near the annulus floor of 1 inch. The degraded area on the shells of both units is limited to 30-foot circumferential sections no higher than 1 + inches [sic]

above the annulus floors. The average depth of the corrosion is 0.1 inch with pits of up to 0.125 inch. Corrosion that is up to 0.03-inch-deep was also found in areas below the level of the annulus floor on the Unit 2 shell, where concrete was removed to expose the shell surface. This below-floor corrosion is due to a lack of sealant at the interface between the shell and the annulus floor.

Discussion:

In July 2010, PG&E responded to an NRC request for additional information regarding the DCPP LRA (Reference 13). One of the requests asked DCPP to Describe the potential effects of steel liner plate corrosion issues discussed in NRC INs 89-79, 97-10 and 2004-09 on the containment liners for DCPP Units 1 and 2, since their ASME Section XI IWE AMP did not discuss those specific INs.

In the response to the RAI, DCPP noted that INs 1989-79, 1997-10, and 2004-09 discuss containment liner corrosion events of differing severities that have occurred in boiling water reactor drywells and suppression pools, PWR ice condenser liners, and PWR reinforced concrete structural liners such as DCPP's. The DCPP ASME Section XI, Subsection IWE Ageing Management Program (AMP) containment liner inspection procedure Units 1 and 2, VT-3 Visual Examination of the Containment Liner, specifically addresses inspection of the containment liner for corrosion and degraded liner surfaces.

DCPP specific examinations have routinely detected minor surface irregularities.

Additional inspection methods have been performed to determine the extent and origin, if possible, of the irregularities. This level of detection demonstrates that conditions and surface indications of liner degradation have a high probability of being detected and addressed, thus ensuring the containment liner license renewal intended function is

Enclosure PG&E Letter DCL-24-070 64 maintained. The periodic (40-month) inspection frequency has been specified by ASME Code as being sufficient to detect incipient indications of damage before it becomes widespread.

3.5.2 NRC IN 1992-20, Inadequate Local Leak Rate Testing The issue discussed in IN 1992-20, Inadequate Local Leak Rate Testing, was based on events at four different plants, Quad Cities, Dresden Nuclear Station, Perry Nuclear Plant, and the Clinton Station. The common issue in the four events was the failure to adequately perform Type B and C testing on different penetration configurations leading to problems that were discovered during Type A tests in the first three cases.

In the event at Quad Cities, the two-ply bellows design was not properly subjected to Type B test pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B tested as configured. In the events at both Dresden and Perry, flanges were not considered a leakage path when the Type C test was designed. This omission led to a leakage path that was not discovered until the plant performed a Type A test.

In the event at Clinton, relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C tested.

Discussion:

DCPP Units 1 and 2 have stainless-steel bellows attached to their fuel transfer tubes; however, they do not provide a containment isolation function. The fuel transfer tubes at DCPP are welded directly to the containment liner via a split ring as a transitional piece.

The expansion bellows are also welded to the fuel transfer tube on either side of the containment barrier in order to connect the fuel transfer tube to the reactor cavity, inside containment, and the fuel transfer canal, in the fuel handling building. There are no steel expansion bellows that form part of the containment boundary at DCPP.

3.5.3 NRC IN 1997-10, Liner Plate Corrosion in Concrete Containments The NRC issued IN 1997-10 on March 13, 1997, to alert addressees to occurrences of corrosion in the liner plates of reinforced and pre-stressed concrete containments, and to detrimental effects such as corrosion could have on containment reliability and availability under design-basis and beyond-design basis events.

Inspections of several containment liners showed various degrees of corrosion. In January 1993, an NRC inspector pointed out corrosion of the drywell liner at Brunswick Unit 2. During NRC structural assessment reviews at Trojan and Beaver Valley Unit 1, the staff noted peeled coating and spots of liner corrosion. The structural assessment at Robinson Unit 2 also revealed discoloration of the vertical portion of the containment liner

Enclosure PG&E Letter DCL-24-070 65 at an insulation joint. Finally, before the Type A test of the containment at Salem Unit 2 in 1993, the staff noted minor corrosion of the containment liner.

Of the five occurrences cited above, four (Trojan, Beaver Valley Unit 1, Salem Unit 2, and Robinson Unit 2) were found to be benign from the standpoint of safety. Corrosion of the liner plate at Brunswick Units 1 and 2 was significant from the standpoint of safety. Prior to the restart of Brunswick Units 1 and 2, the affected areas were cleaned and repaired.

Discussion:

In the response to the RAI (Reference 13), DCPP noted that INs 1989-79, 1997-10, and 2004-09 discuss containment liner corrosion events of differing severities that have occurred in boiling water reactor drywells and suppression pools, PWR ice condenser liners, and PWR reinforced concrete structural liners such as DCPP's. The DCPP ASME Section XI, Subsection IWE AMP containment liner inspection procedures, Units 1 and 2, VT-3 Visual Examination of the Containment Liner, specifically addresses inspection of the containment liner for corrosion and degraded liner surfaces. DCPP specific examinations have routinely detected minor surface irregularities. Additional inspection methods have been performed to determine the extent and origin, if possible, of the irregularities. This level of detection demonstrates that conditions and/or surface indications of liner degradation have a high probability of being detected and addressed, thus ensuring the containment liner license renewal intended function is maintained. The periodic (40-month) inspection frequency has been specified by ASME Code as being sufficient to detect incipient indications of damage before it becomes widespread.

3.5.4 NRC IN 2004-09, Corrosion of Steel Containment and Containment Liner The NRC issued this IN to alert addressees to recent occurrences of corrosion in freestanding metallic containments and in liner plates of reinforced and prestressed concrete containments. Any corrosion (metal thinning) of the liner plate or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition. Thinning changes the geometry of the containment shell or liner plate and may reduce the design margin of safety against postulated accident and environmental loads. Recent experience has shown that the integrity of the moisture barrier seal at the floor-to-liner or floor-to-containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material. Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.

Discussion:

Containment liner plate corrosion has been an industry issue for many years. DCPP is aware of these issues and has taken appropriate action to identify potential problems.

Previous NRC INs have been evaluated, including: IN 1989-79, IN 1991-10, and IN 1997-

29. Thorough inspection of the liner plate under both the Coatings Monitoring Program

Enclosure PG&E Letter DCL-24-070 66 and the Containment Inspection Program have been performed and will continue to be performed to preclude problems similar to those noted in the INs.

Five specific issues were posed by this IN: corrosion and thinning of the liner plate at the floor-to-liner junction, corrosion due to freestanding water, corrosion due to inadequate coatings, liner plate degradation due to foreign objects embedded in the exterior concrete, and degraded moisture barrier seal at the floor-to-liner junction.

The floor-to-liner junction at DCPP is thoroughly inspected through both the ISI Containment Inspection Program and the Coatings Quality Monitoring Program, with no adverse indications identified to date. The coatings applied to the liner and floor slab are safety-related immersion coatings. An area of potential concern compared to the floor-to-liner junction is the RHR recirculation sump area. The RHR recirculation sump area is a potentially corrosive environment for which an augmented inspection is performed. The floor-to-liner junction is a dry (noncorrosive) area and does not require augmented inspections. The augmented inspections are performed in accordance with ASME Section XI, IWE-2500. The augmented examination includes an ultrasonic thickness inspection of the containment liner in the RHR sump area. The liner within the sump area is gridded into 12-inch by 12-inch squares and ultrasonic readings are obtained at the grid intersection points.

Corrosion due to freestanding water (from a clogged drain, etc.) would be detected under the coatings monitoring inspections, performed every outage. Any issues would be identified and resolved according to the Containment Coatings Monitoring Program. The DCPP Coatings Monitoring Program provides assurance that identified problems are evaluated by the Engineering Department such that adequate corrective actions can be implemented.

Corrosion due to inadequate coatings would be detected under the coatings monitoring inspections, which are performed every outage. Any deficiencies would be identified and resolved according to Containment Coatings Monitoring Program.

As industry operating experience has shown, the back of the liner plate can be subject to corrosion as a result of foreign objects embedded in the concrete; however, it is very difficult to identify this type of corrosion until evidence of degradation appears on the interior accessible surface of the liner plate. The Coatings Monitoring Program, performed every outage, would identify this type of degradation as a deficiency and then route the issue to the Engineering Department for further evaluation. In addition, the integrity of the exterior concrete shell is important to the protection of the liner plate. To meet the requirements of ASME Section XI, Subsection IWL, DCPP procedures provide for inspection of the accessible surface of the containment concrete. The purpose of this inspection is to determine the general structure condition by identifying areas of concrete deterioration or distress. The acceptance criteria for the concrete shell are such that any conditions that could affect the liner plate (concrete degradation, discoloration, moisture seepage, etc.) are identified. The results of these inspections at DCPP to date have not

Enclosure PG&E Letter DCL-24-070 67 revealed adverse conditions of any magnitude that would warrant concern about corrosion on the back of the liner plate.

In response to IN 1989-79, DCPP evaluated the installation of a moisture barrier seal at the floor-to-liner junction. It was subsequently determined that the installation of a seal was not necessary. The RHR recirculation sump area and the liner-to-concrete interface area were included in the Containment Coatings Monitoring Program with special attention to ensure that boric acid corrosion of the containment liner near the basemat interface is averted. This area is also included as a line item in the coatings report generated after each outage to ensure that potential problems are identified. Both the Containment Coatings Monitoring Program and the ISI Containment Inspection Program monitor this area.

3.5.5 NRC IN 2010-12, Containment Liner Corrosion This IN was issued to alert plant operators to three events that occurred where the steel liner of the containment building was corroded and degraded. At Beaver Valley and Brunswick plants, material had been found in the concrete which trapped moisture against the liner plant and corroded the steel. In one case, it was material intentionally placed in the building, and in the other case it was foreign material which had inadvertently been left in the form when the wall was poured. But the result in both cases was that the material trapped moisture against the steel liner plate leading to corrosion. In the third case, Salem, an insulating material placed between the concrete floor and the steel liner plate adsorbed moisture and led to corrosion of the liner plate.

Discussion:

The DCPP containment structure is reinforced concrete with a mild carbon steel liner plate. The wall liner is made of 3/8-in. plate, except for the bottom section (approximately 4-ft high) where 3/4-in. plate is used with local reinforcement of the liner around penetration openings. During construction, the liner plate was blast cleaned to Joint Surface Preparation Standard and coated with 3/1000-in. inorganic zinc primer both inside and out. The inside of the liner plate is coated with an epoxy coating.

A detailed review was conducted and found that the exterior concrete structure, liner plate, penetrations, and penetration boundaries do not contain embedded items that could potentially cause corrosion on the concrete side of the containment liner plate.

DCPP Procedure General Visual Examination of the Containment Liner, provides the performance requirements for General Visual examination of accessible surfaces of the containment liner. This procedure meets the requirements of ASME Code Section XI, 2001 Edition with 2003 Addenda (Reference 7), as modified by 10 CFR 50.55a. This procedure applies to the General Visual examination of the containment liner, associated structure, and structural attachments, as required by Subsection IWE. In addition to ISI inspection, the Coating Quality Monitoring Program was developed to provide assurance of continued acceptable performance of coatings inside the containment structures. The

Enclosure PG&E Letter DCL-24-070 68 Coating Quality Monitoring Program is performed during every refueling outage, which is a DCPP commitment to the NRC. This inspection is conducted on all accessible coated surfaces of the containment, which includes the liner plate. IN 2010-12 notes that Beaver Valley has committed to performing supplemental volumetric inspections of 1 square ft samples in at least 75 random locations of each unit's containment liner. Beaver Valley also committed to performing supplemental volumetric examinations of a minimum of eight 1 square ft areas in locations that OE shows are susceptible to localized pitting corrosion. Additionally, Salem committed in its license renewal submittals that they would perform supplemental and augmented examinations of the liner plates at random and non-random locations. The DCPP IWE program consists of the code required visual inspections of the liner plate (augmented ultrasonic inspection in the RHR sump was performed prior to sump replacement with a closed system that made this augmented exam unnecessary). During the inspection process, DCPP identified a small number of suspect areas and then investigated those areas with surface or volumetric exams. The results of these exams have shown no significant degradation or loss of plate section.

3.5.6 NRC IN 2014-07, Degradation of Leak Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner The containment basemat metallic shell and liner plate seam welds of PWRs are embedded in a 3-ft to 4-ft thick concrete floor during construction and are typically covered by a leak chase channel system that incorporates pressurizing test connections. This system allows for pressure testing of the seam welds for leak-tightness during construction and also while in service, as required. A typical basemat shell or liner weld leak-chase channel system consists of steel channel sections that are fillet welded continuously over the entire bottom shell or liner seam welds and subdivided into zones, each zone with a test connection.

Each test connection consists of a small carbon or stainless-steel tube (less than 1-in.

diameter) that penetrates through the back of the channel and is seal welded to the channel steel. The tube extends up through the concrete floor slab to a small steel access (junction) box embedded in the floor slab. The steel tube, which may be encased in a pipe, projects up through the bottom of the access box with a threaded coupling connection welded to the top of the tube, allowing for pressurization of the leak chase channel. After the initial tests, steel threaded plugs or caps are installed in the test tap to seal the leak-chase volume. Gasketed cover plates or countersunk plugs are attached to the top of the access box flush with the containment floor. In some cases, the leak chase channels with plugged test connections may extend vertically along the circumference of the cylindrical containment shell or liner to a certain height above the floor.

Discussion:

The interface of the DCPP containment liner to the concrete base was not constructed with a moisture barrier. The majority of visible leak chase channels are above the concrete basemat (91-ft elevation). There are leak chase channels on the floor liner plate embedded below the 91-ft elevation in 2 ft of concrete. However, there are no leak chase

Enclosure PG&E Letter DCL-24-070 69 test fittings that extend up through the containment floor at elevation 91-ft. The leak chase channels on the containment wall liner penetrate into the concrete floor/basemat and communicate with the basemat leak chase channels. Therefore, there is no need for test fittings to extend up through the floor.

Based on the review, the leak chase configuration is not similar to the examples in the IN.

Therefore, DCPP is not susceptible to the condition.

3.5.7 RIS 2016-07, Containment Shell or Liner Moisture Barrier Inspection The NRC staff identified several instances in which containment shell or liner moisture barrier materials were not properly inspected in accordance with ASME Code Section XI, Table IWE-2500-1, Item E1.30. Note 4 (Note 3 in editions before 2013) for Item E1.30 under the Parts Examined column states that Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application.

Examples of inadequate inspections have included licensees not identifying sealant materials at metal-to-metal interfaces as moisture barriers because they do not specifically match Figure IWE-2500-1, and licensees not inspecting installed moisture barrier materials, as required by Item E1.30, because the material was not included in the original design or was not identified as a moisture barrier in design documents.

Discussion:

Section XI of ASME Code, Item E1.11, in Table IWE-2500-1 (E-A), requires general visual examination of 100 percent of accessible surface areas during each inspection period, while Item E1.30 in the same table requires general visual examination of 100 percent of accessible moisture barriers during each inspection period. Some sites have not included moisture barriers in their Containment Inspection Program.

The Diablo Canyon units were designed and built without moisture barriers at the 91' elevation concrete pad's interface with the liner. Unit 2 did have a limited amount of caulking applied at the interface during 2R16. The largest section of caulking was 6 feet or less. This is a small percentage of the total circumference of approximately 440 feet.

Hence, this limited application cannot be considered an integral part of the design of this structure. The ends of a small piece of caulking would not be considered deficient if the majority of the structure is without caulking, so no reasonable acceptance criteria could be applied. Hence, this limited application cannot be considered an integral part of the design of this structure. The ends of a small piece of caulking would not be considered deficient if the majority of the structure is without caulking, so no reasonable acceptance criteria could be applied.

Enclosure PG&E Letter DCL-24-070 70 3.5.8 Diablo Canyon Power Plant, Unit 1 - NRC Inspection Report 05000275/2023011, dated January 12, 2024 NRC inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, for the licensees failure to conduct general visual examinations of the moisture barriers to the containment liner in accordance with Subsection IWE of ASME,Section XI.

Specifically, the licensee failed to conduct visual examinations of the caulk applied to interior expansion joint locations in the Unit 2 containment.

==

Description:==

During the construction of the containment building, both the concrete floor slab as well as the internal concrete structures were constructed and installed directly on top of the base mat containment liner. Expansion joints were placed along the horizontal interfaces of these concrete structures to reduce internal stressors of the concrete, in order to resist cracking by allowing for independent movement, as well as thermal expansion and contraction. In January 2011, a caulk moisture barrier was applied along the 1/2-inch concrete gap to prevent moisture from reaching the inaccessible portions of the containment liner in Unit 2. In October 2023, during a walk down of the Unit 1 containment, the inspectors requested nondestructive examination (NDE) reports for the moisture barriers within the interior portions of the Unit 2 containment floor and liner interface. The containment ISI program is required by 10 CFR 50.55a to be implemented in accordance with ASME Section XI, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants. Subsection IWE, Table IWE-2500-1, Category E-A, Containment Surfaces, Item E1.30, Moisture Barriers, requires a general visual examination of 100 percent of moisture barriers. The reference to moisture barriers is further defined in Note (3) of this table, which states, in part; Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal welded.

Discussions with licensee staff revealed that the interior moisture barriers for Unit 2 were not part of the containment ISI program. The most recent informal inspection of the interior areas occurred during the initial installation in 2011. At the time that the inspectors identified the failure to inspect the interior moisture barriers, no inspections were scheduled to verify the current or future acceptability of these locations, nor was there reasonable assurance that any potential future inspection would meet the requirements and/or minimum standards of ASME XI, Subsection IWE. In response to the identified condition, the licensee added the moisture barriers to the ISI program and operability of the containment liner was determined to be unaffected based on a review of the past two results of the containment integrated leak rate test.

Corrective Actions:

The issue was entered into the licensees corrective action program.

Enclosure PG&E Letter DCL-24-070 71 Actions Taken by DCPP:

Unit 1 October 11, 2023, while on walkdown of Unit 1 with the NRC, the Inspector noticed a gap at the interface between the containment liner and the floor in the letdown orifice room at location: 91 ft and 90 degrees. The identified gap was documented in the Corrective Action Program (CAP).

Engineering Input Design Engineering did not recommend installing caulking in the gap identified at the interface between the Unit-1 91' concrete floor interior containment steel liner at this location.

Location of the identified GAP in the Unit 1 Containment:

Elev. 91' From 85o to 89o Length = 5 Majority of gap width = 1/16 Max gap width = 5/64 Maximum Depth of gap = ~2.5 (measured in several locations, not across entire length)

Elev. 91' From 89o to 95o Length = 7 Gap width across entire length = 1/64 Maximum Depth of gap = ~3 (measured at 90o only, could not get depth measurements elsewhere)

Basis For Not Installing Caulking at This Unit 1 Location.

There is no history or evidence of moisture at this interface that would cause accelerated corrosion of the liner (i.e., standing water, repeated wetting & drying, persistent leakage) and the geometry of the 91' concrete floor slopes away from the liner to an interior drain trench.

Inspection of the liner has not identified corrosion or significant degradation (other than paint chips/cracking) at this location. As a result, caulking is not required at this location to maintain the condition of the liner.

A small gap between the liner and concrete is normal and should not be considered unusual. This is because, during the hydration process of the concrete, the concrete tends to shrink slightly; thus, creating a small gap. From a design point of view, the steel liner forms a leak tight membrane and small gaps between the liner and concrete do not

Enclosure PG&E Letter DCL-24-070 72 affect this function.

Operating Experience on Moisture in Unit 1 Containment Elev. 91'

• Based on a review of corrective action program information, since 2008 only two notifications documented localized issues of water ponding on the floor in the Unit 1 containment. Experience has shown when water does end up on the floor, it flows to drainage troughs away from the containment liner. Based on the experience documented in the DCPP corrective action program, water on the floor is a very rare occurrence.

• Discussion with the containment HVAC engineer concluded it is not normal to have water cascading down the wall of containment or accumulating on the 91' containment slab.

• Operations personnel guidance states that if Operations identifies water pooling at any time during containment rounds, investigate and write a corrective action program notification. Operations round sheets prompt the operator to look for moisture and inspect the trough capacity. General conditions call for investigating including unusual condensation puddles or streams on the floor and trough.

In conclusion, it is not the normal practice at DCPP to allow for water accumulation or ponding on the ground near the containment liner. Any infrequent wetting of this area is promptly identified through the corrective action program and remediated, and the use of caulking at the liner-slab interface of the 91' containment elevation is not necessary.

Unit 2 The ASME Section XI, Subsection IWE, Examination Category E-A, Containment Liner Surfaces, Unit 2, Item E1.30 - Moisture Barriers, was updated for 2R24 to require the General Visual inspection of Unit 2 caulking. Please refer to Table 3.4.2-2 of this submittal.

3.6 License Renewal Aging Management The following programs, which are part of the supporting basis for this submittal, are also Aging Management Programs (AMPs) for DCPP:

3.6.1 Primary Containment Inservice Inspection Program The Primary Containment ISI Program is divided into two subsections, ASME Section XI, IWE and ASME Section XI, Subsection IWL. The DCPP ASME Section XI, Subsection IWE AMP inspects for loss of material, loss of sealing, and leakage through the containment. It provides aging management of the concrete containment steel liner. IWE inspections are carried out in order to find and manage containment liner aging effects

Enclosure PG&E Letter DCL-24-070 73 that could result in the loss of intended function. Included in the inspection program are the containment liner plate and its integral attachments, containment hatches and airlocks, and containment-related pressure-retaining bolting. The Primary Containment ISI Program complies with the ASME Code Section XI Edition and Addenda approved in accordance with the provisions of 10 CFR 50.55a, including those identified limitations, modifications, augmentations, or approved alternatives.

The DCPP ASME Section XI, Subsection IWL AMP manages cracking due to expansion, loss of bond, and loss of material (spalling, scaling); increase in porosity, permeability, and cracking; and provides aging management of the conventionally-reinforced concrete containment buildings for Units 1 and 2. The design of the DCPP Units 1 and 2 containment buildings does not use post-tensioned tendons. The ASME Section XI, Subsection IWL inspections are performed in order to find and manage containment concrete aging effects that could result in loss of intended function. Accessible surfaces of the containment exterior dome are included within this inspection program.

3.6.2 Protective Coating Monitoring and Maintenance Program AMP The DCPP Protective Coating Monitoring and Maintenance AMP is an existing AMP that manages cracking, blistering, flaking, peeling, and delamination of Service Level I coatings subjected to indoor air in the containment structure.

3.6.3 10 CFR 50, Appendix J AMP The DCPP 10 CFR Part 50, Appendix J AMP manages degradation due to aging effects such as loss of sealing, loss of leak tightness, cracking, loss of material, or loss of preload in various systems penetrating containment. The AMP also provides for detection of age-related degradation in material properties of gaskets, seals, expansion bellows, and flexible seal assemblies for the containment pressure boundary access points. The DCPP 10 CFR Part 50, Appendix J AMP consists of tests performed in accordance with 10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors (Option B as modified by approved exemptions); RG 1.163, Performance-Based Containment Leak-Testing Program Revision 0; NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J;

and ANSI/ANS 56.8, Containment System Leakage Testing Requirements. Three types of tests are performed under Option B. Type A tests are performed to determine the overall primary containment integrated leakage rate at the loss of coolant accident peak containment pressure. Performance of the ILRT per 10 CFR Part 50, Appendix J, Option B demonstrates the leak-tightness and structural integrity of the containment. A general visual examination of the accessible interior and exterior areas of the steel containment structure is performed prior to any ILRT during a period of reactor shutdown (refueling outages) and periodically between ILRTs.

Containment inspections are performed in accordance with the ASME Section XI, Subsections IWE and IWL. The ILRT is performed at the frequency specified in 10 CFR Part 50, Appendix J, Option B. Type B and Type C containment LLRTs, as defined in 10

Enclosure PG&E Letter DCL-24-070 74 CFR Part 50, Appendix J, are intended to detect local leaks and to measure leakage across each pressure-retaining or leakage-limiting boundary of containment penetrations.

LLRTs are performed at frequencies in accordance with the provisions of 10 CFR Part 50, Appendix J, Option B.

3.7 NRC Staff Regulatory Guidance and SER Limitations and Conditions 3.7.1 Staff Regulatory Guidance NEI 94-01, Revision 3-A, provides methods acceptable to the NRC staff for complying with the provisions of Option B in Appendix J to 10 CFR Part 50, subject to the following regulatory positions. Licensees wishing to use this RG should follow the regulatory positions identified in Section C of this RG in addition to the Limitations and Conditions identified in the safety evaluation appended to NEI 94-01, Revision 3-A.

Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

1. NEI 94-01, Revision 3-A, references ANSI/ANS-56.8-2002, Containment System Leakage Testing Requirements (Ref. 17), for detailed descriptions of the technical methods and techniques used for performing Types A, B, and C tests under Option B of Appendix J to 10 CFR Part 50. The NRC staff agrees with the methodology used in ANSI/ANS-56.8-2002 as well as the most recent methodology used in ANSI/ANS-56.8-2020 and accepts these as references for how licensees should perform the tests.

ANSI/ANS-56.8-2020 as approved by this RG may be used in lieu of ANSI/ANS 56.8-2002 without a LAR if (1) the licensees TS incorporate NEI 94-01, Revision 3-A and (2) the licensees TS do not explicitly reference the 2002 ANSI/ANS standard and there is no other license provision that would necessitate a LAR to use ANSI/ANS-56.8-2020.

The NRC staff has one condition for licensees referencing these standards.

Specifically, for calculating the Type A leakage rate, the licensee should use the performance leakage rate definition in NEI 94-01, Revision 3-A, in lieu of that in ANSI/ANS-56.8-2002 or ANSI/ANS-56.8-2020. The definition contained in NEI 94-01, DCPP will utilize ANSI/ANS 56.8-2020.

DCPP will utilize the definition in NEI 94-01 Revision 3-A, Section 5.0.

Enclosure PG&E Letter DCL-24-070 75 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response Revision 3-A, is more inclusive because it considers excessive leakage in the performance determination.

2. The licensee should submit a schedule of containment inspections to be performed before and between Type A tests as part of the LAR submittal for a Type A test interval extension.

Reference Section 3.4.2 of this submittal.

3. The LAR should address the areas of the containment structure potentially subject to degradation. Specifically, the licensee should describe its IWE/IWL Containment Inservice Inspection Program, which implements the requirements of the ASME BPV Code,Section XI, Subsections IWE and IWL, as required by 10 CFR 50.55a. Specific areas identified that should be addressed include a number of containment pressure retaining boundary components (e.g., seals and gaskets of mechanical and electrical penetrations, bolting penetration bellows) and a number of the accessible and inaccessible areas of the containment structures (e.g.,

moisture barriers, steel shells, and liners backed by concrete, inaccessible areas of ice-condenser containments that are potentially subject to corrosion). In addition, the LAR should also address such inaccessible degradation-susceptible areas in plant-specific inspections, using viable, commercially available NDE methods (such as boroscopes, guided wave techniques, etc.)- see Report ORNL/NRC/LTR-02/02, Inspection of Inaccessible Regions of Nuclear Power Plant Containment Metallic Pressure Boundaries, (Ref 18), for recommendations to support plant-specific evaluations.

Reference Section 3.4.2 of this submittal.

Enclosure PG&E Letter DCL-24-070 76 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

4. As part of the LAR submittal, the licensee should provide information about any tests and inspections following major modifications to the containment structure, as applicable.

The regulation at 10 CFR 50.55a(b)(2)(ix)(J) states, in part, that [w]hen applying IWE-5000 to Class MC pressure retaining components, any major containment modification or repair/replacement must be followed by a Type A test to provide assurance of both containment structural integrity and leak-tight integrity prior to returning to service. In general, the NRC staff considers the cutting of a large hole in the containment for replacement of steam generators or reactor vessel heads, or replacement of large penetrations, as major repairs or modifications to the containment structure. The revisions to the Type A interval described in NEI 94-01, Revision 3-A and this RG are limited to Type A testing for the purposes of satisfying Appendix J, and if licensees intend to depart from 50.55a(b)(2)(ix)(J) (i.e., a short duration structural test of the containment), then licensees should submit an alternative request before implementation in accordance with 10 CFR 50.55a(z). For minor modifications (e.g., replacement or addition of a small penetration) or modification of attachments to the pressure retaining boundary (i.e., repair/replacement of steel containment stiffeners), leakage integrity of the affected pressure retaining areas should be verified by a LLRT.

There are no major modifications planned.

Enclosure PG&E Letter DCL-24-070 77 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance DCPP Response

5. The normal Type A test interval should be less than 15 years. If a licensee desires to use the provision of Section 9.1 of NEI 94-01, Revision 3-A, related to extending the ILRT interval beyond 15 years, the licensee should demonstrate in a LAR that the extension is necessary due to an unforeseen emergent condition (see Regulatory Issue Summary 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 (Ref.

19)).

DCPP will follow the requirements of NEI 94-01, Revision 3-A, Section 9.1.

In accordance with the requirements of NEI 94-01, Revision 3-A, Section 9.1, DCPP will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

6. For new reactor plants licensed under 10 CFR Part 52, applications requesting a permanent extension of the performance-based ILRT surveillance interval to 15 years, should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 3-A, and EPRI Report No. 1009325, Revision 2-A, including the use of past containment ILRT data.

Not applicable. DCPP was not licensed under 10 CFR Part 52.

3.7.2 Limitations and Conditions Applicable to NEI 94-01, Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation of the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01, Revision 3-A, NRC SER 4.0, Limitations and Conditions):

Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI TR 94-01, Revision 3. At no time shall an extension be

Enclosure PG&E Letter DCL-24-070 78 allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

Response to Condition 1 Condition 1 presents the following three (3) separate issues that are required to be addressed:

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

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

• ISSUE 3 - Use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.

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

Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the DCPP, Units 1 and 2, administrative leakage summation limit of 0.5 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the DCPP leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Response to Condition 1, ISSUE 3 DCPP, Units 1 and 2 will apply the 9-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.

Enclosure PG&E Letter DCL-24-070 79 Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total is used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total leakage and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2 Condition 2 presents the following two (2) separate issues that are required to be addressed:

• ISSUE 1 - Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

Enclosure PG&E Letter DCL-24-070 80

• ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total and must be included in a licensee's post-outage report.

The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25 percent in the LLRT periodicity. As such, DCPP, Units 1 and 2 will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRTs being carried forward and will be included whenever the total leakage summation is required to be updated (either while on-line or following an outage).

When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, results in the MNPLR being greater than the DCPP administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the DCPP leakage limit. The corrective action plan should focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the DCPP administrative leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Types B and C summation margin, NEI 94-01, Revision 3-A, also has a margin-related requirement as contained in Section 12.1, Report Requirements.

Enclosure PG&E Letter DCL-24-070 81 A post-outage report shall be prepared presenting results of the previous cycles Type B and Type C tests, and Type A, Type B and Type C tests, if performed during that outage.

The technical contents of the report are generally described in ANSI/ANS-56.8-2002 (Reference 3) [ANSI/ANS-56.8-2020 (Reference 29)] and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

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

At DCPP, an adverse trend is defined as three (3) consecutive increases in the final pre-mode change Types B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

3.8 Conclusion NEI 94-01, Revision 3-A, dated October 2012, describes an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years. RG 1.163, Revision 1 and NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. DCPP is adopting the guidance of RG 1.163 Revision 1 and NEI 94-01, Revision 3-A, for DCPP, 10 CFR 50, Appendix J testing program plan.

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

• Containment Inservice Inspection Plan (IWE and IWL)

• Appendix J Program Containment Inspections per TS 5.5.16

Enclosure PG&E Letter DCL-24-070 82

• Protective Coating Monitoring and Maintenance Program This experience is supplemented by risk analysis studies, including the DCPP risk analysis provided in Reference 64. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to be insignificant since it represents a small change to the DCPP risk profile.

4.

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

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

EPRI TR-1009325, Revision 2-A, provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance. NEI 94 01, Revision 3-A, Section 9.2.3.1 (Reference 32), states that Type A ILRT intervals of up to 15 years are allowed by this guideline. The Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI Report 1018243 (formerly TR-1009325, Revision 2-A) (Reference 15), indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small.

However, plant-specific confirmatory analyses are required.

Enclosure PG&E Letter DCL-24-070 83 The NRC staff reviewed NEI TR 94-01, Revision 3, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 3, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporated the regulatory positions stated in RG 1.163 dated September 1995. The NRC staff found that the Type A testing methodology, as described in ANSI/ANS-56.8-2020 (Reference 29), and the modified testing frequencies recommended by NEI TR 94-01, Revision 3, serve to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TS as delineated in RG 1.174 (Reference 4) and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications (Reference 63). The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS regarding containment leakage rate testing, subject to the Staff Regulatory Guidance contained in RG 1.163 Revision 1.

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

4.2 Precedent This LAR is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC in the associated referenced SERs:

• Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, issued September 10, 2020 (Reference 22)

Enclosure PG&E Letter DCL-24-070 84

• McGuire Nuclear Station, Units 1 and 2, issued January 31, 2018 (Reference 23)

• Vogtle Electric Generating Plant, Units 1 and 2, issued October 29, 2018 (Reference 25) 4.3 Significant Hazards Consideration PG&E proposes to amend the Technical Specifications (TS) for DCPP Units 1 and 2, to allow extension of the Type A and Type C leakage test intervals. The extension is based on the adoption of RG 1.163, Revision 1, Performance-Based Containment Leak-Test Program, dated June 2023, and NEI 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, dated July 2012.

Specifically, the proposed change revises DCPP Units 1 and 2 TS 5.5.16, Containment Leakage Rate Testing Program, paragraph a., by replacing the reference to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, with a reference to RG 1.163 Revision 1 and 10 CFR 50, Appendix J, Option B - Performance-Based Requirements, with a reference to NEI 94-01, Revision 3-A.

In addition, the proposed change also deletes the exceptions in TS 5.5.16 for the 15-year Type A test interval beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2. which were previously approved by the NRC in TS Amendment 150 for Unit 1 and Amendment 150 for Unit 2 to allow one-time extensions of the ILRT test frequency for DCPP Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action.

PG&E has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in Title 10 of the Code of Federal Regulation (10 CFR) 50.92, Issuance of amendment, as discussed below:

1.

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

Response: No.

The proposed amendment to the Technical Specifications (TS) involves the revision of DCPP, Units 1 and 2, TS Section 5.5.16 to allow the extension of the Type A integrated leakage rate test (ILRT) containment test interval to 15 years, and the extension of the Type C local leakage rate test (LLRT) interval to 75 months for selected components.

The current Type A test interval of 120 months (10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. Extensions of up to nine months are permissible only for non-routine emergent conditions. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (total

Enclosure PG&E Letter DCL-24-070 85 maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.

The proposed test interval extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.

The change in Type A test frequency to once-per-fifteen years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, based on the internal events probabilistic risk analysis is 0.040 person-rem/year person-rem/yr, which is 2 percent of the population dose risk for Units 1 and 2. Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2-A states that a very small population is defined as an increase of 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This is consistent with the Nuclear Regulatory Commission (NRC) Final Safety Evaluation for Nuclear Energy Institute (NEI) 94-01 and EPRI Report No. 1009325. Moreover, the risk impact when compared to other severe accident risks is negligible. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

In addition, as documented in NUREG-1493, Performance-Based Containment Leak-Test Program, dated September 1995, Types B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The DCPP Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and (2) time based. Activity-based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance. The LLRT requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities.

The design and construction requirements of the containment structure combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components; the station Containment Coatings Program; and TS requirements, serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed test interval extensions do not significantly increase the consequences of an accident previously evaluated.

Enclosure PG&E Letter DCL-24-070 86 The proposed amendment also deletes the exceptions in TS 5.5.16, which were previously approved by the NRC in TS Amendment 150 for Unit 1 and Amendment 150 for Unit 2 to allow one-time extensions of the ILRT test frequency for DCPP Units 1 and

2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no impact on how the unit is operated.

Therefore, the proposed changes do not result in a significant increase in the probability or consequences of an accident previously evaluated.

2.

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

Response: No.

The proposed amendment to the TS 5.5.16, Containment Leakage Rate Testing Program, paragraph a., involves the extension of the DCPP Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plants ability to mitigate the consequences of an accident do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

The proposed amendment also deletes the exceptions in TS 5.5.16.a, which were previously approved by the NRC in TS Amendment 150 for Unit 1 and Amendment 150 for Unit 2 to allow one-time extensions of the ILRT test frequency for DCPP Units 1 and

2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that does not result in any change in how the unit is operated or controlled.

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

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

Response: No.

The proposed amendment to the DCPP Units 1 and 2 TS 5.5.16 involves the extension of the Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment

Enclosure PG&E Letter DCL-24-070 87 structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.

The proposed change involves only the extension of the interval between Type A containment leak rate tests and Type C tests for DCPP, Units 1 and 2. The proposed surveillance interval extension is bounded by the 15-year ILRT interval, and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusions that Types B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section Xl, the station Containment Coatings Program; and TS serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing.

The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Types A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.

The proposed amendment also deletes the exceptions in TS 5.5.16.a, which were previously approved by the NRC in TS Amendment 150 for Unit 1 and Amendment 150 for Unit 2 to allow one-time extensions of the ILRT test frequency for DCPP Units 1 and

2. These exceptions were for activities that have already taken place; therefore, the deletion is solely an administrative action and does not change how the unit is operated and maintained. Thus, there is no reduction in any margin of safety as a result of this administrative change.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

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

4.4 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 Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.

ENVIRONMENTAL CONSIDERATION PG&E has determined that the proposed amendment would change a requirement with

Enclosure PG&E Letter DCL-24-070 88 respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.

However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

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

6.

REFERENCES

1.

American Concrete Institute, ACI 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures, dated January 1, 1996.

2.

American National Standards Institute and American Nuclear Society, ANSI/ANS 56.8-1994, American National Standard for Containment System Leakage Testing Requirements, dated August 4, 1994.

3.

American National Standards Institute. and American Nuclear Society, ANSI/ANS-56.8-2002, Containment System Leakage Testing Requirements, dated November 2002.

4.

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

5.

American Society of Mechanical Engineers, ASME Boiler and Pressure Vessel Code,Section XI, Rules for lnservice Inspection of Nuclear Power Plant Components, 1977 Edition through 2003 Addenda.

6.

NRC Letter from N. Taylor to P. Gerfen (PG&E) Diablo Canyon Power Plant, Unit 1 - NRC Inspection Report 05000275/2023011 dated January 12, 2024 (ADAMS Accession Number: ML24008A244).

7.

American Society of Mechanical Engineers, ASME Section XI, Rules for lnservice Inspection of Nuclear Power Plant Components, 2001 Edition through 2003 Addenda.

8.

American Society of Mechanical Engineers and American Nuclear Society, ASME/ANS RA-Sa-2009, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008, dated February 2009.

Enclosure PG&E Letter DCL-24-070 89

9.

PG&E Letter DCL-85-058, Additional Information on Paint, dated February 09, 1985.

10.

PG&E Letter DCL-85-108, Additional Information on Paint, dated March 13, 1985.

11.

PG&E Letter DCL-06-142, License Amendment Request 06-09, Revision to Technical Specification 5.5.16, 'Containment Leakage Rate Testing Program' (TSTF-343), dated December 29, 2006 (ADAMS Accession No. ML070160261).

12.

PG&E Letter DCL-09-079, License Renewal Application, dated November 23, 2009 (ADAMS Accession No. ML093340086).

13.

PG&E Letter DCL-10-077, Response to NRC Letter dated June 21, 2010, Request for Additional Information (Set 5) for the Diablo Canyon License Renewal Application, dated July 19, 2010 (ADAMS Accession No. ML102530195).

14.

Electric Power Research Institute, EPRI Report No. 1009325, Revision 2, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, dated August 2007.

15.

Electric Power Research Institute, EPRI Report No. 1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, dated October 2008.

16.

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

17.

John M Gisclon (EPRI), William Parkinson, and Ken Canavan (Data Systems and Solutions), Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, developed for NEI, dated October 2001 (ADAMS Accession No. ML012990239).

18.

NRC Letter from A. Wang to J. Keenan (PG&E), Diablo Canyon Power Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Technical Specification 5.5.16,

'Containment Leakage Rate Testing Program,' For Consistency with 10 CFR 50.55a(g)(40) (TAC Nos. MD3977 and MD3978), dated June 26, 2007 (ADAMS Accession No. ML071370731).

19.

NRC Letter from A. Wang to J. Conway (PG&E), Diablo Canyon Power Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Revision to Technical Specification 5.5.16, 'Containment Leakage Rate Testing Program,' (TAC Nos.

Enclosure PG&E Letter DCL-24-070 90 MD8042 and MD8043), dated January 15, 2009 (ADAMS Accession No. ML090080387).

20.

Constellation Nuclear Letter from C. Cruse to the NRC, Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, dated March 27, 2002 (ADAMS Accession No. ML020920100).

21.

NRC Letter from G. Shukla to G. Rueger (PG&E), Diablo Canyon Nuclear Power Plant, Unit Nos. 1 and 2 - Issuance of Amendment Re: Revision of Technical Specifications Section 5.5.16, for a One-Time Extension of the 10 CFR Part 50, Appendix J, Integrated Leak Rate Test Interval (TAC Nos. MB3515 and MB3517), dated April 22, 2002 (ADAMS Accession No. ML020100111).

22.

NRC Letter from J. Wiebe to B. Hanson, Exelon Generation Company, Dated September 10, 2020 (ADAMS Accession No. ML20149K698).

23.

NEC Letter from M. Mahoney to T. D. Ray (Duke Energy), McGuire Nuclear Station, Dated January 31, 2018 (ADAMS Accession No. ML18009A842).

24.

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

25.

NRC Letter from M. Orenak to C. A. Gayheart (Southern Nuclear), Vogtle Electric Generating, Dated October 29, 2018 (ADAMS Accession No. ML18263A039).

26.

PRA Calculation File PRA 23-02, DC05A Application Model Update - Appendix X Closure, 6/29/2023.

27.

NRC Letter from S. Bloom to G. Rueger (PG&E), Issuance of Amendments for Diablo Canyon Nuclear Power Plant Unit No. 1 (TAC No. M94379) and Unit No.

2 (TAC No. M94380), dated March 1, 1996 (ADAMS Accession No. ML022390548).

28.

PWROG-17078-P Revision 0-A, Diablo Canyon Units 1 and 2 Independent Assessment of Seismic Probabilistic Risk Assessment Facts and Observations, PA-RMSC-1476, February 2018.

Enclosure PG&E Letter DCL-24-070 91

29.

American National Standards Institute and American Nuclear Society, ANSI/ANS-56.8-2020, Containment System Leakage Testing Requirements, dated December 2020.

30.

Nuclear Energy Institute, NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, dated July 21, 1995 (ADAMS Accession No. ML11327A025).

31.

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

32.

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

33.

Nuclear Energy Institute, NEI 07-12, Revision 1, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines, dated June 2010 (ADAMS Accession No. ML102230070).

34.

Nuclear Regulatory Commission, NRC IN 1989-79, Degraded Coatings and Corrosion of Steel Containment Vessels, dated December 1, 1989.

35.

Nuclear Regulatory Commission, NRC IN 1992-20, Inadequate Local Leak Rate Testing, dated March 3, 1992.

36.

Nuclear Regulatory Commission, NRC IN 1997-10, Liner Plate Corrosion in Concrete Containments, dated March 13, 1997.

37.

Nuclear Regulatory Commission, NRC IN 2004-09, Corrosion of Steel Containment and Containment Liner, dated April 27, 2004.

38.

Nuclear Regulatory Commission, NRC IN 2010-12, Containment Liner Corrosion, dated June 18, 2010.

39.

Nuclear Regulatory Commission, NRC IN 2014-07, Degradation of Leak Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner, dated May 5, 2014.

40.

DCPP PRA: DCPP Other External Events. Pacific Gas and Electric Company, Calc. File X.1, Revision 1, November 2016.

41.

Nuclear Regulatory Commission, NUREG-1493, Performance-Based Containment Leak-Test Program, September 1995.

Enclosure PG&E Letter DCL-24-070 92

42.

PWROG-17022-P Revision 0A, Peer Review of the Diablo Canyon Units 1 & 2 Seismic Probabilistic Risk Assessment, August 2017.

43.

Nuclear Regulatory Commission, Regulatory Guide 1.163, Performance Based Containment Leak-Test Program, dated September 1995 (ADAMS Accession No. ML003740058).

44.

PWROG-23015-P Revision 0, Diablo Canyon F&O Closure and Focused Scope Peer Review Report, PA-RMSC-1974, July 2023.

45.

Nuclear Regulatory Commission, Regulatory Guide 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated March 2009 (ADAMS Accession No. ML090410014).

46.

NEI 12-13, External Hazards PRA Peer Review Process Guidelines, August 2012.

47.

Nuclear Regulatory Commission, NRC Regulatory Issue Summary 2016-07 Containment Shell or Liner Moisture Barrier Inspection, dated May 9, 2016.

48.

Nuclear Regulatory Commission, Regulatory Guide 1.163, Revision 1, Performance Based Containment Leak-Test Program, dated June 2023 (ADAMS Accession No. ML23073A154).

49.

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

50.

Focused Peer Review of the Diablo Canyon Nuclear Power Plant Fire PRA Against the ASME PRA Standard Requirements, EPM Report P3118-003-001, Revision 0, August 2018.

51.

Fire PRA Peer Review Against the Fire PRA Standard Supporting Requirements from Section 4 of the ASME/ANS Standard, LTR-RAM-II-11-004, May 24, 2011.

52.

F&O Closure by Independent Assessment Report for the DCPP Fire PRA Model, EPM Report P3118-004-001, Revision 0, September 2018.

53.

U.S. Nuclear Regulatory Commission, Refining and Characterizing Heat Release Rates from Electrical Enclosures During Fire (RACHELLE-FIRE), Volume 1, Peak Heat Release Rates and Effect of Obstructed Plume, NUREG-2178, April 2016.

54.

U.S. Nuclear Regulatory Commission, Determining the Effectiveness, Limitations, and Operator Response for Very Early Warning Fire Detection

Enclosure PG&E Letter DCL-24-070 93 Systems in Nuclear Facilities (DELORES-VEWFIRE), NUREG-2180, December 2016.

55.

U.S. Nuclear Regulatory Commission, Joint Assessment of Cable Damage and Quantification of Effects from Fire (JACQUE-FIRE), Volume 2, Expert Elicitation Exercise for Nuclear Power Plant Fire-Induced Electrical Circuit Failure, NUREG-7150 (EPRI 3002001989), May 2014.

56.

Focused Peer Review of the Diablo Canyon Nuclear Power Plant Fire PRA Against the ASME PRA Standard Requirements, EPM Report P3118-003-001, Revision 0, August 2018.

57.

Seismic Peer Review, Peer Review of Diablo Canyon Power Plant Seismic Probabilistic Risk Assessment Against the Seismic PRA Standard Supporting Requirements of the ASME/ANS Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessments for Nuclear Power Plant Applications, LTR-RAM-II-13-04, May 1, 2013.

58.

NEI 12-13, External Hazards PRA Peer Review Process Guidelines, August 2012.

59.

Nuclear Regulatory Commission, Regulatory Guide 1.200, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, Revision 3, December 2020 (ADAMS Accession No. ML20238B871).

60.

Nuclear Regulatory Commission, NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decisionmaking, Dated November 2013 (ML13311A353).

61.

NRC Letter from B. Singal to E. Halpin (PG&E), Diablo Canyon Power Plant, Units 1 and 2 - Issuance of Amendments Re: Revise Licensing Bases to Adopt Alternative Source Term (CAC Nos. MF6399 and MF6400), April 27, 2017.

62.

NRC Letter from B. Singal to E. Halpin (PG&E), Diablo Canyon Power Plant, Units 1 and 2 - Correction Letter Regarding Amendment Nos. 230 And 232 to Adopt Alternative Source Term (CAC Nos. MF6399 and MF6400), May 16, 2017.

63.

Nuclear Regulatory Commission, Regulatory Guide 1.177, Revision 2, Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, dated January 2021 (ADAMS Accession No. ML20164A034).

64.

Jensen Hughes, 30032-CALC-01, Revision 0, "Diablo Canyon Power Plant:

Evaluation of Risk Significance of Permanent ILRT Extension."

Enclosure PG&E Letter DCL-24-070 Proposed Technical Specification Page Markup

Programs and Manuals 5.5 DIABLO CANYON - UNITS 1 & 2 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued) b.

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

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

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

5.5.16 Containment Leakage Rate Testing Program a.

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

3.

The ten-year interval between performance of the integrated leakage rate (Type A) test, beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, has been extended to 15 years.

b.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 43.5 psig. The containment design pressure is 47 psig.

c.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day.

5.0-16 Unit 1 - Amendment No. 135, 150, 172, 197, 198, 203, Unit 2 - Amendment No. 135, 150, 174, 198, 199, 204, June 2023, and NEI 94-01, Revision 3-A, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J,"

dated July 2012 Revision 1,

Enclosure PG&E Letter DCL-24-070 Proposed Retyped Technical Specification Page Remove Page Insert Page 5.0-16 5.0-16

Programs and Manuals 5.5 DIABLO CANYON - UNITS 1 & 2 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued) b.

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

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

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

5.5.16 Containment Leakage Rate Testing Program a.

A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, Revision 1, "Performance-Based Containment Leak-Test Program," dated June 2023, and NEI 94-01, Revision 3-A, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 2012, as modified by the following exceptions:

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.

b.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 43.5 psig. The containment design pressure is 47 psig.

c.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day.

5.0-16 Unit 1 - Amendment No. 135, 150, 172, 197, 198, 203, Unit 2 - Amendment No. 135, 150, 174, 198, 199, 204,