RA-21-0288, Subsequent License Renewal Application Supplement 2

Subsequent License Renewal Application Supplement 2

ML21315A012
Person / Time
Site:	Oconee
Issue date:	11/11/2021
From:	Snider S Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RA-21-0288
Download: ML21315A012 (117)

Text

Steven M. Snider Vice President Oconee Nuclear Station Duke Energy ON01VP l 7800 Rochester Hwy Seneca, SC 29672 o: 864.873.3478 f: 864.873.5791 Steve.Snider @duke-energy.com 10 CFR 50.4 10 CFR Part 54 RA-21-0288 November 11, 2021 ATTN: NRC Document Control Desk U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852

Subject:

Duke Energy Carolinas, LLC (Duke Energy)

Oconee Nuclear Station (ONS), Units 1, 2, and 3 Docket Numbers 50-269, 50-270, 50-287 Renewed License Numbers DPR-38, DPR-47, DPR-55 Subsequent License Renewal Application Supplement 2

References:

1. Duke Energy Letter (RA-21-0132) dated June 7, 2021, Application for Subsequent Renewed Operating Licenses, (ADAMS Accession Number ML21158A193)

2. NRC Letter dated July 22, 2021, Oconee Nuclear Station, Units 1, 2, and 3 - Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, and Opportunity for a Hearing Regarding Duke Energy Carolinas Application for Subsequent License Renewal (ADAMS Accession Number ML21194A245)

3. NRC Letter dated July 23, 2021, Oconee Nuclear Station, Units 1, 2, and 3 - Aging Management Audit Plan Regarding the Subsequent License Renewal Application Review, (ADAMS Accession Number ML21196A076)

4. Duke Energy Letter (RA-21-0249) dated October 28, 2021 Subsequent License Renewal Application Supplement 1 (ADAMS Accession ML21302A208)

Ladies and Gentlemen:

By letter dated June 7, 2021 (Reference 1), Duke Energy Carolinas, LLC (Duke Energy) submitted an application for the subsequent license renewal of Renewed Facility Operating License Numbers DPR-38, DPR-47, and DPR-55 for the Oconee Nuclear Station (ONS), Units 1, 2, and 3 to the U.S. Nuclear Regulatory Commission (NRC). On July 22, 2021 (Reference 2), the NRC determined that ONS Subsequent License Renewal Application (SLRA) was acceptable and sufficient for docketing. By letter dated July 23, 2021 (Reference 3), the NRC issued the regulatory audit plan for the aging management portion of the SLRA review. During the audit conducted July 26, 2021 - October 8, 2021, Duke Energy agreed to supplement the SLRA with new or clarifying information. This letter provides the NRC staff with additional information in support of the development of the safety evaluation report. Reference 4 provided Supplement 1 to update the SLRA.

U.S. Nuclear Regulatory Commission November 11, 2021 Page 2 The Enclosure to this letter provides the index of topics to be supplemented. For each Attachment to this letter, changes are described along with the affected section(s), page number(s), and affected document mark-ups. For clarity, deletions are indicated by strikethrough and inserted text by underlined red font. Also, four commitment changes to Table A6.0-1 are provided in Attachments 11, 14, 15, and 18.

Should you have any questions regarding this submittal, please contact Paul Guill at (704) 382-4753 or by email at paul.guill@duke-energy.com.

I declare under penalty of perjury that the foregoing is true and correct. Executed on November 11, 2021.

Sincerely, Steven M. Snider Site Vice President Oconee Nuclear Station

Enclosure:

Index of Attachment Topics Involving SLRA Supplement

U.S. Nuclear Regulatory Commission November 11, 2021 Page 3 Attachments:

Attachment 1: Revised SLRA Tables 2.3.1-1 and 3.1.2-1 regarding Reactor Vessel Insulation and Core Flood Nozzle Flow Restrictors Attachment 2: Updated SLRA Section 4.3.2.1 to address Reactor Vessel Support Skirt Attachment 3: Revised SLRA Table 3.1.2-4 Note Column for Line Item Primary Manway and Inspection Opening Covers and Backing Plates Attachment 4: Updated PWR Vessel Internals Operating Experience Discussion Attachment 5: Updated Number of Reactor Trips in Table 4.6.3-1 Attachment 6: Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement Discussion Updated Attachment 7: Discussion for Line Item 3.1.1-137 of Table 3.1.1 is revised Attachment 8: Added wall thinning as an aging effect for Recirculating Water System Heat Exchanger Tubes Attachment 9: Updated Fire Water System Program to address Trending Attachment 10: Clarified SLRA Statements Regarding Concrete Containment Unbonded Tendon Prestress Aging Management Program and Time-Limited Aging Analyses Attachment 11: Revised Enhancements, Commitment, Program Description and Exception Discussion for Buried and Underground Piping and Tanks Aging Management Program Attachment 12: Changes to Aging Management Review of Fire Barrier Penetration Seals and Concrete Fire Barrier Components Attachment 13: Additional Information on Startup Transformer Drop Line Replacement Frequency Attachment 14: Revised Exception and Enhancement discussion for Fire Water System Aging Management Program Attachment 15: Clarification of Fire Water System Aging Management Program implementation schedule Attachment 16: Provided additional Information for Containment Further Evaluation and for Other Structure and Component Supports Further Evaluation Attachment 17: Corrected Inconsistency regarding Inaccessible Concrete Elements in Aging Management Review Tables Attachment 18: Revised Inspection of Deluge System Attachment 19 Updated Regarding High-Strength Bolting Attachment 20: Clarification of Operating Experience related to Calcium Leaching Attachment 21: Updated to Address Bottom-Mounted Instrument Guide Tubes and ASME Code Class 1 Small-Bore Piping

U.S. Nuclear Regulatory Commission November 11, 2021 Page 4 CC: W/O

Enclosures:

Laura A. Dudes Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 Angela X. Wu, Project manager (by electronic mail only)

U.S. Nuclear Regulatory Commission Mail Stop 11 G3 11555 Rockville Pike Rockville, Maryland 20852 Shawn A. Williams, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission Mail Stop 8 B1A 11555 Rockville Pike Rockville, Maryland 20852 Jared Nadel (by electronic mail only)

NRC Senior Resident Inspector Oconee Nuclear Station Anuradha Nair-Gimmi, (by electronic mail only: naira@dhec.sc.gov)

Bureau Environmental Health Services Department of Health & Environmental Control 2600 Bull Street Columbia, South Carolina 29201

U.S. Nuclear Regulatory Commission November 11, 2021 Page 5 BCC: W/O

Enclosures:

T.P. Gillespie K. Henderson S.D. Capps T.M. Hamilton P.V. Fisk H.T. Grant D.A. Wilson M.C. Nolan S.M Snider R.K. Nader G.D. Robison T.M. LeRoy P.F. Guill R.V. Gambrell File: (Corporate)

Electronic Licensing Library (ELL)

ENCLOSURE OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION INDEX OF ATTACHMENT TOPICS INVOLVING SLRA SUPPLEMENTS

INDEX OF ATTACHMENT TOPICS INVOLVING SLRA SUPPLEMENTS Attachment Topics Number Revised SLRA Tables 2.3.1-1 and 3.1.2-1 regarding Reactor Vessel Insulation 1

and Core Flood Nozzle Flow Restrictors 2 Updated SLRA Section 4.3.2.1 to address Reactor Vessel Support Skirt 3 Revised SLRA Table 3.1.2-4 Note Column for Line Item Primary Manway and Inspection Opening Covers and Backing Plates 4 Updated PWR Vessel Internals Operating Experience Discussion 5 Updated Number of Reactor Trips in Table 4.6.3-1 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 6

Discussion Updated 7 Discussion for Line Item 3.1.1-137 of Table 3.1.1 is revised Added wall thinning as an aging effect for Recirculating Water System Heat 8

Exchanger Tubes 9 Updated Fire Water System Program to address Trending Clarified SLRA Statements Regarding Concrete Containment Unbonded Tendon 10 Prestress Aging Management Program and Time-Limited Aging Analyses Revised Enhancements, Commitment, Program Description and Exception 11 Discussion for Buried and Underground Piping and Tanks Aging Management Program Changes to Aging Management Review of Fire Barrier Penetration Seals and 12 Concrete Fire Barrier Components Additional Information on Startup Transformer Drop Line Replacement 13 Frequency 14 Revised Exception and Enhancement discussion for Fire Water System Aging Management Program Clarification of Fire Water System Aging Management Program implementation 15 schedule Provided additional Information for Containment Further Evaluation and for 16 Other Structure and Component Supports Further Evaluation Corrected Inconsistency regarding Inaccessible Concrete Elements in Aging 17 Management Review Tables 18 Revised Inspection of Deluge System 19 Updated Regarding High-Strength Bolting 20 Clarification of Operating Experience related to Calcium Leaching Updated to Address Bottom-Mounted Instrument Guide Tubes and ASME Code 21 Class 1 Small-Bore Piping

ATTACHMENT 1 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES REVISED SLRA TABLES 2.3.1-1 AND 3.1.2-1 REGARDING REACTOR VESSEL INSULATION AND CORE FLOOD NOZZLE FLOW RESTRICTORS

Revised SLRA Tables 2.3.1-1 and 3.1.2-1 regarding Reactor Vessel Insulation and Core Flood Nozzle Flow Restrictors (TRP 76 and TRP 143.3)

Affected SLRA Section(s):

SLRA Table 2.3.1-1 SLRA Table 3.1.2-1 SLRA Page Numbers:

2-51 2-52 3-93 3-99 Description of Change:

SLRA Table 2.3.1-1, which lists reactor vessel component types subjected to aging management review, will be revised to include Insulation (reactor vessel) with the Intended Function of thermal resistance. Similarly, Table 3.1.2-1, Reactor Vessel, Reactor Internals, and Reactor Coolant System -

Reactor Vessel - Aging Management Evaluation, will be revised to include an Aging Management Review (AMR) line item for Insulation (reactor vessel). The new AMR line item will be similar to that for Insulation (pressurizer) in SLRA Table 3.1.2-3, page 3-135.

SLRA Tables 2.3.1-1 and 3.1.2-1 will be supplemented to remove the intended function of Pressure Boundary for the Core Flood Nozzle Flow Restrictors. The Table 3.1.2-1 line item for Core Flood Nozzle Flow Restrictors will be supplemented to include Cumulative Fatigue Damage as an aging effect, which is managed as a Time-Limited Aging Analyses (TLAA). After the SLRA is supplemented with these changes, the SLRA will state that the Aging Management Review results for the Core Flood Nozzle Flow Restrictors (venturi) show that the only intended function is Flow Restriction, and that the aging effect of Cumulative Fatigue Damage is managed as a TLAA. SLRA Section 4.3.2.1 states that the effects of fatigue on the intended functions of the reactor vessel (which includes the venturi) will be managed by the Fatigue Monitoring Aging Management Program.

SLRA Table 2.3.1-1 (Page 2-51) is revised as follows:

Table 2.3.1-1 Reactor Vessel Component/Commodity Group Intended Functions Control Rod Drive Mechanism Guide Tube Welding To Closure Pressure Boundary Head Structural Support Control Rod Drive Mechanism Head Penetration Flange Bolting Pressure Boundary Control Rod Drive Mechanism Motor Tube Assembly Pressure Boundary Control Rod Drive Mechanism Nozzle Adaptor Flange Pressure Boundary Structural Support Control Rod Drive Mechanism Nozzle Body Pressure Boundary Control Rod Drive Mechanism Nozzle Body To Nozzle Adaptor Flange Weld Pressure Boundary Structural Support Core Flood Nozzle Flow Restrictors Pressure Boundary Flow Restriction Core Flood Nozzle Safe Ends Pressure Boundary Core Flood Nozzle Thermal Sleeve Thermal Resistance Core Flood Nozzle Weld Pressure Boundary Core Flood Nozzles Pressure Boundary Core Guide Lugs Structural Support Head Vent Pipe Pressure Boundary Incore Monitoring System Lines Pressure Boundary Inlet and Outlet Nozzles Pressure Boundary Instrument Tubes (bottom head) Pressure Boundary

SLRA Table 2.3.1-1 (Page 2-52) is revised as follows:

Table 2.3.1-1 Reactor Vessel Component/Commodity Group Intended Functions Insulation (reactor vessel) Thermal Resistance Lower Nozzle Belt Forging Pressure Boundary Lower Shell Plate Pressure Boundary Structural Support Support Skirt Structural Support Transition Forging Pressure Boundary Structural Support Upper Nozzle Belt Forging Pressure Boundary Upper Shell Flange Pressure Boundary Upper Shell Plate Pressure Boundary Vessel Flange Leak Detection Line Structural Integrity Vessel Flange Leak Detection Line Tap Weld Structural Integrity

SLRA Table 3.1.2-1 (Page 3-93) is revised as follows:

Table 3.1.2-1 Reactor Vessel, Reactor Internals, and Reactor Coolant System - Reactor Vessel - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Control Rod Structural Nickel Alloy Reactor Coolant Cracking Water Chemistry (B2.1.2) IV.A2.RP-186 3.1.1- 045 A Drive Support (Internal)

Mechanism Nozzle Body to Nozzle Adaptor Flange Weld Cumulative Fatigue TLAA IV.A2.R-219 3.1.1- 010 A Damage Loss of Material Water Chemistry (B2.1.2) IV.A2.RP-28 3.1.1- 088 A Core Flood Flow Restriction Stainless Steel Reactor Coolant Cracking ASME Section XI IV.A2.RP-234 3.1.1- 046 A Nozzle Flow (External) Inservice Inspection, Restrictors Subsections IWB, IWC, and IWD (B2.1.1)

Water Chemistry (B2.1.2) IV.A2.RP-234 3.1.1- 046 A Cumulative Fatigue TLAA IV.A2.R-219 3.1.1-010 A Damage Loss of Material Water Chemistry (B2.1.2) IV.A2.RP-28 3.1.1- 088 A Pressure Stainless Steel Reactor Coolant Cracking ASME Section XI IV.A2.RP-234 3.1.1- 046 A Boundary (External) Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1)

Water Chemistry (B2.1.2) IV.A2.RP-234 3.1.1- 046 A Loss of Material Water Chemistry (B2.1.2) IV.A2.RP-28 3.1.1- 088 A Core Flood Pressure Stainless Steel Air - Indoor Cracking One-Time Inspection V.A.EP-103b 3.2.1- 007 A Nozzle Safe Boundary Uncontrolled (External) (B2.1.20)

Ends

SLRA Table 3.1.2-1 (Page 3-99) is revised as follows:

Table 3.1.2-1 Reactor Vessel, Reactor Internals, and Reactor Coolant System - Reactor Vessel - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Instrument Tubes Pressure Nickel Alloy Air with Borated Water None None IV.E.RP- 3.1.1- 106 A (bottom head) Boundary Leakage (External) 378 Reactor Coolant Cracking ASME Section XI IV.A2.RP- 3.1.1- 045 A (Internal) Inservice Inspection, 59 Subsections IWB, IWC, and IWD (B2.1.1)

Cracking of Nickel Alloy IV.A2.RP- 3.1.1- 045 A Components and Loss 59 of Material due to Boric Acid-Induced Corrosion in RCPB Components (B2.1.5)

TLAA None None H Water Chemistry IV.A2.RP- 3.1.1- 045 A (B2.1.2) 59 Cumulative Fatigue TLAA IV.A2.R-219 3.1.1- 010 A Damage Loss of Material Water Chemistry IV.A2.RP- 3.1.1- 088 A (B2.1.2) 28 Insulation (reactor Thermal Stainless Steel Air with Borated None None IV.E.RP-05 3.1.1-107 A vessel) Resistance Water Leakage (External)

Lower Nozzle Belt Pressure Steel (with Air with Borated Water Loss of Material Boric Acid Corrosion IV.A2.R-17 3.1.1- 049 A Forging Boundary Stainless Steel Leakage (External) (B2.1.4)

Cladding)

Reactor Coolant Cracking ASME Section XI IV.A2.RP- 3.1.1- 047 A (Internal) Inservice Inspection, 55 Subsections IWB, IWC, and IWD (B2.1.1)

TLAA IV.A2.R-85 3.1.1- 018 A

ATTACHMENT 2 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES UPDATED SLRA SECTION 4.3.2.1 TO ADDRESS REACTOR VESSEL SUPPORT SKIRT

Updated SLRA Section 4.3.2.1 to address Reactor Vessel Support Skirt TRP 76 Affected SLRA Section:

SLRA Section 4.3.2.1 SLRA Page Number(s):

4-57 Description of Change:

SLRA Section 4.3.2.1 will be updated to address the reactor vessel support skirt. The TLAA Disposition will be updated to state, The effects of fatigue on the intended functions of the reactor vessels, including the reactor vessel support skirts, will be adequately managed by the Fatigue Monitoring Aging Management Program (AMP) (B3.1) for the Subsequent Period of Extended Operation (SPEO).

SLRA Section 4.3.2.1 (page 4-57) is revised as follows:

TLAA Disposition: 10 CFR 54.21(c)(1)(iii):

The effects of fatigue on the intended functions of the reactor vessels, including the reactor vessel support skirt, will be adequately managed by the Fatigue Monitoring AMP (B3.1) for the SPEO.

4.3.2.2 Reactor Vessel Internals TLAA

Description:

As described in BAW-2248A [Reference 4.3-4], Sections 2.0 and 4.5.1, the reactor vessel internals were designed and constructed prior to the development of ASME Code requirements for core support structures. Because of the lack of specific ASME design rules for core support structures at the time of design and construction of the Oconee reactor vessel internals,Section III of the ASME code was used as a guideline for the design criteria for the reactor vessel internals. Qualification of the internals was accomplished by both analytical and test methods.

ATTACHMENT 3 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES REVISED SLRA TABLE 3.1.2-4 NOTE COLUMN FOR LINE ITEM PRIMARY MANWAY AND INSPECTION OPENING COVERS AND BACKING PLATES

Revised SLRA Table 3.1.2-4 Note Column for Line Item Primary Manway and Inspection Opening Covers and Backing Plates (TRP 19)

Affected SLRA Section:

SLRA Table 3.1.2-4 SLRA Page Numbers:

3-197 3-198 Description of Change:

The industry standard Note A for the material(s) of the primary manway and inspection opening covers and backing plates were changed to Note C (since the component is different, but the line item is consistent with the NUREG-2191 item for material, environment, and aging effect) for line items matching to the following:

• IV.D2.RP-47

• IV.D2.R-222

• IV.C2.RP-23

• IV.C2.R-431

SLRA Table 3.1.2-4 (page 3-197) is revised as follows:

Table 3.1.2-4 Reactor Vessel, Reactor Internals, and Reactor Coolant System - Steam Generators - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging NUREG- NUREG- Notes Type Function Management 2191 2192 Program Item Table 1 Main Pressure Stainless Secondary Cumulative Fatigue TLAA IV.C2.R-18 3.1.1- 005 C Feedwater Boundary Steel Feedwater Damage Spray Nozzle (Internal)

Flanges Treated Water Loss of Material One-Time Inspection VIII.D1.SP-87 3.4.1- 085 A (Internal) (B2.1.20)

Water Chemistry VIII.D1.SP-87 3.4.1- 085 A (B2.1.2)

Primary Pressure Steel Air - Indoor Loss of Material Bolting Integrity IV.D2.RP-166 3.1.1- 064 A Manway and Boundary Uncontrolled (B2.1.9)

Inspection (External)

Opening Loss of Preload Bolting Integrity IV.D2.RP-46 3.1.1- 067 A Bolting (B2.1.9)

Air with Borated Loss of Material Boric Acid Corrosion IV.D2.R-17 3.1.1- 049 A Water Leakage (B2.1.4)

(External)

Primary Pressure Nickel Alloy Reactor Coolant Cracking ASME Section XI IV.D2.RP-47 3.1.1- 042 A Manway and Boundary (Internal) Inservice Inspection, C Inspection Subsections IWB, Opening IWC, and IWD Covers and (B2.1.1)

Backing Plates Water Chemistry IV.D2.RP-47 3.1.1- 042 A (B2.1.2) C Cumulative Fatigue TLAA IV.D2.R-222 3.1.1- 008 A Damage C Loss of Material Water Chemistry IV.C2.RP-23 3.1.1- 088 A (B2.1.2) C

SLRA Table 3.1.2-4 (page 3-198) is revised as follows:

Table 3.1.2-4 Reactor Vessel, Reactor Internals, and Reactor Coolant System - Steam Generators - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Primary Pressure Steel Air - Indoor Loss of Material External Surfaces IV.C2.R-431 3.1.1- 124 A Manway and Boundary Uncontrolled Monitoring of C Inspection (External) Mechanical Opening Components (B2.1.23)

Covers and Backing Air with Borated Water Loss of Material Boric Acid Corrosion IV.D2.R-17 3.1.1- 049 A Plates Leakage (External) (B2.1.4)

ATTACHMENT 4 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES UPDATED PWR VESSEL INTERNALS OPERATING EXPERIENCE DISCUSSION

Updated PWR Vessel Internals Operating Experience Discussion (TRP-16)

SLRA Section:

SLRA Appendix B2.1.7 SLRA Page No:

B-78 B-80 B-81 Description of Change:

For the Operating Experience (OE) subsection, OE Item 2, revise Unit 1 to Unit 3 to reflect the correct unit in which an indication was found during a lower grid rib inspection in 2014. A review confirmed that the correct unit for this inspection was Unit 3.

For the Operating Experience subsection, OE Item 9, revise a term in bullet (c) from one barrel- to-former bolt to one baffle-to-former bolt to reflect the correct bolting item. A review confirmed that baffle-to-former bolt is correct for the Unit 3 inspection in 2013.

Add a paragraph to the Operating Experience subsection to describe that the results from ONS reactor internals inspections are provided to the EPRI MRP for compilation into biennial industry operating experience reports of recent MRP-227-A inspection results, and to provide the MRP report names and ADAMS Accession Numbers for recent biennial industry reports that contain ONS reactor internals inspection results.

SLRA Appendix B2.1.7 (page B-78) is revised as follows:

2. In 2014, an indication in the Oconee Unit 1 3 lower grid rib section was discovered while inspecting an adjacent component. Prior to discovery of the indication, inspection of the lower grid rib section was not required by MRP-227-A. As a result of this inspection finding, the lower grid rib section was added as an expansion component to MRP-227, Revision 1-A and is being upgraded to a primary item for SLR.

OE example 2 provides objective evidence that plant-specific OE that potentially involves aging is evaluated and used to adjust the program as necessary.

SLRA Appendix B2.1.7 (page B-80) is revised as follows:

9. Oconee Unit 2, 2013: (a) various issues were found with the vent valve jack-screw locking devices (see OE example 7); (b) one lower core barrel bolt with a crack-like indication was discovered during ultrasonic testing; (c) one barrel baffle-to-former bolt was not inspectable due to incorrect probe seating; (d) two flow distributor bolts with crack-like indications were discovered during ultrasonic testing. The corrective action program was used to address the relevant conditions identified during the examinations. A causal evaluation found that the vent valve condition was legacy damage caused by contact with the plenum assembly as it was being manipulated during previous refueling outages. Contact between the vent valve and plenum assembly was found to be caused by inadequacies associated with the Internals lifting equipment; the lifting equipment issues were resolved. Other actions included an evaluation which showed that the accident analysis for core bypass flow bounded potential leakage past the damaged vent valve (completed). The vent valve was replaced. Actions to address the conditions found for other internals components included (a) structural evaluations (completed), (b) evaluations of potential impacts to fuel performance (completed), and (c) loose parts evaluations (completed). These evaluations identified no impacts to the safe operation of the plant or to the ability of the Internals to perform their intended functions.

SLRA Appendix B2.1.7 (page B-81) is revised as follows:

The above examples of OE provide objective evidence that the aging management activities and methods being implemented by the PWR Vessel Internals AMP will be effective in managing aging effects prior to loss of intended function for the SPEO.

Summary reports of ONS reactor internals inspections and monitoring, items requiring evaluations, and new repairs, are provided periodically to the EPRI MRP for compilation into biennial industry reports of recent MRP-227-A inspection results. The industry reports assist in the review of operating experience and required monitoring and trending for aging management programs established by the industry. The issued industry reports that contain ONS inspection data are MRP 2014-009 (ADAMS Accession Numbers ML14135A383, ML14135A384, and ML14135A385) and MRP 2016-008 (ADAMS Accession Number ML16144A789).

Appropriate guidance for evaluation or corrective actions for additional inspections, reevaluation, repairs, or replacements is provided for locations where aging effects are found. Periodic assessments of the PWR Vessel Internals AMP are performed to identify the areas that need improvement to maintain effective performance of the program. The program is informed and enhanced, when necessary, through the systematic and ongoing review of both plant-specific and industry operating experience.

ATTACHMENT 5 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES Updated Number of Reactor Trips in Table 4.6.3-1

Update Number of Reactor Trips in Table 4.6.3-1 (TRP 146)

Affected SLRA Section(s):

SLRA Table 4.6.3-1 SLRA Appendix A4.6.3 SLRA Page Number(s):

4-102 A-66 Description of Change:

The current count of the maximum accrued Reactor Trip events is 122 for ONS 1. The projected number of Reactor Trip events for 80 years of operation is 204. SLRA Table 4.6.3-1 will be revised to incorporate the appropriate changes to Table 4.6.3-1.

Supplement A4.6.3 to address what the acceptance criteria is that triggers a corrective action. SLRA Section A4.6.3 will be supplemented to include the following revision, The Fatigue Monitoring (A3.1) aging management program will monitor and track the relevant transients to manage fatigue of the main steam and feedwater penetrations during the SPEO in accordance with 10 CFR 54.21(c)(1)(iii).

SLRA Table 4.6.3-1 (page 4-102) is revised as follows:

Table 4.6.3-1: ONS Main Steam and Main Feedwater Containment Penetrations 40-Year Projected Refined Current Governing Design for 80 Name Allowable Transient Allowable Count(2)

Cycles Cycles years(1) 1A Heatup(3) 360 262 125 189 Main Steam Reactor Building 1B Cooldown(3) 360 262 131 197 Penetrations Total Reactor 412 262 135 194 Trips(4) 122 204 Main 1A Heatup(3) 360 249 125 189 Feedwater Reactor Building Penetrations 1B Cooldown(3) 360 249 131 197 Note 1: The projected 80 year cycles are from Table 4.3.1-1 Note 2: The current count is the maximum accrued cycles from each Oconee unit Note 3: These governing transients include seismic loads Note 4: The total number of reactor trips comes from the addition of transients 8A, 8B, 8C, and 8D from Table 4.3.1-1 SLRA Appendix A4.6.3 (page A-66) is revised as follows:

A4.6.3 Containment Penetrations Fatigue Analysis The interior surface of the containment is lined with welded steel plate to provide an essentially leak tight barrier. At all penetrations, the liner plate is thickened to reduce stress concentrations of the liner plate.

ONS Units 1, 2 and 3 process lines that penetrate the primary containment and experience significant thermal expansion and contraction are solidly anchored to the containment wall. These high temperature lines penetrating the containment wall and liner plate are the main steam and feedwater lines.

The transient cycles considered in the main steam and feedwater penetrations analyses were projected for 80 years of operation and the count found to be adequate for the SPEO. The Fatigue Monitoring (A3.1) aging management program will monitor and track the relevant transients to manage fatigue of the main steam and feedwater penetrations during the SPEO in accordance with 10 CFR 54.21(c)(1)(iii).

ATTACHMENT 6 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES LOSS OF FRACTURE TOUGHNESS DUE TO NEUTRON IRRADIATION EMBRITTLEMENT DISCUSSION UPDATED

Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement Discussion Updated (TRP 149.11)

SLRA Section SLRA Section 3.1.2.2.3 SLRA Appendix A4.7.1.1 SLRA Page No:

3-26 A-67 Description of Change:

The SLRA Further Evaluation Recommendation Section 3.1.2.2.3, Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement, requires an update such that the Evaluation Statement 3.1.1-015 is revised to [3.1.1-015] - Reduction in Fracture Toughness is a TLAA as defined in 10 CFR 54.3 and is evaluated in Section 4.7, Other Plant-Specific Time-Limited Aging Analyses.

SLRA Section A4.7.1.1, Reduction in Fracture Toughness Due to Neutron Embrittlement, requires an update to describe that ANP-3899P/NP provides the evaluation which demonstrates that the analysis reported in BAW-10008, Part 1, Revision 1 remains valid for the subsequent period of extended operation.

SLRA Section 3.1.2.2.3 (page 3-26) is revised as follows:

[3.1.1-015] - Reduction in Fracture Toughness is a TLAA as defined in 10 CFR 54.3 and is evaluated in Section 4.2, Reactor Vessel Neutron Embrittlement Analysis. Section 4.7, "Other Plant-Specific Time-Limited Aging Analyses."

SLRA Appendix A4.7.1.1 (page A-67) is revised as follows:

The NRC staff review of this 60-year evaluation concluded that the licensee had projected the neutron fluence for the reactor vessel Internals using an acceptable methodology consistent with RG 1.190. For subsequent license renewal, reduction in fracture toughness due to neutron embrittlement of the reactor vessel internals relative to the evaluation of BAW-10008, Part 1, Revision 1 must be evaluated for 80 years.

ANP-3899P/NP provides an assessment of the applicability of BAW-10008, Part 1, Revision 1, for 80 years.

Each reactor vessel Internals item addressed in BAW-10008, Part 1, Revision 1 is assessed in accordance with one of three process steps (i.e., Categories 1-3) for Faulted Conditions to determine if each reactor vessel Internals item should be considered potentially susceptible to an unacceptable amount of reduction of ductility at 72 EFPY. This multi-step assessment was completed for the Oconee reactor vessel internals. Based on the assessments, the effect of irradiation on the material properties and deformation limits of the reactor vessel Internals at all three units at Oconee is acceptable for an 72 EFPY lifetime such that the internals will have adequate ductility to absorb local strain at the regions of maximum stress intensity, and that irradiation will not adversely affect deformation limits under faulted condition loadings for the SPEO. The analyses reported in BAW-10008, Part 1, Revision 1, remain valid for the subsequent period of extended operation and are managed by the PWR Vessel Internals Program (B2.1.7, GALL-SLR XI.M16A), in accordance with 10 CFR 54.21(c)(1)(iii), consistent with the current licensing basis.

ATTACHMENT 7 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES DISCUSSION FOR LINE ITEM 3.1.1-137 OF TABLE 3.1.1 IS REVISED

Discussion for Line Item 3.1.1-137 of Table 3.1.1 is revised (TRP-85)

Affected SLRA Section:

SLRA Table 3.1.1 SLRA Page Numbers:

3-79 Description of Change:

The discussion in Table 3.1.1, Item Number 3.1.1-137 should be revised to the following:

Not applicable. Copper alloy piping, piping components in the Reactor Vessel, Internals, and Reactor Coolant System were aligned to SRP Item 3.3.1-114 for an Air environment. The associated NUREG-2191 aging items are not used.

SLRA Table 3.1.1 (page 3-79) is revised as follows:

Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Further Item Aging Effect/ Aging Management Component Evaluation Discussion Number Mechanism Program Recommended 3.1.1-136 Stainless steel, nickel alloy Loss of material due AMP XI.M32, One-Time Yes (SRP-SLR Consistent with NUREG-2191. Loss of piping, piping components to pitting, crevice Inspection, AMP XI.M36, Section 3.1.2.2.16) material of stainless steel and nickel alloy exposed to air, condensation corrosion External Surfaces Monitoring components exposed to air is managed by of Mechanical Components, the One-Time Inspection (B2.1.20)

AMP XI.M38, Inspection of program. See further evaluation in Section Internal Surfaces in 3.1.2.2.16.

Miscellaneous Piping and Ducting Components, or AMP XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks 3.1.1-137 Copper alloy piping, piping None None No Not applicable. ONS has no in-scope components exposed to air, Copper alloy piping, piping components condensation, gas exposed to air, condensation, gas in the Reactor Vessel, Internals, and Reactor Coolant System were aligned to SRP Item 3.3.1-114 for an air environment. The associated NUREG- 2191 aging items are not used.

3.1.1-139 Stainless steel, nickel alloy Cracking due to AMP XI.M32, One-Time Yes (SRP-SLR Consistent with NUREG-2191 for the reactor vessel top head stress corrosion Inspection, or AMP XI.M36, Section 3.1.2.2.6.3) remaining leakage detection line, with enclosure flange leakage cracking External Surfaces Monitoring exceptions. The vessel flange leak detection line exposed to air- of Mechanical Components detection lines have been cut and capped indoor uncontrolled, reactor on all three units. Cracking of the coolant leakage remaining stainless steel reactor vessel top head enclosure flange leakage detection line exposed to air-indoor uncontrolled is managed by the One-Time Inspection (B2.1.20) program. See further evaluation in Section 3.1.2.2.6.3.

ATTACHMENT 8 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES ADDED WALL THINNING AS AN AGING EFFECT FOR RECIRCULATING WATER SYSTEM HEAT EXCHANGER TUBES

Added wall thinning as an aging effect for Recirculating Water System Heat Exchanger Tubes (TRP-17)

Affected SLRA Sections:

SLRA Table 3.3.2-21 SLRA Sections 3.3.2.1.21 SLRA Appendix B2.1.8 SLRA Page Numbers:

3-359 3-688 3-692 B-82 Description of Change:

Add wall thinning due to erosion as an aging effect for the Recirculating Water System Heat Exchanger Tubes to be managed by the FAC Program.

Note that discussion provided in page B-82 was previously revised via Supplement 1, which was submitted October 28, 2021. The revision to Appendix B2.1-8 provided by Supplement 1 are incorporated as existing text.

SLRA Section 3.3.2.1.21 (page 3-359) is revised as follows:

• Reduction of Heat Transfer

• Wall Thinning Aging Management Programs The aging effects for components in the Recirculating Cooling Water System are managed by the following AMPs:

• Bolting Integrity (B2.1.9)

• Boric Acid Corrosion (B2.1.4)

• Flow-Accelerated Corrosion (B2.1.8)

• Closed Treated Water System (B2.1.12)

• External Surfaces Monitoring of Mechanical Components (B2.1.23)

• One-Time Inspection (B2.1.20)

• Open-Cycle Cooling Water System (B2.1.11)

• Selective Leaching (B2.1.21)

SLRA Table 3.3.2-21 (page 3-688) is revised as follows:

Table 3.3.2-21 Auxiliary Systems - Recirculating Cooling Water System - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Piping Structural Steel Air with Borated Water Loss of Material Boric Acid Corrosion VII.I.A-79 3.3.1- 009 A Integrity Leakage (External) (B2.1.4)

Closed-Cycle Cooling Loss of Material Closed Treated Water VII.C2.AP-202 3.3.1- 045 A Water (Internal) System (B2.1.12)

Piping and Piping Pressure Copper Alloy Closed-Cycle Wall Thinning Flow-Accelerated None None H, 3 Boundary (>15% Zn) Cooling Water Components Corrosion (B2.1.8)

(External)

Pump Casing Pressure Gray Cast Iron Air - Indoor Loss of Material External Surfaces VII.I.A-77 3.3.1- 078 A (recirculating Boundary Uncontrolled (External) Monitoring of cooling water) Mechanical Components (B2.1.23)

Closed-Cycle Cooling Loss of Material Closed Treated Water VII.C2.AP-202 3.3.1- 045 A Water (Internal) System (B2.1.12)

Selective Leaching VII.C2.A-50 3.3.1- 072 A (B2.1.21)

SLRA Table 3.3.2-21 (page 3-692) is revised as follows:

Plant Specific Notes:

1. The heat exchanger plate performs the same function as a heat exchanger tube. Therefore, the component type is equivalent.

2. Material of construction is inhibited Brass which is not susceptible to selective leaching.

3. The outer surfaces of the RCW Heat Exchanger (0RCW-HX-000A,B,C,D) tubes are susceptible to wall thinning from erosion based on site specific operating experience. GALL does not recognize erosion as an aging effect in closed-cycle cooling water environments.

SLRA Section B2.1.8 (page B-82) (previously revised via Supplement 1, those changes shown as incorporated here) is further revised as follows:

The program also manages wall thinning caused by mechanisms other than flow-accelerated corrosion in copper alloy, copper alloy (> 15% Zn), steel and stainless steel piping and piping components exposed to closed-cycle cooling water, raw water, treated water and treated borated water environments in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanisms.

ATTACHMENT 9 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES UPDATED FIRE WATER SYSTEM PROGRAM TO ADDRESS TRENDING

Updated Fire Water System Program to address Trending (TRP-27)

Affected SLRA Sections:

SLRA Section B2.1.16 SLRA Page Numbers:

B-123 Description of Change:

The Fire Water System program description is revised to include a statement regarding trending of results related to flushing of Fire Water System piping and hose stations.

SLRA Appendix B2.1.16 (page B-123)

B2.1.16 FIRE WATER SYSTEM Program Description The Fire Water System AMP is an existing condition monitoring program that manages loss of material and flow blockage for water-based fire protection systems that consist of sprinklers, nozzles, valve bodies, fire pump casings, hydrants, hose stations, standpipes, aboveground and underground piping and piping components, strainers, and the elevated water storage tank. The program also manages loss of coating integrity of the internal coating of the elevated water storage tank. This program relies on flow testing, visual inspections, and volumetric examination to ensure that loss of material due to due to general, pitting and crevice corrosion, microbiologically influenced corrosion, or fouling, and flow blockage due to fouling is adequately managed.

The high pressure service water system is normally maintained at required operating pressure and is monitored such that loss of system pressure is detected. The Keowee fire detection/protection system is normally charged by static head from Lake Keowee. System flow downstream of the Keowee fire pump is monitored such that leakage from a normally stagnant line would be detected. Monitoring of operating parameters of the high pressure service water system and Keowee fire detection/protection system ensure prompt corrective actions can be initiated if leakage occurs.

The system flow testing, visual inspections and volumetric inspections ensure that aging effects are managed such that the system intended functions are maintained. Flow testing results are reviewed and trended to identify degrading trends prior to loss of system function. Unexpected results from flushing such as increased time to flush a line or the amount of sediment, corrosion products, or debris are entered into the corrective action program for evaluation and trending. Inspections and tests are performed by personnel qualified in accordance with station procedures and programs to perform the specified task. The program ensures that testing and inspection activities have been performed and documented. Abnormal results are entered into the corrective action program for review and resolution.

The Fire Water System program will include testing of a representative sample of the sprinklers prior to fifty years in service consistent with the 2011 Edition of NFPA 25, Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, Section 5.3.1. Performance of the initial 50-year tests will be determined based on the date of the sprinkler system installation.

ATTACHMENT 10 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES CLARIFIED SLRA STATEMENTS REGARDING CONCRETE CONTAINMENT UNBONDED TENDON PRESTRESS AGING MANAGEMENT PROGRAM AND TIME-LIMITED AGING ANALYSES

Clarified SLRA Statements Regarding Concrete Containment Unbonded Tendon Prestress Aging Management Program and Time-Limited Aging Analyses (TRP 62 and TRP 145)

Affected SLRA Section:

SLRA Appendix B3.4 SLRA Section 4.5 SLRA Page Numbers:

B-301 B-302 4-82 Description of Change:

Revised Justification for Exception 1 item #4 and Justification for Exception 2 item #4 to state how the forecasted regression data is trended and used to show tendons will exceed the minimum required value during the subsequent period of extended operation.

Clarified SLRA statements associated with the predicted lower limit lines and forecasted trend lines.

SLRA Appendix B3.4 (page B-301) is revised as follows:

Justification for Exception 1

4. The average of the dome, horizontal, and vertical historical tendon lift-off force datapoints for each group for each examination exceed the minimum required prestressing with significant margin. The forecasted regression data of the historical trended lift-off results for each tendon are used to verify that the dome, horizontal, and vertical tendons will exceed the minimum required value for their selected group with acceptable margin during the extended period of operation.

SLRA Appendix B3.4 (page B-302) is revised as follows:

Justification for Exception 2

4. The average of the dome, horizontal, and vertical historical tendon lift-off force datapoints for each group for each examination exceed the minimum required prestressing with significant margin. The forecasted regression data of the historical trended lift-off results for each tendon are used to verify that the dome, horizontal, and vertical tendons will exceed the minimum required value for their selected group with acceptable margin during the extended period of operation.

SLRA Section 4.5 (page 4-82) is revised as follows:

Evaluation Predicted lower limit lines and forecasted trend lines of measured prestressing forces actual historical liftoff data have been established for applicable tendon groups through the SPEO as part of the Concrete Containment Unbonded Tendon Prestress (B3.4) AMP. The predicted final effective preload based regression analysis of trended data at the end of 80 years exceeds the minimum required preload for all containment tendons. Consequently, the post- tensioning system will continue to perform its intended function throughout the SPEO.

ATTACHMENT 11 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES REVISED ENHANCEMENTS, COMMITMENT, PROGRAM DESCRIPTION AND EXCEPTION DISCUSSION FOR BURIED AND UNDERGROUND PIPING AND TANKS AGING MANAGEMENT PROGRAM

Revised Enhancements, Commitment, Program Description and Exception Discussion for Buried and Underground Piping and Tanks Aging Management Program (TRP-14)

Affected SLRA Section:

SLRA Appendix A2.26 SLRA Table A6.0-1 SLRA Appendix B2.1.26 SLRA Page Numbers:

A-27 A-28 A-90 A-92 B-181 B-183 B-184 Description of Change:

The Buried and Underground Piping and Tanks AMP, as described in SLRA Appendix A and Appendix B, is revised to make three changes. First, Enhancement 4 and Enhancement 7 to the Buried and Underground Piping and Tanks AMP are revised to remove reference to uncoated stainless steel buried piping. All buried stainless steel buried piping within the scope of subsequent license renewal at Oconee is externally coated. Second, the program description in Appendix A is revised to clarify that the acceptance criteria for cathodic protection system effectiveness is based on the instant-off potential relative to a copper/copper sulfate reference electrode. Third, Exception 2 in Appendix B is revised to clarify that the alternative limiting critical potential applies only to the test well on the north side of the standby shutdown facility diesel engine fuel oil tank.

SLRA Appendix A2.26 (pages A-27 and A-28) is revised as follows:

A2.26 Buried and Underground Piping and Tanks Program Description The Buried and Underground Piping and Tanks AMP is an existing condition monitoring program that manages the aging effects associated with the external surfaces of buried and underground piping and tanks including loss of material and cracking of components in soil or underground environments within the scope of SLR. The program addresses piping and tanks of any material, including carbon steel, ductile iron, gray cast iron, stainless steel and copper alloys. There are no buried or underground cementitious or polymeric piping or tanks within the scope of SLR at Oconee. Condition monitoring of the buried and underground piping and tanks relies on inspections conducted by qualified individuals.

The program also manages aging through preventive and mitigative actions (i.e., coatings, backfill quality, and cathodic protection). The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. The acceptance criteria for cathodic protection system effectiveness is -850 mV instant-off potential relative to copper/copper sulfate reference electrode.

Enhancements The Buried and Underground Piping and Tanks AMP will be enhanced to:

1. Install a cathodic protection system in accordance with NACE SP0169-2007 for buried carbon steel piping within the scope of this program.

2. Complete a modification to abandon the buried copper alloy instrument air system piping within the scope of this program.

3. Annual cathodic protection system monitoring will be performed with a maximum grace period of two months. The system will be monitored at least once during each calendar year.

4. Utilize an inspection method that has been demonstrated to be capable of detecting cracking for uncoated stainless steel piping and when visual inspections of coated stainless steel piping detect coating degradation or damage which could potentially result in stress corrosion cracking of the base material. Indications of cracking will be evaluated in accordance with applicable codes and plant-specific design criteria.

5. Perform wall thickness measurement if visual inspections identify evidence of corrosion beyond minor surface rusting for both coated and uncoated metallic piping or tanks. The results of the wall thickness measurement will be used to calculate a corrosion rate and project wall thickness through the end of the SPEO. If the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the SPEO, then additional inspections will be performed as follows: When measured pipe wall thickness, projected to the end of the SPEO, does not meet the minimum pipe wall thickness requirements due to external corrosion, the number of inspections within the affected piping category will be doubled or increased by five, whichever is smaller. If adverse indications are found in the expanded sample, an extent of condition and extent of cause analysis to determine the further extent of inspections. Timing of any additional inspections will be based on the severity of the identified degradation and the consequences of leakage or loss of function. Any additional inspections will be performed within the same 10-year inspection interval in which the original degradation was identified, or within four years after the end of the 10-year interval if the

degradation was identified in the latter half of the 10-year interval. Expansion of sample size may be limited by the extent of piping subject to the observed degradation mechanism or if the piping system or portion of the system is replaced or otherwise mitigated within the same 10-year inspection interval in which the original degradation was identified or within four years after the end of the 10-year interval, if the degradation was identified in the latter half of the 10-year interval.

6. Perform inspections of buried steel condenser circulating water system piping at least once every ten years. The minimum number of inspections will be determined based on the effectiveness of preventive actions in accordance with NUREG-2191, Table XI.M41-Ten linear feet of piping will be exposed for each inspection. Inspections of the large diameter condenser circulating water system intake piping will expose a quadrant (i.e., 9 to 12 oclock or 12 to 3 oclock) of the piping. External inspections of the large diameter condenser circulating water system intake piping will be supplemented by low frequency electromagnetic testing performed from the internal surface of the same section of piping that is externally inspected with follow-up ultrasonic wall thickness measurements performed of areas identified as low points during low frequency electromagnetic testing.

7. Perform visual inspections of at least two ten-linear foot sections of buried uncoated stainless steel piping at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

8. Perform visual inspections of at least four ten linear foot sections of underground coated steel piping at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

9. Internal volumetric inspections of the standby shutdown facility diesel engine fuel oil tank will cover at least 25% of the surface area of the tank and include at least some of both the top and bottom of the tank.

10. Personnel performing inspections of buried coated piping and tanks will either: 1) possess an Association for Materials Protection and Performance coating inspector program level 2 or level 3 inspector qualification, 2) complete the EPRI Comprehensive Coatings Course and complete the EPRI Buried Pipe Condition Assessment and Repair Training Computed Based Training Course, or 3) be qualified as a coatings specialist in accordance with ASTM D7108.

11. If significant coating damage is identified during visual inspections, then perform an evaluation to determine if the coating damage was caused by nonconforming backfill. If it is determined that the coating damage was caused by nonconforming backfill, then conduct an extent of condition evaluation to determine the extent of degraded backfill in the vicinity of the observed damage.

SLRA Table A6-01 (Page A-90) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 26 Buried and Underground The Buried and Underground Piping and Tanks AMP is an B2.1.26 Program enhancements for Piping and Tanks program existing program that will be enhanced to: SLR will be implemented and

1. Install a cathodic protection system in accordance with inspections begin 10 years NACE SP0169-2007 for buried carbon steel piping within before the SPEO and the scope of this program. inspections required during

2. Complete a modification to abandon the buried copper the 10 year interval prior to alloy instrument air system piping within the scope of this the SPEO will be completed program. no later than 6 months prior to

3. Annual cathodic protection system monitoring will be the SPEO.

performed with a maximum grace period of two months. The cathodic protection The system will be monitored at least once during each system for buried steel piping calendar year. will be installed no later than 5

4. Utilize an inspection method that has been demonstrated years prior to the SPEO.

to be capable of detecting cracking for uncoated Modification to abandon the stainless steel piping and when visual inspections of buried copper alloy instrument coated stainless steel piping detect coating degradation air system piping will be or damage which could potentially result in stress implemented no later than 6 corrosion cracking of the base material. Indications of months prior to the SPEO.

cracking will be evaluated in accordance with applicable codes and plant-specific design criteria.

5. Perform wall thickness measurement if visual inspections identify evidence of corrosion beyond minor surface rusting for both coated and uncoated metallic piping or tanks. The results of the wall thickness measurement will be used to calculate a corrosion rate and project wall thickness through the end of the SPEO. If the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the SPEO, then additional inspections will be performed as follows:

When measured pipe wall thickness, projected to the end

SLRA Table A6-01 (Page A-92) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 26 Buried and Underground low points during low frequency electromagnetic testing. B2.1.26 Program enhancements for Piping and Tanks program 7. Perform visual inspections of at least two ten-linear foot SLR will be implemented and sections of buried uncoated stainless steel piping at least inspections begin 10 years once every ten years. Piping inspection locations will be before the SPEO and selected based on risk (i.e., susceptibility to degradation inspections required during and consequences of failure). the 10 year interval prior to

8. Perform visual inspections of at least four ten linear foot the SPEO will be completed sections of underground coated steel piping at least once no later than 6 months prior to every ten years. Piping inspection locations will be the SPEO.

selected based on risk (i.e., susceptibility to degradation The cathodic protection system and consequences of failure). for buried steel piping will be

9. Internal volumetric inspections of the standby shutdown installed no later than 5 years facility diesel engine fuel oil tank will cover at least 25% of prior to the SPEO. Modification the surface area of the tank and include at least some of to abandon the buried copper both the top and bottom of the tank. alloy instrument air system

10. Personnel performing inspections of buried coated piping piping will be implemented no and tanks will either: 1) possess an Association for later than 6 months prior to the Materials Protection and Performance coating inspector SPEO program level 2 or level 3 inspector qualification, 2) complete the EPRI Comprehensive Coatings Course and complete the EPRI Buried Pipe Condition Assessment and Repair Training Computed Based Training Course, or 3) be qualified as a coatings specialist in accordance with ASTM D7108.

11. If significant coating damage is identified during visual inspections, then perform an evaluation to determine if the coating damage was caused by nonconforming backfill. If it is determined that the coating damage was caused by nonconforming backfill, then conduct an extent of condition evaluation to determine the extent of degraded backfill in the vicinity of the observed damage.

SLRA Appendix B2.1.26 (page B-181) is revised as follows:

Exception 2 to NUREG-2191 Program Element Affected: Detection of Aging Effects (Element 4)

2. NUREG-2191 recommends the limiting critical potential for cathodic protection systems should not be more negative than -1200 mV. The Oconee Buried and Underground Piping and Tanks AMP will maintain the instant-off potential of all test locations between -850 mV and -2000 mV for the test well on the north side of the standby shutdown facility diesel engine fuel oil tank.

Justification for Exception 2 The cathodic protection system for the standby shutdown facility diesel engine fuel oil tank was installed in 2010 to replace the original passive sacrificial anode system. Due to the location of the tank and space limitations in the area, anodes could not be installed on the south side of the tank that is adjacent to the standby shutdown facility building wall. Also, the design depth for the anodes on the north side of the tank could not be obtained due to a shallow bedrock layer in the area. In order to achieve adequate polarization at test locations for the south side of the tank, an instant-off potential more negative than - 1200 mV was required for test locations for the north side of the tank.

SLRA Appendix B2.1.26 (page B-183) is revised as follows:

Enhancements The following enhancements shall be implemented in the respective program elements: Preventive Actions (Element 2), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4),

Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7)

1. Install a cathodic protection system in accordance with NACE SP0169-2007for buried carbon steel piping within the scope of the program (Element 2).

2. Complete a modification to abandon the buried copper alloy instrument air system piping within the scope of this program. (Elements 2 and 3)

3. Annual cathodic protection system monitoring will be performed with a maximum grace period of two months. The system will be monitored at least once during each calendar year. (Element 2)

4. Utilize an inspection method that has been demonstrated to be capable of detecting cracking for uncoated stainless steel piping and when visual inspections of coated stainless steel piping detect coating degradation or damage which could potentially result in stress corrosion cracking of the base material. Indications of cracking will be evaluated in accordance with applicable codes and plant-specific design criteria. (Elements 3, 6 and 7)

SLRA Appendix B2.1.26 (page B-184) is revised as follows:

Enhancements

6. Perform inspections of buried steel condenser circulating water system piping at least once every ten years. The minimum number of inspections will be determined based on the effectiveness of preventive actions in accordance with NUREG-2191, Table XI.M41-2. Ten linear feet of piping will be exposed for each inspection. Inspections of the large diameter condenser circulating water system intake piping will expose a quadrant (i.e., 9 to 12 oclock or 12 to 3 oclock) of the piping.

External inspections of the large diameter condenser circulating water system intake piping will be supplemented by low frequency electromagnetic testing performed from the internal surface of the same section of piping that is externally inspected with follow-up ultrasonic wall thickness measurements performed of areas identified as low points during low frequency electromagnetic testing. (Element 4)

7. Perform visual inspections of at least two ten-linear foot sections of buried uncoated stainless steel piping at least once every ten years. Piping inspection locations will be selected based on risk (i.e.,

susceptibility to degradation and consequences of failure). (Element 4)

ATTACHMENT 12 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES CHANGES TO AGING MANAGEMENT REVIEW OF FIRE BARRIER PENETRATION SEALS AND CONCRETE FIRE BARRIER COMPONENTS

Changes to Aging Management Review of Fire Barrier Penetration Seals and Concrete Fire Barrier Components (TRP-26)

Affected SLRA Sections:

SLRA Table 3.3.1 SLRA Section 3.5.2.1.23 SLRA Table 3.5.2-23 SLRA Table 2.4.1-1 SLRA Table 2.4.3-1 SLRA Section 3.5.2.1.2 SLRA Table 3.5.2-1 SLRA Table 3.5.2-2 SLRA Table 3.5.2-3 SLRA Page Numbers:

3-455 3-462 3-480 3-504 3-505 3-1304 3-1453 3-1454 3-1456 2-288 2-289 2-299 3-1266 3-1355 3-1356 3-1357 3-1359 3-1361 3-1365 3-1377 3-1378 3-1379 3-1381

Description of Changes:

Table 3.5.2-23 is revised to add new rows for cementious and subliming type fire barrier penetration seals. Table 3.3.1 items 3.3.1-267 and 3.3.1-268 discussions are updated accordingly.

Table 3.5.2-23 is revised to align grout fire barrier penetration seals to NUREG-2192 Table 1 item 3.3.1-268.

Table 3.5.2-23 is revised to add new rows for steel and stainless steel components of fire barriers that are used to secure fiber blankets and fiberboards in place. The steel components are mechanical fasteners (i.e., threaded thru-rods, ring shank nails, concrete nails, concrete expansion anchors, masonry screws, sheet metal screws). The stainless steel components are tie wire. Section 3.5.2.1.23 is revised to reflect the stainless steel materials. Table 3.3.1 items 3.3.1-012, 3.3.1-058, and 3.3.1-145 discussions are updated accordingly.

Removed fire barrier intended function for concrete elements (accessible and inaccessible) and clarified the fire barrier function for these components are evaluated by the component type Concrete Elements in Tables 2.4.1-1, 2.4.3-1,3.5.2-1,and 3.5.2-3.

Removed fire barrier function from metal siding in Tables 2.4.1-1 and 3.5.2-1. Added missing structural support function for this component in Table 3.5.2-1.

Added new AMR lines to manage fire barrier functions of concrete hatches in Table 3.5.2-1.

Added new AMR lines to manage fire barrier functions of cylinder walls in Table 3.5.2-2.

Updated Section 3.5.2.1.2 to add the Fire Protection program for managing Reactor Building components.

SLRA Table 3.3.1 (page 3-455) is revised as follows Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Program Discussion Recommended 3.3.1-010 High-strength steel closure Cracking due to AMP XI.M18, Bolting No Not applicable. ONS has no in-scope bolting exposed to air, soil, stress corrosion Integrity high-strength steel closure bolting underground cracking; cyclic exposed to air, soil, or underground loading environments in the scope of SLR in auxiliary systems. The associated NUREG-2191 aging items are not used.

3.3.1-012 Steel; stainless steel, nickel Loss of material due AMP XI.M18, Bolting No Consistent with NUREG-2191.

alloy closure bolting exposed to general (steel Integrity Fasteners for fire barrier penetration seals to air - indoor uncontrolled, air only), pitting, crevice are also aligned to this item and credit

- outdoor, condensation corrosion AMP XI.M26, Fire Protection for aging management.

SLRA Table 3.3.1 (page 3-462) is revised as follows Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Further Item Aging Effect/ Aging Management Evaluation Discussion Component Number Mechanism Program Recommended 3.3.1-058 Steel halon/carbon dioxide Loss of material due AMP XI.M26, Fire Protection No Consistent with NUREG-2191.

fire suppression system to general, pitting, Fasteners for fire barrier penetration piping, piping components crevice corrosion seals are also aligned to this item.

exposed to air - indoor uncontrolled, air - outdoor, condensation

SLRA Table 3.3.1 (page 3-480) is revised as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Further Item Aging Effect/ Aging Management Component Evaluation Discussion Number Mechanism Program Recommended 3.3.1-142 Stainless steel, steel, nickel Loss of material due AMP XI.M18, Bolting No Consistent with NUREG-2191.

alloy, copper alloy closure to general (steel; Integrity bolting exposed to fuel oil, copper alloy in raw lubricating oil, treated water, water, waste water treated borated water, raw only), pitting, crevice water, waste water corrosion, MIC (raw water and waste water environments only) 3.3.1-144 Stainless steel, steel, Cracking due to AMP XI.M41, Buried and No Consistent with NUREG-2191 with aluminum piping, piping stress corrosion Underground Piping and exceptions.

components, tanks exposed cracking (steel in Tanks to soil, concrete carbonate/ Exceptions apply to the NUREG-2191 bicarbonate recommendations for the Buried and environment only) Underground Piping and Tanks (B2.1.26) program implementation.

3.3.1-145 Stainless steel closure bolting Cracking due to AMP XI.M18, Bolting No Consistent with NUREG-2191.

exposed to air, soil, concrete, stress corrosion Integrity Fasteners for fire barrier penetration seals underground, waste water cracking are also aligned to this item and credit AMP XI.M26, Fire Protection for aging management.

SLRA Table 3.3.1 (page 3-504) is revised as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Program Discussion Recommended 3.3.1-267 Subliming compound Loss of material due AMP XI.M26, Fire No Not applicable. Fire barrier materials are fireproofing/fire barriers to abrasion, flaking, Protection addressed in SRP Item 3.3.1-269. The (Thermo-lag, Darmatt', vibration; cracking/ associated NUREG-2191 aging items are 3M' Interam', and other delamination due to not used. Consistent with NUREG-2191.

Civil/Structural components are aligned to similar materials) exposed to chemical reaction, this item.

air settlement; change in material properties due to gamma irradiation exposure; separation

SLRA Table 3.3.1 (page 3-505) is revised as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Program Discussion Recommended 3.3.1-268 Cementitious coating Loss of material due AMP XI.M26, Fire No Not applicable. Fire barrier materials are fireproofing/fire barriers to abrasion, Protection addressed in SRP Item 3.3.1-269. The associated NUREG-2191 aging items are (Pyrocrete, BIO' K-10 exfoliation, elevated not used. Consistent with NUREG-2191.

Mortar, Cafecote, and other temperature, flaking, Civil/Structural components are aligned to similar materials) exposed to spalling; cracking/ this item.

air delamination due to chemical reaction, elevated temperature, settlement, vibration; change in material properties due to elevated temperature, gamma irradiation exposure; separation

SLRA Section 3.5.2.1.23 (page 3-1304) as follows:

3.5.2.1.23 Miscellaneous Structural Commodities Materials Components in the Miscellaneous Structural Commodities are constructed of the following materials:

• Cerafiber Bulk, Cerafiber Blanket, Cerafoam, Pyrocrete, Mineral Wool, 3M Putty

• Concrete

• Cork

• Elastomer

• Elastomer, Rubber and Other Similar Materials

• Grout

• Non-Metallic (e.g., Rubber)

• Pyrocrete

• Stainless Steel

• Steel

• 3M Putty

SLRA Table 3.5.2-23 (page 3-1453) is revised as follows Table 3.5.2-23 Containments, Structures, and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Fire Barriers - FB Cerafiber Bulk, Air (External) Loss of Material, Fire Protection (B2.1.15) VII.G.A-807 3.3.1- 269 A Penetration Seals Cerafiber Cracking or Blanket, Delamination, Change Cerafoam, in Material Properties, Pyrocrete, Separation Mineral Wool, 3M Putty Pyrocrete Air (External) Loss of Material, Fire Protection VII.G.A-806 3.3.1-268 A Cracking or (B2.1.15)

Delamination, Change in Material Properties, Separation 3M Putty Air (External) Loss of Material, Fire Protection VII.G.A-805 3.3.1-267 A Cracking or (B2.1.15)

Delamination, Change in Material Properties, Separation

SLRA Table 3.5.2-23 (page 3-1454) is revised as follows:

Table 3.5.2-23 Containments, Structures, and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Fire Barriers - FB Elastomer, Air (External) Hardening, loss of Fire Protection (B2.1.15) VII.G.A-19 3.3.1- 057 A Penetration Seals Rubber and Other strength, or shrinkage Similar Materials Grout Air (External) Cracking, Loss of Fire Protection (B2.1.15) VII.G.A-90 3.3.1- 060 A Material VII.G.A-806 3.3.1-268 Loss of Material, Cracking or Structures Monitoring VII.G.A-90 3.3.1- 060 A Delamination, Change (B2.1.33) in Material Properties, Separation Steel Air (External) Loss of Material Fire Protection VII.G.AP-150 3.3.1- 058 C, 6 (B2.1.15)

Stainless Steel Air (External) Loss of Material Fire Protection VII.I.A-03 3.3.1- 012 E, 6 (B2.1.15)

Cracking Fire Protection VII.I.A-426 3.3.1- 145 E, 6 (B2.1.15)

SLRA Table 3.5.2-23 (page 3-1456) is revised as follows:

Table 3.5.2-23 Containments, Structures, and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Plant Specific Notes:

1. Concrete Elements include Yard Structure Foundations, Valve Pits and Transformer Epuipment Equipment Pads.

2. Sheet piles are aligned to III.A3.TP-219, since metal piles do not appear in GALL Tables for Group 6 Structures.

3. Piles include the foundation dowels, pipe piles and piles.

4. Penetration sleeves includes louvers.

5. Air with Borated Water Leakage Environment is for components in the Auxiliary Building, Reactor Building and Borated Water Storage Tank Superstructure.

6. Steel and stainless steel fasteners used to secure fiber blankets and fiberboards in place are evaluated as fire barriers - penetration seals component type.

SLRA Table 2.4.1.1 (page 2-288) is revised as follows:

Table 2.4.1-1 Auxiliary Building Structural Member Intended Functions Anchor Structural Support Battery Racks Structural Support Bolting (structural) Structural Support Concrete Elements Fire Barrier Concrete Elements (accessible) Flood Barrier Concrete Elements (inaccessible) Heat Sink Missile Barrier Pressure Boundary Shelter, Protection Structural Support Concrete Elements (accessible) Flood Barrier Heat Sink Missile Barrier Pressure Boundary Shelter, Protection Structural Support Concrete Elements (inaccessible) Flood Barrier Heat Sink Missile Barrier Pressure Boundary Shelter, Protection Structural Support

SLRA Table 2.4.1-1 (page 2-289) is revised as follows:

Table 2.4.1-1 Auxiliary Building Structural Member Intended Functions Doors Fire Barrier Flood Barrier Pressure Boundary Structural Support Fiber Reinforced Polymer Structural Support Lead Shield Support Structural Support Masonry Wall Fire Barrier Shelter, Protection Structural Support Metal Siding Fire Barrier Pressure Boundary Shelter, Protection Structural Support Roof Membrane Shelter, Protection Stainless Steel Elements Shelter, Protection Structural Support Steel Elements Shelter, Protection Structural Support Spent Fuel Pool Liner Plates Pressure Boundary Shelter, Protection Structural Support Spent Fuel Storage Racks Shelter, Protection Structural Support Sump Structural Support

SLRA Table 2.4.3-1 (page 2-299) is revised as follows:

Table 2.4.3-1 Turbine Building Structural Component Intended Functions Anchors Structural Support Bolting (structural) Structural Support Concrete Elements Fire Barrier Concrete Elements (accessible) Flood Barrier Concrete Elements (inaccessible) Missile Barrier Shelter, Protection Structural Support Concrete Elements (accessible) Flood Barrier Missile Barrier Shelter, Protection Structural Support Concrete Elements (inaccessible) Flood Barrier Missile Barrier Shelter, Protection Structural Support

SLRA Section 3.5.2.1.2 (page 3-1266) is revised as follows:

Aging Management Programs The aging effects for components in the Reactor Building are managed by the following AMPs:

• 10 CFR 50, Appendix J (B2.1.31)

• ASME Section XI, Subsection IWE (B2.1.28)

• ASME Section XI, Subsection IWL (B2.1.29)

• Boric Acid Corrosion (B2.1.4)

• Fire Protection (B2.1.15)

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B2.1.13)

• Masonry Walls (B2.1.32)

• Protective Coating Monitoring and Maintenance (B2.1.35)

• Secondary Shield Wall Tendon Surveillance Program (B4.1)

• Structures Monitoring (B2.1.33)

• TLAA

SLRA Table 3.5.2-1 (page 3-1355) is revised as follows Table 3.5.2-1 Containments, Structures, and Component Supports - Auxiliary Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Concrete Elements FB; FLD; HS; Concrete Air - Outdoor (External) Increase in Porosity Structures Monitoring III.A3.TP-28 3.5.1- 067 A,1 MB; PB; SP; and Permeability, (B2.1.33)

SS Cracking, Loss of Material (Spalling, Scaling)

Air (External) Cracking, Loss of Fire Protection (B2.1.15) VII.G.A-90 3.3.1- 060 A,1, Material 8 Structures Monitoring VII.G.A-90 3.3.1- 060 A,1 (B2.1.33)

Groundwater/Soil Cracking, Loss of Structures Monitoring III.A3.TP-27 3.5.1- 065 A,1 (External) Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Soil (External) Cracking, Distortion Structures Monitoring III.A3.TP-30 3.5.1- 044 A,1 (B2.1.33)

Concrete Elements FB; FLD; HS; Concrete Air - Indoor Cracking Structures Monitoring III.A3.TP-25 3.5.1- 054 A,1 (Accessible) MB; PB; SP; Uncontrolled (External) (B2.1.33)

SS Cracking, Loss of Structures Monitoring III.A3.TP-26 3.5.1- 066 A,1 Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Air - Outdoor (External) Cracking Structures Monitoring III.A3.TP-25 3.5.1- 054 A,1 (B2.1.33)

Cracking, Loss of Structures Monitoring III.A3.TP-26 3.5.1- 066 A,1 Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

SLRA Table 3.5.2-1 (page 3-1356) is revised as follows:

Table 3.5.2-1 Containments, Structures, and Component Supports - Auxiliary Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Concrete Elements FB; FLD; HS; Concrete Air - Outdoor (External) Loss of Material Structures Monitoring III.A3.TP-23 3.5.1- 064 A,1 (Accessible) MB; PB; SP; (Spalling, Scaling), (B2.1.33)

SS Cracking Water - Flowing Cracking Structures Monitoring III.A3.TP-25 3.5.1- 054 A,1 (External) (B2.1.33)

Increase in Porosity Structures Monitoring III.A3.TP-24 3.5.1- 063 A,1 and Permeability, Loss (B2.1.33) of Strength Concrete Elements FB; FLD; HS; Concrete Air - Indoor Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (Inaccessible) MB; PB; SP; Uncontrolled (External) (B2.1.33)

SS Air - Outdoor (External) Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (B2.1.33)

Groundwater/Soil Cracking, Loss of Structures Monitoring III.A3.TP-212 3.5.1- 065 A,1 (External) Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Increase in Porosity Structures Monitoring III.A3.TP-29 3.5.1- 067 A,1 and Permeability, (B2.1.33)

Cracking, Loss of Material (Spalling, Scaling)

Loss of Material Structures Monitoring III.A3.TP-108 3.5.1- 042 A,1 (Spalling, Scaling), (B2.1.33)

Cracking Soil (External) Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (B2.1.33)

SLRA Table 3.5.2-1(page 3-1357) is revised as follows:

Table 3.5.2-1 Containments, Structures, and Component Supports - Auxiliary Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Concrete Elements FB; FLD; HS; Concrete Water - Flowing Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (Inaccessible) MB; PB; SP; (External) (B2.1.33)

SS Increase in Porosity Structures Monitoring III.A3.TP-67 3.5.1- 047 A,1 and Permeability, Loss (B2.1.33) of Strength Concrete Hatches FB; MB; SP; Concrete Air - Indoor Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A SS Uncontrolled (External) (B2.1.33)

III.A3.TP-25 3.5.1- 054 A Cracking, Loss of Structures Monitoring III.A3.TP-26 3.5.1- 066 A Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Increase in Porosity Structures Monitoring III.A3.TP-28 3.5.1- 067 A and Permeability, (B2.1.33)

Cracking, Loss of Material (Spalling, Scaling)

Air (External) Cracking, Loss of Fire Protection VII.G.A-90 3.3.1- 060 A Material (B2.1.15)

Structures Monitoring VII.G.A-90 3.3.1- 060 A (B2.1.33)

SLRA Table 3.5.2-1 (page 3-1359) is revised as follows:

Table 3.5.2-1 Containments, Structures, and Component Supports - Auxiliary Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Metal Siding FB; PB; SP; Steel Air - Indoor Loss of Material Structures Monitoring III.A3.TP-302 3.5.1- 077 A SS Uncontrolled (External) (B2.1.33)

Air - Outdoor (External) Loss of Material Structures Monitoring III.A3.TP-302 3.5.1- 077 A (B2.1.33)

Air with Borated Water Loss of Material Boric Acid Corrosion III.B5.T-25 3.5.1- 089 A Leakage (External) (B2.1.4)

SLRA Table 3.5.2-1 (page 3-1361) is revised as follows:

Table 3.5.2-1 Containments, Structures, and Component Supports - Auxiliary Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Plant Specific Notes:

1. Concrete Elements include beams, columns, walls, slabs, curbs, foundations and pads.

2. Steel elements include beams, columns, baseplates, bracing, stairs, platforms, grating, decking, ladders and embedded steel.

3. Stainless steel elements include fall restraint system.

4. None.

5. Sump includes the concrete sump and the stainless steel lined concrete cover for the low and high activity tanks.

6. The Masonry Walls are internal to the building structure and are not subject to air - outdoor aging effects.

7. The Structures Monitoring AMP is credited for monitoring the leak chase channels for liner leakage.

8. The credited fire barrier concrete elements (accessible and inaccessible) for the structure are evaluated in this component type.

SLRA Table 3.5.2-2 (page 3-1365) is revised as follows:

Table 3.5.2-2 Containments, Structures, and Component Supports - Reactor Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Cylinder Walls SS; SP; FB; Concrete Air (External) Cracking, Loss of Fire Protection VII.G.A-90 3.3.1- 060 A MB; HS Material (B2.1.15)

ASME Section XI, VII.G.A-90 3.3.1- 060 E Subsection IWL (B2.1.29)

Air - Indoor Cracking ASME Section XI, II.A1.CP-67 3.5.1- 012 A,1 Uncontrolled (External) Subsection IWL (B2.1.29)

Cracking, Loss of ASME Section XI, II.A1.CP-97 3.5.1- 023 A, 1 Bond, Loss of Material Subsection IWL (Spalling, Scaling) (B2.1.29)

Increase in Porosity ASME Section XI, II.A1.CP-100 3.5.1- 024 A, 1 and Permeability, Subsection IWL Cracking, Loss of (B2.1.29)

Material (Spalling, Scaling)

SLRA Table 3.5.2-3 (page 3-1377) is revised as follows:

Table 3.5.2-3 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Anchor SS Steel Air - Indoor Loss of Material Structures Monitoring III.B5.TP-43 3.5.1- 092 A Uncontrolled (External) (B2.1.33)

Loss of Preload Structures Monitoring III.A3.TP-261 3.5.1- 088 A (B2.1.33)

Bolting (Structural) SS Steel Air - Indoor Loss of Material Structures Monitoring III.A3.TP-248 3.5.1- 080 A Uncontrolled (External) (B2.1.33)

Loss of Preload Structures Monitoring III.A3.TP-261 3.5.1- 088 A (B2.1.33)

Air - Outdoor (External) Loss of Material Structures Monitoring III.A3.TP-248 3.5.1- 080 A (B2.1.33)

Loss of Preload Structures Monitoring III.A3.TP-261 3.5.1- 088 A (B2.1.33)

Concrete Elements FB; FLD; MB; Concrete Air - Indoor Increase in Porosity Structures Monitoring III.A3.TP-28 3.5.1- 067 A,1 SP; SS Uncontrolled (External) and Permeability, (B2.1.33)

Cracking, Loss of Material (Spalling, Scaling)

Air - Outdoor (External) Increase in Porosity Structures Monitoring III.A3.TP-28 3.5.1- 067 A,1 and Permeability, (B2.1.33)

Cracking, Loss of Material (Spalling, Scaling)

Air (External) Cracking, Loss of Fire Protection (B2.1.15) VII.G.A-90 3.3.1- 060 A,1, Material 4 Structures Monitoring VII.G.A-90 3.3.1- 060 A,1 (B2.1.33)

SLRA Table 3.5.2-3 (page 3-1378) is revised as follows:

Table 3.5.2-3 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Concrete Elements FB; FLD; MB; Concrete Groundwater/Soil Cracking, Loss of Structures Monitoring III.A3.TP-27 3.5.1- 065 A,1 SP; SS (External) Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Soil (External) Cracking, Distortion Structures Monitoring III.A3.TP-30 3.5.1- 044 A,1 (B2.1.33)

Concrete Elements FB; FLD; MB; Concrete Air - Indoor Cracking Structures Monitoring III.A3.TP-25 3.5.1- 054 A,1 (Accessible) SP; SS Uncontrolled (External) (B2.1.33)

Cracking, Loss of Structures Monitoring III.A3.TP-26 3.5.1- 066 A,1 Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Air - Outdoor (External) Cracking Structures Monitoring III.A3.TP-25 3.5.1- 054 A,1 (B2.1.33)

Cracking, Loss of Structures Monitoring III.A3.TP-26 3.5.1- 066 A,1 Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Loss of Material Structures Monitoring III.A3.TP-23 3.5.1- 064 A,1 (Spalling, Scaling), (B2.1.33)

Cracking Water - Flowing Increase in Porosity Structures Monitoring III.A3.TP-24 3.5.1- 063 A,1 (External) and Permeability, Loss (B2.1.33) of Strength Concrete Elements FB; FLD; MB; Concrete Air - Indoor Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (Inaccessible) SP; SS Uncontrolled (External) (B2.1.33)

Air - Outdoor (External) Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (B2.1.33)

SLRA Table 3.5.2-3 (page 3-1379) is revised as follows:

Table 3.5.2-3 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Concrete Elements FB; FLD; MB; Concrete Groundwater/Soil Cracking, Loss of Structures Monitoring III.A3.TP-212 3.5.1- 065 A,1 (Inaccessible) SP; SS (External) Bond, Loss of Material (B2.1.33)

(Spalling, Scaling)

Increase in Porosity Structures Monitoring III.A3.TP-29 3.5.1- 067 A,1 and Permeability, (B2.1.33)

Cracking, Loss of Material (Spalling, Scaling)

Loss of Material Structures Monitoring III.A3.TP-108 3.5.1- 042 A,1 (Spalling, Scaling), (B2.1.33)

Cracking Soil (External) Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (B2.1.33)

Water - Flowing Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (External) (B2.1.33)

Increase in Porosity Structures Monitoring III.A3.TP-67 3.5.1- 047 A,1 and Permeability, Loss (B2.1.33) of Strength Cranes: Rails, SS Steel Air (External) Cumulative Fatigue TLAA VII.B.A-06 3.3.1- 001 A Bridges, Structural Damage Members, Structural Components Loss of Material, Wear, Inspection of Overhead VII.B.A-07 3.3.1- 052 A Deformation, Cracking Heavy Load and Light Load (Related to Refueling) Handling Systems (B2.1.13)

Table 3.5.2-3, page 3-1381 is revised as follows:

Table 3.5.2-3 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Steel Elements SP; SS Steel Air - Outdoor (External) Loss of Material Structures Monitoring III.A3.TP-302 3.5.1- 077 A,2 (B2.1.33)

Plant Specific Notes:

1. Concrete Elements include beams, columns, walls, slabs, curbs, foundations, sumps, pads and the concrete portion of the CT4 missile door.

2. Steel elements include beams, columns, baseplates, bracing, stairs, platforms, grating, decking, ladders and embedded steel (including the portion in the CT4 missile door).

3. The Masonry Walls are internal to the building structure and are not subject to air - outdoor aging effects.

4. The credited fire barrier concrete elements (accessible and inaccessible) for the structure are evaluated in this component type.

ATTACHMENT 13 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES ADDITIONAL INFORMATION ON STARTUP TRANSFORMER DROP LINE REPLACEMENT FREQUENCY

Additional Information on Startup Transformer Drop Line Replacement Frequency (TRP-53.1, 53.2, 54, 58 and 63)

Affected SLRA Section:

SLRA Section 3.6.2.2.3 SLRA Page Numbers:

3-1468 Description of Changes:

This Supplement provides additional supporting information on the conservative selection of the 10-year replacement frequency for the drop lines on startup transformers CT1, CT2, and CT3.

SLRA Section 3.6.2.2.3 (page 3-1468) is revised as follows:

Wind-Induced Abrasion and Fatigue - Transmission Conductors ONS operating experience includes the partial and complete severance failure of aluminum conductor steel reinforced transformer drop line conductors/terminations to startup transformers CT2 and CT3, respectively.

A 2002 CT2 partial drop line severance failure occurred after approximately 30 years of operation and a 2015 CT3 complete drop line severance failure occurred after approximately 40 years of operation. The ONS startup transformer drop lines consist of 4/0 aluminum conductor steel reinforced cable with a 0.556 inch diameter, which is substantially smaller than the cable size typical of today's standards for 230 kV operation.

While this smaller cable is capable of carrying the required ampacity of the startup transformer, the causal evaluation for this the CT3 failure determined wind-induced (aeolian) vibrations of these smaller conductors can produce damage that will negatively impact the reliability of these lines. The causal evaluation further determined that vulnerability to this aging mechanism at ONS is limited to the overhead transmission conductors and drop lines to startup transformers CT1, CT2, and CT3. The corrective action arising from this failure resulted in a preventive maintenance activity to replace the aluminum conductor steel reinforced transmission conductors and drop lines to all three startup transformers on a 10 year frequency.

During replacement intervals, inspections for drop line degradation are performed on a daily, monthly, and biennial basis. Equipment has been installed on CT1, CT2, and CT3 to actively monitor for drop line open phase conditions. The 10-year replacement frequency combined with daily, monthly, and biennial inspections for degraded drop line conductors provides conservative margin to preclude future conductor failures. If future inspections detect unexpected degradation between drop line replacements, this internal OE will be used to adjust the replacement frequency or make other changes as necessary. Given that these conductors are now replaced on a specified frequency, they are considered short-lived, such that no further aging management is required.

ATTACHMENT 14 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES REVISED EXCEPTION AND ENHANCEMENT DISCUSSION FOR FIRE WATER SYSTEM AGING MANAGEMENT PROGRAM

Revised Exception and Enhancement discussion for Fire Water System Aging Management Program (TRP-27)

Affected SLRA Section:

SLRA Appendix A2.16 SLRA Appendix A6.0-1 SLRA Appendix B2.1.16 SLRA Page Numbers:

A-18 A-83 A-84 B-124 B-127 Description of Change:

The Fire Water System AMP, as described in SLRA Appendix A and Appendix B, is revised to make two changes. First, the AMP is revised to delete Exception 1 and update Enhancement 6 to require periodic hose station flow testing to be performed at the hydraulically most remote hose station in each building. Second, Enhancement 9 is revised to rely only on comparison to a baseline value that will be established during initial testing for the main drain test acceptance criteria rather than also allowing main drain test results to be compared to previous test results to determine acceptability.

SLRA Appendix A2.16 (page A-18) is revised as follows:

Enhancements The Fire Water System AMP will be enhanced to:

6. Perform flow testing of at least one hose station in each building every five years to demonstrate the capability to provide the design pressure at required flow. Flow testing will be performed at the hydraulically most remote hose station or, if an alternative hose station is tested, the acceptance criteria for the test will account for the additional head loss that would occur if the hydraulically most remote hose station were tested such that the results of the flow test are representative of the limiting location. If acceptance criteria are not met, at least two additional tests shall be performed within five years. If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

7. Perform external visual inspections of the elevated water storage tank consistent with Section 9.2.5.5 of NFPA 25, 2011 Edition at least once every two years.

8. Perform flushing of the mainline strainers following system actuation consistent with Section 10.2.7 of NFPA 25, 2011 Edition.

9. Perform main drain testing of the deluge system risers at least once every two years. Main drain testing of deluge systems will be performed consistent with the procedure described in Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value the original acceptance test or previously performed tests, the cause of the reduction shall be identified and corrected if necessary. If acceptance criteria are not met, at least two additional tests shall be performed within two years. If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

SLRA Table A6.0-1 (pages A-83 and A-84) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 16 Fire Water The Fire Water System AMP is an existing program that will be enhanced to: B2.1.16 Program enhancements System program for SLR will be

6. Perform flow testing of at least one hose station in each building every five implemented 6 months years to demonstrate the capability to provide the design pressure at prior to the SPEO.

required flow. Flow testing will be performed at the hydraulically most Inspections or tests that remote hose station, or if an alternative hose station is tested, the are to be completed acceptance criteria for the test will account for the additional head loss prior to SPEO are that would occur if the hydraulically most remote hose station were tested completed 6 months such that the results of the flow test are representative of the limiting prior to the SPEO or no location. If acceptance criteria are not met, at least two additional tests later than the last shall be performed within five years. If subsequent tests do not meet refueling outage prior to acceptance criteria, an extent of condition and extent of cause analysis is the SPEO.

conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

7. Perform external visual inspections of the elevated water storage tank in accordance with Section 9.2.5.5 of NFPA 25, 2011 Edition at least once every two years.

8. Perform flushing of the mainline strainers following system actuation in accordance with Section 10.2.7 of NFPA 25, 2011 Edition.

9. Perform main drain testing of the deluge system risers at last once every two years. Main drain testing of deluge systems will be performed in accordance with the procedure described Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value the original acceptance test or previously performed tests, the cause of the reduction shall be identified and corrected if necessary. If acceptance criteria are not met, at least two additional tests shall be performed within two years.

If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

SLRA Appendix B2.1.16 (page B-124) is revised as follows:

Exception 1 to NUREG-2191 Program Element Affected: Detection of Aging Effects (Element 4)

1. Not used.

NUREG 2191, Table XI.M27-1 recommends flow testing of the hydraulically most remote hose connection of each zone of the automatic standpipe system to verify the water supply can provide the design pressure at the required flow. The Oconee Fire Water System AMP will allow flow testing at hose connections other than the hydraulically most remote location.

Justification for Exception 1 As described in Section A.6.3.1.1 of NFPA 25, 2011 Edition, the hydraulically most remote hose stations are generally located at upper elevations. However, internal sediment and fouling is generally more prevalent at system low points. The program will allow for flow testing of hose stations at or near system low points where flow blockage due to fouling is most likely to occur.

Testing of lower elevation hose stations also allows for additional flushing of the system piping most susceptible to accumulation of silt and debris such that the impact of fouling on system performance is mitigated. Further, Oconee fire suppression system design does not include a typical standpipe system where multiple hose stations on each floor are supplied through a single standpipe equipped with a control valve and alarm check valve. Instead, hose stations are supplied locally from the building header. The three-year flow test of the fire suppression system headers ensures that adequate water supply is available locally to hose stations throughout the station. If the hose station selected for testing is other than the hydraulically most remote, the acceptance criteria for the flow test will be set to account for the additional head loss that would be experienced if the hydraulically most remote hose station were tested such that the results of the flow test are representative of the limiting location.

SLRA Appendix B2.1.16 (page B-127) is revised as follows:

Enhancements The following enhancements shall be implemented in the respective program elements:

Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7)

6. Perform flow testing of at least one hose station in each building every five years to demonstrate the capability to provide the design pressure at required flow. Flow testing will be performed at the hydraulically most remote hose station or, if an alternative hose station is tested, the acceptance criteria for the test will account for the additional head loss that would occur if the hydraulically most remote hose station were tested such that the results of the flow test are representative of the limiting location. If acceptance criteria are not met, at least two additional tests shall be performed within five years. If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

7. Perform external visual inspections of the elevated water storage tank consistent with Section 9.2.5.5 of NFPA 25, 2011 Edition at least once every two years.

8. Perform flushing of the mainline strainers following system actuation consistent with Section 10.2.7 of NFPA 25, 2011 Edition.

9. Perform main drain testing of the deluge system risers at least once every two years. Main drain testing of deluge systems will be performed consistent with the procedure described Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value the original acceptance test or previously performed tests, the cause of the reduction shall be identified and corrected if necessary. If acceptance criteria are not met, at least two additional tests shall be performed within two years. If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at one of the other units with the same material, environment, and aging effect combination.

10. Acceptance criteria and corrective actions for internal inspections of the elevated water storage tank will be in accordance with the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers and Tanks program. Tank wall thickness measurements will be conducted if interior pitting or general corrosion (beyond minor surface rust) is detected.

ATTACHMENT 15 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES CLARIFICATION OF FIRE WATER SYSTEM AGING MANAGEMENT PROGRAM IMPLEMENTATION SCHEDULE

Clarification of Fire Water System Aging Management Program implementation schedule (TRP-27)

Affected SLRA Sections:

SLRA Table A6.0-1 SLRA Page Numbers:

A-82 Description of Change:

The implementation schedule for the subsequent license renewal commitment associated with the Fire Water System program is revised to clarify the schedule.

SLRA Table A6.0-1 (page A-82) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 16 Fire Water System The Fire Water System AMP is an existing program that will be enhanced to: B2.1.16 Program enhancements for program 1. Perform internal visual inspections of deluge system piping by removing a SLR will be implemented hydraulically remote nozzle to identify internal corrosion, foreign material, and inspections or tests will and obstructions to flow. Internal visual inspections will be performed in 50 begin 5 years 6 months percent of the deluge systems within the scope of the Fire Water System prior to the SPEO.

AMP that are not subject to flow testing every five years. During the Inspections or tests that are subsequent five year inspection period, the alternate systems will be to be completed prior to the inspected such that piping in 100 percent of the deluge systems within the SPEO are will be scope of the program is inspected every ten years. Follow-up volumetric completed 6 months prior to wall thickness examinations will be performed if internal visual inspections the SPEO or no later than detect an unexpected level of degradation due to corrosion and corrosion the last refueling outage product deposition. prior to the SPEO.

2. Prior to 50 years in service, sprinkler heads will be submitted for field-service testing by a recognized testing laboratory consistent with NFPA 25, 2011 Edition, Section 5.3.1.

3. Perform a one-time volumetric wall thickness inspection on a representative sample deluge system supply piping that is periodically subjected to flow during functional testing.

4. Perform an obstruction investigation in accordance with NFPA 25, 2011 Edition, Section 14.3 if evidence of unacceptable internal flow blockage that could result in failure of system function is identified during internal inspections. When unacceptable internal flow blockage is detected, corrective actions will include removal of the material, an extent of condition determination, review for increased inspections, follow-up examinations, and a flush in accordance with NFPA 25 Annex D.5, Flushing Procedures.

ATTACHMENT 16 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES PROVIDED ADDITIONAL INFORMATION FOR CONTAINMENT FURTHER EVALUATION AND FOR OTHER STRUCTURE AND COMPONENT SUPPORTS FURTHER EVALUATION

Provided Additional Information for Containment Further Evaluation and for Other Structure and Component Supports Further Evaluation (TRP-74)

Affected SLRA Sections:

SLRA Section 3.5.2.2.1.7 SLRA Section 3.5.2.2.2.1 SLRA Section 3.5.2.2.2.3 SLRA Page Numbers:

3-1311 3-1314 3-1316 Description of Change:

Additional information is provided for the further evaluation required discussions regarding the air content of concrete for Group 1-3, 5, 6, and 7-9 structures. Additional discussion is provided to clarify plant operating experience related to freeze-thaw in relation to the effectiveness of the existing aging management program credited for management of concrete.

SLRA Section 3.5.2.2.1.7 (page 3-1311) is revised as follows:

3.5.2.2.1.7 Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw NUREG-2192 Loss of material (scaling, spalling) and cracking due to freeze-thaw could occur in inaccessible areas of PWR and BWR concrete containments. Further evaluation is recommended of this aging effect to determine the need for a plant-specific AMP or plant-specific enhancements to ASME Code Section XI, Subsection IWL, and/or Structures Monitoring AMPs, to manage these aging effects for plants located in moderate to severe weathering conditions. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR).

Evaluation

[3.5.1-011] - ONS is located in a moderate weathering region, as defined in ASTM C-33. ONS containment concrete components were designed in accordance with ACI 318-63 and constructed in accordance with ACI 301, using ingredients conforming to ACI and ASTM standards which provide a dense, low permeability concrete to protect against corrosion. Procedural controls ensured quality throughout the batching, mixing, and placement processes. Plant specifications for QA concrete list acceptable air content by mix designation. The acceptable air content parameters are all within a range of 3% to 8%. Review of plant OE has not identified instances of aging effects related to freeze-thaw in accessible areas and the, however the structural integrity of the components was not impacted and the conditions will be monitored during subsequent inspections. The Structures Monitoring (B2.1.33) program and the ASME Section XI, Subsection IWL (B2.1.29) program confirm the absence of aging effects by examining normally inaccessible structural components when scheduled maintenance work and planned plant modifications permit access. Therefore, a plant-specific AMP or plant-specific enhancements to the Structures Monitoring (B2.1.33) program and the ASME Section XI, Subsection IWL (B2.1.29) program for inaccessible areas to manage the aging effects of loss of material (scaling, spalling) and cracking due to freeze-thaw are not required.

SLRA Section 3.5.2.2.2.1 (page 3-1314) is revised as follows:

3.5.2.2.2.1 Aging Management of Inaccessible Areas Evaluation

[3.5.1-042] - ONS is located in a moderate weathering region, as defined in ASTM C-33. Reinforced concrete structures at ONS were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete.

Procedural controls ensured quality throughout the batching, mixing, and placement processes. Plant specifications for QA concrete list acceptable air content by mix designation. The acceptable air content parameters are all within a range of 3% to 8%. Review of plant OE has not identified instances of aging effects related to freeze- thaw in accessible areas and the, however the structural integrity of the components was not impacted and the conditions will be monitored during subsequent inspections. The Structures Monitoring (B2.1.33) program confirms the absence of aging effects by examining normally inaccessible structural components when scheduled maintenance work and planned plant modifications permit access. Therefore, a plant-specific AMP or plant-specific enhancements to the Structures Monitoring (B2.1.33) program for inaccessible areas to manage the aging effects of loss of material (scaling, spalling) and cracking due to freeze-thaw are not required.

SLRA Section 3.5.2.2.2.3 (page 3-1316) is revised as follows:

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures Evaluation

[3.5.1-049] - ONS is located in a moderate weathering region, as defined in ASTM C-33. Reinforced concrete structures at ONS were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete.

Procedural controls ensured quality throughout the batching, mixing, and placement processes. Plant specifications for QA concrete list acceptable air content by mix designation. The acceptable air content parameters are all within a range of 3% to 8%. Review of plant OE has not identified any instances of aging effects related to freeze-thaw in accessible areas, however the structural integrity of the components was not impacted and the conditions will be monitored during subsequent inspections. The Structures Monitoring (B2.1.33) program confirms the absence of aging effects by examining normally inaccessible structural components when scheduled maintenance work and planned plant modifications permit access. Therefore, a plant-specific AMP or plant-specific enhancements to the Structures Monitoring (B2.1.33) program for inaccessible areas to manage the aging effects of loss of material (scaling, spalling) and cracking due to freeze-thaw are not required.

ATTACHMENT 17 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES CORRECTED INCONSISTENCY REGARDING INACCESSIBLE CONCRETE ELEMENTS IN AGING MANAGEMENT REVIEW TABLES

Corrected Inconsistency regarding Inaccessible Concrete Elements in Aging Management Review Tables (TRP-74)

Affected SLRA Sections:

SLRA Table 3.5.2-20 SLRA Table 3.5.2-21 SLRA Page Numbers:

3-1438 3-1439 3-1441 Description of Change:

Correct inconsistency regarding the application of aging effects to inaccessible concrete elements in the aging management review tables.

The entries for the Health Physics Office Building and the Administration Building are revised to align with the inaccessible concrete AMR lines for the Auxiliary Building, Turbine Building, Keowee Hydro Station, Electrical Related Structures, Borated Water Storage Tank Superstructure, Essential Siphon Vacuum Building, Protected Service Water Building, Protective Service Water Conduit Duct Banks, Standby Shutdown Facility, Radwaste Facility, Trenches, Technical Support Building, Microwave House Structure, Manholes, and Miscellaneous Structural Commodities.

SLRA Table 3.5.2-20 (page 3-1438) is revised as follows:

Table 3.5.2-20 Containments, Structures, and Component Supports - Health Physics Office Building - Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG- NUREG- Notes Function Management 2191 2192 Program Item Table 1 Concrete Elements SS Concrete Groundwater/Soil Cracking Structures III.A3.TP- 3.5.1- A,1 (Inaccessible) (External) Monitoring 204 043 (B2.1.33)

Cracking, Loss of Bond, Loss of Structures III.A3.TP- 3.5.1- A,1 Material (Spalling, Scaling) Monitoring 212 065 (B2.1.33)

Increase in Porosity and Structures III.A3.TP- 3.5.1- A,1 Permeability, Cracking, Loss of Monitoring 29 067 Material (Spalling, Scaling) (B2.1.33)

None None III.A3.TP- 3.5.1- I,1,3 Loss of Material (Spalling, Scaling), Structures 108 042 A,1 Cracking Monitoring (B2.1.33)

Water - Flowing Cracking Structures III.A3.TP- 3.5.1- A,1 (External) Monitoring 204 043 (B2.1.33)

Increase in Porosity and Structures III.A3.TP- 3.5.1- A,1 Permeability, Loss of Strength Monitoring 67 047 (B2.1.33)

SLRA Table 3.5.2-20 (page 3-1439) is revised as follows:

Table 3.5.2-20 Containments, Structures, and Component Supports - Health Physics Office Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG- NUREG- Notes Type Function Program 2191 2192 Item Table 1 Doors SP; SS Steel Air - Indoor Uncontrolled Loss of Structures Monitoring III.A3.TP-302 3.5.1- 077 A (External) Material (B2.1.33)

Air - Outdoor (External) Loss of Structures Monitoring III.A3.TP-302 3.5.1- 077 A Material (B2.1.33)

Metal Siding SP Aluminum Air - Outdoor (External) Loss of Structures Monitoring III.B3.T-37b 3.5.1- 100 C Material, (B2.1.33)

Cracking Roof SP Elastomer, Air - Outdoor (External) Loss of Structures Monitoring III.A6.TP-7 3.5.1- 072 A Membrane Rubber and Sealing (B2.1.33)

Other Similar Materials Steel Elements SS Steel Air - Indoor Uncontrolled Loss of Structures Monitoring III.A3.TP-302 3.5.1- 077 A,2 (External) Material (B2.1.33)

Air - Outdoor (External) Loss of Structures Monitoring III.A3.TP-302 3.5.1- 077 A,2 Material (B2.1.33)

Plant Specific Notes:

1 Concrete Elements include the footers and slabs.

2 Steel elements includes support members, bearing plates, base plates and connections 3 The concrete is not subject to loss of material (spalling, scaling) and cracking due to freeze-thaw. See Further Evaluation 3.5.2.2.2.1.1.

SLRA Table 3.5.2-21 (page 3-1441) is revised as follows:

Table 3.5.2-21 Containments, Structures, and Component Supports - Administration Building - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG- NUREG- Notes Type Function Program 2191 2192 Item Table 1 Concrete SS Concrete Groundwater/Soil Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 Elements (External) (B2.1.33)

(Inaccessible)

Cracking, Loss of Bond, Structures Monitoring III.A3.TP-212 3.5.1- 065 A,1 Loss of Material (B2.1.33)

(Spalling, Scaling)

Increase in Porosity and Structures Monitoring III.A3.TP-29 3.5.1- 067 A,1 Permeability, Cracking, (B2.1.33)

Loss of Material (Spalling, Scaling)

None None III.A3.TP-108 3.5.1- 042 I,1,2 Loss of Material Structures Monitoring A,1 (Spalling, Scaling), (B2.1.33)

Cracking Water - Flowing Cracking Structures Monitoring III.A3.TP-204 3.5.1- 043 A,1 (External) (B2.1.33)

Increase in Porosity and Structures Monitoring III.A3.TP-67 3.5.1- 047 A,1 Permeability, Loss of (B2.1.33)

Strength Plant Specific Notes:

1 Concrete Elements include the foundation.

2 The concrete is not subject to loss of material (spalling, scaling) and cracking due to freeze-thaw. See Further Evaluation 3.5.2.2.2.1.1.

ATTACHMENT 18 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES REVISED INSPECTION OF DELUGE SYSTEM

Revised Inspection of Deluge System (TRP-27)

Affected SLRA Sections:

SLRA Appendix A2.16 SLRA Table A6.0-1 SLRA Appendix B2.1.16 SLRA Page Numbers:

A-18 A-82 B-126 Description of Change:

One-time volumetric wall thickness inspection of deluge system piping that is periodically subject to flow but is normally dry will be performed as part of the Fire Water System program. The commitment associated with the one-time inspection volumetric wall thickness is revised to include parameters from the One-Time Inspection program (i.e., sample size, identification of inspection locations, acceptance criteria, and evaluation of the need for follow-up examinations).

SLRA Section A2.16 (page A-18) is revised as follows:

A2.16 Fire Water System Enhancements The Fire Water System AMP will be enhanced to:

3. Perform a one-time volumetric wall thickness inspection on a representative sample of deluge system supply piping that is periodically subjected to flow during functional testing. The representative sample will be based on the population of deluge system piping that is periodically subject to flow but is normally dry. The one-time volumetric wall thickness inspection activity will include criteria for selection of inspection locations, acceptance criteria, and will specify the need for follow-up examinations based on inspection results.

SLRA Table A6.0-1 (page A-82) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 16 Fire Water System The Fire Water System AMP is an existing program that will be enhanced to: B2.1.16 Program enhancements for program 1. Perform internal visual inspections of deluge system piping by removing a SLR will be implemented 6 hydraulically remote nozzle to identify internal corrosion, foreign material, months prior to the SPEO.

and obstructions to flow. Internal visual inspections will be performed in 50 Inspections or tests that are percent of the deluge systems within the scope of the Fire Water System to be completed prior to AMP that are not subject to flow testing every five years. During the SPEO are completed 6 subsequent five year inspection period, the alternate systems will be months prior to the SPEO inspected such that piping in 100 percent of the deluge systems within the or no later than the last scope of the program is inspected every ten years. Follow-up volumetric refueling outage prior to the wall thickness examinations will be performed if internal visual inspections SPEO.

detect an unexpected level of degradation due to corrosion and corrosion product deposition.

2. Prior to 50 years in service, sprinkler heads will be submitted for field-service testing by a recognized testing laboratory consistent with NFPA 25, 2011 Edition, Section 5.3.1.

3. Perform a one-time volumetric wall thickness inspection on a representative sample of deluge system supply piping that is periodically subjected to flow during functional testing. The representative sample will be based on the population of deluge system piping that is periodically subject to flow but is normally dry. The one-time volumetric wall thickness inspection activity will include criteria for selection of inspection locations, acceptance criteria, and will specify the need for follow-up examinations based on inspection results.

SLRA Appendix B2.1.16 (page B-126) is revised as follows:

B2.1.16 Fire Water System Enhancements The following enhancements shall be implemented in the respective program elements:

Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7)

3. Perform a one-time volumetric wall thickness inspection on a representative sample of deluge system supply piping that is periodically subjected to flow during functional testing. The representative sample will be based on the population of deluge system piping that is periodically subject to flow but is normally dry. The one-time volumetric wall thickness inspection activity will include criteria for selection of inspection locations, acceptance criteria, and will specify the need for follow-up examinations based on inspection results.

ATTACHMENT 19 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES UPDATED REGARDING HIGH-STRENGTH BOLTING

Updated Regarding High-Strength Bolting (TRP-43)

Affected SLRA Section(s):

SLRA Section A2.30 SLRA Table A6.0-1 SLRA Appendix B2.1.30 SLRA Page Number(s):

A-33 A-97 B-209 B-210 Description of Change:

SLRA Section A2.30 and Section A6.0, Table A6.0-1, will be updated to include that the sample population is 20 percent of the population or a maximum of 17 bolts per unit.

SLRA Section B2.1.30 will be updated to include a statement that the only high-strength bolting within the scope of the IWF program is located on NSSS components. A statement will also be added to address the similarities between the design, operating conditions and environments for each of the three ONS units. Enhancement 5 will be updated to include the sample population is 20 percent or a maximum of 17 bolts per unit.

SLRA Appendix A2.30 (page A-33) is revised as follows:

Enhancements The ASME Section XI, Subsection IWF AMP will be enhanced to:

5. Procedures will be revised to specify that, for NSSS component supports, high strength bolting greater than one-inch nominal diameter, volumetric examination comparable to that of ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1 will be performed to detect cracking in addition to the VT-3 examination. In each 10-year period during the SPEO, a representative sample of bolts will be inspected. The sample of high- strength bolting greater than one-inch nominal diameter subject to volumetric examination will consist of 20 percent of the population or a maximum of 17 bolts per unit. The sample shall include the bolting that is most susceptible to age-related degradation (i.e., based on time in service, aggressive environment, etc.).

SLRA Table A6.0-1 (page A-97) is revised as follows:

Table A6.0-1: Subsequent License Renewal Commitments

1. Program Commitment AMP Implementation 30 ASME Section XI, The ASME Section XI, Subsection IWF AMP is an existing B2.1.30 Program enhancements for SLR will Subsection IWF program program that will be enhanced to: be implemented and a one-time

5. Procedures will be revised to specify that, for NSSS inspection of an additional 5% of the component supports, high strength bolting greater than sample size specified in Table IWF-one inch nominal diameter, volumetric examination 2500-1 for Class 1, 2, and 3 piping comparable to that of ASME Code,Section XI, Table IWB- supports is conducted within 5 years 2500-1, Examination Category B-G-1 will be performed to prior to the SPEO, and is to be completed prior to the SPEO. Other detect cracking in addition to VT-3 examination. In each 10 enhancements are completed 6 year period during the SPEO, a representative sample of months prior to the SPEO or no later bolts will be inspected. The sample of high strength bolting than the last refueling outage prior to greater than one inch nominal diameter subject to the SPEO.

volumetric examination will consist of 20 percent of the population or a maximum of 17 bolts per unit. The sample shall include the bolting that is most susceptible to age-related degradation (i.e., based on time in service, aggressive environment, etc.).

SLRA Appendix B2.1.30 (page B-209) is revised as follows:

B2.1.30 ASME XI, SUBSECTION IWF Program Description The requirements of subsection IWF are supplemented to include monitoring of high-strength bolting (actual measured yield strength greater than or equal to 150 ksi or 1,034 MPa and greater than one inch nominal diameter), with volumetric examination comparable to that of ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1 to detect cracking in addition to the VT-3 examination. The only high-strength bolting greater than one inch nominal diameter, within the scope of the IWF program, is located on NSSS components. In each ten year period during the SPEO, a representative sample of bolts will be inspected. The sample will be 20% of the population (for a material/environment combination) up to a maximum of 17 bolts per unit. This sample size is appropriate because design, operating, and environmental conditions between the units are similar enough such that aging effects are not occurring differently.

SLRA Appendix B2.1.30 (page B-210) is revised as follows:

Enhancements The following enhancements will be implemented in the following program elements: Scope of Program (Element 1), Preventive Actions (Element 2), Detection of Aging Effects (Element 4), and Monitoring and Trending (Element 5):

5. Procedures will be revised to specify that, for NSSS component supports, high-strength bolting greater than one-inch nominal diameter, volumetric examination comparable to that of ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1 will be performed to detect cracking in addition to the VT-3 examination. In each ten year period during the SPEO, a representative sample of bolts will be inspected. The sample of high- strength bolting greater than one-inch nominal diameter subject to volumetric examination will consist of 20 percent of the population or a maximum of 17 bolts per unit. The sample shall include the bolting that is

ATTACHMENT 20 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES CLARIFICATION OF OPERATING EXPERIENCE RELATED TO CALCIUM LEACHING

Clarification of Operating Experience related to Calcium Leaching (TRP-74)

Affected SLRA Sections:

SLRA Section 3.5.2.2.2.1 SLRA Section 3.5.2.2.2.3 SLRA Page Numbers:

3-1314 3-1317 Description of Change:

Additional discussion is provided to clarify plant operating experience related to calcium leaching in relation to the effectiveness of the existing aging management program credited for management of concrete.

SLRA Section 3.5.2.2.2.1 (page 3-1314) is revised as follows:

3.5.2.2.2.1 Aging Management of Inaccessible Areas NUREG-2192

4. Increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation could occur in below-grade inaccessible concrete areas of Groups 1-5 and 7-9 structures.

Further evaluation is recommended to determine the need for a plant-specific AMP or plant-specific enhancements to Structures Monitoring AMP, to manage these aging effects if leaching is observed in accessible areas that impact intended functions. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR).

Evaluation

((3.5.1-047] - Reinforced concrete structures at ONS were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well- cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. Review of plant OE has not identified instances of aging effects related to increase in porosity and permeability due to leaching of calcium hydroxide and carbonation in accessible areas, however the structural integrity of the components was not impacted and the conditions will be monitored during future inspections. The Structures Monitoring (B2.1.33) program confirms the absence of aging effects related to leaching of calcium hydroxide and carbonation. Therefore, a plant-specific AMP or plant-specific enhancements to the Structures Monitoring (B2.1.33) program for inaccessible areas to manage the aging effects of increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are not required in below-grade inaccessible concrete areas of ONS groups 1-5 and 7-9 structures.

SLRA Section 3.5.2.2.2.3 (page 3-1317) is revised as follows:

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures NUREG-2192 Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging effect combinations as identified below, whether or not they are covered by inspections in accordance with the GALL-SLR Report, AMP XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power Plants, or Federal Energy Regulatory Commission (FERC)/U.S. Army Corp of Engineers dam inspection and maintenance procedures.

3. Increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide and carbonation could occur in inaccessible areas of concrete elements of Group 6 structures. Further evaluation is recommended to determine the need for a plant- specific AMP or plant-specific enhancements to Structures Monitoring AMP, to manage these aging effects if leaching is observed in accessible areas that impact intended functions. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRPSLR).

Evaluation

[3.5.1-051] - Reinforced concrete structures at ONS were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well- cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. The Structures Monitoring (B2.1.33) program, which includes Group 6 structures, identifies and manages cracks in the concrete structures. Review of plant OE has not identified instances of aging effects related to increase in porosity and permeability due to leaching of calcium hydroxide and carbonation in accessible areas, however the structural integrity of the components was not impacted and the conditions will be monitored during future inspections. Therefore, a plant-specific AMP or plant-specific enhancements to the Structures Monitoring (B2.1.33) program for inaccessible areas to manage the aging effects of increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are not required in Group 6 structures.

ATTACHMENT 21 OCONEE NUCLEAR STATION SUBSEQUENT LICENSE RENEWAL APPLICATION SLRA UPDATES UPDATED TO ADDRESS BOTTOM-MOUNTED INSTRUMENT GUIDE TUBES AND ASME CODE CLASS 1 SMALL-BORE PIPING

Updated to Address Bottom-Mounted Instrument Guide Tubes and ASME Code Class 1 Small-Bore Piping (TRP 1)

Affected SLRA Section(s):

SLRA Section 3.1.2.2.6 SLRA Table 3.1.1 SLRA Table 3.1.2-1 SLRA Page Number(s):

3-28 3-46 3-49 3-97 Description of Change:

The evaluation in SLRA Section 3.1.2.2.6 and Table 3.1.1 for SRP Item 3.1.1-019 will be updated to the following: Not applicable. The ONS Units 1, 2, and 3 bottom-mounted instrument guide tubes are nickel alloy. These items are addressed in SRP Item 3.1.1-045. The associated NUREG-2191 aging items are not used.

SLRA Table 3.1.2-1, Reactor Vessel, Reactor Internals, and Reactor Coolant System - Reactor Vessel - Aging Management Evaluation (Page 3-97), will be updated to remove the ASME Code Class 1 Small-Bore Piping aging management program for cracking with a reactor coolant environment. This environment/aging effect combination will be managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water Chemistry aging management programs. SLRA Table 3.1.1, Item 3.1.1-039 will be updated to include a discussion for the ASME Code Class 1 Small-Bore Piping aging management program not being used for the Incore Monitoring System lines.

SLRA Section 3.1.2.2.6 (page 3-28) is revised as follows:

3.1.2.2.6 Cracking Due to Stress Corrosion Cracking Evaluation

[3.1.1-019] - Not applicable. ONS Units 1, 2, and 3 bottom-mounted instrument guide tubes are nickel alloy utilize B&W reactors. These items are addressed in SRP Item 3.1.1-045. The associated NUREG-2191 aging items are not used.

[3.1.1-020] - Cracking due to stress corrosion cracking could occur in Class 1 PWR cast austenitic stainless steel reactor coolant system piping and piping components exposed to reactor coolant. ONS applicable components are valve bodies and reactor coolant pump suction and discharge nozzles.

Mitigation and monitoring of cracking of valve bodies and reactor coolant pump suction and discharge nozzles are managed by the Water Chemistry (B2.1.2) program and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1) program, respectively. The Water Chemistry (B2.1.2) program provides controls to minimize the presence of contaminants that promote stress corrosion cracking. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1) program provides for periodic testing and inspections to detect cracking.

[3.1.1-139] - Cracking due to stress corrosion cracking could occur in stainless steel or nickel alloy reactor vessel flange leak detection lines of PWR light-water reactor facilities. A review of ONS OE identified that a subset of these lines was susceptible to inner diameter initiated cracking in a localized vertical region of NSSS vendor supplied piping where contaminants could concentrate. Based on the results of metallurgical investigation, plant modifications were implemented between 2004 and 2008 on all three units to cut and cap the affected lines above the area of concern. This design change alleviated the potential for cracking associated with this OE. No evidence of cracking or leakage has been identified in the remaining segments of capped piping or in the unaffected reactor vessel leakage detection lines. The One-Time Inspection (B2.1.20) program will be used to verify that cracking is not occurring in the remaining reactor vessel leakage detection piping (including capped piping segments) or in comparable locations in the reactor coolant system aligned to this standard review plan item.

SLRA Table 3.1.1 (page 3-46) is revised as follows:

Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Further Item Aging Effect/ Aging Management Component Evaluation Discussion Number Mechanism Program Recommended 3.1.1-019 Stainless steel reactor Cracking due to Plant-specific aging Yes (SRP-SLR Not applicable. ONS Units 1, 2 and 3 vessel bottom-mounted stress corrosion management program Section 3.1.2.2.6.1) bottom-mounted instrument guide tubes instrument guide tubes cracking are nickel alloy utilize Babcock and (external to reactor vessel) Wilcox reactors. These items are exposed to reactor coolant addressed in SRP Item 3.1.1-045. The associated NUREG-2191 aging items are not used.

3.1.1-020 Cast austenitic stainless Cracking due to AMP XI.M2, Water Yes (SRP-SLR Consistent with NUREG-2191. Cracking of steel Class 1 piping, piping stress corrosion Chemistry and plant-specific Section 3.1.2.2.6.2) cast austenitic stainless steel Class 1 components exposed to cracking aging management program piping, piping components exposed to reactor coolant reactor coolant is managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1) program and the Water Chemistry (B2.1.2) program. See further evaluation in Section 3.1.2.2.6.2.

3.1.1-021 Steel and stainless steel Cracking due to AMP XI.M1, ASME Yes (SRP-SLR Not applicable - BWR only.

isolation condenser cyclic loading Section XI Inservice Section 3.1.2.2.7) components exposed to Inspection, Subsections IWB, reactor coolant IWC, and IWD 3.1.1-022 Steel steam generator Loss of material due Plant-specific aging Yes (SRP-SLR Not applicable to ONS steam generators.

feedwater impingement to erosion management program Section 3.1.2.2.8) The associated NUREG-2191 aging items plate and support exposed to are not used.

secondary feedwater 3.1.1-025 Steel (with nickel alloy Cracking due to AMP XI.M2, Water Yes (SRP-SLR Consistent with NUREG-2191. See further cladding) or nickel alloy primary water stress Chemistry, and AMP XI.M19, Sections evaluation in Section 3.1.2.2.11.

steam generator primary corrosion cracking Steam Generators. In 3.1.2.2.11.1 side components: divider addition, a plant-specific and 3.1.2.2.11.2) plate and tube-to-tube sheet program is to be evaluated.

welds exposed to reactor coolant

SLRA Table 3.1.1 (page 3-49) is revised as follows:

Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Item Component Aging Effect/ Aging Management Further Discussion Number Mechanism Program Evaluation Recommended 3.1.1-038 Cast austenitic stainless Loss of fracture AMP XI.M1, ASME No Consistent with NUREG-2191.

steel Class 1 valve bodies toughness due to Section XI Inservice and bonnets exposed to thermal aging Inspection, Subsections reactor coolant >250 °C embrittlement IWB, IWC, and IWD

(>482 °F) 3.1.1-039 Stainless steel, steel (with or Cracking due to AMP XI.M1, ASME No Consistent with NUREG-2191 with the without nickel alloy or stress corrosion exception of the Incore Monitoring Section XI Inservice stainless steel cladding), cracking (for System Lines.

Inspection, Subsections nickel alloy Class 1 piping, stainless steel or IWB, IWC, and IWD, AMP The Incore Monitoring System Lines do fittings, and branch nickel alloy XI.M2, not utilize the XI.M35, ASME Code Class connections < NPS 4 surfaces exposed 1 Small-Bore Piping aging management exposed to reactor coolant to reactor coolant Water Chemistry, and program. The alignment of AMPs XI.M1, only), IGSCC XI.M35, ASME Code Class ASME Section XI Inservice Inspection, 1 Small-Bore Piping (for stainless steel Subsection IWB, IWC and IWD and or nickel alloy XI.M2, Water Chemistry still apply.

surfaces exposed to reactor coolant only), or thermal, mechanical, or vibratory loading 3.1.1-040 Steel with stainless steel or Cracking due to AMP XI.M1, ASME No Consistent with NUREG-2191.

nickel alloy cladding; or cyclic loading Section XI Inservice stainless steel pressurizer Inspection, Subsections components exposed to IWB, IWC, and IWD reactor coolant

SLRA Table 3.1.2-1 (page 3-97) is revised as follows:

Table 3.1.2-1 Reactor Vessel, Reactor Internals, and Reactor Coolant System - Reactor Vessel - Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG- Notes Type Function Program Item 2192 Table 1 Head Vent Pipe Pressure Nickel Alloy Reactor Coolant Cracking Cracking of Nickel Alloy IV.A2.R-90 3.1.1- 045 A Boundary (Internal) Components and Loss of Material due to Boric Acid-Induced Corrosion in RCPB Components (B2.1.5)

Water Chemistry IV.A2.R-90 3.1.1- 045 A (B2.1.2)

Cumulative Fatigue TLAA IV.A2.R-219 3.1.1- 010 A Damage Loss of Material Water Chemistry IV.A2.RP-28 3.1.1- 088 A (B2.1.2)

Incore Monitoring Pressure Stainless Steel Air - Indoor Cracking One-Time Inspection IV.A2.R-74a 3.1.1- 139 C System Lines Boundary Uncontrolled (External) (B2.1.20)

Loss of Material One-Time Inspection IV.C2.R-452a 3.1.1- 136 A (B2.1.20)

Air with Borated Water None None IV.E.RP-05 3.1.1- 107 A Leakage (External)

Reactor Coolant Cracking ASME Code Class 1 IV.C2.RP-235 3.1.1- 039 A (Internal) Small-Bore Piping (B2.1.22)

ASME Section XI IV.C2.RP-235 3.1.1- 039 A Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1)

Water Chemistry IV.C2.RP-235 3.1.1- 039 A (B2.1.2)