RA-25-0075, License Amendment Request to Revise Technical Specification 5.5.2, Containment Leakage Rate Testing Program, for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

License Amendment Request to Revise Technical Specification 5.5.2, Containment Leakage Rate Testing Program, for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML25232A073
Person / Time
Site:	Oconee   (DPR-038, DPR-047, DPR-055)
Issue date:	08/19/2025
From:	Snider S Duke Energy Carolinas
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
RA-25-0075
Download: ML25232A073 (1)

Text

(,DUKE

<{_;;ENERGY August 19, 2025 RA-25-0075 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001 Duke Energy Carolinas, LLC Oconee Nuclear Station (ONS), Units 1, 2, and 3 Docket Numbers 50-269, 50-270, and 50-287 Renewed Facility Operating License Nos. DPR-38, DPR-47, and DPR-55 Steven M. Snider Vice President Oconee Nuclear Station Duke Energy ON01 VP I 7800 Rochester Hwy Seneca, SC 29672 o: 864.873.3478

f. 864.873.5791 Steve.Snider@duke-energy.com 10 CFR 50.90

Subject:

License Amendment Request to Revise Technical Specification 5.5.2, "Containment Leakage Rate Testing Program," for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Pursuant to 10 CFR 50.90, Duke Energy Carolinas, LLC (Duke Energy) proposes to amend the Technical Specifications (TS) for Oconee Nuclear Station (ONS) Units 1, 2, and 3. The proposed amendment would revise TS 5.5.2, "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, Adopt an extension of the containment isolation valve (CIV) leakage rate testing frequency for Type C leakage rate testing of selected components, Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2020, "Containment System Leakage Testing Requirements," and 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 Enclosure provides a description and assessment of the proposed changes. Attachment 1 provides the existing TS pages marked to show the proposed changes. Attachment 2 provides an evaluation of the risk significance associated with the proposed changes.

The proposed changes have been evaluated in accordance with 10 CFR 50.91 (a)(1) using criteria in 10 CFR 50.92(c), and it has been determined that the proposed changes involve no significant hazards consideration. The basis for this determination is included in the Enclosure.

Duke Energy requests approval of the proposed amendment to the ONS TS by September 2026 to support the 01 R34 fall outage. Once approved, Duke Energy will implement the license amendments within 120 days.

RA-25-0075 Page2 There are no new regulatory commitments contained in this submittal.

In accordance with 1 O CFR 50.91, Duke Energy is notifying the State of South Carolina of this license amendment request by transmitting a copy of this letter and Enclosure to the designated State Official.

If there are any questions or if additional information is needed, please contact Ryan Treadway, Director - Nuclear Fleet Licensing at 980-373-5873.

I declare under penalty of perjury that the foregoing is true and correct. Executed on August 19, 2025.

Sincerely, Steven M. Snider Vice President Oconee Nuclear Station

Enclosure:

Description and Assessment of the Proposed Changes Attachments:

1. Proposed Technical Specification Changes (Mark-up)

2. Evaluation of Risk Significance of Permanent ILRT Extension, Seismic PRA F&Os

RA-25-0075 Page 3 cc:

NRC Regional Administrator, Region II USNRC Senior Resident Inspector - ONS NRR Senior Project Manager - ONS R. Mack (mackrs@dhec.sc.gov), SC DHEC, Bureau of Environmental Health Services

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Evaluation of the Proposed Change

SUBJECT:

License Amendment Request to Revise Oconee Nuclear Station Units 1, 2 and 3 Technical Specification 5.5.2, "Containment Leakage Rate Testing Program" for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

3.0 TECHNICAL EVALUATION

3.1 Description of Primary Containment System 3.2 Justification for the Technical Specification Change 3.3 Plant Specific Confirmatory Analysis 3.4 Non-Risk Based Assessment 3.5 Operating Experience (OE) 3.6 License Renewal Aging Management 3.7 NRC SER Limitations and Conditions 3.8 Conclusion

4.0 REGULATORY EVALUATION

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

6.0 REFERENCES

Attachments: 1.

Proposed Technical Specification Changes (Mark-up)

2.

Evaluation of Risk Significance of Permanent ILRT Extension, Seismic PRA F&Os

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 2 of 126 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, Application for amendment of license, construction permit, or early site permit, Duke Energy Carolinas (Duke Energy), requests an amendment to the Renewed Facility Operating License DPR-38 for Oconee Nuclear Station, Unit 1 (ONS 1),

Renewed Facility Operating License DPR-47 for Oconee Nuclear Station, Unit 2 (ONS 2), and Renewed Facility Operating License DPR-55 for Oconee Nuclear Station, Unit 3 (ONS 3).

Specifically, the proposed change is a request to revise Technical Specifications (TS) 5.5.2 Containment Leakage Rate Testing Program, to allow the following:

x Increase the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with the regulatory guidance specified in Regulatory Guide (RG) 1.163, Revision 1, Performance-Based Containment Leak-Test Program (Reference 49) and 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 2).

x 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, to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.

x Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2020, Containment System Leakage Testing Requirements (Reference 52).

x 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 contained herein would revise Oconee Nuclear Station (ONS)

TS 5.5.2, by replacing the references to the September 1995 revision of RG 1.163 with a reference to RG 1.163, Revision 1, dated June 2023. This document will be used by ONS 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) also proposes the following administrative changes to TS 5.5.2:

x Deleting the information regarding the performance of containment visual inspections as required by RG 1.163, Regulatory Position C.3 as the containment inspections are presently addressed in TS SR 3.6.1.1.

x Deleting the information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026 for ONS 1, November 28, 2027 for ONS 2, and May 25, 2028 for ONS 3 as these Type A tests shall be scheduled in accordance with RG 1.163, Revision 1.

A plant specific risk assessment was conducted to support this proposed change. This risk assessment followed the guidelines of Nuclear Regulatory Commission (NRC) RG 1.174,

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 3 of 126 Revision 3 (Reference 39) and RG 1.200, Revision 3 (Reference 41). The risk assessment concluded that increasing the ILRT frequency on a permanent basis from a one-in-ten-year frequency to a one-in-fifteen-year frequency is considered to be small since it represents a small change to the ONS risk profile.

2.0 DETAILED DESCRIPTION 2.1 Current Containment Leakage Rate Testing Program A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

The next Unit 1 ILRT following the November 29, 2014 test shall be performed no later than November 29, 2026. The next Unit 2 ILRT following the November 7, 2015 test shall be performed no later than November 28, 2027. The next Unit 3 ILRT following the May 10, 2016 test shall be performed no later than May 25, 2028. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, dated September 1995. Containment system visual examinations required by Regulatory Guide 1.163; Regulatory Position C.3 shall be performed as follows:

1.

Accessible concrete surfaces and post-tensioning system component surfaces of the concrete containment shall be visually examined prior to initiating SR 3.6.1.1 Type A test. These visual examinations, or any portion thereof, shall be performed no earlier than 90 days prior to the start of refueling outages in which Type A tests will be performed. The validity of these visual examinations will be evaluated should any event or condition capable of affecting the integrity of the containment system occur between the completion of the visual examinations and the Type A test.

2.

Accessible interior and exterior surfaces of metallic pressure retaining components of the containment system shall be visually examined at least three times every ten years, including during each shutdown for SR 3.6.1.1 Type A test, prior to initiating the Type A test.

The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 59 psig. The containment design pressure is 59 psig.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of the containment air weight per day.

Leakage rate acceptance criterion is:

a.

&RQWDLQPHQWOHDNDJHUDWHDFFHSWDQFHFULWHULRQLV/a. During the first unit startup following testing in accordance with this program, the leakage rate DFFHSWDQFHFULWHULDDUH/a IRUWKH7\SH%DQG&WHVWVDQG/a for Type A tests; The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 4 of 126 Nothing in these Technical Specifications shall be construed to modify the testing Frequencies of 10 CFR 50, Appendix J.

2.2 TS Change Description The proposed change would revise ONS TS 5.5.2, by replacing the reference to Regulatory Guide (RG) 1.163 (Reference 1) with a reference to RG 1.163, Revision 1 dated June 2023, as the specific document used by ONS to implement the Unit 1, Unit 2, and Unit 3 performance-based leakage testing programs in accordance with Option B of 10 CFR 50, Appendix J.

The proposed change would allow an increase in the Integrated Leak Rate Test (ILRT) test interval from its current 10-year frequency to a maximum of 15 years and the extension of the containment isolation valves leakage test (Type C tests) from its current 60-month frequency to 75 months. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.2:

x Deleting the information regarding the performance of containment visual inspections as required by RG 1.163 Regulatory Position C.3, exceptions 1 and 2 as the containment inspections are already addressed in TS SR 3.6.1.1.

x Deleting the information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026, for ONS 1, November 28, 2027, for ONS 2, and May 25, 2028, for ONS 3 as these Type A shall be scheduled in accordance with RG 1.163 Revision 1.

The proposed change revises ONS TS 5.5.2 to read as follows (with recommended changes using strike-out for deleted text and bold-type to show new text insertions, for clarification purposes):

A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The next Unit 1 ILRT following the November 29, 2014 test shall be performed no later than November 29 2026. The next Unit 2 ILRT following the November 7, 2015 test shall be performed no later than November 28, 2027. The next Unit 3 ILRT following the May 10, 2016 test shall be performed no later than May 25, 2028. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, Revision 1 Performance-Based Containment Leak-Test Program, dated September 1995 June 2023. Containment system visual examinations required by Regulatory Guide 1.163, Regulatory Position C.3 shall be performed as follows:

1.

Accessible concrete surfaces and post-tensioning system component surfaces of the concrete containment shall be visually examined prior to initiating SR 3.6.1.1 Type A test. These visual examinations, or any portion thereof, shall be performed no earlier than 90 days prior to the start of refueling outages in which Type A tests will be performed. The validity of these visual examinations will be evaluated should any event or condition capable of affecting the integrity of the containment system occur between the completion of the visual examinations and the Type A test.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 5 of 126

2.

Accessible interior and exterior surfaces of metallic pressure retaining components of the containment system shall be visually examined at least three times every ten years, including during each shutdown for SR 3.6.1.1 Type A test, prior to initiating the Type A test.

The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 59 psig. The containment design pressure is 59 psig.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of the containment air weight per day.

Leakage rate acceptance criterion is:

a.

&RQWDLQPHQWOHDNDJHUDWHDFFHSWDQFHFULWHULRQLV/a. During the first unit startup following testing in accordance with this program, the leakage rate DFFHSWDQFHFULWHULDDUH/a IRUWKH7\SH%DQG&WHVWVDQG/a for Type A tests; The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

Nothing in these Technical Specifications shall be construed to modify the testing Frequencies of 10 CFR 50, Appendix J.

A mark-up of the affected TS pages is provided in Attachment 1.

3.1 DESCRIPTION

OF PRIMARY CONTAINMENT SYSTEM The containment consists of the reactor building (RB) structure, its steel liner, and the penetrations of this liner and structure. The containment is designed to contain radioactive material that may be released from the reactor core following a design basis loss of coolant accident (LOCA). Additionally, the containment provides shielding from the fission products that may be present in the containment atmosphere following accident conditions.

The containment is a reinforced concrete structure with a cylindrical wall, a flat foundation mat, and a shallow dome roof. The containment design includes ungrouted tendons where the cylinder wall is prestressed with a post tensioning system in the vertical and horizontal directions, and the dome roof is prestressed using a three way post tensioning system. The inside surface of the containment is lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions.

The reinforced concrete structure is required for structural integrity of the containment under Design Basis Accident (DBA) conditions. The steel liner and its penetrations establish the leakage limiting boundary of the containment. Maintaining the containment OPERABLE, limits the leakage of fission product radioactivity from the containment to the environment. SR 3.6.1.1

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 6 of 126 leakage rate requirements comply with 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

Description of the Containment The structure consists of a post-tensioned reinforced concrete cylinder and dome connected to and supported by a massive reinforced concrete foundation slab. The entire interior surface of the structure is lined with a 1/4-inch-thick welded ASTM A36 steel plate to assure a high degree of leak tightness. Numerous mechanical and electrical systems penetrate the Reactor Building wall through welded steel penetrations. The mechanical penetrations and access openings are design, fabricated, inspected, and installed in accordance with Subsection B,Section III, of the ASME Pressure Vessel Code. Principal dimensions are as follows:

x Inside Diameter 116 ft x

Inside Height (Including Dome) 208-1/2 ft x

Vertical Wall Thickness 3-3/4 ft x

Dome Thickness 3-1/4 ft x

Foundation Slab Thickness 8-1/2 ft x

Liner Plate Thickness 1/4 in.

In the concept of a post-tensioned Reactor Building, the internal pressure load is balanced by the application of an opposing external pressure type load on the structure. Sufficient posttensioning is used on the cylinder and dome to more than balance the internal pressure so that a margin of external pressure exists beyond that required to resist the design accident pressure. Nominal bonded reinforcing steel is also provided to distribute strains due to shrinkage and temperature. Additional bonded reinforcing steel is used at penetrations and discontinuities to resist local moments and shears.

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

The post-tensioning system consists of:

x Three groups of 54 dome tendons oriented at 120oto each other for a total of 162 tendons anchored at the vertical face of the dome ring girder.

x 176 vertical tendons anchored at the top surface of the ring girder and at the bottom of the base slab.

x Six groups of 105 hoop tendons plus two additional tendons enclosing 120o of arc for a total of 632 tendons anchored at the six vertical buttresses.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 7 of 126 Each tendon consists of ninety 1/4-inch diameter wires with buttonheaded BBRV type anchorages, furnished by the Prescon Corporation. Replacement tendons installed during steam generator replacement were furnished by PSC. The tendons are housed in spiral wrapped corrugated thin wall sheathing. After fabrication, the tendon is shop dipped in a petroleum corrosion protection material, bagged and shipped. After installation, the tendon sheathing is filled with a corrosion preventive grease.

Ends of all tendons are covered with pressure tight grease filled caps for corrosion protection.

ASTM A615, Grade 60 reinforcing steel, mechanically spliced with T-series CADWELDS, is used throughout the foundation slab and around the large penetrations. A615, Grade 40 steel is used for the bonded reinforcing throughout the cylinder and dome as crack control reinforcing.

At areas of discontinuities where additional steel is used, such steel is generally A615, Grade 60 to provide an additional margin of elastic strain capability. ASTM A615, Grade 60 was also used as necessary for the repaired area following steam generator replacement.

The 1/4-inch-thick liner plate is attached to the concrete by means of an angle grid system stitch welded to the liner plate and embedded in the concrete. The frequent anchoring is designed to prevent significant distortion of the liner plate during accident conditions and to insure that the liner maintains its leak tight integrity. The design of the liner anchoring system also considers the various erection tolerances and their effect on its performance. The liner plate was coated during construction for corrosion protection. There is no paint on the side in contact with concrete.

The concrete used in the original construction of the structure is made with crushed marble aggregate obtained from Blacksburg, South Carolina. Such aggregate produces an excellent high strength, dense, sound concrete. The design strengths are 5000 psi at 28 days for the shell and foundation slab. A 5000-psi high early strength, non-shrink or slightly expansive mix was used for repairing the temporary construction opening following steam generator replacement.

Personnel and equipment access to the structure is provided by a double door personnel hatch with double seals on the outer door and by a 19 ft. - 0 in. clear diameter double gasketed single door equipment hatch. A double door emergency personnel escape hatch is also provided.

These hatches are designed and fabricated of A516, Grade 70 firebox quality steel made to A3000 specification, Charpy V-notch impact tested to 0o F in accordance with Section III of the ASME Pressure Vessel Code. All piping penetrations are furnished to the same requirements.

Structural brackets provided for the Reactor Building polar crane runway are fabricated of A36 steel shapes and A516, Grade 70 insert plates. Structural brackets and thickened plates are shop fabricated, stress relieved and shipped to the jobsite for welding into the 1/4-inch liner plate similar to the penetration assemblies.

Penetrations Penetrations conform to the applicable sections of ASA N6.2-1965, Safety Standard for the Design, Fabrication and Maintenance of Steel Containment Structures for Stationary Nuclear Power Reactors. Piping penetrations 25, 26, 27, 28, 63 and 64 conform to the requirements of ASME Section III, Subsections NE and NC, 1992 Edition, including all 1992 Addenda.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 8 of 126 Subsection NC applies only to the piping portion of the penetration. All personnel locks and any portion of the equipment access door extending beyond the concrete shell conform in all respects to the requirements of ASME Section III, Nuclear Vessels Code.

The basis for limiting strains in the penetration steel is the ASME Boiler and Pressure Vessel Code for Nuclear Vessels,Section III, Article 4, 1965, and therefore, the penetration structural and leak tightness integrity are maintained. Local heating of the concrete immediately around the penetration will develop compressive stress in the concrete adjacent to the penetration and a negligible amount of tensile stress over a large area. The mild steel reinforcing added around penetrations distributes local compressive stresses for overall structural integrity.

Horizontal and vertical bonded reinforcement is provided to help resist membrane and flexural loads at the penetrations. This reinforcement was located on both the inside and outside face of the concrete. Stirrups were also used to assist in resisting shear loads.

Local crushing of the concrete due to deflection of the reinforcing or tendons is precluded by the following details:

x The surface reinforcements either have a very large radius such as hoop bars concentric with the penetration or are practically straight, having only standard hooks as anchorages where necessary.

x The tendons are bent around penetrations at a minimum radius of approximately 20 feet.

Maximum tendon force at initial prestress is 850 kips, which results in a bearing stress of about 880 psi on the concrete.

It is also important to note that the deflected tendons are continuous past the openings and are isolated from the local effects of stress concentrations by virtue of being unbonded.

In accordance with ASME Section III, piping penetration reinforcing plates and the weldment of the pipe closure to it are stress relieved. This code requirement and the grouping of penetrations into large shop assemblies permit a minimum of field welding at penetrations.

Personnel Hatch The personnel hatch consists of a steel cylinder with 3 ft-6 in. x 6 ft-8 in. doors at each end interlocked so that only one door can be open at any time. The hatch is designed to withstand all Reactor Building design conditions with either or both doors closed and locked. Doors open toward the center of the Reactor Building and are thus sealed under Reactor Building pressure.

Design live load on the hatch floor is 200 psf.

Operation of the hatch is normally manual, that is, without power assist. Interlocks will prevent opening both doors at once.

Double gaskets are provided on the outer door to permit periodic pressurizing of the space between the gaskets from outside the Reactor Building. The hatch barrel may be pressurized to demonstrate its leak tightness without pressurizing the Reactor Building. Auxiliary restraint beams are attached to the inner door in this case to help the locking bars to resist internal lock

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 9 of 126 pressure, which is greatly in excess of the Reactor Building design external pressure of 3 psig.

The personnel hatch was pneumatically shop tested for pressure and leakage.

Emergency Hatch An emergency hatch is provided with 30-inch diameter doors. Its features are identical to the personnel hatch.

In order to support outage work activities during refueling operations, a temporary cover plate can be placed in the emergency hatch. The cover plate provides emergency hatch closure during refueling operations and is considered to be closed when a visual inspection shows no obvious leakage path.

The cover plate is approximately 36-inches in diameter and approximately 1-inch thick. The cover plate has multiple penetrations through it of various diameters. These penetrations have sleeves of varying lengths inserted through them and welded in place. The cover plate is installed and sealed against the inner emergency hatch door flange gasket. Positive sealing of the cover plate is accomplished by the use of RTV sealants. The cover plate is visually inspected to ensure that no gaps exist. All cables and hoses routed through the sleeves on the cover plate will also be installed and sealed. The sleeves will also be inspected to ensure that no gaps exist. Leak testing is not required prior to beginning fuel handling operations.

Therefore, visual inspection of the cover plate over the emergency hatch satisfies the requirement that the emergency hatch be closed.

Equipment Hatch A 19-foot diameter equipment hatch opening to the outside provides the movement of large items into and out of the Reactor Building. The door is secured by bolts on the inside of the Reactor Building wall and can be opened only from inside the Reactor Building. It is opened only when the reactor is subcritical. Double gaskets on the door permit the seals to be pressurized from outside the Reactor Building to check the integrity of the seals. During operation, the space between the double gaskets is vented to the penetration room.

Piping and Ventilation Penetrations All piping and ventilation penetrations are of the rigid welded type and are solidly anchored to the Reactor Building wall or foundation slab, thus precluding any requirements for expansion bellows. All penetrations and anchorages are designed for the forces and moments resulting from operating conditions. External guides and stops are provided as required to limit motions, bending and torsional moments to prevent rupture of the penetrations and the adjacent liner plate for postulated pipe rupture. Piping and ventilation penetrations have no provision for individual testing since they are of all-welded construction.

Electrical Penetrations Medium voltage penetrations for reactor coolant pump power are canister type using glass sealed bushings for conductor seals. The canisters are filled to a positive pressure with an inert gas. The assemblies are bolted to mating flanges which incorporate double 0 ring seals with a

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 10 of 126 test port between as a means of verifying seal integrity.

Low voltage power, control and instrumentation assemblies are designed to bolt to mating flanges mounted inside the Reactor Building. Electrical penetrations are designed to maintain containment integrity; thus, reliable environmental seals must be maintained. To accomplish the required reactor building environment seals, the interface between the mounting flange and the penetration header plate must be sealed and also the interfaces between the header plate and individual penetration feedthrough conductors must be sealed.

Dual O rings are used to complete the seal between the mating flange and the penetration header plate. The mating flange is welded to the penetration nozzle. The space between the O ring seals is charged with an inert gas. The charged gas space is piped to a charging valve located outside of the Reactor Building, which allows leakage around the O ring seals to be detected.

Depending upon the type of penetration utilized in a particular application, two different schemes are used to accomplish the seals between the header plate and the penetration feedthrough conductors. One scheme accomplishes the seal by utilizing two header plates to which are welded glass to metal sealed conductors. Another scheme accomplishes the feedthrough seals by use of polysulfide to metal sealed conductors. In both schemes, the space between the seals is also charged with an inert gas. The charged gas space is piped to a pressure gauge and a charging valve located outside of the Reactor Building, which allows leakage to be tested.

Fuel Transfer Tubes Two horizontal tubes are provided to convey fuel between each Reactor Building and the respective Auxiliary Building. These tubes contain tracks for the fuel transfer carriages, gate valves on the spent fuel pool side, and a means for flanged closure on the Reactor Building side. The fuel transfer tubes penetrate the spent fuel pool and the fuel transfer canal at their lower depth, where space is provided for the rotation of the fuel transfer carriage baskets.

3.1.1 Steam Generator Replacement Analysis of the Reactor Building for Steam Generator Replacement Replacement of the steam generators required the creation of a construction opening in the shell wall of the reactor buildings. The structural analysis required to accomplish this task consisted of a finite element model which explicitly represented the vertical tendons, hoop tendons, and opening geometry. The model represented 180 degrees of the structure with the symmetry plan placed along the 0-to-180-degree azimuth of the building.

The structure was analyzed for the load combinations given in the UFSAR and further delineated by Oconee calculations. Additional load combinations were added, per ACI 318-63, that describe the structural loadings while the containment opening is in place. Each load combination was applied to the model in twelve load steps. Each step represents a significant point of change as the building is undergoing opening creation and repair.

Construction Opening for Steam Generator Replacement

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 11 of 126 Replacement concrete for the construction opening was developed through an exhaustive testing program developed especially for the purpose. The details are delineated in Reactor Building - SGRP Construction Opening Concrete Work. The testing regiment covers all the original requirements for reactor building concrete plus testing to verify the shrinkage characteristics of the mix. The development efforts insure that the repair mix is compatible with the existing concrete and performs acceptability over the life of the building.

Tendons Installed During Steam Generator Replacement New tendons installed during the SGR are of the BBRV system type currently existing in the structure, however, they are manufactured in accordance with the Inryco design instead of the Prescon system currently used. The differences in these two systems are minor, head material is AISI 4140 and the wire button heads are slightly larger, which allows the use of the current maintenance equipment and ISI procedures.

Steam Generator Replacement Tensioning Schedule During steam generator replacement, tendons in the temporary construction opening were relaxed and/or removed. At the completion of the outage, the tendons were re-tensioned in accordance with ONS specifications.

Steam Generator Replacement Reinforcing Steel All new reinforcing steel, including replacement bars, are ASTM A615 Grade 60. The existing bars within the opening are A615 Grade 40. Mechanical splicing of bars will be accomplished through the use of BarSplice BPI XI swaged couplers. These devices are in compliance with ASME Section III, Division 2, Subsection CC and are capable of developing not less than of 125% of the specified yield strength of the bars in question.

Splice testing is in compliance with the UFSAR.

Where mechanical splices could not be used, direct-butt fusion welded splices were used.

These splices were welded and inspected in accordance with AWS D1.4-98, Structural Welding Code - Reinforcing Steel.

Steam Generator Replacement Liner Plate Repair and Fabrication The liner plate and stiffeners removed to facilitate generator removal will be reused or replaced with new materials of the same grade as the existing. Fabrication of the new materials will be per ASME Boiler and Pressure Vessel Code,Section VIII, 1998 Edition with 1998 Addenda.

Testing will be per ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWL, IWE, and IWA of the 1992 Edition with 1992 Addenda. The actual repair was in accordance with the original liner plate specification.

Steam Generator Replacement Field Welding of Liner Plate

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 12 of 126 Field welding, inspection, and welder qualifications are per ASME Boiler and Pressure Vessel Code,Section VIII, 1998 Edition with 1998 Addenda. ASME Boiler and Pressure Vessel Code,Section VIII, 1998 Edition with 1998 Addenda.

Steam Generator Replacement Structural Testing At the completion of the repair process the structure will undergo post modification testing. The building will be pressurized to the design pressure, Pa = 59 psig. This test will provide verification of the integrity of the reactor building. The test will be performed in conjunction with a Type A Integrated Leak Rate Test.

Reactor Building Structural Instrumentation for Steam Generator Replacement Instrumentation will consist of a Laser Tracker Metrology System used to acquire the measurements on the outside of the Reactor Building by placing/adhering semi-permanent Spherical Mounted Retro-Reflector (SMR) Nests to the outside concrete in the area of the repair. The Laser Tracker combines the linear distance of the interferometer or Absolute Distance Measurement (ADM) with a position angle of the elevation and azimuth axes to derive a targets three-dimensional (3-D) coordinate position. The 3-D coordinates are acquired by tracking the laser beam to SMRs and recording the data via wireless remote or keyboard entry.

The expected accuracy in the volume of this scope is 0.006 of an inch. The Tracker will be positioned on a stable platform at ground level and the adhered targets will be acquired for a baseline. SMRs will be placed in each nest for continuous monitoring during the pressure test.

A working coordinate system will be established to aid in interpretation of the displaced measurements.

Steam Generator Replacement Leakage Testing Following the steam generator replacement, a Type A Integrated Leakage Test, (ILRT), will be performed in accordance with the requirements of 10 CFR 50 Appendix J. This test will not be materially different from current station requirements.

3.1.2 Containment Isolation System The general design basis governing isolation requirements is:

Leakage through all fluid penetrations not serving accident-consequence limiting systems is to be minimized by a double barrier so that no single, credible failure or malfunction of an active component can result in loss-of-isolation or intolerable leakage.

The installed double barriers take the form of closed piping systems, both inside and outside the Reactor Building, and various types of isolation valves.

Reactor Building Essential and Non-essential Isolation occurs on an Engineered Safeguards signal of 3 psig (4 psig Technical Specification value) in the Reactor Building. Reactor Building Non-Essential Isolation occurs on an Engineered Safeguards signal of 1600 psig (1590 psig Technical Specification Value). Valves which isolate the Reactor Building purge flow path will also be closed on a high radiation signal during the movement of recently irradiated fuel. The Reactor Building sump drain flow path will also be isolated by closing a valve on a high radiation signal. Recently irradiated fuel is fuel that has occupied part of a critical reactor core within the

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 13 of 126 previous 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The radiation monitor signal is not an Engineered Safeguards signal.

Although normally open to the Reactor Building, the Reactor Building Gaseous Radiation Monitor penetrations are not closed on a high radiation signal; they remain open (except during ES isolation) to provide continuous monitoring. The isolation system closes all fluid penetrations, not required for operation of the engineered safeguards systems, to prevent the leakage of radioactive materials to the environment.

All remotely operated Reactor Building isolation valves that are active to close for containment isolation have position limit indicators in the control room. All solenoid valves used in actuating pneumatic RB isolation valves are environmentally qualified to the requirements of the IE Bulletin 79-01B.

System Design

The fluid penetrations which require isolation after an accident may be classed as follows:

Type A.

Each line connecting directly to the Reactor Coolant System has two Reactor Building isolation valves. One valve is inside, and the other is outside the Reactor Building.

These valves may be either a check valve and an automatic remotely operated valve, two automatic remotely operated valves, or two check valves, depending upon the direction of normal flow.

Type B.

Each line connecting directly to the Reactor Building atmosphere has two isolation valves. At least one valve is outside and the other may be inside or outside the Reactor Building. These valves may be either a check valve and an automatic remotely operated valve, or one check valve and one, normally closed manual valve, or two automatic remotely operated valves, or two check valves, depending upon the direction of normal flow. For piping not part of the process flow, double isolation will be used. One or more of the isolations will be a normally closed manual valve located on the vent, drain, or test connection. The other isolation valve may be located on the process piping.

Type C.

Each line not directly connected to the Reactor Coolant System or not open to the Reactor Building atmosphere has at least one valve, either a check valve or an automatic remotely operated valve. This valve is located outside the Reactor Building. A seismic closed loop forms the inside barrier for most Type C penetrations. Since the Component Cooling System has a nonseismic closed loop, penetrations for this system have an additional automatic remotely operated valve or check valve located inside the Reactor Building.

A variation to a non-seismic closed loop piping system inside containment is the low pressure service water (LPSW) piping to and from the Reactor Building Auxiliary Coolers. Penetrations for this piping system have additional automatic remotely operated valve located outside the Reactor Building. Note that the closed loop piping is

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 14 of 126 actually Seismic Category II but is not treated as such since it is not QA Condition I that is required for containment boundary items.

Type D.

Each line connected to either the Reactor Building atmosphere or the Reactor Coolant System, but which is not normally open during reactor operation, has two isolation valves. They may be manual valve(s) with provisions for locking in a closed position, check valve(s), and/or remotely operated valve(s), depending upon the direction of the normal flow.

There are additional subdivisions in each of these major groups. The specific system penetrations to which each of the arrangements is applied is also presented. It may be noted that only electric motor operated, manual normally closed, or check valves are used inside the Reactor Building. Each valve will be tested periodically during normal operation or during shutdown conditions to assure its operability when needed. The valves in the reactor building purge flow path are required to be maintained closed in Modes where the engineered safeguards system is required operable. This is a requirement of NUREG 0737, Item II.E.4.2.6.

Therefore, Engineered Safeguards system testing of these reactor building purge valves is not required.

As the result of Generic Letter 96-06, the issue of thermal overpressurization of certain containment penetrations was addressed by installation of relief valves, check valves, or other appropriate devices. Additionally, specific penetration(s) required administrative controls to prevent thermal overpressurization. The NRC accepted Oconees response to Generic Letter 96-06 in correspondence dated December 6, 2007.

Fluid penetrations which do not require isolation after an accident are also classified as Type A through D, however the redundant containment isolation provisions described above are not applicable.

There is sufficient redundancy in the instrumentation circuits of the engineered safeguards protective system to minimize the possibility of inadvertent tripping of the isolation system.

Periodic Operability Tests Each containment isolation valve will be tested periodically during normal operation or during shutdown conditions to assure its operability when needed.

A program of testing and surveillance of each of the three duplicate Reactor Buildings has been developed to provide assurance, during service, of the capability of each containment system to perform its intended safety function. This program consists of tests defined as follows:

Overall integrated leak rate tests of the Reactor Buildings and systems which under post-accident conditions become an extension of the containment boundary.

Local leak detection tests of components having resilient seals, gaskets, or sealant compounds that penetrate or seal the boundary of the containment system.

Components included in this category are:

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 15 of 126 x

Personnel Hatches x

Emergency Hatches x

Equipment Hatches x

Fuel Transfer Tube Covers x

Electrical Penetrations x

Leak Rate Test Pressurization/Exhaust Penetration Local leak detection and operability tests of containment isolation valves in systems that vent directly to the Reactor Building atmosphere or the Reactor Coolant system that must close upon receiving an isolation signal and seal the containment under accident conditions.

Operability tests of engineered safeguards systems which under post accident conditions are relied upon to limit or reduce leakage from the containment. Included in these tests are:

x Reactor Building Spray Systems x

Reactor Building Penetration Room Ventilation Systems (not required for accident mitigation due to adoption of alternate source term) (Reference 14).

x Reactor Building Cooling Systems x

Reactor Building Isolation Valves not covered above 3.1.3 Containment Overpressure on ECCS Performance ONS credits 0.44 psi of overpressure for calculation of available NPSH for the Reactor Building Spray (RBS) in recirculation mode from approximately 3000 seconds to 30000 seconds in a design-basis accident. The Low-Pressure Injection (LPI) pumps do not require overpressure credit for NPSH. The RBS pumps are not credited in the ONS PRA, so there is no impact to the ILRT extension application due to the RBS pumps requirement for containment overpressure for adequate NPSH.

Since containment overpressure is not credited in the PRA models, no delta core damage frequency (CDF) estimate is required and there is no impact to the ILRT extension PRA evaluation.

3.2 JUSTIFICATION FOR THE TECHNICAL SPECIFICATION CHANGE 3.2.1 Chronology of Testing Requirements of 10 CFR 50, Appendix J

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 16 of 126 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 DBA. 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. Type B and C tests identify the vast majority of potential containment leakage paths.

Type A tests identify the overall (i.e., integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term performance-based in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also in 1995, RG 1.163 (Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A ILRT test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493 (Reference 6) and Electric Power Research Institute (EPRI) TR-104285 (Reference 7), both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months 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 8), 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 1). 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 17 of 126 In 2012, NEI 94-01, Revision 3-A (Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 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 dated June 25, 2008 (Reference 9), and June 8, 2012 (Reference 10), 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 9 and 10, 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 Types B and 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 air locks) 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 (Reference 2).

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 (Reference 9):

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

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

NEI 94-01, Revision 3-A, Section 10.1, Introduction, concerning the use of test interval extensions in the deferral of Type B and Type C LLRTs, 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 18 of 126 extension) does not apply to valves that are restricted and/or limited to 30-month intervals in Section 10.2 (such as BWR MSIVs [main steam isolation valves]) 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, Item 2 (Reference 10):

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.

RG 1.163, Revision 1, dated June2023, endorsed the guidance in NEI 94-01, Revision 3-A for implementing Option B of Appendix J to 10 CFR Part 50, subject to the regulatory positions listed in section C of the 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. RG 1.163, Revision 1, also endorses EPRI Report No.1009325, Revision 2-A, subject to the applicable regulatory positions listed in section C of the RG. In addition, RG 1.163, Revision 1, also endorses ANSI/ANS 56.8-2020, for acceptable industry standards on technical methods and techniques for performing Type A, B, and C tests.

3.2.2 Current ONS CLRT Program Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose Containment leakage testing under either Option A, Prescriptive Requirements, or Option B, Performance-Based Requirements. ONS has implemented the requirements of 10 CFR 50, Appendix J, Option B for Types A, B and C testing. Current TS 5.5.2 requires the following:

A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The next Unit 1 ILRT following the November 29, 2014 test shall be performed no later than November 29, 2026. The next Unit 2 ILRT following the November 7, 2015 test shall be performed no later than November 28, 2027. The next Unit 3 ILRT following the May 10, 2016 test shall be performed no later than May 25, 2028. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, dated September 1995. Containment system visual examinations required by Regulatory Guide 1.163; Regulatory Position C.3 shall be performed as follows:

1.

Accessible concrete surfaces and post-tensioning system component surfaces of the concrete containment shall be visually examined prior to initiating SR 3.6.1.1 Type A test. These visual examinations, or any portion thereof, shall be performed no earlier than 90 days prior to the start of refueling outages in which Type A tests will be performed. The validity of these visual examinations will be evaluated should any event or condition capable of affecting the integrity of the containment system occur between the completion of the visual examinations and the Type A test.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 19 of 126

2.

Accessible interior and exterior surfaces of metallic pressure retaining components of the containment system shall be visually examined at least three times every ten years, including during each shutdown for SR 3.6.1.1 Type A test, prior to initiating the Type A test.

Currently, TS 5.5.2 requires that a program be established to comply with the CLRT requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B for Type A, Type B and Type C testing, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163 with exceptions. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (Reference 5) rather than using test intervals specified in ANSI/ANS 56.8-1994. NEI 94-01, Section 11.0 refers to Section 9.0, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once-per-ten years based on acceptable performance history. Acceptable performance history is defined as completion of two (2) consecutive periodic Type A tests where the calculated performance leakage rate was less than 1.0 La (where La is the maximum allowable leakage rate at design pressure). Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

Adoption of the Option B performance based CLRT program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the as found leakage history to determine a frequency for leakage testing, which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493 (Reference 6). The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing containment types. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT) from the original three tests per 10 years to one test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk.

3.2.3 ONS 10 CFR 50, Appendix J, Option B Licensing History October 30, 1996 - License Amendment Nos. 218, 218 and 215 (Reference 12)

The NRC issued Amendment Nos. 218, 218 and 215 for ONS which revised the TS to incorporate the performance-based 10 CFR 50, Appendix J, Option B, for Type A containment ILRTs.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 20 of 126 January 18, 2000 - License Amendment Nos. 310, 310 and 310 (Reference 13)

The NRC issued Amendment Nos. 310, 310 and 310 for ONS which revised the TS 5.5.2 to revise the Containment Inservice Inspection Program TS related to the containment leakage testing program and the pre-stressed concrete containment tendon surveillance program. The proposed revision to TS 5.5.2 requested two clarifications to the requirements of Regulatory Guide (RG) 1.163 (Reference 1).

June 1, 2004 - License Amendment Nos. 338, 339, and 339 (Reference 14)

The NRC issued Amendment Nos. 338, 339 and 339 for ONS which revised the TSs to incorporate changes resulting from use of an alternate source term.

July 28, 2011 - License Amendments Nos. 375, 377 and 376 (Reference 15)

The NRC issued Amendment Nos. 375, 377 and 376 for ONS which revised the TSs to adopt technical specification task force technical change Traveler 52, Revision 3, to implement option B of Appendix J to Title 10 of the Code of Federal Regulations, Part 50.

October 1, 2012 - License Amendment No. 381 (Reference 16)

The NRC issued Amendment No. 381 for ONS Unit 1, which revised the due date for the next integrated leak rate test of the reactor building from December 8, 2013, to March 8,2015, which aligns with the two-year refueling outage schedule at Oconee Nuclear Station, Unit 1.

August 5, 2013 - License Amendment Nos. 383 and 382 (Reference 23)

The NRC issued Amendment Nos. 383 and 382 for ONS Units 2 and 3, which revised the due date for the next integrated leak rate test of the Unit 2 reactor building from May 29, 2014, to December 29, 2015, and revises the due date for the next integrated leak rate test of the Unit 3 reactor building from December 21, 2014, to July 21, 2016, which better aligns with the two-year refueling outage schedules at Units 2 and 3.

August 26, 2024 - License Amendment Nos. 430, 432 and 431 (Reference 26)

The NRC issued License Amendment Nos. 430, 432 and 431 for ONS Units 1, 2, and 3, which revised Technical Specification (TS) 5.5.2, Containment Leakage Rate Testing Program, by allowing a one-time extension to the 10-year frequency of the containment integrated leakage rate test (ILRT or Type A test). The amendments permit the existing ILRT frequency to be extended from 10 years to approximately 12 years for all three Oconee units.

3.2.4 Integrated Leakage Rate Testing History As noted previously, ONS TS 5.5.2 currently requires Type A testing in accordance with RG 1.163, which endorses the methodology for complying with 10 CFR 50, Appendix J, Option B.

Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing.

Table 3.2.4-1 lists the past Periodic Type A ILRT results for ONS Unit 1, Unit 2 and Unit 3.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 21 of 126 Table 3.2.4-1, Periodic Type A ILRT Results for ONS Units 1, 2 and 3 95% Upper Confidence Limit (UCL)

(wt%/day)

Test Pressure Test Date Unit 1 0.127789 58.9961 psig November 2014 0.097334 60.016 psig December 20031 0.1544 60.39 January 1993 0.158117 59 psig May 1990 0.1734 59 psig April 1986 0.15205 59 psig August 1983 0.052167 29.5 psig February 1980

-0.00143 29.5 psig March 1976 0.0475 59 psig August 1971 0.0147 29.5 psig August 1971 Unit 2 0.1046768 59.2507 psig November 2015 0.093723 59.762 psig May 20041 0.1506 60.48 June 1993 0.117803 29.5 psig October 1990 0.070276 29.5 psig March 1988 0.1209 29.5 psig November 1983 0.0595 29.5 psig June 1980 0.097 29.5 psig August 1977 0.00223 59 psig July 1973 0.00828 29.5 psig July 1973 Unit 3 0.109894 59.9548 psig May 2016 0.07075 59.46 psig December 20041 0.1196 59 psig September 1992 0.118797 29.5 psig December 1989 0.1054 29.5 psig March 1987 0.1080 29.5 psig May 1984 0.0656 30 psig February 1981 0.132 29.5 psig July 1978 0.0215 59 psig May 1974 0.0248 29.5 psig May 1974

1)

The Steam Generators were each replaced at ONS Unit 1, Unit 2, and Unit 3 during EOC21. A post modification leakage test was required to be performed per Appendix J and in accordance with UFSAR Section 3.8.1.7.3.1 (Steam Generator Replacement Leakage Testing), which stated "Following the steam generator replacement and opening closure a Type A Integrated Leakage Rate Test (ILRT) will be performed in accordance with the requirements of 10 CFR 50 Appendix J. This test will not be materially different from current station requirements."

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 22 of 126 The current ILRT test interval for ONS Units 1, 2, and 3 is ten years. Verification of this interval is presented in Table 3.2.4-2. The acceptance criteria used for this verification is contained in NEI 94-01, Revisions 2-A and 3-A, Section 5.0, Definitions, and is as follows:

"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 3.2.4-2, ONS ILRT Test Results Verification of Current Extended ILRT Interval for ONS Units 1, 2 and 3 Test Date Upper 95%

Confidence Limit (wt.%/day)

(Test Pressure)

Level Corrections (Leakage Savings)

(wt.%/day)

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

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

ILRT Acceptance Criteria (wt.%/day)

Test Method /

Data Analysis Techniques Unit 1 November 2014 0.127744 (58.9961 psig) 0.0 0.000045 0.127789 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point December 2003 0.096294 (60.016 psig) 0.0 0.001039 0.097334 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point Unit 2 November 2015 0.10459 (59.2507 psig) 0.000019 0.0000678 0.1046768 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point May 2004

0. 092043 (59.762 psig) 0.0 0.00168 0.093723 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point Unit 3 May 2016 0.109056 (59.9548 psig) 0.000736 0.0001017 0.109894 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point December 2004 0.07008 (59.46 psig) 0.0 0.00067 0.07075 0.1875 Absolute /

ANSI/ANS 56.8-1994 Mass Point

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 23 of 126 3.3 PLANT SPECIFIC CONFIRMATORY ANALYSIS 3.3.1 Methodology An analysis was performed to provide a risk assessment of permanently extending the currently allowed containment Type A ILRT from ten years to fifteen years. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for ONS. The risk assessment follows the guidelines from the following:

x NEI 94-01, Revision 3-A (Reference 2),

x 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 19),

x NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 Revision 3 (Reference 41) 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 39),

x 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 40),

x Methodology used in EPRI 1018243, Revision 2-A of EPRI 1009325 (Reference 11).

x This assessment also meets the guidance in Regulatory Guide 1.163, Revision 1 (Reference 49).

The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, 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 6], provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. To supplement the NRCs rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals (Reference 7).

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% 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 ONS.

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 (Reference 11). The Guidance provided in Appendix H of EPRI Report No. 1009325 Revision 2-A builds on the EPRI Risk Assessment methodology, EPRI TR-104285 (Reference 7). This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 24 of 126 ILRT changes. These documents form the basis for the guidance in Regulatory Guide 1.163, Revision 1 It should be noted that containment leak-tight integrity is also verified through periodic in-service inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, Subsection IWE provides the rules and requirements for in-service inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. The associated change to NEI 94-01 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% 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%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% is assumed to be small (Reference 2).

In addition, the total annual risk (person-rem/year 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 [Reference 6] and Safety Evaluations (SEs) for one-time interval extension (summarized in Appendix G of Reference 24) indicate a range of incremental increases in population dose that have been accepted by the NRC. The range of incremental population dose increases LVIURPWRSHUVRQ-rem/year and/or 0.002% to 0.46% of the total accident dose (Reference 11). The total doses for the spectrum of all accidents (NUREG-1493 (Reference 6), Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a small population dose is defined as an increase from the baseline interval (3 WHVWVSHU\HDUVGRVHRIperson-rem per year or 1% of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 25 of 126 Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance ONS 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, ONS has documented the technical adequacy of the PRA used to support its performance-based Appendix J program in Section 3.3.2 below.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 26 of 126 Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance ONS 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.

Since the ILRT does not impact core damage frequency (CDF), the relevant criterion is Large Early Release Frequency (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 8.35E-08/year, 7.82E-08/year, and 7.89E-08/year for units 1, 2, and 3 using the EPRI guidance. Therefore, the estimated change in LERF is determined to be very small using the acceptance guidelines of Regulatory Guide 1.174 (Reference 39). The risk change resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years bounds the 1 in 10 years to 1 in 15 years risk change. Considering the increase in LERF resulting from a change in the Type A ILRT test interval from 1 in 10 years to 1 in 15 years is estimated as 3.48E-08/year, 3.26E-08/year, and 3.29E-08/yr for units 1, 2, and 3, the risk increase is very 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 0.0076 person-rem/year, 0.0071 person-rem/year, and 0.0072 person-rem/year for units 1, 2, and 3, respectively. EPRI Report No.

1009325, Revision 2-A (Reference 9) states that a very small population dose is defined as an LQFUHDVHRISHUVRQ-UHPSHU\HDURURI 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 27 of 126 Table 3.3.1-1, RG 1.163, Revision 1, Section C, Staff Regulatory Guidance Staff Regulatory Guidance ONS Response

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 preexisting 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.

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.

ONS credits 0.44 psi of overpressure for calculation of available NPSH for the Reactor Building Spray (RBS) in recirculation mode from approximately 3000 seconds to 30000 seconds in a design-basis accident [Reference 41]. The Low-Pressure Injection (LPI) pumps do not require overpressure credit for NPSH. The RBS pumps are not credited in the ONS PRA, so there is no impact to the ILRT extension application due to the RBS pumps requirement for containment overpressure for adequate NPSH.

Since containment overpressure is not credited in WKH35$PRGHOVQR&')HVWLPDWHLVUHTXLUHG

and there is no impact to the ILRT extension PRA evaluation.

3.3.2 PRA Acceptability PRA Quality Statement for Permanent 15-Year ILRT Extension The ONS PRA has undergone numerous peer reviews and Fact and Observation (F&O) closure

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 28 of 126 reviews. These reviews are described in Reference 21 and Reference 51. Most finding level F&Os have been resolved and F&O closure reviews performed to document closure. There are several open finding level F&Os associated with the seismic PRA, which are described and dispositioned for this application in the subsequent sections. Capability Category I is appropriate since approximate values of CDF and LERF and their distribution among release categories are sufficient for use in the EPRI methodology (Reference 49).

Internal Events and Internal Flood PRA The Oconee Nuclear Station (ONS) internal events at power PRA Peer Review was performed in October 21-25, 2013 at the Duke Energy offices in Charlotte, North Carolina, using the NEI 05-04 Revision 3 process and the ANS/ASME PRA Standard RA-Sa-2009 (along with the NRC clarifications provided in Regulatory Guide 1.200, Revision 2).

After the peer review, the F&Os were resolved, and an F&O closure review was held to confirm closure of the internal events F&Os prior to the issuance of Appendix X to NEI 05-04/07-12/12-

13. A subsequent closure review that fully meets the guidance in Appendix X to NEI 05-04/07-12/12-13 confirmed all Level 1 model finding F&Os are closed. All Level 1 model finding F&Os are closed and all SRs are MET (Reference 21 and Reference 51).

One F&O resolution was determined to result in a PRA upgrade. A focused-scope PRA peer review of the applicable SR was performed, and the SR was determined MET at CC-III with no F&Os (Reference 21).

The LERF model was peer reviewed in December of 2012 against the ANS/ASME PRA Standard RA-Sa-2009 (along with the NRC clarifications provided in Regulatory Guide 1.200, Revision 2). The model was peer-reviewed to CC-I, and additional work to upgrade the CC-I SRs to CC-II was performed and a focused scope peer review and F&O closure were performed which confirmed the CC-II status of the SRs and verified all F&Os are closed. (Reference 21and Reference 51).

The Oconee Nuclear Station (ONS) Focused Internal Flooding PRA (IFPRA) Peer Review was performed in January 2013 at Duke Energy headquarters in Charlotte, NC, using the NEI 05-04 process and the ASME PRA Standard ASME/ANS RA-Sa-2009, along with the NRC clarifications provided in Regulatory Guide 1.200, Rev. 2 (Reference 21).

The peer review determined all SRs were met at CC-II or above. Peer review F&Os were resolved and incorporated into the model, and an F&O closure review was performed which confirmed all findings are closed (Reference 21 and Reference 51).

Fire PRA A full-scope peer review to determine compliance with Addendum A of the ASME/ANS PRA Standard and RG 1.200, Revision 2 was performed on the ONS fire PRA by the Pressurized Water Reactors Owners Group in 2012. In 2014, after updating the ONS fire PRA to address selected facts and observations (F&O) identified in the full-scope fire PRA peer review, an F&O closure review was held in 2019 which resulted in most of the F&Os being closed. After additional resolution work was incorporated into the Fire PRA, another closure review was performed in 2020 which closed the remaining F&Os. During this closure review, a focused

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 29 of 126 scope peer review was performed which resulted in two new finding level (and two suggestion)

F&Os. The F&Os were resolved, incorporated into the Fire PRA model, and confirmed closed via another F&O closure review (Reference 51). All SRs are MET at CC-II or higher and there are no open finding F&Os.

Seismic PRA Duke Energy conducted a full scope Seismic PRA model peer review in June 2018, against the requirements of the case for ASME/ANS RA-Sb-2013, from now on referenced as the seismic Code Case, as amended by the Nuclear Regulatory Commission (NRC) on March 12, 2018.

Subsequently, work was completed to resolve the F&Os which was incorporated into the SPRA.

An F&O closure review was performed on select F&Os. Several F&Os were confirmed closed, while others were partially closed with documentation updates required, and other F&Os that were not reviewed by the closure team (Reference 21).

The 25 finding F&Os that remain open are described and dispositioned in Attachment 2, Evaluation of Risk Significance of Permanent ILRT Extension, Seismic PRA F&Os, of this submittal.

PRA Maintenance and Update The Duke risk management process ensures that the applicable PRA models used in this application continue to reflect the as-built and as-operated plant for each of the ONS units. The process delineates the responsibilities and guidelines for updating the PRA model and includes criteria for both regularly scheduled and interim PRA model updates. The process includes provisions for monitoring potential areas affecting the PRA model (e.g., due to changes in the plant, errors or limitations identified in the model, industry operational experience) for assessing the risk impact of unincorporated changes, and for controlling the model and associated computer files. The process will assess the impact of these changes on the plant PRA model in a timely manner.

3.3.3 Summary of Plant-Specific Risk Assessment Results The findings of the ONS risk assessment confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three-in-ten years to 1-in-15 years is small.

Based on the results of the ONS risk assessment 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:

x Regulatory Guide 1.174 (Reference 39) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. Regulatory Guide 1.174 defines very small changes in risk as resulting in increases of CDF less than 1.0E-06/year and increases in LERF less than 1.0E-07/yr. 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 8.35E-08/year, 7.82E-08/year, and 7.89E-08/year for units 1, 2, and 3 using the EPRI guidance.

Therefore, the estimated change in LERF is determined to be very small using the

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 30 of 126 acceptance guidelines of Regulatory Guide 1.174. The risk change resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years bounds the 1 in 10 years to 1 in 15 years risk change. Considering the increase in LERF resulting from a change in the Type A ILRT test interval from 1 in 10 years to 1 in 15 years is estimated as 3.48E-08/year, 3.26E-08/year, and 3.29E-08/yr for units 1, 2, and 3, the risk increase is very small using the acceptance guidelines of Regulatory Guide 1.174 x

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 9.96E-07/year, 9.73E-07/year, and 8.93E-07/year for units 1, 2, and 3 using the EPRI guidance, and total LERF is 4.62E-06/year, 5.87E-06/year, and 5.04E-06/year for units 1, 2, and 3. As such, the estimated change in LERF is determined to be small using the acceptance guidelines of Regulatory Guide 1.174. The risk change resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years bounds the 1 in 10 years to 1 in 15 years risk change. When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 1 in 10 years to 1 in 15 years is estimated as 4.15E-07/year, 4.06E-07/year, and 3.72E-07/year and the total LERF is 4.04E-06/year, 5.30E-06/year, and 4.52E-06/year for units 1, 2, and 3. Therefore, the risk increase is small using the acceptance guidelines of Regulatory Guide 1.174 x

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 0.0076 person-rem/year, 0.0071 person-rem/year, and 0.0072 person-rem/year for units 1, 2, and 3. NEI 94-01 (Reference 2) states that a

³VPDOO'SRSXODWLRQGRVHLVGHILQHGDVDQLQFUHDVHRISHUVRQ-UHPSHU\HDURU

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.

x The increase in the conditional containment failure probability (CCFP) from the 3 in 10-year interval to 1 in 15-year interval is 0.89% for each unit. NEI 94-01 (Reference 2) states WKDWLQFUHDVHVLQ&&)3RILV³VPDOO' Therefore, this increase is judged to be small.

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

3.3.4 Previous Assessments The NRC in NUREG-1493 (Reference 6) has previously concluded that:

x 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 31 of 126 x

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

3.3.5 RG 1.174 Revision 3 Defense-in-Depth Evaluation RG 1.174, Revision 3 (Reference 39), describes an approach that is acceptable for developing risk-informed 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 ONS.

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 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 ONS 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 Integrated Leakage Rate Test (ILRT) from 10 years to 15 years and Type C Local Leakage Rate Tests (LLRTs) for selected components from 60-months to 75-months.

As shown in NUREG-1493 (Reference 6), 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 32 of 126 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 ONS containment pressure boundary. RG 1.163 Revision 1 and NEI 94-01 Revision 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. 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, BWR main steam and feedwater isolation 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 ONS post-outage report(s). Therefore, the proposed change does not challenge or limit the layers of defense available to assess the ability of the ONS containment structure to perform its safety function.

PRA Response:

The use of the risk metrics of LERF, population dose, and CCFP collectively ensures the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. The change in LERF is small with respect to internal events and small 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 38),

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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 33 of 126 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 defined in the response to Question 1 above, which are required when adopting NEI 94-01, Revision 3-A. These factors are conservative in nature and are designed to generate corrective actions if the required testing or inspections are deemed 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 ONS containment pressure boundary will perform its intended safety function. Since the proposed change does not alter the configuration of the ONS 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 34 of 126

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 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, ONS will be required to adopt the performance-based testing standards outlined in RG 1.163 Revision 1 and 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 35 of 126 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 require 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. 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.

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, ONS will be required to adopt the performance-based testing standards outlined in RG 1.163 Revision 1 and NEI 94-01, Revision 3-A along with 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 36 of 126 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% and 40% 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 require 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 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 testing 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 37 of 126 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 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, ONS will be required to adopt the performance-based testing standards outlined in RG 1.163 Revision 1 and NEI 94-01, Revision 3-A along with ANSI/ANS 56.8-2020. The leakage limits imposed by plant TS remain unchanged when adopting the performance-based testing standards outlined in RG 1.163 Revision 1, NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2020. Plant design limits imposed by the Updated Final Safety Analysis Report (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 ONS 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, ONS has assessed other non-risk-based considerations relevant to the proposed amendment. ONS has multiple inspection and testing programs that ensure the containment structure continues to remain capable of meeting its design functions and is designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

3.4.1 Nuclear Coatings Program Coating Materials The original coating materials applied to all structures within the containment during plant construction were qualified by withstanding autoclave tests designed to simulate LOCA conditions. The qualification testing of Service Level I substitute coatings now used for new applications or repair/replacement activities inside containment was in accordance with ANSI N 101.2 for LOCA conditions and radiation tolerance. The substitute coatings when used for

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 38 of 126 maintenance over the original coatings were tested, with appropriate documentation, to demonstrate a qualified coating system.

The original, maintenance, and new coating systems defining surface preparation, type of coating, and dry film thickness are tabulated in the UFSAR.

The elements of the ONS Coatings Program are documented in a Nuclear Generation Department Directive. The ONS Coatings Program includes periodic condition assessments of Service Level I coatings used inside containment. As localized areas of degraded coatings are identified, those areas are evaluated for repair or replacement, as necessary.

ONS has performed all GL 2004-02 required analyses and evaluations in accordance with the approved methodology. As a result of these evaluations, ONS made a number of plant modifications and programmatic enhancements, such as:

Enhancement of plant containment coatings program to ensure that degraded coatings identified from maintenance inspections are evaluated for potential effects on Reactor Building Emergency Sump (RBES) evaluations.

ONS Nuclear Coatings Program The Nuclear Coatings Program (NCP) provides a standardized method of selecting, procuring, applying, maintaining, and periodically assessing coatings so they can be used to minimize the adverse impacts of degraded (i.e., detached) coatings on Systems, Structures and Components (SSCs), minimize material degradation of SSCs, facilitate decontamination of SSCs, and satisfy licensing and regulatory commitments.

Service Level I Coatings are applied to exposed surface areas inside the reactor containment where coating failure (i.e., detachment) could adversely affect the operation of post-accident fluid systems and, thereby, impair safe shutdown. Systems, which could be impacted by detached coatings, include the ECCS and the Containment Spray system. Therefore, coating systems used within the reactor containment are required to be Qualified Coating Systems.

Primary Containment Coatings Condition Assessment Primary Containment Coatings Condition Assessment is used to assess and document the condition of in-service Service Level I coatings.

x Condition assessments of Service Level I coatings used inside containment are performed during each refueling outage.

x As localized areas of degraded coatings are identified, the areas are evaluated and scheduled for repair or replacement.

x The periodic condition assessments and the resulting repair and replacement activities, provide reasonable assurance the amount of Service Level I coatings that may be susceptible to detachment from the substrate and travel to the Emergency Core Cooling System (ECCS) sump during a Loss of Coolant Accident (LOCA) event is minimized.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 39 of 126 Containment Unqualified Coatings ONS routinely conducts condition assessment walkdowns of both qualified and unqualified protective coatings inside the containment. These coating condition assessments are conducted as part of ONSs periodic maintenance program that requires a coating assessment walkdown every refueling outage. Typically, these Containment walkdowns encompass 100% inspections of all concrete and steel surfaces by elevation. Any localized areas of degraded coatings identified are evaluated and scheduled for repair or recoating as necessary. These periodic condition assessments and any resulting repair or recoating activities help ensure that the amount of containment protective coatings susceptible to detachment during a LOCA is minimized.

Refueling Outage Unqualified Coatings Quantity Summary The trend data, as identified below, shows that the amount of new degraded coating inside containment has not changed significantly in the last several years. The amount of degraded coating and exposed zinc are well below the allowable degraded coating for the sump.

Summary of O1R33 Coating Activities - 11/5/2024 Approximately 1354 sq ft of degraded coating remains inside containment at the end of O1R33.

Approximately 10087 sq ft of exposed zinc remains inside containment at the end of O1R33.

Approximately 0 sq ft of new degraded coating was identified and 0 sq ft was remediated during O1R33.

These values are well within the ECCS margin.

Summary of O2R31 Coating Activities - 11/20/23 Approximately 3560 sq ft of degraded coating remains inside containment at the end of O2R31.

Approximately 3003 sq ft of exposed zinc remains inside containment at the end of O2R31.

Approximately 0 sq ft of new degraded coating was identified and 37 sq ft was remediated.

These values are well within the ECCS margin.

Summary of O3R32 Coating Activities - 5/21/2024 Approximately 3134 sq ft of degraded coating remains inside containment at the end of O3R32.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 40 of 126 Approximately 1291 sq ft of exposed zinc remains inside containment at the end of O3R32.

Approximately 69 sq ft of new degraded coating was identified and 90 sq ft was remediated.

These values are well within the ECCS margin.

3.4.2 Containment Inservice Inspection (CISI) Program Scope This document details the Inservice Inspection (ISI) Plan for the 6th Inspection Interval for Oconee Nuclear Station (ONS) Units 1, 2, and 3. All further references to Oconee (ONS) in this document are understood to include Oconee Unit 1 (ONS1), Oconee Unit 2 (ONS2), and Oconee Unit 3 (ONS3). This document shall be referred to as the ISI Plan.

The ONS ISI Plan provides requirements for examination, testing, and inspection of Class 1, 2, and 3, MC, and CC pressure retaining components and systems, and their supports. This Plan was prepared in accordance with Fleet Procedure "ASME Section XI Plan Development" and "ASME Section XI Inservice Inspection Program Administration" which provides guidance in developing the ISI Plan when implementing an American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code,Section XI ISI Program (ASME Section XI).

The scope of this document includes the Containment ISI (CISI) Program and Pressure Testing ISI Program, but does not include the Augmented ISI Program, Appendix J Program, Inservice Testing of Pumps and Valves (IST), Snubber Functional Testing Program, or the Steam Generator Tubing Program. These are described in the respective standalone program documents.

Purpose The purpose of this document is to dictate the 6th Interval ISI Plan for ONS Units 1, 2, and 3.

Based on a 6th Interval start date of July 15, 2024 for ONS1, ONS2, and ONS3 and the requirements of 10CFR50.55a(g)(4)(ii), inservice inspection activities for Oconee shall be performed in accordance with the 2019 Edition of ASME Section XI, as modified by the 10CFR50.55a Conditions, ASME Section XI Code Cases, and Relief Requests included in this Inservice Inspection Plan. Based on the start date of July 15, 2024, the 4th interval Containment Inservice Inspection (CISI) of ISI Class MC metal containments and ISI Class CC concrete containment at Oconee Units 1, 2, and 3 will also be performed in accordance with the 2019 Edition, as modified by the 10CFR50.55a Conditions, ASME Section XI Code Cases, and Relief Requests included in this ISI Plan.

First And Second Containment Inservice Inspection Interval Effective September 9, 1996 the NRC amended 10CFR50.55a to incorporate by reference the 1992 Edition with the 1992 Addenda of the ASME BPV Code,Section XI Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Concrete Components of Light Water Cooled Power Plants, and Subsection IWL, Requirements for Class CC Concrete

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 41 of 126 Components of Light Water Cooled Power Plants, of Section XI, Division I of the ASME Code with specified modifications and limitations. These Subsections outline the requirements for inservice inspection of Class CC (concrete containments) and Class MC (metal containments and metallic shell and penetration liners of concrete containments). Licensees were required to incorporate Subsection IWE and Subsection IWL into their inservice inspection program and were required to expedite implementation of the containment examinations within 5 years of the effective date (September 9, 2001).

The First CISI Interval began on September 9, 1998 and was scheduled to end on September 9, 2008 in order to implement expedited implementation requirements imposed by 10CFR50.55a following September 9, 1996. Duke Energy chose to establish the new inspection intervals for CISI so that the end of the first period of the First CISI Interval coincided with the end of the expedited examination period on September 9, 2001. The First Interval ClSI Plan was written to meet the requirements of the 1992 Edition with the 1992 Addenda of the ASME BPV Code,Section XI. ONS proposed Relief Request 03-GO-010 to modify the interval dates of the First CISI Interval. This permitted the subsequent ISI and CISI Programs to share a common inspection interval start and end date and to implement common Code Editions for ISI Class 1, 2, 3, MC, and CC components. The First ClSI Interval ended on July 15, 2004 for ONS Units 1, 2, and 3. The Second Interval ClSI Plan was written to meet the requirements of the 1998 Edition with the 2000 Addenda of the ASME BPV Code,Section XI and started on July 15, 2004 and ended on July 15, 2014.

Third Containment Inservice Inspection Interval The Third ClSI Interval started on July 15, 2014, and ended on July 14, 2024 for ONS Units 1, 2, and 3. The Third Interval ClSI Plan was written to meet the requirements of the 2007 Edition with the 2008 Addenda of the ASME BPV Code,Section XI.

Applicable Editions and Addenda to ASME Section XI In accordance with the requirements of Paragraphs 10CFR50.55a(g)(4)(ii), the inservice inspection of ONS Units 1, 2, and 3 shall be performed in accordance with the 2019 Edition of ASME Section XI hereafter referred to asSection XI, subject to conditions identified below:

Code of Federal Regulations 10CFR50.55a Conditions The following mandatory and optional Code of Federal Regulations Conditions and Augmented Examination Requirements are included in 10CFR50.55a as published on October 27, 2022 (87 FR 65148). Only those 10CFR50.55a conditions applicable to the 2019 Edition of Section XI nondestructive examination requirements for Class MC components and component supports are listed. These conditions were reviewed for inclusion in the ISI Plan per procedure AD-EG-ALL-1701 and dispositioned as follows:

10CFR50.55a(b)(2)(viii) - Concrete containment examinations Applicants or licensees applying Subsection IWL, 2007 Edition with the 2009 Addenda through the latest edition and addenda incorporated by reference in 10CFR50.55a(a)(1)(ii), must apply

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 42 of 126 paragraphs (b)(2)(viii)(H) and (I).

10CFR50.55a(b)(2)(viii)(H) - Concrete containment examinations: Eighth provision. For each inaccessible area of concrete identified for evaluation under IWL-2512(a) or identified as susceptible to deterioration under IWL-2512(b), the licensee must provide the applicable information specified in 10CFR50.55a(b)(2)(viii)(E)(1), (2), and (3) in the ISI Summary Report required by IWA-6000.

10CFR50.55a(b)(2)(viii)(I) - Concrete containment examinations: Ninth provision. During the period of extended operation of a renewed license under part 54 of this chapter, the licensee must perform the technical evaluation under IWL-2512(b) of inaccessible below-grade concrete surfaces exposed to foundation soil, backfill, or groundwater at periodic intervals not to exceed 5 years. In addition, the licensee must examine representative samples of the exposed portions of the below-grade concrete, when such below-grade concrete is excavated for any reason.

ONS will implement the requirements in 10CFR50.55a(b)(2)(viii)(H) and (b)(2)(viii)(I), for the examination of concrete containments.Section XI, Subsection IWL requirements are addressed in this ISI Program Plan.

10CFR50.55a(b)(2)(ix) - Metal Containment Examinations ONS is applying Subsection IWE, 2019 Edition, therefore ONS will satisfy the requirements of paragraphs (b)(2)(ix)(A)(2) and (b)(2)(ix)(B) and (J).

10CFR50.55a(b)(2)(ix)(A)(2) - Metal containment examinations: For each inaccessible area identified for evaluation, the applicant or licensee must provide the following in the ISI Summary Report as required by IWA-6000:

(i)

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

An evaluation of each area, and the result of the evaluation; and (iii)

A description of necessary corrective actions.

ONS will implement the requirements in 10CFR50.55a(b)(2)(ix)(A)(2) for the examination of metal containments and the liners of concrete containments.Section XI, Subsection IWE requirements are addressed in this ISI Plan.

10CFR50.55a(b)(2)(ix)(B) - Metal containment examinations: Second provision. When performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2211-1 (2005 Addenda through the latest edition and addenda incorporated by reference in 10CFR50.55a(a)(1)) may be extended and the minimum illumination requirements specified 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.

ONS will implement the requirements in 10CFR50.55a(b)(2)(ix)(B) for the examination of metal containments and the liners of concrete containments.Section XI, Subsection IWE

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 43 of 126 requirements are addressed in this ISI Plan.

10CFR50.55a(b)(2)(ix)(J) - Metal containment examinations: Tenth provision.

The requirements for performing metal containment repair/replacement as stated in 10CFR50.55a(b)(2)(ix)(J) are not addressed in the ONS ISI Plan. Repair and Replacement activities are addressed in Fleet Procedures and applicable Station Procedures.

Subsection IWE for Class MC and Metallic Liners of Class CC Components Examination Categories and Requirements This section of the ISI Plan outlines the examination that apply to ASME Class MC pressure-retaining components and their integral attachments and to metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments at ONS. Although there are no Class MC components at Oconee, the term Class MC may be used throughout this inspection plan to refer to containment metallic shells and penetration liners of Class CC components, which are subject to the inservice inspection, and repair/replacement requirements of Subsection IWE, as well as conditions imposed by 10CFR50.55a(b)(2)(ix).

The examination categories to be used are those listed in Table IWE-2500-1 of Section XI Specific examinations shall be identified by an Item Number listed in Table IWE-2500-1 of Section XI along with a unique component identifier.

The inservice inspection of ASME Class MC components shall be performed in accordance with the requirements of Article IWE-2000 of Section XI. Class MC examinations were scheduled as applicable for the 4th CISI Interval in accordance with Table IWE-2500-1 and Table IWE-2411-1 (used for Item E1.32 only), as shown below.

Table 3.4.2-1, IWE-2411-1 Inspection Interval Inspection Period Minimum Examinations Completed, %

Maximum Examinations Credited, %

4th 1

16 50 2

50(1) 75 3

100 100 Notes:

1.

If the first period completion percentage for any examination category exceeds 34%, at least 16% of the required examinations shall be performed in the second period.

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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 44 of 126 Subsection IWE does not specify requirements for periodic pressure testing of containment.

Containment pressure testing shall be performed in accordance with the provisions of IWE-5000, 10CFR50.55a(b)(2)(ix)(J), and Title 10, Part 50 of the Code of Federal Regulations, Appendix J. The Containment Inservice Inspection Plan does contain requirements for periodic pressure testing. Requirements for containment system pressure tests following repair/replacement activities are specified in AD-EG-ALL-1703, ASME Section XI Repair/Replacement Program Administration.

The following sections detail the Class MC components to be inspected for ONS Units 1, 2, and

3.

Category E-A, Containment Surfaces As required by IWE-2411(a), examinations in Category E-A Containment Surfaces shall be completed in accordance with the requirements of Table IWE-2500-1 and Table IWE-2411-1.

Table 3.4.2-2, Category E-A Containment Surfaces IWE-2500-1 Item No.

Component To Be Examined Comments E1.10 Containment Vessel Pressure-Retaining Boundary E1.11 Accessible Surface Areas General Visual, 100% each Inspection Period E1.12 Wetted Surfaces of Submerged Areas NA for Oconee 1, 2, & 3 E1.20 BWR Vent System Accessible Surface Areas NA for Oconee 1, 2, & 3 E1.30 Moisture Barriers E1.31 Accessible caulking, flashing, and sealants General Visual, 100% each Inspection Period E1.32 Accessible Leak Chase Channel System Closures Not Deferrable.

General Visual, 100% each Inspection Interval.

Table 3.4.2-3 Unit 1 Table E-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E1.11(1)

Accessible Surface Areas 14 14 14 14

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 45 of 126 Table 3.4.2-3 Unit 1 Table E-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E1.31 Accessible caulking, flashing, and sealants 4

4 4

4 E1.32(3)

Accessible Leak Chase Channel System Closures 1

1 0

0 Totals 19 19 18 18 Cumulative Interval Percentages(2) 100%

100%

100%

Notes:

1.

If this examination is to be credited towards satisfying the examinations required by 10CFR50, Appendix J, the examination shall be performed during the refueling outage during which a Type A test is to be performed, just prior to the start of the Type A test.

Duke Energy Corporation intends to credit Item E1.11 visual exams towards satisfying the requirements of 10CFR50, Appendix J.

2.

Cumulative Percentages exclude the examinations performed once a period.

3.

Conservatively, 100% of the Leak Chase Channels will be examined each inspection

period, Table 3.4.2-4 Unit 2 Table E-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E1.11(1)

Accessible Surface Areas 14 14 14 14 E1.31 Accessible caulking, flashing, and sealants 4

4 4

4 E1.32(3)

Accessible Leak Chase Channel System Closures 1

1 0

0 Totals 19 19 18 18 Cumulative Interval Percentages(2) 100%

100%

100%

Notes:

1.

If this examination is to be credited towards satisfying the examinations required by 10CFR50, Appendix J, the examination shall be performed during the refueling outage

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 46 of 126 during which a Type A test is to be performed, just prior to the start of the Type A test.

Duke Energy Corporation intends to credit Item E1.11 visual exams towards satisfying the requirements of 10CFR50, Appendix J.

2.

Cumulative Percentages exclude the examinations performed once a period.

3.

Conservatively, 100% of the Leak Chase Channels will be examined each inspection period, but only the first period examinations are credited in the table.

Table 3.4.2-5 Unit 3 Table E-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E1.11(1)

Accessible Surface Areas 14 14 14 14 E1.31 Accessible caulking, flashing, and sealants 4

4 4

4 E1.32(3)

Accessible Leak Chase Channel System Closures 1

1 0

0 Totals 19 19 18 18 Cumulative Interval Percentages(2) 100%

100%

100%

Notes:

1.

If this examination is to be credited towards satisfying the examinations required by 10CFR50 Type A test is to be performed, just prior to the start of the Type A test. Duke Energy Corporation intends to credit Item E1.11 visual exams towards satisfying the requirements of 10CFR50, Appendix J.

2.

Cumulative Percentages exclude the examinations performed once a period.

3.

Conservatively, 100% of the Leak Chase Channels will be examined each inspection period, but only the first period examinations are credited in the table.

Category E-C, Containment Surfaces Requiring Augmented Examination Containment surface areas requiring augmented examination are those identified in IWE-1240.

Methods for augmented examination of surface areas identified in IWE-1242 shall comply with the criteria in IWE-2500(b).

The containment sections of the ONS ISI Basis Document discuss the containment design and components. Metal containment surface areas subject to accelerated degradation and aging require augmented examination per Examination Category E-C, Item Numbers E4.11 and E4.12, and Paragraph IWE-1240.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 47 of 126 Table 3.4.2-6 Examination Category E-C IWE-2500-1 Item No.

Component To Be Examined Comments E4.10 Containment Surface Areas E4.11 Visible Surfaces Not Deferrable.

VT-1 Visual, 100% Each Period.

E4.12 Surface Area Grid Minimum Wall Thickness Locations Not Deferrable.

Volumetric, Ultrasonic Thickness Measurement 100% Each Inspection Period.

Table 3.4.2-7 Unit 1 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E4.11 Visible Surfaces 0

0 0

0 E4.12 Surface Area Grid Minimum Wall Thickness Locations 0

0 0

0 Totals 0

0 0

0 Cumulative Interval Percentages 0%

0%

0%

Table 3.4.2-8 Unit 2 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E4.11 Visible Surfaces 0

0 0

0 E4.12 Surface Area Grid Minimum Wall Thickness Locations 0

0 0

0

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 48 of 126 Table 3.4.2-8 Unit 2 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

Totals 0

0 0

0 Cumulative Interval Percentages 0%

0%

0%

Table 3.4.2-9 Unit 3 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E4.11 Visible Surfaces 0

0 0

0 E4.12 Surface Area Grid Minimum Wall Thickness Locations 0

0 0

0 Totals 0

0 0

0 Cumulative Interval Percentages 0%

0%

0%

Category E-G, Pressure Retaining Bolting Examination Category E-G of the ASME BPV Code,Section XI, 2019 Edition requires 100% of each bolted connection on the containment vessel to be examined once each inspection interval.

Table 3.4.2-10, Table E-G IWE-2500-1 Item No.

Component To Be Examined Comments E8.10 Bolted Connections Deferrable to End of Interval

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 49 of 126 Table 3.4.2-11, Unit 1 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E8.10 Bolted Connections 132 47 40 45 Totals 132 47 40 45 Cumulative Interval Percentages 35.6%

65.9%

100%

Table 3.4.2-12, Unit 2 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E8.10 Bolted Connections 132 43 43 46 Totals 132 43 43 46 Cumulative Interval Percentages 32.6%

65.2%

100%

Table 3.4.2-13, Unit 3 Table E-C Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 3

E8.10 Bolted Connections 131 42 47 42 Totals 131 42 47 42 Cumulative Interval Percentages 32.1%

67.9%

100%

Subsection IWL for Class CC Concrete Components This program outlines the requirements for the inservice inspection of ASME Class CC (concrete containment) at ONS. The inservice inspection of ASME Class CC Items shall be performed in accordance with the requirements of Article IWL-2000 of ASME Section XI as well as conditions imposed by 10CFR50.55a(b)(2)(viii).

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 50 of 126 The examination categories to be used are those listed in Table IWL-2500-1 of Section XI. In the ISI Database, specific examinations shall be identified by an Item Number listed in Table IWL-2500-1 of Section XI along with a unique component identifier.

ASME Section XI Subsection IWL requires the Responsible Engineer to be involved in the development, approval, and review of the CISI examinations. The Responsible Engineer assigned to perform these duties shall meet the requirements of ASME Section XI, Paragraph IWL-2330. The personnel performing general or detailed visual examinations approved by the Responsible Engineer shall meet the requirements of IWL-2320.

The Responsible Engineer designated by Oconee Nuclear Station is Adam T. Johnson, P.E.

Oconee reserves the right to designate more than one Responsible Engineer, without requiring revision to this Containment Inservice Inspection Plan. Contractors meeting the qualification requirements of IWL-2320 may also be utilized to perform all, or part, of the duties specified above.

Category L-A, Concrete Examination Category L-A, Item Number L1.11 requires all accessible surface areas to be examined per IWL-2510 and at a frequency defined in IWL-2410. IWL-2511(a) requires concrete surface areas, including coated areas, except those exempted by IWL-1220(b) through IWL-1220(d), to be visually examined in accordance with IWL-2310(a) for evidence of conditions indicative of damage or degradation. IWL-2410 requires this visual examination to be completed at five-year intervals (after the 1-, 3-, and 5-years interval following the Structural Integrity Test).

Table 3.4.2-14, IWL-2500-1 IWL-2500-1 Item No.

Component To Be Examined Comments L1.10 Concrete Surface See Note 1 L1.11 All accessible surface areas General Visual Examination (See Note 2)

L1.12 Suspect areas Detailed Visual Examination (See Note 2)

L1.13 Inaccessible Below-Grade Areas See IWL-2512(c)

Notes:

1.

Examination shall include 100% of accessible tendon grease caps per IWL-2511(c).

2.

General and Detailed Visual examinations shall be performed by personnel with valid VT-3 (Concrete Containment Surfaces) and VT-1 (Concrete Containment Surfaces) certifications, respectively.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 51 of 126 Table 3.4.2-15, Unit 1 Table L-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 L1.11(1)

All accessible surface areas 24 24 24 L1.12 Suspect areas 0

0 0

L1.13(2)

Inaccessible Below-Grade Areas 0

0 0

Totals 24 24 24 Cumulative Interval Percentages(3) 100%

100%

Notes:

1.

Includes concrete surfaces at tendon anchorage areas not selected by IWL-2521 or exempted by IWL-1220(a) or IWL-1220(d).

2.

Concrete surfaces exposed to foundation soil, backfill, or ground water. Method of examination as defined by the Responsible Engineer, based on IWL-2512(b) evaluation.

3.

Cumulative Percentages are calculated on a periodic basis.

Table 3.4.2-16, Unit 2 Table L-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 L1.11(1)

All accessible surface areas 24 24 24 L1.12 Suspect areas 0

0 0

L1.13(2)

Inaccessible Below-Grade Areas 0

0 0

Totals 24 24 24 Cumulative Interval Percentages(3) 100%

100%

Notes:

1.

Includes concrete surfaces at tendon anchorage areas not selected by IWL-2521 or exempted by IWL-1220(a) or IWL-1220(d).

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 52 of 126

2.

Concrete surfaces exposed to foundation soil, backfill, or ground water. Method of examination as defined by the Responsible Engineer, based on IWL-2512(b) evaluation.

3.

Cumulative Percentages are calculated on a periodic basis.

Table 3.4.2-17, Unit 3 Table L-A Item Numbers Parts Examined Number of Components Number Scheduled by Period 1

2 L1.11(1)

All accessible surface areas 24 24 24 L1.12 Suspect areas 0

0 0

L1.13(2)

Inaccessible Below-Grade Areas 0

0 0

Totals 24 24 24 Cumulative Interval Percentages(3) 100%

100%

Notes:

1.

Includes concrete surfaces at tendon anchorage areas not selected by IWL-2521 or exempted by IWL-1220(a) or IWL-1220(d).

2.

Concrete surfaces exposed to foundation soil, backfill, or ground water. Method of examination as defined by the Responsible Engineer, based on IWL-2512(b) evaluation.

3.

Cumulative Percentages are calculated on a periodic basis.

Category L-B, Unbonded Post-Tensioning System In addition to visual inspection methods, the following inspection methods are required for examination of the post-tensioning tendons performed in accordance with IWL. See NCR 02436929 for OE related to completion of post-tensioning examinations.

1.

The prestressing force in inspection sample tendons will be performed by force measurement (Lift-off testing).

2.

Tension tests will be performed on wires removed from detensioned sample tendons to determine yield strength, ultimate tensile strength, and elongation.

3.

Corrosion protection medium and free water (if present) of sample tendons will be analyzed in accordance with IWL-2525.2.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 53 of 126 Table 3.4.2-18, IWL-2500-1 IWL-2500-1 Item No.

Component To Be Examined Comments (See Note 1)

L2.10 Tendon Tendon Force Measurement L2.20 Wire or strand Visual Examination and Tension Tests L2.30 Anchorage hardware and surrounding concrete Detailed Visual Examination (See Note 2)

L2.40 Corrosion protection medium Chemical Analysis L2.50 Free water pH Notes:

1.

The schedule for performing these examinations is modified by Relief Request RA 0418.

2.

Detailed Visual examinations shall be performed by personnel with valid VT-1 (Concrete Containment Surfaces) certifications.

IWL-2421 specifies alternative requirements that may be used when selecting post-tensioning system components for examination. These requirements are provided for multi-plant sites, such as Oconee. The provisions of IWL-2421 require that the same number of tendons must be selected for examination every 5-years but uses an alternate schedule for performing these examinations. The alternative schedule is also modified by approval of Relief Request RA 0418 such that all of the examinations required using the IWL-2421 alternative will be performed once every ten years on each unit. Note that examinations required by Table IWL-2500-1 (L-A) will continue to be performed in accordance with the schedule specified in IWL-2410.

Duke Energy will comply with the alternative sampling provisions of IWL-2421 (as modified by Relief Request RA-19-0418) using a 2% sample size (3 Minimum/5 Maximum) of each tendon type (dome, hoop, vertical) for the 4th CISI Interval since the requirement of Table IWL-2521-1, Note 2 has been met for each Oconee Unit.

The examination and testing of at least one end of one buried hoop tendon is performed during each tendon surveillance. During each surveillance, at least one end of one buried tendon shall be selected for IWL-2522, -2524, -2525, and -2526 examinations. If the random tendon selection does not include one of these tendons, then one shall be added to the selection sample and shall be considered Owner Specified (not required by Subsection IWL, since the selection of the tendon would be above and beyond that required by IWL). Tendons that are selected as Owner Specified shall be identified in the ONS Units 1, 2, and 3 ISI Schedules.

The number of tendons required to be examined as specified in Table IWL-2521-1 are shown in the tables below.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 54 of 126 Table 3.4.2-19, Unit 1 Table L-B Item Numbers Parts Examined Number of Components Minimum Number Scheduled by Period(5) 1 (55th Year) 2 (60th Year)

L2.10(1)(2)

Tendon 162 (Dome) 592 (Hoop) 135 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical) 4 (Dome) 5 (Hoop) 3 (Vertical)

L2.20(4)

Wire or strand 0 (Dome) 0 (Hoop) 0 (Vertical) 1 (Dome) 1 (Hoop) 1 (Vertical)

L2.30(3)

Anchorage hardware and surrounding concrete 0 (Dome) 0 (Hoop) 0 (Vertical) 8 (Dome) 10 (Hoop) 6 (Vertical)

L2.40(3)

Corrosion protection medium 0 (Dome) 0 (Hoop) 0 (Vertical) 8 (Dome) 10 (Hoop) 6 (Vertical)

L2.50(3)

Free water 0 (Dome) 0 (Hoop) 0 (Vertical) 8 (Dome) 10 (Hoop) 6 (Vertical)

Notes:

1.

Per IWL-2521(d), the total population of hoop and vertical tendons from which the Table IWL-2521-1 sample sizes should be selected may be reduced by the number of tendons affected by repair/replacement as required by IWL-2521.2. There are 632 hoop tendons, of which 40 of those hoop tendons are affected by repair/replacement. There are 176 vertical tendons, of which 41 of those vertical tendons are affected by repair/replacement.

2.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-1, Note 2 has been met for each Oconee Unit. Therefore, 4 (2% of 162

= 3.24) dome tendons, 5 (2% of 591 = 11.82, maximum of 5) hoop tendons, and 3 (2%

of 135 = 2.7) vertical tendons are required to be selected.

3.

IWL-2524 and IWL-2525 examinations that were required at 55 years (Unit 1) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 50 and 60 (Unit 1). This is an approved alternative via Relief Request RA-19-0418.

4.

Of the required tendons to be examined, only one tendon wire sample is required from one tendon of each type.

5.

During the random tendon selection process, alternate tendons may need to be selected which could result in additional tendon examinations. See the Unit 1 Random Tendon Selection and Required Examinations table at the end of this section.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 55 of 126 Table 3.4.2-20, Unit 2 Table L-B Item Numbers Parts Examined Number of Components Minimum Number Scheduled by Period(5) 1 (55th Year) 2 (60th Year)

L2.10(1)(2)

Tendon 162 (Dome) 592 (Hoop) 134 (Vertical) 4 (Dome) 5 (Hoop) 3 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.20(4)

Wire or strand 1 (Dome) 1 (Hoop) 1 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.30(3)

Anchorage hardware and surrounding concrete 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.40(3)

Corrosion protection medium 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.50(3)

Free water 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

Notes:

1.

Per IWL-2521(d), the total population of hoop and vertical tendons from which the Table IWL-2521-1 sample sizes should be selected may be reduced by the number of tendons affected by repair/replacement as required by IWL-2521.2. There are 632 hoop tendons, of which 40 of those hoop tendons are affected by repair/replacement. There are 176 vertical tendons, of which 42 of those vertical tendons are affected by repair/replacement.

2.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-1, Note 2 has been met for each Oconee Unit. Therefore, 4 (2% of 162

= 3.24) dome tendons, 5 (2% of 592 = 11.84, maximum of 5) hoop tendons, and 3 (2%

of 134 = 2.68) vertical tendons are required to be selected.

3.

IWL-2524 and IWL-2525 examinations that were required at 50 years (Units 2 and 3) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 55 for Units 2 and 3. This is an approved alternative via Relief Request RA-19-0418.

4.

Of the required tendons to be examined, only one tendon wire or strand sample is required from one tendon of each type.

5.

During the random tendon selection process, alternate tendons may need to be selected which could result in additional tendon examinations. See the Unit 2 Random Tendon Selection and Required Examinations table at the end of this section.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 56 of 126 Table 3.4.2-21, Unit 3 Table L-B Item Numbers Parts Examined Number of Components Minimum Number Scheduled by Period(5) 1 (55th Year) 2 (60th Year)

L2.10(1)(2)

Tendon 162 (Dome) 592 (Hoop) 136 (Vertical) 4 (Dome) 5 (Hoop) 3 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.20(4)

Wire or strand 1 (Dome) 1 (Hoop) 1 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.30(3)

Anchorage hardware and surrounding concrete 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.40(3)

Corrosion protection medium 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

L2.50(3)

Free water 8 (Dome) 10 (Hoop) 6 (Vertical) 0 (Dome) 0 (Hoop) 0 (Vertical)

Notes:

1.

Per IWL-2521(d), the total population of hoop and vertical tendons from which the Table IWL-2521-1 sample sizes should be selected may be reduced by the number of tendons affected by repair/replacement as required by IWL-2521.2. There are 632 hoop tendons, of which 40 of those hoop tendons are affected by repair/replacement. There are 176 vertical tendons, of which 40 of those vertical tendons are affected by repair/replacement.

2.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-1, Note 2 has been met for each Oconee Unit. Therefore, 4 (2% of 162

= 3.24) dome tendons, 5 (2% of 592 = 11.84, maximum of 5) hoop tendons, and 3 (2%

of 136 = 2.72) vertical tendons are required to be selected.

3.

IWL-2524 and IWL-2525 examinations that were required at 50 years (Units 2 and 3) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 55 for Units 2 and 3. This is an approved alternative via Relief Request RA-19-0418.

4.

Of the required tendons to be examined, only one tendon wire or strand sample is required from one tendon of each type.

5.

During the random tendon selection process, alternate tendons may need to be selected which could result in additional tendon examinations. See the Unit 3 Random Tendon Selection and Required Examinations table at the end of this section.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 57 of 126 Tendons Affected by Repair/Replacement as Required by IWL-2521.2 Hoop and vertical tendons affected by the Steam Generator Replacement Project repair/replacement activities are subject to the requirements of Table IWL-2521-2. These tendons are identified in the ISI database as R/R Group 1 for the component group description. The population of tendons of a particular type affected by repair/replacement activities equals or exceeds 5% of the total number of tendons of that type. The exam sample size for all units will use a 2% sample size, or 1 hoop and 1 vertical tendon on each unit will be examined every 5 years because the requirement of Table IWL-2521-2, Note 6 has been met for each Oconee Unit.

The provisions of IWL-2421 may be used for scheduling tendons examined in accordance with Table IWL-2521-2. As such, the same number of tendons must be selected for examination every 5 years, but during one of the 5-year inspections ONS is only required to perform examinations required by IWL-2524 and IWL-2525 (no lift-off testing, no elongation measurements, no wire examinations and tests). The table below shows the number of examinations required on tendons affected by repair/replacement activity using the requirements of Table IWL-2521-2 and IWL-2421, as modified by Relief Request RA-19-0418.

Table 3.4.2-22, Unit 1 Table L-B Item Numbers Parts Examined Number of Components Number Scheduled by Period 1 (55th Year) 2 (60th Year)

L2.10(1)

Tendon 40 (Hoop) 41 (Vertical) 0 (Hoop) 0 (Vertical) 1 (Hoop) 1 (Vertical)

L2.20(3)

Wire or strand 0 (Hoop) 0 (Vertical) 1 (Hoop) 1 (Vertical)

L2.30(2)

Anchorage hardware and surrounding concrete 0 (Hoop) 0 (Vertical) 2 (Hoop) 2 (Vertical)

L2.40(2)

Corrosion protection medium 0 (Hoop) 0 (Vertical) 2 (Hoop) 2 (Vertical)

L2.50(2)

Free water 0 (Hoop) 0 (Vertical) 2 (Hoop) 2 (Vertical)

Notes:

1.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-2, Note 6 has been met for each Oconee Unit. Therefore, 1 (2% of 40 =

0.8) hoop tendon and 1 (2% of 41 = 0.82) vertical tendon are required to be selected.

2.

IWL-2524 and IWL-2525 examinations that were required at 55 years (Unit 1) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 50 and 60 (Unit 1). This is an approved alternative via Relief Request RA-19-0418.

3.

Of the required tendons to be examined, only one tendon wire or strand sample is required from one tendon of each type.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 58 of 126 Table 3.4.2-23 Unit 2 Table L-B Item Numbers Parts Examined Number of Components Number Scheduled by Period 1 (55th Year) 2 (60th Year)

L2.10(1)

Tendon 40 (Hoop) 42 (Vertical) 1 (Hoop) 1 (Vertical) 0 (Hoop) 0 (Vertical)

L2.20(3)

Wire or strand 1 (Hoop) 1 (Vertical) 0 (Hoop) 0 (Vertical)

L2.30(2)

Anchorage hardware and surrounding concrete 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

L2.40(2)

Corrosion protection medium 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

L2.50(2)

Free water 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

Notes:

1.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-2, Note 6 has been met for each Oconee Unit. Therefore, 1 (2% of 40 =

0.8) hoop tendon and 1 (2% of 42 = 0.84) vertical tendon are required to be selected.

2.

IWL-2524 and IWL-2525 examinations that were required at 50 years (Units 2 and 3) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 55 for Units 2 and 3. This is an approved alternative via Relief Request RA-19-0418.

3.

Of the required tendons to be examined, only one tendon wire or strand sample is required from one tendon of each type.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 59 of 126 Table 3.4.2-24, Unit 3 Table L-B Item Numbers Parts Examined Number of Components Number Scheduled by Period 1 (55th Year) 2 (60th Year)

L2.10(1)

Tendon 40 (Hoop) 40 (Vertical) 1 (Hoop) 1 (Vertical) 0 (Hoop) 0 (Vertical)

L2.20(3)

Wire or strand 1 (Hoop) 1 (Vertical) 0 (Hoop) 0 (Vertical)

L2.30(2)

Anchorage hardware and surrounding concrete 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

L2.40(2)

Corrosion protection medium 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

L2.50(2)

Free water 2 (Hoop) 2 (Vertical) 0 (Hoop) 0 (Vertical)

Notes:

1.

Sample sizes (based on 2% sample) may now be used because the requirement of Table IWL-2521-2, Note 6 has been met for each Oconee Unit. Therefore, 1 (2% of 40 =

0.8) hoop tendon and 1 (2% of 40 = 0.8) vertical tendon are required to be selected.

2.

IWL-2524 and IWL-2525 examinations that were required at 50 years (Units 2 and 3) are modified to occur concurrently with IWL-2522 and IWL-2523 exams at year 55 for Units 2 and 3. This is an approved alternative via Relief Request RA-19-0418.

3.

Of the required tendons to be examined, only one tendon wire or strand sample is required from one tendon of each type.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 60 of 126 The tables below identify the randomly selected tendons and required examinations for each unit as specified by Section IWL-2521, Tables IWL-2521-1 and IWL-2521-2, and as modified by Relief Request RA-19-0418.

Table 3.4.2-25, Unit 1 Random Tendon Selection and Required Examinations Unit Tendon Exam Year Exams Required 55 (I4P1) 60 (I4P2)

L2.10 L2.20 L2.30 L2.40 L2.50 Verticals 1

45V25 (Common)

No Yes Yes No Yes Yes Yes 1

61V19 No Yes Yes Yes Yes Yes Yes 1

45V26 No Yes Yes No Yes Yes Yes 1

56V29 No Yes No No Yes Yes Yes 1

56V20 No Yes No No Yes Yes Yes 1

56V14 No Yes No No Yes Yes Yes 1

34V3 (Table IWL-2521-2)

No Yes Yes Yes Yes Yes Yes 1

34V12 (Table IWL-2521-2)

No Yes No No Yes Yes Yes Hoops 1

24H39 (Common)

No Yes Yes No Yes Yes Yes 1

13H26 No Yes No No Yes Yes Yes 1

24H80 No Yes Yes No Yes Yes Yes 1

46H79 No Yes Yes No Yes Yes Yes 1

13H14 No Yes Yes No Yes Yes Yes 1

62H49 (One End Only)(1)

No Yes No No Yes Yes Yes 1

62H50 (Alt for 62H49)(1)

No Yes No No Yes Yes Yes 1

62H57 No Yes Yes Yes Yes Yes Yes 1

35H80 No Yes No No Yes Yes Yes 1

46H43 No Yes No No Yes Yes Yes 1

24H12 No Yes No No Yes Yes Yes 1

51H5 (Owner Specified)(2)

No Yes No No Yes Yes Yes 1

35H47 (Table IWL-2521-2)

No Yes Yes Yes Yes Yes Yes 1

24H63 (Table IWL-2521-2)

No Yes No No Yes Yes Yes Domes 1

3D05 (Common)

No Yes Yes No Yes Yes Yes 1

2D35 No Yes Yes Yes Yes Yes Yes 1

1D35 No Yes Yes No Yes Yes Yes 1

2D16 No Yes Yes No Yes Yes Yes 1

1D23 No Yes No No Yes Yes Yes 1

1D22 No Yes No No Yes Yes Yes 1

2D26 No Yes No No Yes Yes Yes 1

2D46 No Yes No No Yes Yes Yes Notes:

1.

Field end cap of tendon 62H49 is completely embedded in Aux Bldg. roof flashing.

Inaccessible for lift-off testing. Perform required exams/tests at opposite end and select alternate tendon. The alternate tendon selected for examination is 62H50.

2.

Examination of at least one end of one buried hoop tendon is performed during each tendon surveillance. Tendon 51H5 was added as an Owner Specified tendon since the random tendon selection did not include one of these tendons. Exams/tests shall be

~

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 61 of 126 performed from accessible end of tendon (at Buttress #5). No L2.10 or L2.20 exams will be performed on this tendon, due to access restrictions for the rams and safety concerns with not being able to inspect the button heads and stressing hardware on the buried end.

Table 3.4.2-26, Unit 2 Random Tendon Selection and Required Examinations Unit Tendon Exam Year Exams Required 55 (I4P1) 60 (I4P2)

L2.10 L2.20 L2.30 L2.40 L2.50 Verticals 2

45V17 (Common)

Yes No Yes No Yes Yes Yes 2

56V10 Yes No Yes Yes Yes Yes Yes 2

56V29 Yes No Yes No Yes Yes Yes 2

12V3 Yes No No No Yes Yes Yes 2

45V24 Yes No No No Yes Yes Yes 2

12V24 Yes No No No Yes Yes Yes 2

23V26 (Table IWL-2521-2)

Yes No Yes Yes Yes Yes Yes 2

34V17 (Table IWL-2521-2)

Yes No No No Yes Yes Yes Hoops 2

62H86 (Common)

Yes No Yes No Yes Yes Yes 2

24H12 (Alternate for 24H4)(1)

Yes No Yes No Yes Yes Yes 2

13H77 Yes No Yes Yes Yes Yes Yes 2

51H5 (Accessible One End Only)(2)

Yes No Yes No Yes Yes Yes 2

51H12 (Alternate for 51H5)(2)

Yes No No No Yes Yes Yes 2

35H95 Yes No Yes No Yes Yes Yes 2

35H27 Yes No Yes No Yes Yes Yes 2

13H31 Yes No No No Yes Yes Yes 2

24H41 Yes No No No Yes Yes Yes 2

62H23 Yes No No No Yes Yes Yes 2

62H61 Yes No No No Yes Yes Yes 2

35H57 (Table IWL-2521-2)

Yes No Yes Yes Yes Yes Yes 2

35H49 (Table IWL-2521-2)

Yes No No No Yes Yes Yes Domes 2

1D19 (Common)

Yes No Yes No Yes Yes Yes 2

2D49 Yes No Yes Yes Yes Yes Yes 2

1D21 Yes No Yes No Yes Yes Yes 2

1D01 Yes No Yes No Yes Yes Yes 2

3D10 Yes No No No Yes Yes Yes 2

3D08 Yes No No No Yes Yes Yes 2

1D22 Yes No No No Yes Yes Yes 2

1D16 Yes No No No Yes Yes Yes Notes:

1.

Tendon 24H4 is a buried tendon that is inaccessible at both ends. Tendon 24H12 was selected as an alternate.

2.

Tendon 51H5 is accessible from one end only. Tendon 51H12 was selected as an alternate tendon. Examinations of tendon 51H5 shall be performed from accessible end and shall also be credited for satisfying the Owner Specified Examination of a buried tendon.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 62 of 126 Table 3.4.2-26, Unit 3 Random Tendon Selection and Required Examinations Unit Tendon Exam Year Exams Required 55 (I4P1) 60 (I4P2)

L2.10 L2.20 L2.30 L2.40 L2.50 Verticals 3

23V9 (Common)

Yes No Yes No Yes Yes Yes 3

45V24 Yes No Yes Yes Yes Yes Yes 3

23V4 Yes No Yes No Yes Yes Yes 3

12V4 Yes No No No Yes Yes Yes 3

45V23 Yes No No No Yes Yes Yes 3

45V12 Yes No No No Yes Yes Yes 3

34V14 (Table IWL-2521-2)

Yes No Yes Yes Yes Yes Yes 3

34V16 (Table IWL-2521-2)

Yes No No No Yes Yes Yes Hoops 3

62H51 (Common)

Yes No Yes No Yes Yes Yes 3

62H83 Yes No No No Yes Yes Yes 3

51H86 Yes No Yes Yes Yes Yes Yes 3

13H41 Yes No Yes No Yes Yes Yes 3

35H13 (Alternate for 35H9)(1)

Yes No No No Yes Yes Yes 3

24H13 Yes No Yes No Yes Yes Yes 3

51H100 Yes No No No Yes Yes Yes 3

35H89 Yes No No No Yes Yes Yes 3

35H9 (Partially inaccessible -

Select Alternate)(1)

Yes No Yes No Yes Yes Yes 3

51H87 Yes No No No Yes Yes Yes 3

62H80 Yes No Yes No Yes Yes Yes 3

35H64 (Table IWL-2521-2)

Yes No Yes Yes Yes Yes Yes 3

35H57 (Table IWL-2521-2)

Yes No No No Yes Yes Yes Domes 3

3D09 (Common)

Yes No Yes No Yes Yes Yes 3

3D01 Yes No Yes Yes Yes Yes Yes 3

1D03 Yes No Yes No Yes Yes Yes 3

1D19 Yes No Yes No Yes Yes Yes 3

3D47 Yes No No No Yes Yes Yes 3

1D11 Yes No No No Yes Yes Yes 3

3D50 Yes No No No Yes Yes Yes 3

1D12 Yes No No No Yes Yes Yes Notes:

1.

Tendon 35H9 is accessible from one end only. Tendon 35H13 was selected as an alternate tendon. Examinations of tendon 51H5 shall be performed from accessible end and shall also be credited for satisfying the Owner Specified Examination of a buried tendon.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 63 of 126 Fourth Containment Inservice Inspection (CISI) Interval Periods and Outages:

The Fourth CISI Intervals for Oconee are shown below. Duke Energy Corporation submitted Request for Alternative Serial #03-GO-010 on June 17, 2003, and amended on August 31, 2004, to more closely align the CISI and ISI Intervals start and end dates.

Subsection IWL does not specify ISI Periods. However, the term IWL Period is used to designate when examinations required by Subsection IWL are required to be performed. The CISI Interval start and end date for Subsection IWL shall be the same as that specified for Subsection IWE.

Table 3.4.2-27, Unit 1 (IWE)

(See Notes 1 and 2)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2024 O1R33 Fall 2024 4th CISI Interval 07/15/2024 to 07/14/2034 to 07/14/2028 O1R34 Fall 2026 2nd 07/15/2028 to 07/14/2032 O1R35 Fall 2028 O1R36 Fall 2030 3rd 07/15/2032 O1R37 to 07/14/2034 Fall 2032 Table 3.4.2-28, Unit 1 (IWL)

(See Note 3)

IWL Period 1:

8/4/25 - 8/4/27 (55th Year Exams)

IWL Period 2:

8/4/30 - 8/4/32 (60th Year Exams)

Notes:

1.

The interval end date may be extended by as much as 1 year or reduced without restriction, in accordance with IWA-2430(c)(1). The original pattern of intervals as described in IWA-2430(c)(1) has been modified per alternative 03-GO-010 and shall now be based on the pattern of intervals established during the 2nd CISI Interval, which began on 07/15/2004.

2.

IWE Examinations are scheduled for the 4th CISI Interval in accordance with ASME Section XI Inspection Plan, Table IWE-2411-1 and Table IWE-2500-1.

3.

IWL Periods for Unit 1 are based on a repeating 5-year schedule (+/- 12 month) following the completion of the containment Structural Integrity Test, as required by IWL-

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 64 of 126 2410 and IWL-2420. The Unit 1 Structural Integrity Test was completed on 08/04/1971.

Initial post-tensioning operations were completed in November 1970.

Table 3.4.2-29, Unit 2 (IWE)

(See Notes 1 and 2)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2024 O2R32 Fall 2025 4th CISI Interval 07/15/2024 to 07/14/2034 to 07/14/2028 O2R33 Fall 2027 2nd 07/15/2028 to 07/14/2032 O2R34 Fall 2029 O2R35 Fall 2031 3rd 07/15/2032 O2R36 to 07/14/2034 Fall 2033 Table 3.4.2-30, Unit 2 (IWL)

(See Note 3)

IWL Period 1:

6/22/27 - 6/22/29 (55th Year Exams)

IWL Period 2:

6/22/32 - 6/22/34 (60th Year Exams)

Notes:

1.

The interval end date may be extended by as much as 1 year or reduced without restriction, in accordance with IWA-2430(c)(1). The original pattern of intervals as described in IWA-2430(c)(1) has been modified and shall now be based on the pattern of intervals established during the 2nd CISI Interval, which began on 07/15/2004.

2.

IWE Examinations are scheduled for the 4th CISI Interval in accordance with ASME Section XI Inspection Plan, Table IWE-2411-1 and Table IWE-2500-1.

3.

IWL Periods for Unit 2 are based on a repeating 5-year schedule (+/- 12 months) following the completion of the containment Structural Integrity Test, as required by IWL-2410 and IWL-2420. The Unit 2 Structural Integrity Test was completed on 06/22/1973.

Initial post-tensioning operations were completed in December 1971.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 65 of 126 Table 3.4.2-31, Unit 3 (IWE)

(See Notes 1 and 2)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2024 O3R33 Spring 2026 4th CISI Interval 07/15/2024 to 07/14/2034 to 07/14/2028 O3R34 Spring 2028 2nd 07/15/2028 to 07/14/2032 O3R35 Spring 2030 O3R36 Spring 2032 3rd 07/15/2032 O3R37 to 07/14/2034 Spring 2034 Table 3.4.2-32, Unit 3 (IWL)

(See Notes 3 and 4)

IWL Period 1:

5/07/28 - 5/07/30 (55th Year Exams)

IWL Period 2:

5/07/33 - 5/07/35 (60th Year Exams)

Notes:

1.

The interval end date may be extended by as much as 1 year or reduced without restriction, in accordance with IWA-2430(c)(1). The original pattern of intervals as described in IWA-2430(c)(1) has been modified and shall now be based on the pattern of intervals established during the 2nd CISI Interval, which began on 07/15/2004.

2.

IWE Examinations are scheduled for the 4th CISI Interval in accordance with ASME Section XI Inspection Plan, Table IWE-2411-1 and Table IWE-2500-1.

3.

The IWL Periods for Unit 3 are based on a repeating 5-year schedule (+/- 12 month) following the completion of the containment Structural Integrity Test, as required by IWL-2410 and IWL-2420. The Unit 3 Structural Integrity Test was completed on 5/07/1974.

Initial post-tensioning operations were completed in June, 1973.

4.

Although the 24-month window for IWL Period 2 extends beyond the 4th Interval CISI end date of 07/14/2034, examinations/tests performed between 07/14/2034 and 05/07/2035 for IWL Period 2 shall be performed in accordance with the requirements of the 4th Interval CISI Plan.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 66 of 126 Fifth Containment Inservice Inspection (CISI) Interval Periods and Outages:

Table 3.4.2-33, Unit 1 (IWE)

(Note 1)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2034 O1R38 Fall 2034 5th CISI Interval 07/15/2034 to 07/14/2044 to 07/14/2038 O1R39 Fall 2036 2nd 07/15/2038 to 07/14/2042 O1R40 Fall 2038 O1R41 Fall 2040 3rd 07/15/2042 O1R42 to 07/14/2044 Fall 2042 Table 3.4.2-34, Unit 1 (IWL)

IWL Period 1:

8/4/35 - 8/4/37 (65th Year Exams)

IWL Period 2:

8/4/40 - 8/4/42 (70th Year Exams)

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 67 of 126 Table 3.4.2-35, Unit 2 (IWE)

(Note 1)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2034 O2R37 Fall 2035 5th CISI Interval 07/15/2034 to 07/14/2044 to 07/14/2038 O2R38 Fall 2037 2nd 07/15/2038 to 07/14/2042 O2R39 Fall 2039 O2R40 Fall 2041 3rd 07/15/2042 O2R41 to 07/14/2044 Fall 2043 Table 3.4.2-36, Unit 2 (IWL)

IWL Period 1:

6/22/37 - 6/22/39 (65th Year Exams)

IWL Period 2:

6/22/42 - 6/22/44 (70th Year Exams)

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 68 of 126 Table 3.4.2-37, Unit 3 (IWE)

(Note 1)

Interval Periods Outages Start Date to End Date Start Date to End Date Outage Numbers 1st 07/15/2034 O3R38 Spring 2036 5th CISI Interval 07/15/2034 to 07/14/2044 to 07/14/2038 O3R39 Spring 2038 2nd 07/15/2038 to 07/14/2042 O3R40 Spring 2040 O3R41 Spring 2042 3rd 07/15/2042 O3R42 to 07/14/2044 Spring 2044 Table 3.4.2-38, Unit 3 (IWL)

IWL Period 1:

5/07/38 - 5/07/40 (65th Year Exams)

IWL Period 2:

5/07/43 - 5/07/45 (70th Year Exams)

Note:

1.

The 5th CISI intervals are postulated as the 5th CISI interval plan has yet to be developed.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 69 of 126 Relief Requests Each request for relief from a requirement of the ASME Section XI Code specified in the ISI Plan shall be submitted by the Station Regulatory Affairs Department to the Nuclear Regulatory Commission for approval. The list below contains all requests for relief that affect Inservice Inspection at ONS during the 6th ISI Interval. For a listing of requests for relief pertaining to topics other than ISI, contact the ONS Regulatory Affairs Department.

Table 3.4.2-39, Relief Requests Serial Number Description Units Affected Date RFR Submitted Date SER Approved Comments RA 0418 (CISI) Alternative for Inservice Inspection of Containment Post-Tensioning System Components.

1, 2, & 3 05/06/2021 (ML21126A002) 12/07/2021 (ML21335A106)

Remains in effect for the remainder of the current renewed operating licenses of ONS Units 1, 2, and 3.

NDE Procedures Examination Methods and Procedures to be used for Inservice Inspection Inservice inspection of Oconee Units 1, 2, & 3 shall be performed using procedures which comply with the requirements of the applicable codes and code cases referenced in this plan.

Volumetric, surface, and visual methods of examination shall be used as required. Each examination shall be performed under the QA Program of the organization performing the examination.

A specific examination procedure is assigned by the site NDE Level III at the time of the exam and is selected from approved and issued NDE procedure referenced below. Procedures beginning with NDE or PDI are found in the Duke Energy NDE Procedures Manuals. Vendor inspection procedures that are to be used shall be listed in this Section as they become identified or as approved by Duke in contract documentation. The Electronic Document Management System shall always be used to determine the latest revision for all NDE procedures used.

The following abbreviations are used to describe the type of inspection required for each item:

ECT Eddy Current Testing EVT-1 Enhanced VT-1 Inspection (ISI Visual Inspection)

GV General Visual PT Liquid Penetrant Inspection MT Magnetic Particle Inspection RT Radiographic Inspection UT Ultrasonic Inspection VT-1 ISI Visual Inspection (Detect Discontinuities and Imperfections)

VT-2 ISI Visual Inspection (Evidence of Leakage)

VT-3 ISI Visual Inspection (General Condition of Components and Supports)

VTW Visual Testing Welding

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 70 of 126 Volumetric Examination Volumetric examination shall be performed by manual and/or automated ultrasonic methods, except in some cases where ultrasonic methods are not practical. Radiographic examinations shall be used in these cases in lieu of ultrasonic examinations. Examination of reactor vessel welds shall be performed using an automated ultrasonic inspection device.

Steam Generator tubing shall be examined using eddy current inspection methods as outlined in the Oconee Technical Specifications. The Steam Generator Maintenance and Engineering Section/Engineering Support GO have overall responsibility for implementing and reporting any examinations pertaining to the Steam Generator Tubes. This work is planned, implemented, documented and reported independently from this document.

Surface Examination Surface examination shall be performed using either liquid penetrant or magnetic particle methods. The liquid penetrant method shall be used for all surface examinations on austenitic steels and may also be used on ferritic steel. The magnetic particle method shall only be used on ferritic steel.

Visual Examination Inservice visual examinations shall be performed using direct methods where practical. Remote visual examinations may be used in some cases. Enhanced visual methods may be used in lieu of ultrasonic for some examinations, as permitted by ASME Section XI and/or 10CFR50.55a.

Examination Procedures The following Duke Energy Nuclear Fleet NDE Procedure Manual identifies active NDE procedures that are applicable to NDE conducted at Duke Energy Nuclear facilities. This support document lists new fleet level NDE procedures, the NDE method, ISI applicability, and scope of the procedure. It also lists legacy NDE procedures that are applicable to DEC and DEP Nuclear Power facilities that are still active and have not yet been superseded.

For Oconee Nuclear Station Units 1, 2, and 3, the latest revision of each procedure that has been approved shall be used. These procedures shall have Duke Energy approval prior to implementation. All Vendor procedures with Duke approvals shall be included in contract final report documentation and shall be added to this Appendix.

The procedure to be used for the examination shall be selected by the NDE Level III, for the inspection methods listed in the ONS Schedule documents. Any procedure listed in the schedule shall be for reference use only.

Calibration Blocks The calibration block(s) to be used for the UT examination shall be selected by the NDE Level III, from the calibration blocks listed in this ISI Plan, Appendix B. The designation of TBD is used to indicate cases where the calibration block is still being designed and or fabricated. This

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 71 of 126 listing of calibration blocks shall be updated after new calibration blocks are fabricated and approved for use.

3.4.3 Supplemental Inspection Requirements In the SER for NEI 94-01, Revision 2-A, the NRC stated the following requirement for the performance of Supplemental Visual Inspections in SER Section 3.1.1.3, Adequacy of Pre-Test Inspections (Visual Examinations):

Subsections IWE and IWL of the ASME Code,Section XI, as incorporated by reference in 10 CFR 50.55a, require general visual examinations two times within a 10-year interval for concrete components (Subsection IWL), and three times within a 10-year interval for steel components (Subsection IWE). To avoid duplication or deletion of examinations, licensees using NEI TR 94-01, Revision 2, have to develop a schedule for containment inspections that satisfy the provisions of Section 9.2.3.2 of this TR and ASME Code,Section XI, Subsection IWE and IWL requirements.

Containment Structural Inspection Purpose To verify by general visual inspection the structural integrity of containment structure in accordance with 10CFR 50, Appendix J and Technical Specifications, to satisfy general visual examination requirements for Concrete Containment in accordance with ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWL, as required by 10CFR 50.55a, and to satisfy general visual examination requirements for Steel Containment Liner in accordance with ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE, as required by 10CFR 50.55a.

General Description Inspection of the containment portion of Reactor Building is performed by personnel meeting specified qualification requirements. Inspection is intended to identify degraded areas having potential to adversely affect structural integrity or leak tight integrity of existing containment structure.

Major Components x

Concrete surfaces of Containment Structure x

Metallic shell of Reactor Building x

Penetration Liners of Reactor Building Other Information All inspections are performed by qualified engineering or non-engineering personnel, however all signoffs are to be performed by Responsible Individual attesting to completion of particular step unless specified otherwise.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 72 of 126 ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE-2330 provides the following qualifications and responsibilities of "Responsible Individual":

ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWL-2330 provides the following of the IWL "Responsible Individual":

"The Responsible Engineer shall be a Registered Professional Engineer experienced in evaluating the condition of structural concrete. The Responsible Engineer shall have knowledge of the design and Construction Codes and other criteria used in design and construction of concrete containments in nuclear power plants."

The Responsible Engineer shall be responsible for the following:

Development of plans and procedures for examination of concrete surfaces.

Approval, instruction, and training of personnel performing general and detailed visual examination.

Evaluation of examination results Preparation or review of Repair/Replacement Plans and procedures Review of procedures for pressure tests following repair/replacement activities Submittal of a report to the Owner documenting results of examinations, repair/replacement activities, and pressure tests 10CFR 50, Appendix J, Option A Paragraph V.A. requires that A general inspection of the accessible interior and exterior surfaces of the containment structures and components shall be performed prior to any Type A test to uncover any evidence of structural deterioration which may affect either the containment structural integrity or leak-tightness. If there is evidence of structural deterioration, Type A tests shall not be performed until corrective action is taken in accordance with repair procedures, nondestructive examinations, and tests as specified in the applicable code specified in section 50.55a at the commencement of repair work. Such structural deterioration and corrective actions taken shall be included in the summary report required by V.B."

10CFR 50, Appendix J, Option B Paragraph III.A. requires that A general inspection of the accessible interior and exterior surfaces of the containment system for structural deterioration which may affect the containment leak-tight integrity must be conducted prior to each test, and at a periodic interval between tests based on the performance of the containment system."

The ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE requires that a general visual examination be performed on Class MC (Metal Containments) and Metallic Liners of Class CC (Concrete Containments) Components each inspection period. A general visual examination shall be performed as required by the ASME Code,Section XI, Subsection IWE.

General visual examinations of the metallic liner may be used to satisfy the inspection requirements of 10CFR50, Appendix J.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 73 of 126 Examination of the accessible concrete and post-tensioning system component surfaces of the concrete containment in accordance with 10CFR 50, Appendix J need only be performed prior to each Type A test, as specified in Oconee Technical Specifications, 5.5.2. Examinations conducted in accordance with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWL, may be used to satisfy examination requirements of this procedure for accessible containment concrete and post-tensioning system component surfaces in accordance with the requirements of the Technical Specifications, if the examination has been performed within 90 days of the Type A test.

Limits IF this procedure is being performed to satisfy requirements of 10CFR50, Appendix J just prior to conducting an Integrated Leak Rate Test (ILRT),

x Section 7.2 examinations are to be performed NO greater than 90 days prior to scheduled start of refueling outage.

x Section 7.3 examinations are to be performed during NO-MODE, MODE 6 OR MODE 5.

3.4.4 Results of Recent Containment Examinations The results of recent visual examinations of IWE surfaces are detailed in Tables 3.4.4-1 through 3.4.4-3 below. Note that the contents of Tables 3.4.4-1 through 3.4.4-3 do not include the results of inspections where there were "No Reportable Indications", and the inspection results were evaluated and found acceptable.

The results of recent visual examinations of IWL surfaces are detailed in Table 3.4.4-4 through 3.4.4.6 below. Note that the contents of Table 3.4.4-4 through 3.4.7-6 do not include the results of inspections where there were No Reportable Indications, and the inspection results were evaluated and found acceptable.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 74 of 126 General Comments Unit 1 EOC32 x

Minor coatings damage (dings, scratches, top coat flaking) was observed at a number of locations throughout the interior surface of the containment liner plate. Except as noted, these conditions are not considered problematic, nor do they require immediate corrective maintenance. At most of these locations, the primer coat remains intact, and damage is limited to the top coating. General coatings inspection are performed and remedial actions for coatings follow from that inspection.

Table 3.4.4-1, Unit 1 EOC32, Containment Structural Inspection Indication No.

Azimuth/Elev.

Description Resolution 1-MOBR-001 0o-43o& 318o-360o 777'-6" A VT-I Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-I was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

The moisture barrier indications were repaired.

1-MOBR-005 104o-170o 777'-6" A VT-I Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-I was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

The moisture barrier indications were repaired.

1-MOBR-010 204o-257o 777'-6" VT-1 Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-1 was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

The moisture barrier indications were repaired.

1-MOBR-011 RB Grating Platform Support Angles Performed a General Visual Exam of the moisture barrier and identified areas of degradation. A VT-I Exam was performed on the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-1 was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

The shelf angle sealant indications were repaired.

1-SCV-011 RX Bldg.

The UT shows the plate in this location is greater than 0.25. At the deepest pit the liner plate is still 0.225 thick which is equivalent to a 10% loss of a 0.25" thick plate.

The liner plate findings documented in this NCR are Acceptable by Engineering Evaluation.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 75 of 126 General Comments Unit 2 EOC31 x

Minor coatings damage (dings, scratches, top coat flaking) was observed at a number of locations throughout the interior surface of the containment liner plate. Except as noted, these conditions are not considered problematic, nor do they require immediate corrective maintenance. At most of these locations, the primer coat remains intact, and damage is limited to the top coating. General coatings inspection are performed and remedial actions for coatings follow from that inspection.

Table 3.4.4-2, Unit 2 EOC31, Containment Structural Inspection Indication No.

Azimuth/Elev.

Description Resolution 2-MOBR-001 0o-43o& 318o-360o 777+6 A VT-I Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-I was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

All moisture barrier indications noted during O2R31 were repaired.

2-MOBR-005 104o-170o 777'-6" A VT-I Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-I was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

All moisture barrier indications noted during O2R31 were repaired.

2-MOBR-010 204o-257o 777'-6" A VT-I Exam was performed on the moisture barrier and the degraded areas for leak paths. The degraded sections of moisture barrier were removed, and a VT-I was performed of the liner plate for evidence of corrosion. No evidence of material wastage was identified.

All moisture barrier indications noted during O2R31 were repaired.

2-MOBR-011 RB Grating Platform Support Angles During this inspection MB observed numerous locations of grating elevations were identified as degraded and are being repaired All moisture barrier indications noted during O2R31 were repaired.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 76 of 126 General Comments Unit 3EOC32 x

Minor coatings damage (dings, scratches, top coat flaking) was observed at a number of locations throughout the interior surface of the containment liner plate. Except as noted, these conditions are not considered problematic, nor do they require immediate corrective maintenance. At most of these locations, the primer coat remains intact, and damage is limited to the top coating. General coatings inspection are performed and remedial actions for coatings follow from that inspection.

Table 3.4.4-3, Unit 3 EOC32, Containment Structural Inspection Indication No.

Azimuth/Elev.

Description Resolution 3-MOBR-001 0o-43o& 318o-360o 777+6 General Visual / VT-1 Exam was performed on the moisture barrier and degraded areas of moisture barrier that could permit intrusion of moisture against inaccessible areas of pressure retaining surfaces of the metal containment liner.

NCR was generated to document the areas where the moisture barrier was found to be degraded. The degraded areas of moisture barrier were removed, a VT-1 exam was performed on the metallic liner for evidence of corrosion, and no evidence of material wastage was identified.

All moisture barrier indications repaired.

3-MOBR-005 104o-170o 777'-6" A General Visual/ VT-1 Exam was performed on the moisture barrier and degraded areas of moisture barrier that could permit intrusion of moisture against inaccessible areas of pressure retaining surfaces of the metal containment liner.

NCR was generated to document the areas where the moisture barrier was found to be degraded. The degraded areas of moisture barrier were removed, a VT-1 exam was performed on the metallic liner for evidence of corrosion, and no evidence of material wastage was identified.

All moisture barrier indications repaired.

3-MOBR-011 RB Grating Platform Support Angles A General Visual/ VT-1 Exam was performed on the moisture barrier and degraded areas of moisture barrier that could permit intrusion of moisture against inaccessible areas of pressure retaining surfaces of the metal containment liner.

All moisture barrier indications repaired.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 77 of 126 Table 3.4.4-3, Unit 3 EOC32, Containment Structural Inspection Indication No.

Azimuth/Elev.

Description Resolution NCR was generated to document the areas where the moisture barrier was found to be degraded. The degraded areas of moisture barrier were removed, a VT-1 exam was performed on the metallic liner for evidence of corrosion, and no evidence of material wastage was identified.

Containment Concrete Inspection Previous inspection report's indications were revisited during this inspection. Indications from previous exams are not reported unless they have changed in some way.

With the adoption of Subsection IWL, 2007 Edition through the 2008 Addenda, grease leakage no longer must be reported in an ISI Summary Report (10CFR50.55a(b)(2)(viii). Concrete surfaces and tendon end anchorage areas shall be examined for corrosion protection medium leakage (ASME Code Section XI, Subsection IWL, IWL-2510(c), and the condition of the concrete surface and tendon end anchorage areas is acceptable if the Responsible Engineer determines that there is no evidence of corrosion protection medium leakage sufficient to warrant further evaluation or performance of repair/replacement activities (ASME Code Section XI, Subsection IWL, IWL3211). To that end, an attempt has been made to conservatively note all evidence of grease leakage, including slight grease stains around the base of tendon caps and on the concrete surface that may or may not result from leaks above those being reported. However, there is no requirement to list specifically all caps which may have evidence of leakage. Based on previous ONS experience with tendons found to contain substantial voids in the tendon sheath, minor loss of less viscous tendon grease does not appear to lead to corrosive degradation of the tendon wires or other components, so long as these items were adequately coated initially, and there has been no significant intrusion of rainwater. The component of the filler grease leaking from these tendon caps is the less viscous oil. The heavier grease is contained in the sheath and caps and continues to protect the metallic components.

Table 3.4.4-4, Unit 1, 50th Year, Containment Concrete Inspection Indication or Finding No.

Description Location Resolution Previous inspection report's indications were revisited during this inspection. Indications from previous exams are not repeated unless they have changed in some way.

All Indications or Findings identified during the 50th year Containment Concrete Inspection were reviewed and determined to be acceptable in the as-found condition.

I I

I

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 78 of 126 Table 3.4.4-5, Unit 2, 50th Year, Containment Concrete Inspection Indication or Finding No.

Description Location Resolution Previous inspection report's indications were revisited during this inspection. Indications from previous exams are not repeated unless they have changed in some way.

All Indications or Findings identified during the 50th year Containment Concrete Inspection were reviewed and determined to be acceptable in the as-found condition.

Table 3.4.4-6, Unit 3, 50th Year, Containment Concrete Inspection Indication or Finding No.

Description Location Resolution Previous inspection report's indications were revisited during this inspection. Indications from previous exams are not repeated unless they have changed in some way.

All Indications or Findings identified during the 50th year Containment Concrete Inspection were reviewed and determined to be acceptable in the as-found condition.

I I

I I

I I

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 79 of 126 3.4.5 Results of Recent IWL Tendon Examinations ONS Unit 1, Year 50 Tendon Surveillance Summary Report In accordance with Technical Specification 3.6.1, Containment and Selected Licensee Commitment 16.6.2, Containment Tendon Surveillance Program, the Unit 1 IWL Year 50 Inservice Post Tensioning System Examination was performed in accordance with the 2007 Edition with the 2008 Addenda of Subsection IWL, Requirements for Class CC Concrete Components of Light Water Cooled Power Plants, of Section XI, Division 1 of the ASME Code (The Code), with the modifications and limitations outlined in 10CFR Part 50, Paragraphs 50.55a(b)(2)(viii) and 50.50.55a(b)(2)(ix), except as amended by approved relief requests and submitted Safety evaluations granted by the NRC. Surveillances were performed under Work Order 20376931 between the dates of August 4th, 2020, to August 4th, 2022. Final grease sample test results and tendon wire mechanical properties were completed after August 4th, 2022.

Subsection IWL-3310 requires an evaluation report of any items not meeting the acceptance standards of Subsection IWL-3100 or IWL-3200. This Summary and Evaluation Report summarizes the 50-year tendon surveillance results and provides any required evaluations.

Schedule In accordance with IWL-2420(a) and (c), surveillances were scheduled for the 50th anniversary of the Structural Integrity test, which was completed August 4th, 1971, plus or minus 12 months.

That is, between August 4th, 2020, and August 4th, 2022. Exams did not commence prior to August 4th, 2020, and all exams were completed prior to August 4th, 2022 with exception to the receipt of the grease sample test report and wire sample test report.

Tendons were randomly selected for surveillance in accordance with IWL-2521(a) and (b) and IWL-2521.1(a) and (b). In addition, tendons affected by repair/replacement activities were selected at random for surveillance in accordance with IWL-2521.2(a) and (b).

The number of tendons selected for examination is selected for a two percent sample size due to having met the acceptance criteria of IWL-3221.1 for the last three inspections.

The number of tendons selected for augmented examination is selected for a 4% sample size although the Year 50 surveillance inspection is the third inspection following the repair and replacement activities associated with the Steam Generator Replacement for Unit 1.

Subsequent inspections beyond Year 50 may use a reduced sample size given the provisions of IWL-2521-2(6) have been met.

All exams were performed as required per the Code. Inspections performed prior to the adoption of the 2007 Edition with the 2008 Addenda of the Code considered augmented examination inspections on the Steam Generator Replacement affected tendons to be Owner specified additions to the inspection scope, since no specific requirements for additional examinations were required. However, the 2007 Edition with the 2008 Addenda requires a random sampling of tendons to be selected from the population of affected tendons due to repair and replacement activities as was done for the Year 50 surveillance inspection.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 80 of 126 Scope Tendon Mark No.

L2.10 L2.20 L2.30 L2.40 L2.50 Notes Lift-off Wire test Anchorage Concrete Grease Tests Free H2O pH 45V25 Y

N Y

Y Y

COMMON TENDON 56V24 Y

Y Y

Y Y

61V28 Y

N Y

Y Y

45V12 Y

N Y

Y Y

23V30 Y

Y Y

Y Y

SGR NEW Tendon 34V7 Y

N Y

Y Y

SGR NEW Tendon 24H39 Y

N Y

Y Y

COMMON TENDON 62H66 Y

N Y

Y Y

46H100 Y

N Y

Y Y

13H28 N

N Y

Y Y

Access in WPR limited, no lift off 24H32 Y

N Y

Y Y

35H91 Y

Y Y

Y Y

35H63 Y

Y Y

Y Y

SGR NEW TENDON NEW CONCRETE 24H55 Y

N Y

Y Y

SGR NEW TENDON NEW CONCRETE 35H2 N(1)

N Y

Y Y

BURIED TENDON 3D05 Y

N Y

Y Y

COMMON TENDON 1D17 Y

N Y

Y Y

2D10 Y

N Y

Y Y

Inaccessible 2D14 Y

N Y

Y Y

Alternate for 2D10 1D54 Y

Y Y

Y Y

NOTE 1:

BURIED TENDON, ONLY 1 END ACCESSIBLE Surveillance Tendon Force Measurement Results All tendons tested were found to exceed both the MRV and PLL forces; therefore, the requirements of IWL-3221.1(a) and IWL-3221.1(b) are met and no evaluation is required.

Additionally, Duke Energy has decided to perform lift-off measurements on the common tendons each surveillance interval as an owner specified examination for tracking and trending purposes. The tendons that were replaced as part of repair and replacement activities were tensioned to near original construction values. Hydraulic ram pressures are limited not to exceed 70% of yield strength for the tendon wire material, while in most cases tendons were tensioned to 80% of the yield strength. Until sufficient loss of prestress occurs over time, lift-off may not be achieved during tendon surveillances for those tendons that were replaced.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 81 of 126 Tendon Force Prestress Loss for Predicted Tendon Forces The projected tendon force measurements for the Unit 1 Year 60 Tendon Surveillance were developed using construction stressing information as well as previous surveillance measurements.

The trend lines showed a projected force for each tendon type expected for the 60 Year Tendon Surveillance that exceeds both the MRV and PLL forces. The standard deviation for the data for the past twenty years is calculated along with the cumulative distribution function to evaluate future tendon forces. The cumulative distribution is determined assuming the trend line is the same at Year 60. The trend data shows that the vertical tendons have an 4.11% chance of being lower than PLL at Year 60, hoop tendons have a 4.87% chance of being lower, and dome tendons have a negligible 0.00% chance of being lower than PLL at Year 60. These projected forces are acceptable given the acceptance criteria specified in IWL-3221.1(c).

Tendon Wire Samples Tendon wire tests were performed at the Duke Energy Metallurgy Lab at McGuire Nuclear Station on August 29th, 2022. Tendons 56V24, 23V30, 35H91, 35H63, 1D54 were selected for wire removal and inspection.

No corrosion or mechanical damage was recorded. All samples met their mechanical requirements of Tensile Strength and Percent Elongation in accordance with IWL 3221.2.

Tendon Elongation/Retensioning Tendons 56V24, 23V30, 35H91, 35H63, 1D54 were selected for elongation measurements and re-tensioning.

Tendon 35H91 was not adequately stressed to the Overstressing Force on End 1 or End 2 due to End 2 having a PC-38 type anchor head. In the past ONS has experienced failures of the threads of PC-38 anchor heads. A detailed review of all other data sets for tendon 35H91 indicates that this tendon is performing adequately. The wire samples from this tendon show acceptable ultimate strength and elongation ranges. There were no visual indications of corrosion on the tendon wire sample or the tendon anchorage, and no free water was observed.

The tendon remains acceptable as indicated by the acceptable lift off values noted previously even though the data set cannot confirm being within the 10% acceptance standard provided by IWL 2523.3.

All other tendons tested for elongation are within the 10% acceptance standard provided by IWL 2523.3.

All tendon average seating forces exceed PLL; therefore, the requirements of IWL-2523.3 are met.

Tendon Grease Tests Test results for water content, water soluble chlorides, nitrates, and sulfites all met the required acceptance criteria and no further evaluation is required.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 82 of 126 3D05 End 1 had a Reserve Alkalinity of 12.7 and End 2 had a Reserve Alkalinity of 11.2.

Reserve alkalinity is acceptable for all tendons with exception to those evaluated in the following paragraphs.

Tendon 3D05 is the Unit 1 common tendon and may have a mixture of both 2009P and 2009P-4 grease. Given that there may be a mixture of grease types, the acceptance criteria for the common tendons is taken as a reserve alkalinity greater than 0, which is met for all common tendons tested.

(a) the cause of the condition that does not meet the acceptance standards; The cause of the low reserve alkalinity in tendon 3D05 Ends 1 and 2 is not known but indicates acidic contamination although no corrosion consistent with this type of contamination was found during the surveillance inspections.

(b) the applicability of the condition to any other plants at the same site; Low reserve alkalinity has been identified in tendons in all Oconee Units. Therefore, this condition does apply to other plants.

(c) the acceptability of the concrete containment without repair of the item; Low reserve alkalinity has been reported previously in this and other Oconee plants. No excessive corrosion has ever been identified as being associated with low reserve alkalinity.

Tendon 3D05 was partially drained of the old grease and new 2090P-4 grease was installed as part of the surveillance.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required beyond the grease replenishment already completed.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of IWL ISI surveillances.

Tendon Grease Fill Volume Tendons 45V25, 56V24, 61V28, 45V12, 23V30, 34V7, 24H39, 46H100, 35H63, 3D05, 2D14, and 1D54 failed to meet the acceptance criteria for tendon grease fill volume. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards;

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 83 of 126 The cause for the condition that does not meet the acceptance standards is loss of tendon grease over time through a potential combination of leaking tendon grease cap gaskets, leaking grease cap stud holes, leaking filler ports, or loss of grease from the tendon sheath to the concrete.

(b) the applicability of the condition to any other plants at the same site; The condition has been observed for all Oconee Units.

(c) the acceptability of the concrete containment without repair of the item; There is no evidence or documented technical data which suggests a loss of grease of this nature has any effect on the concrete containment. All tendons where net volume of grease exceeded 10% of the net duct volume of the sheath were found to have adequate grease coverage on anchorage components and no active corrosion was observed. Several years of experience have shown that an adequate covering of grease on all components provides adequate corrosion protection unless there is a source of water infiltration that could wash away the grease covering.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement activity is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances.

Examination of Tendon Anchorage Areas Concrete Cracks:

In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated. Tendons 2D10 End 1 and 2D14 End 1 do not meet the acceptance criteria for concrete cracks adjacent to the tendon anchorage. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards; A crack exceeding 0.01 inches in width was found within the inspection boundary for the tendons in question. The cause is most likely attributed to a combination of tendon prestress forces, concrete creep, concrete temperature and shrinkage, or poor consolidation at the outermost surface of the containment structure.

(b) the applicability of the condition to any other plants at the same site; Concrete cracking has been documented for all three Oconee Units primarily in the ring girder.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 84 of 126 (c) the acceptability of the concrete containment without repair of the item; Cracks exceeding 0.10 in outer face of ring girder are due to minimal reinforcing and large clear cover in this area due to existence of tendon pockets. This condition is not indicative of structural degradation and is acceptable in the as-found condition. No additional actions are required.

The additional concrete indications noted for Tendons 62H66 End 2, 1D17 End 2, and 1D54 End 2 are outside the load path for the tendon and do not adversely impact the tendons ability to maintain required prestress forces.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. Cracks near the tendons will continue to be monitored in subsequent surveillances and actions will be taken if conditions change.

Common Tendons (Unit 1 45V25, 24H39, and 3D05)

The common tendons are subject to examination categories L2.10, L2.30, L2.40, and L2.50.

The results for the common tendons are included in the results for the randomly selected population of tendons examined as part of the Year 50 Tendon Surveillance. The summaries and any required evaluations for the common tendons are discussed above.

Unit 2, Year 45 Tendon Surveillance Summary In accordance with Technical Specification 3.6.1, Containment and Selected Licensee Commitment 16.6.2, Containment Tendon Surveillance Program, the Unit 2 IWL Year 45 Inservice Post Tensioning System Examination was performed in accordance with the 2007 Edition with the 2008 Addenda of Subsection IWL, Requirements for Class CC Concrete Components of Light Water Cooled Power Plants, of Section XI, Division 1 of the ASME Code (The Code), with the modifications and limitations outlined in 10CFR Part 50, Paragraphs 50.55a(b)(2)(viii) and 50.50.55a(b)(2)(ix), except as amended by approved relief requests and submitted Safety evaluations granted by the NRC. Surveillances were performed under Work Order 02185403 between the dates of June 22, 2017, and June 22, 2019. Final grease sample test results were completed after Sep 27, 2019.

Subsection IWL-3310 requires an evaluation report of any items not meeting the acceptance standards of Subsection IWL-3100 or IWL-3200. This Summary and Evaluation Report summarizes the 45-year tendon surveillance results and provides any required evaluations.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 85 of 126 Schedule In accordance with IWL-2420(a) and (c), surveillances were scheduled for the 45th anniversary of the Structural Integrity test, which was completed June 22, 1973, plus or minus 12 months.

That is, between June 22, 2017, and June 22, 2019. Exams did not commence prior to June 22, 2017 and all exams were completed prior to June 22, 2019 with exception to the receipt of the grease sample test report and wire sample test report.

Tendons were randomly selected for surveillance in accordance with IWL-2521(a) and (b) and IWL-2521.1(a) and (b). In addition, tendons affected by repair/replacement activities were selected at random for surveillance in accordance with IWL-2521.2(a) and (b).

The number of tendons selected for examination is selected for a two percent sample size due to having met the acceptance criteria of IWL-3221.1 for the last three inspections.

The number of tendons selected for augmented examination is selected for a 4% sample size although the Year 45 surveillance inspection is the third inspection following the repair and replacement activities associated with the Steam Generator Replacement for Unit 2.

Subsequent inspections beyond Year 45 may use a reduced sample size given the provisions of IWL-2521-2(6) have been met.

All exams were performed as required per the Code. Inspections performed prior to the adoption of the 2007 Edition with the 2008 Addenda of the Code considered augmented examination inspections on the Steam Generator Replacement affected tendons to be Owner specified additions to the inspection scope, since no specific requirements for additional examinations were required. However, the 2007 Edition with the 2008 Addenda requires a random sampling of tendons to be selected from the population of affected tendons due to repair and replacement activities as was done for the Year 45 surveillance inspection.

Scope The following tendons were randomly selected in accordance with IWL-2521(a) and (b) and IWL-2521.2(a) and (b).

Table 3.4.5-2, Scope of Unit 2, Year 45 Tendon Surveillance Tendon Mark No.

L2.10 Lift-off L2.20 Wire Test L2.30 Anchorage &

Concrete L2.40 Grease Tests L2.50 Free H2O pH Notes 1D19 Y

N Y

Y Y

Common Tendon 2D04 Y

N Y

Y Y

2D22 Y

Y Y

Y Y

2D27 Y

N Y

Y Y

13H23 Y

N Y

Y Y

35H47 N

N Y

Y Y

SGRP R/R, DET/RET 35H51 Y

Y Y

Y Y

SGRP R/R, NEW Note 1 35H66 Y

N Y

Y Y

SGRP R/R, NEW AH 46H61 Y

Y Y

Y Y

46H94 Y

N Y

Y Y

51H104 Y

N Y

Y Y

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 86 of 126 Table 3.4.5-2, Scope of Unit 2, Year 45 Tendon Surveillance Tendon Mark No.

L2.10 Lift-off L2.20 Wire Test L2.30 Anchorage &

Concrete L2.40 Grease Tests L2.50 Free H2O pH Notes 62H86 Y

N Y

Y Y

Common Tendon 23V27 Y

N Y

Y Y

SGRP R/R, DET/RET 34V25 Y

Y Y

Y Y

SGRP R/R, NEW AH 45V17 Y

N Y

Y Y

Common Tendon 56V4 Y

N Y

Y Y

56V6 Y

Y Y

Y Y

61V23 Y

N Y

Y Y

Note 1: Alternate for 35H47 wire test and lift off due to interference.

The Code examination categories are specified for each tendon mark number in accordance with the ONS Third Interval Containment lnservice Inspection Plan. All Code required examinations were completed for the listed tendons.

Surveillance Tendon Force Measurement Results All tendons tested were found to exceed both the MRV and PLL forces; therefore, the requirements of IWL-3221.1(a) and IWL-3221.1(b) are met and no evaluation is required.

Additionally, Duke Energy has decided to perform lift-off measurements on the common tendons each surveillance interval as an owner specified examination for tracking and trending purposes. The tendons that were replaced as part of repair and replacement activities were tensioned to near original construction values. Hydraulic ram pressures are limited not to exceed 70% of yield strength for the tendon wire material, while in most cases tendons were tensioned to 80% of the yield strength. Until sufficient loss of prestress occurs over time, lift-off may not be achieved during tendon surveillances for those tendons that were replaced.

Tendon Force Prestress Loss for Predicted Tendon Forces In accordance with IWL-3221.1(c), tendon forces are acceptable given the prestressing forces for each type of tendon measured in IWL-3221.1(a) and (b) and if the measurement from the previous examination indicate a prestress loss such that predicted tendon forces meet the minimum design prestress forces at the next scheduled examination. The previous surveillance data is used with the results from the 45 Year Tendon Surveillance to determine a trend line to predict the tendon forces for each type of tendon at the 50 Year Tendon Surveillance.

The trend lines show a projected force for each tendon type expected for the 50 Year Tendon Surveillance that exceeds both the MRV and PLL forces. The standard deviation for the data for the past twenty years is calculated along with the cumulative distribution function to evaluate future tendon forces. The cumulative distribution is determined assuming the trend line is the same at Year 50. The trend data shows that the vertical tendons have an eight percent chance of being lower than PLL at Year 50, hoop tendons have a three percent chance of being lower, and dome tendons have a negligible chance of being lower than PLL at Year 50. These projected forces are acceptable given the acceptance criteria specified in IWL-3221.1(c).

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 87 of 126 Tendon Wire Samples Tendon wire tests were performed at the Duke Energy Metallurgy Lab at McGuire Nuclear Station on July 25, 2019. Tendons 2D22, 34V25, 35H51, 46H61 and 56V6 were selected for wire removal and inspection.

No corrosion or mechanical damage was recorded. All samples met their mechanical requirements of Tensile Strength and Percent Elongation in accordance with IWL 3221.2.

Tendon Elongation/Retensioning Tendons 2D22, 34V25, 35H51, 46H61 and 56V6 were selected for elongation measurements and retensioning.

All tendon average seating forces exceed PLL; therefore, the requirements of IWL-2523.3 are met.

Tendon Grease Tests Test results for water content, water soluble chlorides, nitrates, and sulfites all met the required acceptance criteria, and no further evaluation is required.

46H61 End 2 had a moisture content of 20% during initial testing of grease, a second grease sample was submitted and had a confirmation moisture content of 8%. The 8% moisture content is below the 10% threshold and is acceptable.

Reserve alkalinity is acceptable for all tendons with exception to those evaluated in the following paragraphs.

Tendons 62H86, 1D19, and 45V17 are the Unit 2 common tendons and may have a mixture of both 2009P and 2009P-4 grease. The test results imply that 45V17 is solely greased with 2009P-4 due to the higher reserve alkalinity. Given that there may be a mixture of grease types, the acceptance criteria for the common tendons is taken as a reserve alkalinity greater than 0, which is met for all common tendons tested.

Tendons 2D04 End 1, 2D22 End 2 13H23 End 2, and 51H104 End 2 had a base number that could not be detected and had results of < 0.500 which is the reporting limit. A follow-up acid test was performed for each of the four tendons. The follow-up test indicated the same findings of < 0.500 indicating the grease had acidic contamination. None of the tendons with this condition had failed results at both ends indicating that grease in the tendons could be somewhat segregated causing different results in different portions of the tendons.

(a) the cause of the condition that does not meet the acceptance standards; The cause of the low reserve alkalinity in tendons 2D04 End 1, 2D22 End 2 13H23 End 2, and 51H104 End 2 is not known, but indicates acidic contamination although no corrosion consistent with this type of contamination was found during the surveillance inspections.

(b) the applicability of the condition to any other plants at the same site;

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 88 of 126 Low reserve alkalinity has been identified in tendons in all Oconee Units. Therefore, this condition does apply to other plants.

(c) the acceptability of the concrete containment without repair of the item; Low reserve alkalinity has been reported previously in this and other Oconee plants. No excessive corrosion has ever been identified as being associated with low reserve alkalinity.

Tendons 2D04 End 1, 2D22 End 2, 13H23 End 2, and 51H104 End 2 were partially drained of the old grease and new 2090P-4 grease was installed as part of the surveillance.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required beyond the grease replenishment already completed.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of IWL ISI surveillances.

Tendon Grease Fill Volume Tendons 1D19, 2D04, 2D22, 2D27, 13H23, 46H61, 46H94, and 34V25 failed to meet the acceptance criteria for tendon grease fill volume. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards; The cause for the condition that does not meet the acceptance standards is loss of tendon grease over time through a potential combination of leaking tendon grease cap gaskets, leaking grease cap stud holes, leaking filler ports, or loss of grease from the tendon sheath to the concrete.

(b) the applicability of the condition to any other plants at the same site; The condition has been observed for all Oconee Units.

(c) the acceptability of the concrete containment without repair of the item; There is no evidence or documented technical data which suggests a loss of grease of this nature has any effect on the concrete containment. All tendons where net volume of grease exceeded 10% of the net duct volume of the sheath were found to have adequate grease coverage on anchorage components and no active corrosion was observed. Several years of experience have shown that an adequate covering of grease on all components provides adequate corrosion protection unless there is a source of water infiltration that could wash away the grease covering.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 89 of 126 (d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement activity is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances.

Examination of Tendon Anchorage Areas Replacing corrosion protection medium post surveillance inspection ensures that the metal surfaces are protected from further corrosion. Additionally, there are 6-month grease walkdowns performed to identify leaks and take remedial actions when possible or log the leak for next available opportunity repair.

Tendon 2D27 does not meet the concrete crack acceptance criteria. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated. Tendon 2D27 End 2 does not meet the acceptance criteria for concrete cracks adjacent to the tendon anchorage. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards; A crack exceeding 0.01 inches in width was found within the inspection boundary for the tendon.

The cause is most likely attributed to a combination of tendon prestress forces, concrete creep, concrete temperature and shrinkage, and poor consolidation at the outermost surface of the ring girder.

2D27 End 2 has a concrete Surface Crack within 2' of the bearing plate: Review of photo of the crack indicates the crack is just above the acceptance criteria of 0.010" and approximately 7" in length. The crack is on the ring girder exterior surface and does not run all the way to the bearing plate. Cracks exceeding 0.10 in outer face of ring girder are due to minimal reinforcing and large clear cover in this area due to existence of tendon pockets. This condition is not indicative of structural degradation and is acceptable in the as-found condition. No additional actions are required.

(b) the applicability of the condition to any other plants at the same site; Concrete cracking has been documented for all three Oconee Units primarily in the ring girder.

(c) the acceptability of the concrete containment without repair of the item; Cracks exceeding 0.10 in outer face of ring girder are due to minimal reinforcing and large clear cover in this area due to existence of tendon pockets. This condition is not indicative of structural degradation and is acceptable in the as-found condition. No additional actions are required.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 90 of 126 The indications noted for 2D27 are outside the load path for the tendon and do not adversely impact the tendons ability to maintain required prestress forces.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. Cracks near the tendons will continue to be monitored in subsequent surveillances and actions will be taken if conditions change.

Common Tendons The common tendons, 1D19, 62H86, and 45V17, are subject to examination categories L2.10, L2.30, L2.40, and L2.50. The results for the common tendons are included in the results for the randomly selected population of tendons examined as part, of the Year 45 Tendon Surveillance.

The summaries and any required evaluations for the common tendons are discussed above.

Unit 3, Year 50 Tendon Surveillance Summary In accordance with Technical Specification 3.6.1, Containment and Selected Licensee Commitment 16.6.2, Containment Tendon Surveillance Program, the Unit 3 IWL Year 45 Inservice Post Tensioning System Examination was performed in accordance with the 2007 Edition with the 2008 Addenda of Subsection IWL, Requirements for Class CC Concrete Components of Light Water Cooled Power Plants, of Section XI, Division 1 of the ASME Code (The Code), with the modifications and limitations outlined in 10CFR Part 50, Paragraphs 50.55a(b)(2)(viii) and 50.50.55a(b)(2)(ix), except as amended by approved relief requests and submitted Safety evaluations granted by the NRC. Surveillances were performed between the dates of May 7, 2018, to May 7, 2020. Final grease sample test results and tendon wire mechanical properties were completed after May 7, 2020.

Subsection IWL-3310 requires an evaluation report of any items not meeting the acceptance standards of Subsection IWL-3100 or IWL-3200. This Summary and Evaluation Report summarizes the 45-year tendon surveillance results and provides any required evaluations.

Schedule In accordance with IWL-2420(a) and (c), surveillances were scheduled for the 45th anniversary of the Structural Integrity test, which was completed May 7, 1974, plus or minus 12 months.

That is, between May 7, 2018, and May 7, 2020. Exams did not commence prior to May 7, 2018, and all exams were completed prior to May 7, 2020, with exception to the receipt of the grease sample test report and wire sample test report.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 91 of 126 Tendons were randomly selected for surveillance in accordance with IWL-2521(a) and (b) and IWL-2521.1(a) and (b). In addition, tendons affected by repair/replacement activities were selected at random for surveillance in accordance with IWL-2521.2(a) and (b).

Scope The following tendons were randomly selected in accordance with IWL-2521(a) and (b) and IWL-2521.2(a) and (b).

Table 3.4.5-3, Scope of Unit 3, Year 45 Tendon Surveillance Tendon Mark No.

L2.10 Lift-off L2.20 Wire Test L2.30 Anchorage &

Concrete L2.40 Grease Tests L2.50 Free H2O pH Notes 23V9 Y

N Y

Y Y

Common Tendon 56V5 Y

N Y

Y Y

61V11 Y

N Y

Y Y

61V1 Y

Y Y

Y Y

34V30 Y

Y Y

Y Y

SGR New AH 23V26 Y

N Y

Y Y

SGR New AH 62H51 Y

N Y

Y Y

Common Tendon 46H45 Y

N Y

Y Y

13H78 Y

N Y

Y Y

62H70 Y

Y Y

Y Y

13H43 Y

N Y

Y Y

35H59 Y

Y Y

Y Y

SGR New Tendon 35H50 Y

N Y

Y Y

SGR New Tendon 51H1 N(1)

N Y

Y Y

Buried Tendon 3D09 Y

N Y

Y Y

Common Tendon 3D18 Y

N Y

Y Y

2D24 Y

Y Y

Y Y

3D22 Y

N Y

Y Y

Note 1: Buried tendon, only 1 end accessible.

Surveillance Tendon Force Measurement Results All tendons tested were found to exceed both the MRV and PLL forces; therefore, the requirements of IWL-3221.1(a) and IWL-3221.1(b) are met and no evaluation is required.

Additionally, Duke Energy has decided to perform lift-off measurements on the common tendons each surveillance interval as an owner specified examination for tracking and trending purposes. The tendons that were replaced as part of repair and replacement activities were tensioned to near original construction values. Hydraulic ram pressures are limited not to exceed 70% of yield strength for the tendon wire material, while in most cases tendons were tensioned to 80% of the yield strength. Until sufficient loss of prestress occurs over time, lift-off may not be achieved during tendon surveillances for those tendons that were replaced.

Tendon Force Prestress Loss for Predicted Tendon Forces In accordance with IWL-3221.1(c), tendon forces are acceptable given the prestressing forces for each type of tendon measured in IWL-3221.1(a) and (b) and if the measurement from the previous examination indicate a prestress loss such that predicted tendon forces meet the

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 92 of 126 minimum design prestress forces at the next scheduled examination. The previous surveillance data is used with the results from the 45 Year Tendon Surveillance to determine a trend line to predict the tendon forces for each type of tendon at the 50 Year Tendon Surveillance.

The trend lines show a projected force for each tendon type expected for the 50 Year Tendon Surveillance that exceeds both the MRV and PLL forces. The standard deviation for the data for the past twenty years is calculated along with the cumulative distribution function to evaluate future tendon forces. The cumulative distribution is determined assuming the trend line is the same at Year 50. The trend data shows that the vertical tendons have an 0% chance of being lower than PLL at Year 50, hoop tendons have a 6.39% chance of being lower, and dome tendons have a negligible 0.01% chance of being lower than PLL at Year 50. These projected forces are acceptable given the acceptance criteria specified in IWL-3221.1(c).

Tendon Wire Samples Tendon wire tests were performed at the Duke Energy Metallurgy Lab at McGuire Nuclear Station on June 16, 2020. Tendons 2D24, 34V30, 35H59, 61V1 and 62H70 were selected for wire removal and inspection. The test results for each of the tested wires is as follows:

No corrosion or mechanical damage was recorded. All samples met their mechanical requirements of Tensile Strength and Percent Elongation in accordance with IWL 3221.2.

Tendon Elongation/Retensioning Tendons 2D24, 34V30, 35H59, 61V1 and 62H70 were selected for elongation measurements and re-tensioning.

All tendon average seating forces exceed PLL; therefore, the requirements of IWL-2523.3 are met.

Tendon Grease Tests Test results for water content, water soluble chlorides, nitrates, and sulfites all met the required acceptance criteria, and no further evaluation is required.

62H51 End 2 had a Reserve Alkalinity of 6.41.

Reserve alkalinity is acceptable for all tendons with exception to those evaluated in the following paragraphs.

Tendon 62H51 is the Unit 3 common tendon and may have a mixture of both 2009P and 2009P-4 grease. Given that there may be a mixture of grease types, the acceptance criteria for the common tendons are taken as a reserve alkalinity greater than 0, which is met for all common tendons tested.

(a) the cause of the condition that does not meet the acceptance standards;

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 93 of 126 The cause of the low reserve alkalinity in tendon 62H51 End 2 is not known but indicates acidic contamination although no corrosion consistent with this type of contamination was found during the surveillance inspections.

(b) the applicability of the condition to any other plants at the same site; Low reserve alkalinity has been identified in tendons in all Oconee Units. Therefore, this condition does apply to other plants.

(c) the acceptability of the concrete containment without repair of the item; Low reserve alkalinity has been reported previously in this and other Oconee plants. No excessive corrosion has ever been identified as being associated with low reserve alkalinity.

Tendon 62H51 was partially drained of the old grease and new 2090P-4 grease was installed as part of the surveillance.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required beyond the grease replenishment already completed.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of IWL ISI surveillances.

Tendon Grease Fill Volume Tendons 3D22, 2D24, 3D18, 35H50, 35H59, 13H43, 62H70, 13H78, 34V30, 61V1 and 61V11 failed to meet the acceptance criteria for tendon grease fill volume. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards; The cause for the condition that does not meet the acceptance standards is loss of tendon grease over time through a potential combination of leaking tendon grease cap gaskets, leaking grease cap stud holes, leaking filler ports, or loss of grease from the tendon sheath to the concrete.

(b) the applicability of the condition to any other plants at the same site; The condition has been observed for all Oconee Units.

(c) the acceptability of the concrete containment without repair of the item; There is no evidence or documented technical data which suggests a loss of grease of this nature has any effect on the concrete containment. All tendons where net volume of grease exceeded 10% of the net duct volume of the sheath were found to have adequate grease

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 94 of 126 coverage on anchorage components and no active corrosion was observed. Several years of experience have shown that an adequate covering of grease on all components provides adequate corrosion protection unless there is a source of water infiltration that could wash away the grease covering.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement activity is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances.

Examination of Tendon Anchorage Areas Concrete Cracks:

In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated. Tendons 23V9 End 2, 13H78 End 2, 3D09 End 1 and 2, 3D18 End 1 and 2, 2D24 End 1 and 3D22 End 1 does not meet the acceptance criteria for concrete cracks adjacent to the tendon anchorage. In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated.

(a) the cause of the condition that does not meet the acceptance standards; A crack exceeding 0.01 inches in width was found within the inspection boundary for the tendons in question. The cause is most likely attributed to a combination of tendon prestress forces, concrete creep, concrete temperature and shrinkage, or poor consolidation at the outermost surface of the containment structure.

(b) the applicability of the condition to any other plants at the same site; Concrete cracking has been documented for all three Oconee Units primarily in the ring girder.

(c) the acceptability of the concrete containment without repair of the item; Cracks exceeding 0.10 in outer face of ring girder are due to minimal reinforcing and large clear cover in this area due to existence of tendon pockets. This condition is not indicative of structural degradation and is acceptable in the as-found condition. No additional actions are required.

The indications noted for Tendons 23V9 End 2, 13H78 End 2, 3D09 End 1 and 2, 3D18 End 1 and 2, 2D24 End 1 and 3D22 End 1 are outside the load path for the tendon and do not adversely impact the tendons ability to maintain required prestress forces.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 95 of 126 (e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. Cracks near the tendons will continue to be monitored in subsequent surveillances and actions will be taken if conditions change.

Undocumented Broken Wires:

In accordance with IWL-3310, items with results which do not meet the acceptance standards of IWL-3100 or 3200 shall be evaluated. Tendon 3D18 does not meet the acceptance criteria for missing or undocumented wires or strands.

(a) the cause of the condition that does not meet the acceptance standards; The cause for the missing button head is unknown and there was no appreciable corrosion present to blame additionally there was not a protruding button head on the opposite end indicating that the button head could have simply been malformed and pulled into the stressing washer and not visible.

(b) the applicability of the condition to any other plants at the same site; Broken and missing button heads has been noted on all three Oconee units.

(c) the acceptability of the concrete containment without repair of the item; The missing or damaged button head does not adversely impact the concrete containments ability to maintain prestressed concrete as demonstrated by the lift-off forces observed during the surveillance.

(d) whether or not repair / replacement activity is required and, if required, the extent, method, and completion date for the repair /replacement activity; No repair/replacement is required.

(e) extent, nature, and frequency of additional examinations.

No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. No additional examinations are required beyond those scheduled as part of ASME Section IWL ISI surveillances. Cracks near the tendons will continue to be monitored in subsequent surveillances and actions will be taken if conditions change.

Common Tendons The common tendons, 62H51, 3D18, and 23V9, are subject to examination categories L2.10, L2.30, L2.40, and L2.50. The results for the common tendons are included in the results for the randomly selected population of tendons examined as part, of the Year 45 Tendon Surveillance.

The summaries and any required evaluations for the common tendons are discussed above.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 96 of 126 3.4.6 Containment Leakage Rate Testing Program - Type B and Type C Testing Program The ONS Type B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges and CIVs in accordance with 10 CFR 50, Appendix J, Option B. The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life. The 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 TS 5.5.2, the allowable maximum pathway total Type B and C leakage is 0.60 La (212,402 standard cubic centimeters per minute (sccm)) where La equals 354,000 sccm.

As discussed in NUREG-1493 (Reference 6), 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.

Type B and Type C Test Results A review of the as-left test values for ONS Units 1, 2, and 3 can be summarized as follows:

x ONS Unit 1 As-Left maximum pathway leak rate shows an average of 10.7% of 0.60 La with a high of 16.7% of 0.60 La.

x ONS Unit 2 As-Left maximum pathway leak rate shows an average of 11.8% of 0.60 La with a high of 18.5% of 0.60 La.

x ONS Unit 3 As-Left maximum pathway leak rate shows an average of 15.5% of 0.60 La with a high of 20.3% of 0.60 La.

Tables 3.4.5-1, 3.4.5-2 and 3.4.5-3 provides LLRT data trend summaries for ONS Unit 1, Unit 2, and Unit 3 since 2015 (the last ILRTs were performed in 2014, 2015 and 2016 respectively).

Table 3.4.6-1, ONS Unit 1 Types B and C LLRT Combined As-Left Trend Summary Outage & Year 1EOC29 2016 1EOC30 2018 1EOC31 2020 1EOC32 2022 1EOC33 2024 As-Left Max Path (sccm) 14,811 11,684 29,106 22,238 35,517 Fraction of 0.6La 7.0 5.5 13.7 10.5 16.7 Table 3.4.6-2, ONS Unit 2 Types B and C LLRT Combined As-Left Trend Summary Outage & Year 2EOC27 2015 2EOC28 2017 2EOC29 2019 2EOC30 2021 2EOC31 2023 As-Left Max Path (sccm) 10,485 20,359 39,353 19,372 35,553 Fraction of 0.6La 4.9 9.6 18.5 9.1 16.7

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 97 of 126 As shown in Tables 3.4.5-1, 3.4.5-2, and 3.4.5-3 above, the record keeping requirements for ONS are different from those identified in other LARs requesting a permanent 15-year ILRT Interval with Containment Leakage Rate Testing Programs already following 10 CFR 50, Appendix J, Option B. For ONS, which adopted 10 CFR 50, Appendix J, Option B on July 28, 2011 (Reference 15), has not implemented extended Type B or Type C LLRT intervals beyond the base interval of 30 months as provided in NEI 94-01 Revision 0. Therefore, it is the position of ONS that as-found testing was not required since performance-based intervals were not being established. However, going forward, it is the intention of ONS to establish and implement extended interval testing in accordance with NEI 94-01 Revision 0 and then NEI 94-01 Revision 3-A upon the approval of this submittal.

Repeat As-Found Failures None were identified.

Performance Summary x

For Unit 1, 0% of all penetrations eligible for extended intervals are on extended intervals.

x For Unit 2, 0% of all penetrations eligible for extended intervals are on extended intervals.

x For Unit 3, 0% of all penetrations eligible for extended intervals are on extended intervals.

3.4.7 Type B and Type C Local Leak Rate Testing Program Implementation Review Tables 3.4.6-1, 3.4.6-2, and 3.4.6-3 (above) identify that ONS, Units 1, 2, and 3 components, respectively, are not on Appendix J, Option B performance-based extended test intervals. The component test intervals for ONS components are on 24-month intervals except airlocks, which are on 30-month intervals.

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

Table 3.4.6-3, ONS Unit 3 Types B and C LLRT Combined As-Left Trend Summary Outage & Year 3EOC28 2016 3EOC29 2018 3EOC30 2020 3EOC31 2022 3EOC32 2024 As-Left Max Path (sccm) 32,178 24,443 36,055 28,473 43,165 Fraction of 0.6La 15.2 11.5 17.0 13.4 20.3

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 98 of 126 For the ONS Primary Containment, the following site specific and industry events have been evaluated for impact:

x Information Notice (IN) 1992-20, Inadequate Local Leak Rate Testing x

IN 2010-12, Containment Liner Corrosion x

RIS 2016-07, Containment Shell or Liner Moisture Barrier Inspection x

ML24110A112, Duke Energys response to RAI questions Each of these areas is discussed in detail in Sections 3.5.1 through 3.5.4, respectively.

3.5.1 IN 1992-20, Inadequate Local Leak Rate Testing The NRC issued IN 92-20 to alert licensees of problems with local leak rate testing of two-ply stainless-steel bellows used on piping penetrations at four different plants: Quad Cities, Dresden Nuclear Station, Perry Nuclear Plant, and the Clinton Station. Specifically, LLRTs could not be relied upon to accurately measure the leakage rate that would occur under accident conditions, because, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to the problem. The common issue in the four events was the failure to adequately perform local leak rate testing on different penetration configurations leading to problems that were discovered during ILRT tests in the first three cases.

In the event at Quad Cities, the two-ply bellows design was not properly subjected to LLRT pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B LLRT tested as configured.

In the events at both Dresden and Perry, flanges were not considered a leakage path when the Type C LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT 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 LLRT tested.

At ONS, the only bellows assemblies present on each unit is found on the fuel transfer tube penetrations. However, the transfer tube penetrations are welded directly to the containment liner and the bellows do not represent a containment atmospheric release pathway. ONS does not have the problems described in IN 92-20.

3.5.2 IN 2010-12, Containment Liner Corrosion The NRC issued this IN to inform addressees of recent issues involving corrosion of the steel

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 99 of 126 reactor containment building liner, providing examples from three different units.

Concrete reactor containments are typically lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions. Operating experience shows that containment liner corrosion is often the result of liner plates being in contact with objects and materials that are lodged between or embedded in the containment concrete. Liner locations that are in contact with objects made of an organic material are susceptible to accelerated corrosion because organic materials can trap water that combined with oxygen will promote carbon steel corrosion. Organic materials can also cause a localized low pH area when they decompose. Organic materials located inside containment can come in contact with the containment liner and cause accelerated corrosion. However, corrosion that originates between the liner plate and concrete is of a greater concern because visual examinations typically identify the corrosion only after it has significantly degraded the liner. In some cases, licensees identified such corroded areas by performing ultrasonic examination of suspect areas (e.g., areas of obvious bulging, hollow sound).

Duke Energys evaluation of this OE concluded that it is applicable to ONS as the ONS containment has a steel liner. It also noted that the Containment IWE-IWL Program and examination procedures contain steps to perform visual examinations for corrosion of the steel liner and identify liner bulge areas.

3.5.3 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.

Two examples of recent operating experience are provided below.

Watts Bar Nuclear Plant, Unit 2 Watts Bar Nuclear Plant, Unit 2, uses a stand-alone steel containment vessel shell. The concrete base mat is poured directly against the containment shell. The lower approximately 4-foot (1.2-meter) portion of the containment vessel is covered by a thermal insulation package that includes stainless steel flashing and caulking. The flashing and caulking acts as a barrier to protect the insulation underneath from moisture. As a result, the thermal barrier also protects the concrete-liner interface and serves as a moisture barrier. Inspection of the flashing was performed as a non-ASME Code examination.

NRC inspectors questioned whether this barrier also acts to prevent moisture intrusion at the base mat to containment vessel shell interface and should be inspected per the ASME

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 100 of 126 requirements, specifically Subsection IWE, Table IWE-2500-1, Category E-A, Item E1.30, Moisture Barriers. The applicant subsequently revised its Containment Preservice Inspection Program Plan to include the flashing and caulking as an Item E1.30 ASME Code examination.

This issue was documented as an observation in Inspection Report (IR) 05000391/2015604 (ADAMS Accession No. ML15181A446).

Surry Power Station, Units 1 and 2 The Surry Power Station containment configuration includes a concrete containment with a steel liner, and a concrete floor poured flush to the steel liner. The original design did not include a moisture barrier at the interface between the concrete floor and the steel liner. Subsequently, the licensee installed a moisture barrier at this junction. However, the area was never identified as a moisture barrier, and never received the appropriate inspections per ASME Section XI, Subsection IWE. Once the licensee installed a moisture barrier, regardless of the original design, examinations per Table IWE-2500-1, Item E1.30, were required under 10 CFR 50.55a(b). The licensee later removed the moisture barrier. At this point, the licensee reintroduced the configuration that is discussed in IWE-1240, Surface Areas Requiring Augmented Examination.Section XI of ASME Code, IWE-1241, Examination Surface Areas, specifically mentions concrete-to-steel shell or liner interfaces as areas that may require augmented examinations in accordance with Table IWE-2500-1, Examination Category E-C, Item E4.11. When the licensee reintroduced this configuration, an augmented examination should have been performed, or an evaluation should have been completed demonstrating why augmented examinations in accordance with IWE-1241 were unnecessary. The lack of proper inspection resulted in a green finding with an associated non-cited violation because the licensee failed to make an augmented examination in accordance with Section XI, Subsection IWE-1241, Table IWE-2500-1, Category E-C, Item E 4.11, as required by 10 CFR 50.55a(g).

This issue is documented in IR 05000280/2015002 (ADAMS Accession No. ML040280056).

The NRC staff expects licensees to inspect 100 percent of accessible moisture barriers during each inspection period, in accordance with Table IWE-2500-1, Item E1.30, as required by 10 CFR 50.55a(g). Items within the scope of E1.30 inspections shall be identified based on the function of the item as described in the associated Table IWE-2500-1 note rather than relying on the name given to the material or the similarity to Figure IWE-2500-1. As noted previously, Figure IWE-2500-1 represents one typical moisture barrier geometry; however, it is not all-inclusive. If a material prevents intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces or at metal-to-metal interfaces that are not seal-welded, the material shall be inspected as a moisture barrier. If the material is used as a basis for not performing augmented examinations of a shell or liner interface location per IWE-1241, the material is serving the purpose as described above, and shall be inspected as a moisture barrier. Furthermore, if the Item E1.11 and Item E1.30 inspections are addressed in the same procedures, the inspection scope and acceptance criteria should identify the different surfaces. Items E1.11 and E1.30 address different materials with different geometries and acceptance criteria.

Duke Energys evaluation of this OE concluded that it is applicable to ONS and the following actions were taken:

1.

Identify all specific locations within each Containment where the following conditions exist:

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 101 of 126 x

Back-to-back metal interfaces at the containment shell (interior and exterior surfaces) or liner (interior surfaces only) that are not seal-welded (e.g., baseplates, stitch-welded attachments). For each of these, identify and document whether any moisture barrier material exists, and the configuration and type of moisture barrier present, including any coatings that seal the interface.

x Interfaces between the containment shell (interior and exterior surfaces) or liner (interior surfaces only) and any adjacent concrete (e.g.,

embedment zones, interior floor or wall interfaces) where the existence of concrete or other materials (e.g., expansion joint material) prevents visual examination of any containment shell or liner metallic surface beyond the interface. For each of these, identify and document whether any moisture barrier material exists, and the configuration and type of moisture barrier present, including any coatings that seal the interface.

x Expansion joints and other concrete-to-concrete interfaces in concrete floors placed directly over on the interior surfaces of the containment liner plate. For each of these, identify and document whether any moisture barrier material exists, and the configuration and type of moisture barrier present, including any coatings that seal the interface.

2.

For all locations identified above where there is no moisture barrier present, or where the condition of any moisture barrier has degraded such that moisture intrusion behind the joint could occur if the joint is exposed to water, take one of the following actions:

x Install a moisture barrier and revise the Inservice Inspection Plan to document the location of the moisture barrier. Schedule the item for examination in accordance with Table IWE-2500-1, Examination Category E-A, Item E1.30 x

Document the basis for why inaccessible surfaces of the containment shell or liner behind the specific location are not subject to Augmented Examination in accordance with IWE-1241 in the Inservice Inspection Plan (or in another document that shall be maintained as a QA Record and can be referenced in the Inservice Inspection Plan) x Revise the Inservice Inspection Plan to document the location of each interface and schedule the affected item (moisture barrier) for augmented examination in accordance with IWE-1242 and Table IWE-2500-1, Examination Category E-C, Item E4.11 or E4.12, as applicable

3.

Verify that procedures for performing Table IWE-2500-1, Examination Category E-A, Item E1.30 examinations contain sufficient information pertaining to the scope (examination boundary) and acceptance standards for visual examination of all types of moisture barriers at each site. Generate a PRR for any procedure

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 102 of 126 used for visual examination of moisture barriers if the scope or acceptance standards are not clear.

ONS Unit 1 Refueling Outage 1EOC29 (Fall 2016), Unit 2 Refueling Outage 2EOC28 (Fall 2017), and Unit 3 Refueling Outage 3EOC29 (Spring 2018) are the last outages remaining in Period 1 of Interval 5 during which full compliance with the moisture barrier periodic examination requirements of Table IWE-2500-1, Examination Category E-A, Item E1.30 may be possible.

During each of these refueling outages, the actions detailed in 1, 2 and 3 above were completed to avoid the possibility of an NRC violation. Any additional examinations required as a result of actions taken in response to actions 1, 2, and 3 above were completed by the end of outages 1EOC29, 2EOC28, and 3EOC29 to remain compliant during Period 1 of the 5th Interval.

3.5.4 ML24110A112, Duke Energys response to RAI questions By letter dated November 16, 2023 ADAMS Accession No. ML23320A111, Duke Energy, submitted a LAR for ONS Units 1, 2, and 3. The proposed change allowed for a one-time extension to the ten-year frequency of the ONS Units 1, 2 and 3 ILRT or Type A test.

The U.S. Nuclear Regulatory Commission (NRC) staff reviewed the LAR and determined that additional information is needed to complete their review. Duke Energy received the request for additional information (RAI) from the NRC through electronic mail on March 26, 2024 (ADAMS Accession No. ML24086A377).

The following provides Duke Energys response to the RAI questions.

RAI No. 1

=

Background===

In Section 3.1.2, Containment Isolation System, of its LAR, the licensee describes the types of fluid penetrations which require isolation after an accident at ONS. In the subsection titled Periodic Operability Tests, the licensee states that each containment isolation valve will be tested periodically during normal operation or during shutdown conditions to assure its operability when needed. In addition, the licensee states that a program of testing and surveillance of each of the three Reactor Buildings has been developed to provide assurance, during service, of the capability of each containment system to perform its intended safety function. The NRC regulations require the licensee to implement the AMSE OM Code as incorporated by reference in 10 CFR 50.55a for the IST Program to assess the operational readiness of specific pumps, valves, and dynamic restraints at ONS.

Request for Additional Information Please describe any changes to the IST Program at ONS, including testing of containment isolation valves, that will be implemented as part of the LAR to revise TS 5.5.2 for a one-time extension of the containment Type A leak rate test frequency at ONS. If any IST Program changes are planned that would not meet the NRC regulatory requirements in the ASME OM Code as incorporated by reference in 10 CFR 50.55a, the licensee should submit requests for those changes in accordance with the NRC regulations.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 103 of 126 Duke Energy Response to RAI No. 1 No changes to the IST Program at ONS will be implemented as a result of this proposed change to revise TS 5.5.2 for a one-time extension of the containment Type A leak rate test frequency.

RAI No. 2

=

Background===

Enclosure to the LAR, Section 3.3.3 Results of Recent Containment Examinations, Part Oconee Unit 2 2019 Moisture Barrier Inspection, identified 9 non-conforming conditions during the examination of the moisture barrier.

Issue The non-conforming conditions states the moisture barrier is missing, cracked, has separated from the wall, or contain holes; however, insufficient discussion is provided about the condition of the containment liner behind the non-conforming moisture barrier. A degraded moisture barrier could indicate the presence of degradation in the inaccessible areas behind the moisture barrier. Furthermore, a degraded moisture barrier could allow moisture to contact the containment and cause degradation in an inaccessible area.

Requests for Additional Information

1. Summarize the results of any 10 CFR 50.55a(b)(2)(ix)(A) evaluations associated with the noted non-conforming moisture barrier conditions or explain how it was determined that the inaccessible portions of the containment were not impacted and that an evaluation was not necessary.

2. Provide a description of the corrective actions taken or engineering evaluation for the non-conforming moisture barrier defects that were identified (missing, cracked, separated from the wall, and holes).

Duke Energy Response to RAI No. 2

1.

During refueling outage O2R29 (Fall, 2019), periodic visual examinations of all moisture barriers within containment were performed in accordance with ASME Section XI requirements (Reference 1). The examination of the moisture barrier was to identify any unacceptable defects that would permit intrusion of moisture against inaccessible areas of pressure retaining surfaces of the metallic containment liner. These visual examinations revealed several areas of the degradation and delamination between the moisture barrier and the containment liner. Per IWE-3512, degraded moisture barriers that could permit intrusion of moisture against inaccessible surfaces of the metallic containment liner shall be corrected by corrective measures. Therefore, all identified areas with degradation or delamination were replaced with new moisture barriers and reinspected in accordance with ASME Section XI, Section IWE-3122.2 during O2R29. When the old moisture barrier was removed, the liner behind the moisture barrier was made accessible for VT-1 examination. A VT-1 examination of the exposed metallic containment liner was performed and revealed no corrosion or relevant conditions. Afterwards, the moisture

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 104 of 126 barrier was replaced, and a preservice VT-1 exam of the replaced moisture barrier was performed. Therefore, since all the metallic containment liner located behind degraded moisture barriers was examined and no relevant conditions were identified, evaluations associated with inaccessible portions of containment were not required.

2.

Prior to completing outage O2R29, corrective measures in compliance with IWE-3122.2 were performed on all degraded moisture barriers identified during the IWE visual examinations. Specifically, all degraded/delaminated moisture barriers identified were completely removed allowing accessibility to perform a VT-1 exam of the exposed metallic containment liner. These VT-1 exams revealed no corrosion or relevant conditions associated with the metallic containment liner. As needed, touch-up coatings were applied to the metallic containment liner in accordance with site coatings maintenance requirements. Following these metallic liner coating repairs, a new moisture barrier was installed between the liner and concrete basement floor. A preservice VT-1 of the newly replaced moisture barrier was performed prior to continued service. Subsequent periodic examinations of all moisture barriers are performed in accordance with ASME Section XI, Subsection IWE as scheduled in the ONS Containment IWE Inservice Inspection Plan and Schedule document.

3.6 LICENSE RENEWAL AGING MANAGEMENT ONS UFSAR Chapter 18, Aging Management Programs and Activities, contains the UFSAR Supplement as required by 10 CFR 54.21(d) for the ONS License Renewal Application (LRA).

The application (Reference 36), including information provided in additional correspondence, provided sufficient information for the NRC to complete their technical and environmental reviews and provided the basis for the NRC to make the findings required by Section 54.29 (Final Safety Evaluation Report - Final SER) (Reference 37). Pursuant to the requirements of Section 54.21(d), the UFSAR supplement for the facility must contain a summary description of the programs and activities for managing the effects of aging and the evaluation of time-limited aging analyses for the period of extended operation determined by Section 54.21 (a) and (c),

respectively.

3.6.1 ASME Section XI, Subsection IWE

a.

The Oconee containment structures each consist of a post-tensioned reinforced concrete cylinder and dome connected to and supported by a massive reinforced concrete foundation slab. The entire interior surface of these structures is lined with a 1/4 thick (or greater) ASTM A36 or A516 steel plate to assure a high degree of leak tightness. The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWE aging management program implements the requirements of ASME Code Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, Subsection IWE, in accordance with 10 CFR 50.55a and addresses the steel containment liners and their integral attachments, containment penetrations, hatches, airlocks, moisture barriers, and pressure-retaining bolting.

The program was developed in accordance with ASME Section XI, 2007 Edition through the 2008 Addenda as approved by 10 CFR 50.55a. The ONS CISI Plans and Schedules are updated every 10 years in accordance with 10 CFR 50.55a(g)(4)(ii). Current activities implemented to satisfy the Oconee Nuclear Station ASME Section XI, Subsection IWE

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 105 of 126 aging management program are defined in the ONS Containment Inservice Inspection (CISI) Program submitted for the Third Ten-Year Interval.

b.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWE aging management program inservice inspections of Units 1, 2, and 3 components are implemented using procedures which comply with the requirements of the applicable codes referenced in the Containment ISI Plan. Visual, volumetric, and other examinations will be used as required. The ONS ASME Section XI, Subsection IWE aging management program specifies acceptance standards consistent with those in IWE-3000, documents relevant conditions in the corrective action program, and includes expansion of the inspection scope when degradation exceeding the acceptance criteria are found.

c.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWE aging management program inspects surfaces completely covered by coatings or sealant.

These surfaces receive a general visual inspection to identify evidence of damage or degradation. The ONS Protective Coating Monitoring and Maintenance aging management program monitors containment coatings to provide reasonable assurance of emergency core cooling system (ECCS) operability. This is a separate program from the ASME Section XI, Subsection IWE aging management program.

d.

Oconee Nuclear Station (ONS) Units 1, 2, and 3 are pressurized water reactors (PWRs) and not boiling water reactors (BWR). Therefore; the ONS ASME Section XI, Subsection IWE aging management program does not incorporate the aging management activities, recommended in the Final License Renewal Interim Staff Guidance (LR-ISG)-2006-01, needed to address the potential loss of material due to corrosion in the inaccessible areas of the boiling water reactor (BWR) Mark I steel containment.

e.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWE aging management program does not contain any two-ply bellows within the scope of the program. Stainless steel pipes that penetrate the containment are welded to a stainless steel split ring that is welded to a carbon steel dished head. The dished head is welded to the carbon steel containment liner. A dissimilar metal weld exists between the carbon steel dished head and stainless steel split ring. Plant operating experience has not identified any stress corrosion cracking associated with these welds. The ASME Section XI, Subsection IWE program and the 10 CFR Part 50, Appendix J program manages the aging of these dissimilar metal welds. Containment liners and penetrations were analyzed for cyclic fatigue and, except for the main steam and feedwater penetrations, were exempted from further fatigue consideration by fatigue waiver. For the containment liner, a one-time volumetric examination of metal liner surfaces that are inaccessible from one side will be performed if triggered by plant-specific operating experience. This supplemental volumetric examination consists of a sample of one-foot square locations that include both randomly-selected and focused areas most likely to experience degradation based on operating experience and/or relevant considerations such as environment. The program includes preventative actions for storage, lubrication, and stress corrosion cracking potential of high strength structural bolting.

3.6.2 ASME Section XI, Subsection IWL

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 106 of 126

a.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWL aging management program implements the examination requirements of the ASME Code Section XI, Subsection IWL, as mandated by 10 CFR 50.55a, Codes and Standards.

The scope of the program includes reinforced concrete and unbonded post-tensioning system.

The current program complies with ASME Code Section XI, Subsection IWL, 2007 Edition through 2008 Addenda, supplemented with the applicable requirements of 10 CFR 50.55a(b)(2). This program is consistent with provisions in 10 CFR 50.55a that specify the use of the ASME Code edition in effect 12 months prior to the start of the start of the inspection interval. The program will use the ASME Code edition consistent with the provisions of 10 CFR 50.55a during the subsequent period of extended operation. In accordance with 10 CFR 50.55a(g)(4)(ii), the ISI program is updated each successive 120-month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval

(

Reference:

O-ISIC3-62-0001, Section 1.0). ONS does not utilize grouted tendons, and the guidance of U.S. Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.90 is not applicable.

b.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWL aging management program uses visual examination as the primary inspection method, supplemented by testing. The program requires that tension tests will be performed on wires removed from detensioned sample tendons to determine yield strength, ultimate tensile strength, and elongation. Lift-off testing is performed on selected tendons. Lift-off forces are measured and compared to established acceptance criteria in accordance with IWL-3200.

The program examines corrosion protection medium and free water (if present) of sample tendons and will analyze in accordance with IWL-2525.2. ASME Section XI, Subsection IWL-2525.2 requires that corrosion protection medium samples shall be thoroughly mixed and analyzed for reserve alkalinity, water content, and concentration of water soluble chlorides, nitrates, and sulfides. Analyses shall be performed in accordance with the procedures specified in Table IWL-2525-1. Free water samples shall be analyzed to determine pH.

c.

The Oconee Nuclear Station (ONS) ASME Section XI, Subsection IWL aging management program identifies all tendons that have been impacted by repair and replacement activity. In accordance with Table IWL-2521-2, if the population of tendons of a particular type affected by repair/replacement activities equals or exceeds 5% of the total number of tendons of that type, then Item L2.20 is applicable to that population as well. This is the case for ONS, therefore the exam sample size for all units will use a 4%

sample size or 2 hoops and 2 vertical tendons on each unit every 5 years. Exams L2.10, L2.30, L2.40, & L2.50 are required for both tendons of each type. In addition, wire removal, elongation measurement, and wire testing exams (L2.20) are required only on 1 tendon of each type during each surveillance.

3.6.3 Protective Coating Monitoring and Maintenance The Protective Coating Monitoring and Maintenance program is an existing condition monitoring

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 107 of 126 program that manages loss of coating integrity of Service Level I coatings inside Containment.

The program manages coating system selection, application, visual inspections, assessments, repairs, and maintenance of Service Level I protective coatings.

Maintenance of coatings is consistent with ASTM D5163-05a, Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants. The program includes activities to monitor and assess the material condition of Service Level I coatings applied to steel and concrete surfaces inside Containment by performing visual inspections with qualified inspectors to ensure there is no coating degradation.

Maintenance of Service Level I coatings applied to carbon steel and concrete surfaces inside Containment (e.g., steel liner, structural steel, supports, penetrations, and concrete walls and floors) will serve to prevent or minimize the loss of material of carbon steel components due to corrosion and aids in decontamination. This program ensures that the Service Level I coatings maintain adhesion to not affect the intended function of the emergency core cooling systems (ECCS) suction strainers.

The program also provides controls over the amount of unqualified coatings. Unqualified coating may fail in a way to affect the intended function of the ECCS suction strainers. Therefore, the quantity of degraded and unqualified coating is controlled and assessed during each inspection report to ensure that the amount of unqualified coating in the primary containment is kept within acceptable design limits to support the post-accident operability of the ECCS.

3.6.4 10 CFR Part 50, Appendix J

a.

The Oconee primary reactor containment system consists of the containment liner, and fluid penetrations, lock and hatch penetrations, and electrical penetrations. The existing 10 CFR Part 50, Appendix J aging management program utilizes periodic containment leak rate tests performed in accordance with the requirements described in Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," to ensure that containment leakage does not exceed allowable leakage rates specified in Technical Specifications and that the integrity of the containment structure is maintained during its service life.

b.

The Oconee 10 CFR Part 50, Appendix J aging management program is an existing program that relies on periodic leak rate testing to ensure that age-related degradation does not impact the pressure-retention function of the primary containment boundary components. This program relies on indirect detection of age-related degradation and is supplemented by other aging management programs including, the ASME Section XI, Subsection IWE and ASME Section XI, Subsection IWL aging management programs which include visual inspections to allow for direct detection of age-related degradation mechanisms.

c.

Oconee implements a performance-based (Option B) containment leak rate test program to meet the requirements of 10 CFR Part 50, Appendix J. The Oconee 10 CFR Part 50, Appendix J aging management program complies with the guidance provided in U.S.

Nuclear Regulatory Commission (NRC) Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program" and Nuclear Energy Institute (NEI) 94-01, "Industry Guideline for Implementing Performance-Based Option for 10 CFR Part 50, Appendix J,"

as approved by the NRC final safety evaluation for NEI 94-01, Revision 2-A and Revision

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 108 of 126 3-A. The program consists of periodic containment leak rate testing including, integrated leak rate testing (Type A), Type B local leak rate testing of pressure-retaining boundaries other than valves (i.e., penetrations), and Type C local leak rate testing of valves.

d.

The Oconee 10 CFR Part 50, Appendix J integrated leak rate tests (Type A tests) measure the containment system overall integrated leakage rate under conditions representing DBA containment pressure and system alignments. This testing ensures that the containment leakage rate used in the evaluation of offsite dose resulting from postulated accidents is bounding for all accident scenarios including for the calculated maximum peak containment pressure resulting from the limiting design basis LOCA (59.0 psig).

Type B local leak rate testing of containment penetrations are performed to detect local leaks and measure leakage across each pressure-retaining containment penetration.

Type B tests measure leakage across pressure-retaining boundaries including, containment penetrations of which the design incorporates resilient seals, gaskets, sealant components, expansion bellows, or flexible seal assemblies; seals, including door operating mechanism penetrations; and doors and hatches with resilient seals or gaskets except for seal-welded doors.

Type C local leak rate testing of containment isolation valves are performed to detect local leaks and measure leakage across containment isolation valves installed in containment penetrations or lines penetrating containment. Type C leak rate test measure leakage rates from containment isolation valves which are potential gaseous leakage pathways from containment during a design-basis LOCA.

e.

The Oconee 10 CFR Part 50, Appendix J aging management program requires a general visual inspection of accessible interior and exterior surfaces of the containment system and components prior to pressurization for a Type A leak rate test. Any irregularities (e.g.,

cracking, peeling, delamination, corrosion, structural deterioration) identified during this inspection are evaluated or repaired as required prior to commencing the Type A Test. In addition, the program is supplemented by other aging management programs including, the ASME Section XI, Subsection IWE and ASME Section XI, Subsection IWL aging management programs which include periodic visual inspections to allow for direct detection of age-related degradation mechanisms. These inspections are sufficient to uncover any evidence of structural deterioration that may affect the containment structure leakage integrity or the performance of Type A testing.

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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 109 of 126 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance ONS 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.

ONS will utilize 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, Revision 3-A, is more inclusive because it considers excessive leakage in the performance determination.

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

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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 110 of 126 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance ONS Response

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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 111 of 126 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance ONS 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.

Steam Generator replacements were conducted using construction openings in each containment followed by the performance of ILRTs following restoration.

Reference Section 3.1.1 of this submittal.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 112 of 126 Table 3.7.1-1: RG 1.163 Revision 1, Staff Regulatory Guidance Staff Regulatory Guidance ONS 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)).

ONS 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, Duke Energy 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. ONS 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 in the associated SER (Reference 2):

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 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 113 of 126 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:

x 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.

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

x 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 ONS, Units 1, 2 and 3, 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 ONS 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 ONS, Units 1, 2 and 3 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.

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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 114 of 126 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:

x 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.

x 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%

in the LLRT periodicity. As such, ONS, Units 1, 2 and 3 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 115 of 126 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 ONS 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 ONS 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 ONS 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.

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-56.8-2020 (Reference 52) 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 ONS, 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 ONS, 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 116 of 126 3.8 Conclusion RG 1.163 Revision 1, dated June 2023, and NEI 94-01, Revision 3-A, dated July 2012, describe 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 and Type C test intervals to 75 months. NEI 94-01, Revision 3-A, delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. ONS is adopting the guidance of RG 1.163 Revision 1 and NEI 94-01, Revision 3-A for the ONS, Units 1, 2 and 3, 10 CFR 50, Appendix J testing program plan.

Based on the previous ILRTs conducted at ONS, Units 1, 2 and 3, Duke Energy concludes 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 ONS inspection programs:

x Containment Inservice Inspection Program, Subsection IWE x

Containment Inservice Inspection Program, Subsection IWL x

Nuclear Coatings Program This experience is supplemented by risk analysis studies, including a risk assessment performed specifically for ONS. The risk assessment concludes that increasing the ILRT interval on a permanent basis to a one-in-fifteen-year frequency is not considered to be significant because it represents only a small change in the ONS risk profile.

4.0 REGULATORY EVALUATION

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

10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, 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

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 117 of 126 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 (Reference 11), 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 2), 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), indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.

The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2.

For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC staff finds that the Type A testing methodology, as described in ANSI/ANS-56.8-2002 (Reference 30), and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, 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 3) and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications (Reference 42). The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regard to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the SE.

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 in regard to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and RG 1.163 Revision 1, 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 RG 1.163 Revision 1 license amendment to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 118 of 126 authorized by the NRC in the associated referenced SER:

x Diablo Canyon Nuclear Power Plant, Units 1, and 2 issued March 27, 2025 (Reference

22) 4.3 No Significant Hazards Consideration Duke Energy Carolinas, LLC (Duke Energy), proposes to amend the Technical Specifications for Oconee Nuclear Station Units 1, 2 and 3 (ONS) 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 ONS TS 5.5.2, 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 NEI 94-01, Revision 3-A.

In addition, the proposed change also proposes the following administrative changes to TS 5.5.2:

x Deleting the information regarding the performance of containment visual inspections as required by RG 1.163, Regulatory Position C.3 as the containment inspections are presently addressed in TS SR 3.6.1.1.

x Deleting the information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026, for ONS 1, November 28, 2027, for ONS 2, and May 25, 2028, for ONS 3 as these Type A tests shall be scheduled in accordance with RG 1.163 Revision 1.

Duke Energy has evaluated whether or not a significant hazards consideration is involved with the proposed amendment to the ONS TS by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:

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

Response: No.

The proposed amendment to the Technical Specifications (TS) involves the revision of ONS TS Section 5.5.2 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.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 119 of 126 Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.

The proposed 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 (IE) probabilistic risk analysis (PRA) is 0.0076 person-rem/year, 0.0071 person-rem/year, and 0.0072 person-rem/year for Units 1, 2 and 3.

Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2-A states that a "small" SRSXODWLRQLVGHILQHGDVDQLQFUHDVHRISHUVRQ-rem per year RURIWKHWRWDO

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 ONS 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 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; 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.

The proposed amendment also deletes the following from TS 5.5.2:

x The information regarding the performance of containment visual inspections as required by RG 1.163, Regulatory Position C.3 as the containment inspections are presently addressed in TS SR 3.6.1.1.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 120 of 126 x

The information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026, for ONS 1, November 28, 2027, for ONS 2, and May 25, 2028, for ONS 3 as these Type A tests shall be scheduled in accordance with RG 1.163 Revision 1.

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

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

Response: No.

The proposed amendment to the TS 5.5.2, Containment Leakage Rate Testing Program, involves the extension of the ONS Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the 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 following from TS 5.5.2:

x The information regarding the performance of containment visual inspections as required by RG 1.163, Regulatory Position C.3 as the containment inspections are presently addressed in TS SR 3.6.1.1.

x The information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026, for ONS 1, November 28, 2027, for ONS 2, and May 25, 2028, for ONS 3 as these Type A tests shall be scheduled in accordance with RG 1.163 Revision 1.

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

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

Response: No.

The proposed amendment to TS 5.5.2 involves the extension of the ONS Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 121 of 126 leaktightness 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 the extension of the interval between Type A containment leak rate tests and Type C tests for ONS Units 1, 2 and 3. The proposed surveillance interval extension is bounded by the 15-year ILRT interval, and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusions that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section Xl 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 following from TS 5.5.2:

x The information regarding the performance of containment visual inspections as required by RG 1.163, Regulatory Position C.3 as the containment inspections are presently addressed in TS SR 3.6.1.1.

x The information regarding the performance of the next ONS Type A tests to be performed no later than November 29, 2026, for ONS 1, November 28, 2027, for ONS 2, and May 25, 2028, for ONS 3 as these Type A tests shall be scheduled in accordance with RG 1.163 Revision 1.

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

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

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

5.0 ENVIRONMENTAL CONSIDERATION

Duke Energy has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 122 of 126 in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1.

RG 1.163, Performance-Based Containment Leak-Test Program, September 1995 (ADAMS Accession No. ML003740058)

2.

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

3.

RG 1.174, Revision 2, An Approach for Using Probabilistic Risk Assessment in Risk Informed Decisions on Plant-Specific Changes to the Licensing Basis, May 2011 (ADAMS Accession No. ML100910006)

4.

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

5.

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

6.

NUREG-1493, Performance-Based Containment Leak-Test Program - Final Report, September 1995 (ADAMS Accession No. 9510200161)

7.

Electric Power Research Institute (EPRI) Topical Report No. 104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, Palo Alto, California, August 1994

8.

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

9.

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

MC9663), dated June 25, 2008 (ADAMS Accession No. ML081140105)

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 123 of 126

10.

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

11.

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

12.

Letter from NRC (D.E. LaBarge) to Duke Power Company (J. W. Hampton), Issuance of Amendment Nos. 218, 218 and 215 - Oconee Nuclear Station, Units 1, 2, and 3 (TAC NOS. M96317, M96318, M96319) dated October 30, 1996

13.

Letter from NRC (D.E. LaBarge) to Duke Energy Corporation (W. R. McCollum),

Issuance of Amendment Nos. 310, 310 and 310 - Oconee Nuclear Station, Units 1, 2 And 3 - Issuance of Amendments Re: (TAC NOS. MA6568, MA6569, AND MA6570) dated January 18, 2000

14.

Letter from NRC (L.N. Olshan) to Duke Energy Corporation (R. A. Jones), Issuance of Amendment Nos. 338, 339 and 339 - Oconee Nuclear Station, Units 1, 2 and 3 Re:

Issuance of Amendments (TAC NOS. MB3537, MB3538, AND MB3539) dated June 1, 2004

15.

Letter from NRC (J. Stang) to Duke Energy Carolinas, LLC (P. Gillespie), Oconee Nuclear Station, Units 1, 2, and 3, Issuance of Amendments Regarding A Proposed Change To The Technical Specifications To Adopt Technical Specification Task Force (TSTF) Technical Change Traveler 52, Revision 3, To Implement Option B Of Appendix J To Title 10 Of The Code Of Federal Regulations, Part 50 (TAC NOS. ME4557, ME4558, AND ME4559) dated July 28, 2011

16.

Letter from NRC (J. Boska) to Duke Energy Carolinas, LLC (P. Gillespie), Oconee Nuclear Station, Unit 1, Issuance of Amendment Regarding Extension of The Reactor Building Integrated Leak Rate Test (TAC NO. ME8407) dated October 1, 2012

17.

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

18.

Containment Liner Corrosion Operating Experience Summary, Technical Letter Report -

Revision 1, by D. S. Dunn, A. L. Pulvirenti, and M. A. Hiser (Office of Nuclear Regulatory Research - NRC), dated August 2, 2011 (ADAMS Accession No. ML112070867)

19.

Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, Revision 4, Developed for NEI by EPRI and Data Systems and Solutions, November 2001

20.

RG 1.200, Revision 0, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, February 2004 (ADAMS Accession No. ML040630078)

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 124 of 126

21.

Duke Energy Calculation, Oconee Nuclear Station Peer Review F&O Resolutions, OSC-11576, Revision 7.

22.

Letter from NRC (S. S. Lee) to Pacific Gas and Electric Company (P. Gerfen), Diablo Canyon Nuclear Power Plant, Units 1 and 2 - Issuance of Amendment Nos. 248 and 250 RE: Extension of Type A and Type C Leak Rate Test Frequencies (EPID L-2024-LLA-0106) dated March 27, 2025 (ADAMS Accession No. ML20250327)

23.

Letter from NRC (J. P. Boska) to Duke Energy Carolinas, LLC (S. Batson), Oconee Nuclear Station, Units 2 And 3, Issuance of Amendments Regarding Extension of The Reactor Building Integrated Leak Rate Test (TAC NOS. ME9777 AND ME9778) dated August 5, 2013

24.

NEI 00-02, Probabilistic Risk Assessment (PRA) Peer Review Process Guidance Rev.

A3, PSA Peer Review Enclosures, dated March 20, 2000 (ADAMS Accession No. ML003728023)

25.

ASME/ANS, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, dated March 2009. Addendum A to RA-S-2008

26.

Letter from NRC (S. A. Williams) to Duke Energy Carolinas, LLC (S. M Snider), Oconee Nuclear Station, Units 1, 2, and 3, Issuance of Amendment Nos. 430, 432 and 431, To Technical Specification 5.5.2, Containment Leakage Rate Testing Program For A One-time Extension of the Units 1, 2, and 3 Type A Leak Rate Test Frequency (EPID L-2023-LLA-0162) (ADAMS Accession No. ML24145A178)

27.

Not used

28.

RG 1.54, Revision 0, Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants, June 1973 (ADAMS Accession No. ML003740187)

29.

Letter from Entergy Operations, Inc. (K. Mulligan) to NRC (Document Control Desk),

Grand Gulf Nuclear Station Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications for Containment Leak Rate Testing, Grand Gulf Nuclear Station, Unit 1, Docket No. 50-416, License No. NPF-29, (GNRO-2015/00063), dated October 28, 2015 (ADAMS Accession No. ML15302A042)

30.

American Nuclear Society, ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements, LaGrange Park, Illinois, November 2002

31.

ASME B&PV Code,Section XI, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants

32.

ASME B&PV Code,Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plant

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 125 of 126

33.

RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Revision 17, August 2014 (ADAMS Accession No. ML13339A689)

34.

RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, Revision 1, May 2011 (ADAMS Accession No. ML100910008)

35.

ASME/ANS, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sb-2009, dated March 2009. Addendum B to RA-S-2008

36.

Application for Renewed Operating Licenses for Oconee Nuclear Station, Units 1, 2, and 3, submitted by M. S. Tuckman (Duke) letter dated July 6, 1998 to Document Control Desk (NRC), Docket Nos. 50-269, - 270, and -287.

37.

NUREG-1723, Safety Evaluation Report Related to the License Renewal of Oconee Nuclear Station, Units 1, 2, and 3, Docket Nos. 50-269, 50-270, and 50-287.

38.

NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, November 2013 (ADAMS Accession No. ML13311A353)

39.

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

40.

Letter from Constellation Nuclear (C.Cruse) to NRC (Document Control Desk),

Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, March 27, 2002 (ADAMS Accession No. ML020920100)

41.

RG 1.200, Revision 3, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, March 2009 (ADAMS Accession No. ML20238B871)

42.

Letter from NRC (J. Giitter and M. Ross-Lee) to NEI (Greg Krueger), U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 7-12, and 12-13, Close Out of Facts and Observations (F&Os), May 3, 2017, (ADAMS Accession No. ML17079A427)

43.

ANSI N101.2-1972, Protective Coatings (Paints) for Light-Water Nuclear Reactor Containment Facilities, American National Standards Institute, Washington, DC.

44.

Industry/TSTF Standard Technical Specification Change Traveler TSTF-52, Implement 10 CFR 50, Appendix J, Option B, Revision 3 (ADAMS Accession No. ML040400371)

45.

ANSI N101.4-1972, Quality Assurance for Protective Coatings Applied to Nuclear Facilities, American National Standards Institute, Washington, DC.

46.

RG 1.1, Revision 0, Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps (ADAMS Accession No. ML003739925)

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Page 126 of 126

47.

RG 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors, July 2000 (ADAMS Accession No. ML003716792)

48.

Federal Register (Vol. 85, No. 86, May 4, 2020) - American Society of Mechanical Engineers 2015 - 2017 Code Editions Incorporation by Reference

49.

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

50.

Letter from NRC (S. Williams) to Duke Energy Carolinas, LLC (S. Snider) - Oconee Nuclear Station, Units 1, 2, And 3 - Issuance of Amendment Nos. 430, 432 and 431, to Technical Specification 5.5.2, Containment Leakage Rate Testing Program For A One-time Extension of the Units 1, 2, And 3 Type A Leak Rate Test Frequency (EPID L-2023-LLA-0162) (ADAMS Accession No. ML24145A178)

51.

Westinghouse Report BOCOM-RAGN-DR-RR-000003, Rev 0, ONS Probabilistic Risk Assessment models F&O closures, December 2023.

52.

American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2020, Containment System Leakage Testing Requirements

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Attachment 1 PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)

OCONEE NUCLEAR STATION UNITS 1, 2 AND 3 DOCKET NO.

RENEWED LICENSE NOS. DPR-38, DPR-47, AND DPR-55 (3 pages including cover)

OCONEE UNITS 1, 2, & 3 5.0-7 Amendment Nos. 430, 432, & 431 Programs and Manuals 5.5 5.0 ADMINISTRATIVE CONTROLS 5.5 Programs and Manuals The following programs shall be established, implemented, and maintained.

5.5.1 Offsite Dose Calculation Manual (ODCM)

The ODCM shall contain the methodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm and trip setpoints, and in the conduct of the radiological environmental monitoring program.

Licensee initiated changes to the ODCM:

a.

Shall be documented and records of reviews performed shall be retained.

This documentation shall contain:

1.

sufficient information to support the change(s) together with the appropriate analyses or evaluations justifying the change(s), and 2.

a determination that the change(s) do not adversely impact the accuracy or reliability of effluent, dose, or setpoint calculations; b.

Shall become effective after the approval of the Plant Manager or Radiation Protection Manager; and c.

Shall be submitted to the NRC in the form of a complete, legible copy of the entire ODCM as a part of or concurrent with the Radioactive Effluent Release Report for the period of the report in which any change in the ODCM was made. Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (i.e., month and year) the change was implemented.

5.5.2 Containment Leakage Rate Testing Program A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The next Unit 1 ILRT following the November 29, 2014 test shall be performed no later than November 29, 2026. The next Unit 2 ILRT following the November 7, 2015 test shall be performed no later than November 28, 2027. The next Unit 3 ILRT following the May 10, 2016 test shall be performed no later than May 25, 2028. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163,5HYLVLRQ

Performance-Based

Programs and Manuals 5.5 5.5 Programs and Manuals OCONEE UNITS 1, 2, & 3 5.0-8 Amendment Nos. 430, 432, & 431 Containment Leak-Test Program, dated September 1995-XQH.

Containment system visual examinations required by Regulatory Guide 1.163, Regulatory Position C.3 shall be performed as follows:

1.

Accessible concrete surfaces and post-tensioning system component surfaces of the concrete containment shall be visually examined prior to initiating SR 3.6.1.1 Type A test. These visual examinations, or any portion thereof, shall be performed no earlier than 90 days prior to the start of refueling outages in which Type A tests will be performed. The validity of these visual examinations will be evaluated should any event or condition capable of affecting the integrity of the containment system occur between the completion of the visual examinations and the Type A test.

2.

Accessible interior and exterior surfaces of metallic pressure retaining components of the containment system shall be visually examined at least three times every ten years, including during each shutdown for SR 3.6.1.1 Type A test, prior to initiating the Type A test.

The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 59 psig. The containment design pressure is 59 psig.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of the containment air weight per day.

Leakage rate acceptance criterion is:

a.

Containment leakage rate acceptance criterion is d 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are d 0.60 La for the Type B and C tests, and d 0.75 La for Type A tests; The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

Nothing in these Technical Specifications shall be construed to modify the testing Frequencies of 10 CFR 50, Appendix J.

U.S. Nuclear Regulatory Commission RA-25-0075 Enclosure Attachment 2 EVALUATION OF RISK SIGNIFICANCE OF PERMANENT ILRT EXTENSION, SEISMIC PRA F&OS OCONEE NUCLEAR STATION UNITS 1, 2 AND 3 DOCKET NOS.

RENEWED LICENSE NOS. DPR-38, DPR-47, AND DPR-55 (32 pages including cover)

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