Text

Subsequent License Renewal Application - Aging Management Supplement 1
	ML21111A155
Person / Time
Site:	Point Beach
Issue date:	04/21/2021
From:	Maher W; Point Beach
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	L-2021-081
	Download: ML21111A155 (271)
	v • d • e

April 21, 2021 L-2021-081 10 CFR 54.17 U.S. Nuclear Regulatory Commission Attention: Document Control Desk 11545 Rockville Pike One White Flint North Rockville, MD 20852-2746 Point Beach Nuclear Plant Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR 27 SUBSEQUENT LICENSE RENEWAL APPLICATION - AGING MANAGEMENT SUPPLEMENT 1

References:

1. NextEra Energy Point Beach, LLC (NEPB) Letter NRC 2020-0032 dated November 16, 2020, Application for Subsequent Renewed Facility Operating Licenses (ADAMS Package Accession No. ML20329A292)

2. U.S. Nuclear Regulatory Commission (NRC) Letter dated January 15, 2021, Point Beach Nuclear Plant, Units 1 and 2 - Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, and Notice of Opportunity to Request a Hearing Regarding the NextEra Energy Point Beach, LLC Application for Subsequent License Renewal (EPID No. L-2020-SLR-0002)

(ADAMS Accession No. ML21006A417)

3. NRC Letter dated January 15, 2021, Point Beach Nuclear Plant, Units 1 and 2 - Aging Management Audit Plan Regarding the Subsequent License Renewal Application Review (ADAMS Accession No. ML21007A260)

NEPB, owner and licensee for Point Beach Nuclear Plant (PBN) Units 1 and 2, has submitted a subsequent license renewal application (SLRA) for the Facility Operating Licenses for PBN Units 1 and 2 (Reference 1).

On January 15, 2021, the NRC determined that NEPBs SLRA was acceptable and sufficient for docketing and issued the regulatory audit plan for the aging management portion of the SLRA review (References 2 and 3). During this audit conducted between January 19, 2021 to March 26, 2021, NEPB agreed to supplement the SLRA (Enclosure 3, Attachment 1 of Reference 1) with new or clarifying information. The attachments to this letter provide that information.

For ease of reference, the index of attachment topics is provided on page 3 of this letter. In each attachment, changes are described along with the affected section(s) and page number(s) of the docketed SLRA (Enclosure 3 Attachment 1) where the changes are to apply. For clarity, revisions to the SLRA are provided with deleted text by strikethroughs and inserted text by bold red underline. Revisions to SLRA tables are shown by providing excerpts from each affected table.

Pursuant to 10 CFR 50.91(b)(1), a copy of this letter is being forwarded to the State of Wisconsin.

NextEra Energy Point Beach, LLC 6610 Nuclear Road, Two Rivers, WI 54241

Document Control Desk L-2021-081 Page 2 Should you have any questions regarding this submittal, please contact me at (561) 691-2294 or William.Maher@fpl.com.

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

Executed on the 21st day of April 2021.

Sincerely, William Digitally signed by William Maher DN: cn=William Maher, o=Nuclear, ou=Nuclear Licensing Projects, Maher email=william.maher@fpl.com, c=US Date: 2021.04.21 12:06:38 -04'00' William D. Maher Licensing Director - Nuclear Licensing Projects Cc: Administrator, Region III, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC Public Service Commission Wisconsin

Attachments Index Attachment PBN SLRA Enclosure 3 Attachment 1 Topic No.

1 Environmental Qualification (EQ): Updated AMP and TLAA to Include OE Non-EQ Electrical Cable and Connections AMP: Added Testing and Sampling Requirements 2

and Revised Adverse Localized Environment Description Non-EQ Inaccessible Wetted Cable AMPs: Updated to be consistent with 3

SLR-ISG-Electrical-2021-04 TLAAs: Updated the CLB by Removing ASME Code Case N-514 and Adding HELB as 4

applicable to PBN Emergency Power System AMR Results: Revised to Reflect Plastic Piping being Replaced by 5

Stainless Steel Piping Auxiliary System Mechanical Further Evaluation: Clarified that Stainless Steel in Auxiliary 6

Systems are Not Exposed to Concrete 7 Recurring Internal Corrosion 8 Flow-Accelerated Corrosion: Revised Further Evaluation, AMR Results, and AMP Bolting Integrity AMP: Clarified Enhancements, Identified Similar Environments, and 9

Clarified AMP 10 Steam Generator: Revised Further Evaluation, AMR Results, and AMP 11 Water Chemistry AMP: Clarified the Implementation Schedule 12 Inspection of Overhead Heavy Load Handling Systems AMP: Code Clarifications 13 Fire Protection AMP: Clarified Enhancement 14 Fire Water System: Revised Further Evaluation, AMR Results, and AMP Outdoor and Large Atmospheric Metallic Storage Tanks: Clarified Enhancement for 15 Inspecting Refueling Water Storage Tanks 16 Selective Leaching AMR Results: Added Ductile Iron Piping One-Time Inspection Small Bore Piping AMP: Clarified to Add a New Procedure to the 17 Existing Program Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components: Revised 18 Further Evaluation, AMR Results, and AMP Buried and Underground Piping and Tanks: Revised Further Evaluation, AMR Results, and 19 AMP Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and 20 Tanks AMP: Clarified an Exception and Inspection Frequency Irradiated Concrete and Reactor Vessel Supports: Revised Further Evaluation, AMR Results, 21 and AMP 22 Plant Structures: Clarified Scoping, Screening and AMR Results 23 Tendon Prestress: Clarified the 80-Year Prestress Calculation to be Used ASME Section XI, Subsection IWF AMP: Clarified Discussions for the Enhancement, 24 Exception, Code Classes, and OE 10 CFR 50 Appendix J AMP: Clarified List of Programs which Manage Aging Effects for 25 Containment Boundary Components 26 Masonry Walls AMP: Clarified an Enhancement Structures Monitoring AMP: Clarified Procedures and Enhancements and Added 27 Enhancements 28 Water Control Structures AMP: Added an Enhancement and Revised OE 29 Containment Structure: AMR, Penetration Fatigue and IWE AMP Changes

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 1 Page 1 of 3 Environmental Qualification (EQ): Updated AMP and TLAA to Include OE Affected SLRA Sections: Section B.2.2.4 SLRA Page Numbers: B-40 Description of Change:

Revised Plant Specific Operating Experience review to show that the NRCs focused engineering inspection conducted in 2019 was considered as part of operating experience for the EQ Program.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 1 Page 2 of 3 SLRA Section B.2.2.4, page B-40 is revised as follows:

B.2.2.4 Environmental Qualification of Electric Equipment Plant Specific Operating Experience The following examples of OE provide objective evidence that the PBN Environmental Qualification of Electric Equipment program will be effective in ensuring that component intended functions are maintained consistent with the CLB during the SPEO.

A review of quarterly system health reports covering the period from the first quarter (Q1) of 2015 through Q1 2020 was conducted to determine program performance during the PEO. The EQ program health report is currently GREEN and has shown green for several quarters.

In 2010 and 2013, the NRC examined activities conducted under PBNs Unit 1 and Unit 2 renewed operating licenses, respectively, as they relate to safety and compliance with the Commissions rules and regulations under the conditions of the renewed operating licenses.

The NRC reviewed the licensing basis, program basis document, implementing procedures, assessments, and related condition reports (CRs); and interviewed the plant personnel responsible for the PBN Environmental Qualification of Electric Equipment program. The NRC also reviewed the self-assessment reports completed in 2006 and 2010, and the corrective actions resulting from these assessments. The NRC verified that program implementing documents contain the appropriate License Renewal references. The NRC verified that PBN had conducted an assessment of all EQ components which include field verification and completion of EQ checklist reviews, which evaluates operating experience.

Based on the review of the timeliness and adequacy of PBNs actions, the NRC concluded that the PBN Environmental Qualification of Electric Equipment program commitments were met.

In 2018, an effectiveness review was performed following the guidelines provided in NEI 14-12, Aging Management Program Effectiveness. The effectiveness review covered the applicable ten program elements with particular attention focused on the detection of aging effects (Element 4), corrective action (Element 7), and operating experience (Element 10). The effectiveness review found that this program continues to be effectively implemented. Aside from two minor administrative enhancements, the PBN Environmental Qualification of Electric Equipment program was judged to be effective.

In 2019, the NRC conducted a focused engineering inspection of the EQ Program in accordance with inspection procedure (IP) 71111.21(N). Although there were no program findings, the following administrative items were identified and placed into the PBN corrective action program for resolution.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 1 Page 3 of 3 SLRA Section B.2.2.4, page B-40 revision continued:

x An incorrect qualification file was referenced for an EQ component x A PM frequency discrepancy was identified in a plant procedure A search of the action request (AR) database in the corrective action program (CAP) for EQ related issues discovered the following:

In 2019, a pre-design basis assurance inspection (DBAI) review of the PBN Environmental Qualification of Electric Equipment program was conducted in preparation for the NRC EQ DBAI. The following findings were identified:

x The EQ master list and NAMS data fields were inconsistent x Certain EQ maintenance requirements needed updating x Certain EQ documentation packages needed to incorporate industry OE/NRC identified issues and provide additional bases for activation energies (eVs).

There is one remaining AR to develop an action plan to resolve remaining identified gaps and enhancements. This demonstrates the EQ program is continually self-improving.

In December 2019, PBN received notice from Ultra Electronics that the qualified life of their N-E10 series pressure transmitters had changed. This item has been placed into the PBN corrective action program for resolution.

This demonstrates the EQ program is informed and enhanced due to the review of external plant OE.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 1 of 6 Non-EQ Electrical Cable and Connections AMP: Added Testing and Sampling Requirements and Revised Adverse Localized Environment Description Affected SLRA Sections: Section 16.2.2.37, Table 16-3 (Appendix A, Section 16.4), B.2.3.37 SLRA Page Numbers: A-37, A-107, B-251, B-252 Description of Change:

Clarified that the testing and sampling requirement applies to a large number of cables and connections identified as potentially degraded consistent with the corresponding element in GALL-SLR XI.E1 AMP.

Revised adverse localized environment description to include a moisture parameter consistent with the corresponding element in GALL-SLR XI.E1 AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 2 of 6 SLRA Appendix A, Section 16.2.2.37, page A-37 is revised as follows:

16.2.2.37. Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The PBN Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP, previously part of the Cable Conditioning Monitoring Program, is an existing AMP. This AMP applies to accessible non-EQ electrical cable and connection electrical insulation material within the scope of SLR subjected to an adverse localized environment (e.g., heat, radiation, or moisture). Adverse localized environments are identified through the use of an integrated approach, which includes, but is not limited to, a review of relevant site-specific and industry OE, field walkdown data, etc. Accessible non-EQ insulated cable and connections within the scope of SLR installed in adverse localized environments are visually inspected for cable and connection jacket surface anomalies indicating signs of reduced electrical insulation resistance. The first inspection for SLR is to be completed no later than six months prior to entering the SPEO. Recurring inspections are to be performed at least once every 10 years thereafter.

If visual inspections identify cable jacket and connection insulation surface anomalies, then testing may be performed. Testing may include thermography and other proven condition monitoring test methods applicable to the cable and connection insulation. For a large number of cables and connections identified as potentially degraded, a sample population is tested. A sample population of cable and connection insulation is utilized if testing is performed. If testing is deemed necessary, a sample of 20 percent of each cable and connection type with a maximum sample size of 25 is tested. When acceptance criteria are not met, a determination is made as to whether the surveillance, inspection, or tests, including frequency intervals, need to be modified.

Electrical insulation material for cables and connectors previously identified and dispositioned during the first period of extended operation as subjected to an adverse localized environment are evaluated for cumulative aging effects during the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 3 of 6 SLRA Appendix A, Section 16.4, Table 16-3, page A-107 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 41 Electrical Insulation XI.E1 Continue the existing PBN Electrical Insulation for Electrical Cables and No later than 6 months prior for Electrical Cables Connections Not Subject to 10 CFR 50.49 Environmental Qualification to the SPEO, i.e.:

and Connections Requirements AMP including enhancement to: PBN1: 04/05/30 Not Subject to a) Review plant-specific OE for previously identified and mitigated adverse PBN2: 09/08/32 10 CFR 50.49 localized environments cumulative aging effects applicable to in-scope Environmental cable and connection electrical insulation during the original PEO.

Qualification Evaluate to confirm that the dispositioned corrective actions continue to Requirements support in-scope cable and connection intended functions during the (16.2.2.37) SPEO.

b) If cable testing is deemed necessary warranted on a large number of cables and connections, utilize sampling methodology consistent with guidance of Section XI.E1 of NUREG-2191.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 4 of 6 SLRA Section B.2.3.37, pages B-251 and B-252 are revised as follows:

B.2.3.37 Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The PBN Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualifications (EQ) Requirements AMP, previously part of the Cable Conditioning Monitoring Program, is an existing AMP. This AMP provides reasonable assurance that the intended functions of cable and connection electrical insulation exposed to adverse localized environments caused by heat, radiation and moisture can be maintained consistent with the CLB through the SPEO.

This AMP applies to accessible non-EQ electrical cable and connection electrical insulation material within the scope of SLR subjected to an adverse localized environment (e.g., excessive heat, radiation, and/or moisture) localized environment(s). Adverse localized environments (ALEs) are identified through the use of an integrated approach which includes, but is not limited to, a review of relevant plant-specific and industry OE, a review of EQ zone maps, real-time infrared thermographic inspections, conversations with plant personnel cognizant of specific area and room environmental conditions, etc. To facilitate the identification of an adverse localized environment, a temperature threshold and a radiation threshold will be identified in the plant implementing procedure for cable and connection insulation materials within the scope of this program.

Accessible non-EQ insulated cables and connections within the scope of SLR installed in adverse localized environments are visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination including signs of the presence of moisture. The inspection of accessible cable and connection insulation material is used to evaluate the adequacy of inaccessible cable and connection electrical insulation. If visual inspections identify cable jacket and connection insulation surface anomalies, then testing may be performed. For a large number of cables and connections identified as potentially degraded, a sample population is tested. A sample population of cable and connection insulation is utilized if testing is performed of 20 percent of each cable and connection type with a maximum sample size of 25 is tested. The component sampling methodology includes a representative sample of in-scope non-EQ electrical cable and connection types regardless of whether or not the component was included in a previous aging management or maintenance program. The technical basis for the sample selections is documented.

The first inspection for SLR is to be completed no later than six months prior to entering the SPEO. Recurring inspections are to be performed at least once every 10 years thereafter.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 5 of 6 SLRA Section B.2.3.37, pages B-251 and B-252 revision continued:

Plant-specific OE will be evaluated to identify in-scope cable and connection insulation previously subjected to adverse localized environment during the initial period of extended operation. Cable and connection insulation will be evaluated to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the SPEO.

If testing is deemed necessary, a sample of 20 percent of each cable and connection type with a maximum sample size of 25 is tested. Trending actions are not included as part of this AMP. Acceptance criteria under this AMP specifies that no unacceptable visual indications of cable and connection jacket surface anomalies should be observed. An unacceptable indication is defined as a noted condition or situation that, if left unmanaged, could lead to a loss of the intended function. If testing is deemed necessary warranted on a large number of cables and connections, the acceptance criteria for testing electrical cable and connection insulation material is defined in the work order for each cable and connection test and is determined by the specific type of test performed and the specific cable tested.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 2 Page 6 of 6 SLRA Section B.2.3.37, page B-252 is revised as follows:

Enhancements The PBN Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP will be enhanced for alignment with NUREG-2191, as discussed below. This enhanced AMP is to be implemented with inspections completed no later than six months prior to entering the SPEO, or no later than the last refueling outage (RFO) prior to the SPEO.

Element Affected Enhancement

4. Detection of Aging Effects Review plant-specific OE for previously identified and mitigated adverse localized environments cumulative aging effects applicable to in-scope cable and connection electrical insulation during the original PEO. Evaluate to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the SPEO.

4. Detection of Aging Effects If cable testing is deemed necessary warranted on a large number of cables and connections, utilize sampling methodology consistent with guidance of Section XI.E1 of NUREG-2191.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 1 of 7 Non-EQ Inaccessible Wetted Cable AMPs: Updated to be consistent with SLR-ISG-Electrical-2021-04 Affected SLRA Sections: Sections 16.2.2.39, 16.2.2.40, 16.2.2.41, B.2.3.39, B.2.3.40, B.2.3.41 SLRA Page Numbers: A-38, A-39, A-40, B-260, B-265, B-271 Description of Change:

Revised AMP scope to include the term potentially for consistency with the corresponding element in Electrical Interim Staff Guidance SLR-ISG-Electrical-2021-04 XI.E3A, XI.E3B, and XI.E3C AMPs.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 2 of 7 SLRA Appendix A, Section 16.2.2.39, page A-38 is revised as follows:

16.2.2.39. Electrical Insulation for Inaccessible Medium Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The PBN Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP, previously part of the Cable Conditioning Monitoring Program, is an existing AMP. The purpose of this AMP is to provide reasonable assurance that the intended functions of inaccessible medium-voltage (M-V) power cables (operating voltages of 2 kV to 35 kV) that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO. This AMP applies to inaccessible (e.g.,

installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct-buried installations) non-EQ medium-voltage power cables within the scope of SLR and potentially exposed to wetting or submergence (i.e., significant moisture). Significant moisture is defined as exposure to moisture that lasts more than three days (i.e., long-term wetting or submergence over a continuous period), which if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that occurs for a limited time as drainage from either automatic or passive drains is not considered significant moisture for this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 3 of 7 SLRA Appendix A, Section 16.2.2.40, page A-39 is revised as follows:

16.2.2.40. Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The PBN Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP is a new AMP. The purpose of this AMP is to provide reasonable assurance that the intended functions of inaccessible instrumentation and control (I&C) cables that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO. This AMP applies to inaccessible (e.g., installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct buried installations) I&C cables within the scope of SLR and potentially exposed to significant moisture. Significant moisture is defined as exposure to moisture that lasts more than three days (i.e., long-term wetting or submergence over a continuous period), which if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that results from event-driven occurrences and is mitigated by either automatic or passive drains is not considered significant moisture for the purposes of this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 4 of 7 SLRA Appendix A, Section 16.2.2.41, page A-40 is revised as follows:

16.2.2.41. Electrical Insulation for Inaccessible Low Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The PBN Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP is a new AMP. The purpose of this AMP is to provide reasonable assurance that the intended functions of inaccessible (e.g., underground) low-voltage ac and dc power cables (i.e., typical operating voltage of less than 1,000 V, but no greater than 2 kV) that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO. This AMP applies to inaccessible (e.g., installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct buried installations) low-voltage power cables, including those designed for continuous wetting or submergence, within the scope of SLR and potentially exposed to significant moisture. In-scope inaccessible low-voltage power cable splices potentially subjected to wetting or submergence are also included within the scope of this program. Significant moisture is defined as exposure to moisture that lasts more than three days (i.e., long-term wetting or submergence over a continuous period), which if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that results from event-driven occurrences and is mitigated by either automatic or passive drains is not considered significant moisture for the purposes of this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 5 of 7 SLRA Section B.2.3.39, pages B-260 is revised as follows:

B.2.3.39 Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The PBN Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements AMP, previously part of the Cable Conditioning Monitoring Program, is an existing AMP.

The purpose of the PBN Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP is to provide reasonable assurance that the intended functions of inaccessible medium-voltage (M-V) power cables (operating voltages of 2 kV to 35 kV) that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO.

This AMP applies to underground (e.g., installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct buried installations) non-EQ cables within the scope of SLR and potentially exposed to wetting or submergence (i.e., significant moisture). Significant moisture is defined as exposure to moisture that lasts more than three (3) days (i.e., long term wetting or submergence over a continuous period) that if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that occurs for a limited time, as in the case of automatic or passive drainage, is not considered significant moisture for this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 6 of 7 SLRA Section B.2.3.40, pages B-265 is revised as follows:

B.2.3.40 Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The PBN Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements AMP is a new AMP for SLR. The purpose of the PBN Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP is to provide reasonable assurance that the intended functions of inaccessible instrument and control cables that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO.

This AMP applies to underground (e.g., installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct buried installations) non-EQ instrumentation and control cables, including those designed for continuous wetting or submergence, within the scope of SLR and potentially exposed to significant moisture. Significant moisture is defined as exposure to moisture that lasts more than three days (i.e., long term wetting or submergence over a continuous period) that if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that results from event-driven occurrences and is mitigated by either automatic or passive drains is not considered significant moisture for the purposes of this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 3 Page 7 of 7 SLRA Section B.2.3.41, pages B-271 is revised as follows:

B.2.3.41 Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The PBN Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements AMP is a new AMP for SLR. The purpose of the PBN Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP is to provide reasonable assurance that the intended functions of inaccessible and underground low-voltage ac and dc power cables (i.e., typical operating voltage of less than 1,000 V, but no greater than 2 kV) that are not subject to the EQ requirements of 10 CFR 50.49 are maintained consistent with the CLB through the SPEO.

This AMP applies to underground (e.g., installed in buried conduit, embedded raceway, cable trenches, cable troughs, duct banks, vaults, manholes, or direct buried installations) non-EQ low-voltage (L-V) power cables, including those designed for continuous wetting or submergence, within the scope of SLR and potentially exposed to significant moisture. Significant moisture is defined as exposure to moisture that lasts more than three days (i.e., long term wetting or submergence over a continuous period) that if left unmanaged, could potentially lead to a loss of intended function. Cable wetting or submergence that results from event-driven occurrences and is mitigated by either automatic or passive drains is not considered significant moisture for the purposes of this AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 4 Page 1 of 5 TLAAs: Updated the CLB by Removing ASME Code Case N-514 and Adding HELB as applicable to PBN Affected SLRA Sections: Section 4.1.4, Table 4.1.5-1 and Section 4.3.3 SLRA Page Numbers: 4.1-3, 4.1-5, 4.1-6, and 4.3-11 Description of Change:

By letter and safety evaluation dated January 27, 1997 (ML021970302), the NRC staff granted PBN a regulatory exemption (under the requirements in 10 CFR 50.12) that permitted use of the safety margins recommended in ASME Code Case N-514 Low Temperature Overpressure Protection. However, due to changes in the PBN low temperature overpressure protection analysis methodology, the previously granted regulatory exemption to use ASME Code Case N-514 is no longer part of the PBN CLB.

SLRA Section 4.1.4 is revised to provide the basis for removing the previously granted regulatory exemption to use ASME Code Case N-514 from the PBN CLB.

Based on the review of PBN UFSAR Appendix A.2., the NUREG-2192, Table 4.1-2 Generic TLAA High-Energy Line Break (HELB) is determined to be applicable to PBN.

SLRA Table 4.1.5-1 is revised to indicate the HELB TLAA is applicable to PBN. SLRA Section 4.3.3 is revised to include the disposition of the HELB TLAA for SLR.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 4 Page 2 of 5 SLRA Section 4.1.4, page 4.1-3 is revised as follows:

4.1.4. Identification and Evaluation of Exemptions 10 CFR 54.21(c)(2) states: A list must be provided of plant-specific exemptions granted pursuant to 10 CFR 50.12 and in effect that are based on TLAAs as defined in 10 CFR 54.3. The applicant shall provide an evaluation that justifies the continuation of these exemptions for the SPEO.

A search of docketed licensing correspondence, the operating license, and the Updated Final Safety Analysis Report (UFSAR) identified the active exemptions currently in effect pursuant to 10 CFR 50.12. These exemptions were then reviewed to determine whether the exemption was based on a TLAA. There were no exemptions to 10 CFR 50.12 identified for PBN Units 1 and 2 that are currently in effect that are based upon a TLAA.

By letter and safety evaluation dated January 27, 1997 (ML021970302), the staff granted PBN a regulatory exemption (under the requirements in 10 CFR 50.12) that permitted use of the safety margins recommended in ASME Code Case N-514 Low Temperature Overpressure Protection in lieu of the safety margins required by 10 CFR 50, Appendix G. ASME Code Case N-514 allows determination of the setpoints for low-temperature overpressure protection (LTOP) events such that the maximum pressure in the reactor vessel would not exceed 110 percent of the P-T limits. The provisions of Code Case N-514 have been incorporated into later versions of Section XI of the ASME Code that have been endorsed by the NRC (e.g., 1996 version, which is approved per 10 CFR 50.55a).

However, NEE confirms that the previously granted regulatory exemption to use ASME Code Case N-514 is no longer part of the PBN CLB. By (PTLR)|letter dated January 15, 2013]] (ML13016A028), as supplemented on March 1, April 18, and September 12, 2013, and March 11, 2014 (ML13063A292, ML13113A008, ML13256A064, and ML14071A405, respectively), NEE submitted a license amendment request for PBN Units 1 and 2 to revise its Technical Specifications for the Pressure Temperature Limit Report (PTLR), which contains the pressure-temperature (P-T) limit curves for the reactor pressure vessel. The methodology for generating these P/T limits is documented in WCAP-16669-NP and was developed using the KIc methodology in the 1998 Edition through 2000 Addenda of the ASME Code,Section XI. The KIC methodology uses 100% of the P-T limit curve. By letter dated June 30, 2014 (ML14126A378), the staff determined the proposed P-T limits, valid for 50 effective full-power years, satisfy the requirements of Appendix G to Section XI of the ASME Code and Appendix G to 10 CFR Part 50.

Since Code Case N-514 is not relied upon for any portion of the current CLB analysis, Code Case N-514 is not considered to be a regulatory exemption that remains in effect for the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 4 Page 3 of 5 SLRA Table 4.1.5-1, pages 4.1-5 and 4.1-6 are revised as follows:

Table 4.1.5-1 Review of Generic TLAAs Listed in NUREG-2192, Table 4.1-2 Applies to SLRA NUREG-2192, Table 4.1 Generic TLAAs PBN Section Neutron Fluence Yes 4.2.1 Pressurized Thermal Shock (PWRs Only) Yes 4.2.2 Upper Shelf Energy (PWRs and BWRs) Yes 4.2.3 Pressure Temperature (P-T) Limits (PWRs and BWRs) Yes 4.2.4 Low Temperature Overpressure Protection System Reactor Vessel Yes 4.2.5 Setpoints (PWRs Only)

Neutron Embrittlement Ductility Reduction Evaluation for Reactor Internals (B&W No N/A designed PWRs only)

RV Circumferential Weld Relief-Probability of Failure and Mean Adjusted Reference Temperature Analysis for the No N/A RV Circumferential Welds (BWRs only)

Reactor Vessel Axial Weld Probability of Failure and Mean Adjusted Reference Temperature Analysis (BWRs No N/A only)

Metal Fatigue of Class 1 Components Yes 4.3.1 Metal Fatigue of Non-Class 1 Components Yes 4.3.3 Environmentally-Assisted Fatigue Yes 4.3.4 Metal Fatigue YesNo High-Energy Line Break Analyses 4.3.3N/A (Note 1)

Cycle-dependent Fracture Mechanics or Flaw Yes 4.7.3 Evaluations (Note 12)

Cycle-dependent Fatigue Waivers Yes 4.3.2

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 4 Page 4 of 5 SLRA Table 4.1.5-1, pages 4.1-5 and 4.1-6 revision continued:

Table 4.1.5-1 Review of Generic TLAAs Listed in NUREG-2192, Table 4.1-2 Applies SLRA NUREG-2192, Table 4.1 Generic TLAAs to PBN Section Environmental Qualification of Electric Equipment Yes 4.4 Concrete Containment Tendon Prestress Yes 4.5 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Yes 4.6 Response to NRC Bulletin 88-11, Pressurizer Surge Line Thermal Stratification Yes 4.3.1 Response to NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Cooling Systems Yes 4.3.1 Fatigue of Cranes (Crane Cycle Limits) Yes 4.7.6 No Fatigue of the Spent Fuel Pool Liner N/A (Note 23)

No Corrosion Allowance Calculations N/A (Note 34)

No Flaw Growth Due to Stress Corrosion Cracking N/A (Note 45)

Predicted Lower Limit Yes 4.5 Note 1: High energy line break is not a TLAA for PBN since HELB methodology does not involve time-limited assumptions defined by the current operating term.

Note 12: PBN currently has five (5) RCS component flaw evaluations identified as TLAAs in Sections 15.4-7, 15.4-8, 15.4-9, 15.4-10 and 15.4-11 of the UFSAR. Review of these five (5) flaw evaluations has determined that they do not meet Criterion 3 of 10 CFR 54.3(a) consistent with the flaw evaluation example discussed in Table 4.1-1 of NUREG-2192, because they only justify further service until a subsequent outage. However, for SLR, an additional flaw tolerance evaluation for reactor coolant loop CASS piping components meets the six TLAA criterion and is evaluated in Section 4.7.3.

Note 23: There is no fatigue analysis for the PBN spent fuel pool liner.

Note 34: No time limited metal corrosion allowance analyses were identified.

Note 45: No time limited flaw growth due to stress corrosion analyses were identified.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 4 Page 5 of 5 SLRA Section 4.3.3, page 4.3-11 is revised as follows:

plant operation. These projections, which are presented in Table 4.3.3-2, indicate that 7000 thermal cycles will not be exceeded for 80 years of operation.

The PBN high-energy line break (HELB) analysis methodology is discussed in UFSAR Appendix A.2. UFSAR Section A.2.5 describes the methodologies for determining locations, size, and orientation of pipe breaks. The piping systems in the PBN HELB scope were designed to the requirements of the ANSI B31.1-1967, Power Piping Code and breaks were postulated to occur at any location that meets one of the following criteria:

a. Any terminal end.

b. Any intermediate location where the circumferential or longitudinal stresses derived on an elastically calculated basis under the loadings associated with an operating basis earthquake (OBE) seismic event and operational plant conditions exceed 0.8 (1.2Sh + SA). Sh is the allowable stress limit at the operating temperature, and SA is the allowable stress range for thermal expansion as found in ANSI B31.1-1967.

c. Any intermediate location where the thermal expansion stress term exceeds 0.8 SA.

The term SA used in criteria b and c, above, represents the maximum allowable stress range for thermal expansion based on the number of equivalent full temperature cycles and corresponding stress range reduction factor. The evaluations for required stress reduction factors are considered implicit fatigue analyses because they are based on the number of fatigue cycles anticipated for the life of the component. Table 4.3.3-2 provides the results of the evaluation that was performed to determine a conservative number of projected fatigue cycles for 80 years of plant operation for piping systems in the scope of SLR and designed to the B31.1 piping Code. These projections indicate that the fatigue cycles limits for these piping systems will not be exceeded for the 80 year SPEO. Therefore, the implicit fatigue analyses and postulated HELB break locations also remain valid for the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 5 Page 1 of 3 Emergency Power System AMR Results: Revised to Reflect Plastic Piping being Replaced by Stainless Steel Piping Affected SLRA Sections: Section 3.3.2.1.8 and Table 3.3.2-8 SLRA Page Numbers: 3.3-11 and 3.3-216 Description of Change:

The plastic piping in the emergency power system has been replaced by stainless steel piping and is exposed to uncontrolled indoor air internally and externally. SLRA Table 3.3.2-8 is revised to state that cracking and loss of material of stainless steel piping exposed to uncontrolled indoor air internally in the emergency power system is subject to loss of material and cracking and is managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP. Stainless steel piping exposed to indoor uncontrolled air externally is already accounted for in Table 3.3.2-8.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 5 Page 2 of 3 SLRA Section 3.3.2.1.8, page 3.3-11 is revised as follows:

3.3.2.1.8 Emergency Power Materials The materials of construction for the emergency power system components are:

Aluminum

Carbon steel

CASS

Coating

Copper alloy

Copper alloy >15% Zn

Elastomer

Glass

Gray cast iron

Plastic

Stainless steel

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 5 Page 3 of 3 SLRA Table 3.3.2-8, page 3.3-216 is revised as follows:

Table 3.3.2-8: Emergency Power System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Piping Pressure Plastic Air - indoor None None VII.J.AP-268 3.3-1, A boundary uncontrolled 119 (ext)

Piping Pressure Plastic Air - indoor None None VII.J.AP-268 3.3-1, A boundary Stainless uncontrolled (int) Cracking Inspection of Internal VII.H1.AP-209c 119 steel Surfaces in 3.3-1, Miscellaneous Piping and 004 Ducting Components (B.2.3.25)

Piping Pressure Stainless Air - indoor Loss of Inspection of Internal VII.H1.AP-221c 3.3-1, A boundary steel uncontrolled material Surfaces in 006 (int) Miscellaneous Piping and Ducting Components (B.2.3.25)

Piping Pressure Stainless Air - dry (int) Loss of Compressed Air Monitoring VII.D.A-764 3.3-1, A boundary steel material (B.2.3.14) 235 Piping Pressure Stainless Air - indoor Cracking External Surfaces VII.H1.AP-209b 3.3-1, A boundary steel uncontrolled Monitoring of Mechanical 004 (ext) Components (B.2.3.23)

Piping Pressure Stainless Air - indoor Loss of External Surfaces VII.H1.AP-221b 3.3-1, A boundary steel uncontrolled material Monitoring of Mechanical 006 (ext) Components (B.2.3.23)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 6 Page 1 of 2 Auxiliary System Mechanical Further Evaluation: Clarified that Stainless Steel in Auxiliary Systems are Not Exposed to Concrete Affected SLRA Sections: 3.3.2.2.9 SLRA Page Numbers: 3.3-29 Description of Change:

Further evaluation 3.3.2.2.9 is revised to clarify that stainless steel components in the auxiliary systems are not exposed to concrete to be consistent with SLRA Table 3.3.1 item 202.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 6 Page 2 of 2 SLRA Section 3.3.2.2.9, page 3.3-29 is revised as follows:

The Auxiliary Systems includes both steel and stainless steel piping and tanks exposed to concrete and does not include stainless steel components exposed to concrete. The concrete at PBN is designed and constructed in accordance with ACI 318-63 using ingredients/materials conforming to ACI and ASTM standards. The stainless steel components are above groundwater and, therefore, do not require management as detailed above. A review of OE for PBN indicates there are occurrences of concrete degradation that could lead to the penetration of water to the metal surface; therefore, a loss of material due to general, pitting, and crevice corrosion of steel piping and tanks exposed to concrete is an aging effect that requires management.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 7 Page 1 of 1 Recurring Internal Corrosion Affected SLRA Sections: N/A SLRA Page Numbers: N/A Description of Change:

Based on a further review of site-specific OE, the applicability of the loss of material due to recurring internal corrosion aging effect in raw water systems is being re-evaluated. No changes to the SLRA are made at this time. Any changes regarding this topic, if required, will be provided in a future supplement to the SLRA.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 8 Page 1 of 5 Flow-Accelerated Corrosion: Revised Further Evaluation, AMR Results, and AMP Affected SLRA Sections: Section 3 (Table 3.3-1), Section 3 (Table 3.4.2-1), Appendix A.16.4 (Table 16-3), Appendix B.2.3.8 SLRA Page Numbers: 3.3-55, 3.4-58, A-67 through 68, B-79 through 80 Description of Change:

The components exposed to treated water and steam in the heating system are subject to the wall thinning due to erosion aging effect. SLRA Table 3.3-1 item 126 is revised to state that wall thinning due to erosion of components exposed to treated water and steam in the heating steam system is addressed by line item 3.4-1, 060.

Wall thinning due to erosion is an applicable aging effect for the low-alloy steel piping in the main and auxiliary steam system. SLRA Table 3.4.2-1 is revised to state that wall thinning due to erosion for low-alloy steel piping components exposed to treated water is an applicable aging effect managed by the Flow-Accelerated Corrosion (FAC) AMP. The NUREG-2191 Item and Table 1 Item for the existing low-alloy steel row in SLRA Table 3.4.2-1 is also corrected.

The SLRA is updated to reference revision 4 of NSAC-202L, Recommendations for an Effective Flow-Accelerated Corrosion Program for the PBN FAC AMP.

The SLRA is clarified to formalize an erosion program scope which will trend wall thickness to adjust the monitoring frequency of erosion mechanism.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 8 Page 2 of 5 SLRA Table 3.3-1, page 3.3-55 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 126 Metallic piping, piping Wall thinning due to AMP XI.M17, No Consistent with NUREG-2191 with components exposed erosion "Flow-Accelerated exception for the Open-Cycle Cooling to treated water, Corrosion" Water System (B.2.3.11) AMP. The treated borated water, Fire Water System (B.2.3.16),

raw water Open-Cycle Cooling Water System (B.2.3.11), and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.3.25) AMPs are credited with managing wall thinning due to erosion of metallic components exposed to raw and waste water. Erosion is not an applicable aging effect in treated water or treated borated water environments in the Auxiliary Systems. Wall thinning due to erosion of components exposed to treated water and steam in the heating steam system is addressed using a different line item (3.4-1, 060).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 8 Page 3 of 5 SLRA Table 3.4.2-1, page 3.4-58 is revised as follows:

Table 3.4.2-1: Main and Auxiliary Steam - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Function Requiring Management Item Item Management Program Piping Leakage Low-alloy steel Treated Loss of material Water Chemistry VIII.B1.S-408 3.4-1, 060 B boundary water (int) (B.2.3.2) VIII.B1.SP-74 3.4-1, 014 A (spatial) One-Time Inspection (B.2.3.20)

Piping Leakage Low-alloy Treated Wall thinning - Flow- VIII.B1.S-408 3.4-1, 060 A boundary steel water (int) erosion Accelerated (spatial) Corrosion (B.2.3.8)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 8 Page 4 of 5 SLRA Appendix A.16.4, Table 16-3, pages A-67 through 68 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 12 Flow-Accelerated XI.M17 Continue the existing PBN Flow-Accelerated Corrosion AMP, including No later than 6 months Corrosion (16.2.2.8) enhancement to: prior to the SPEO, i.e.:

a) Reassess piping systems excluded from wall thickness monitoring due to PBN1: 04/05/2030 operation less than 2% of plant operating time (as allowed by NSAC-202L PBN2: 09/08/2032

-R4) to ensure the exclusion remains valid and applicable for operation beyond 60 years.

b) Formalize a separate erosion program scope, and an erosion susceptibility evaluation (ESE) that will include all components determined to be susceptible to wall loss due to erosion through OE and industry guidance.

c) Perform or compile baseline inspections of erosion susceptible locations where site OE indicates periodic monitoring may be warranted instead of design or operational correction to eliminate the cause of erosion.

d) Revise or develop procedural guidance relative to erosion based on the results that includes -

x Components treated in a manner similar to susceptible-not-modeled lines discussed in NSAC-202L-R4.

e) Consideration of EPRI 1011231 for identifying potential damage locations and EPRI TR-112657 and/or NUREG/CR-6031 guidance for cavitation erosion as warranted.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 8 Page 5 of 5 SLRA Appendix B.2.3.8, Enhancements Table on Pages B-79 through 80 is revised as follows:

Enhancements The PBN Flow-Accelerated Corrosion AMP will be enhanced as follows for alignment with NUREG-2191. Enhancements are to be implemented no later than six months prior to entering the SPEO.

Element Affected Enhancement

1. Scope of Program x Reassess piping systems excluded from wall thickness monitoring due to operation less than 2 percent of plant operating time (as allowed by NSAC-202L-R4) to ensure the exclusion remains valid and applicable for operation beyond 60 years.

x Formalize a separate erosion program scope, and an erosion susceptibility evaluation (ESE) that will include all components determined to be susceptible to wall loss due to erosion through OE and industry guidance.

4. Detection of Aging x Perform or compile baseline inspections of erosion susceptible Effects locations where site OE indicates periodic monitoring may be warranted instead of design or operational correction to eliminate the cause of erosion.

x Revise or develop procedural guidance relative to erosion based on the results that includes -

o Components treated in a manner similar to susceptible-not-modeled lines discussed in NSAC-202L

-R4.

o Consideration of EPRI 1011231 for identifying potential damage locations and EPRI TR-112657 and/or NUREG/CR-6031 guidance for cavitation erosion as warranted.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 1 of 10 Bolting Integrity AMP: Clarified Enhancements, Identified Similar Environments, and Clarified AMP Affected SLRA Sections: Section 16.2.2.9; Section 16.4, Table 16-3, Commitment 13 d) and 13 g), B.1.4, B.2.3.9 SLRA Page Numbers: A-18, A-19, A-69, A-70, B-10, B-82, B-83, B-85 Description of Change:

The Point Beach (PBN) Bolting Integrity Aging Management Program (AMP) requires an enhancement to revise plant procedures to include the requirements for leakage monitoring, sample expansion and additional inspections if inspection results do not meet acceptance criteria. The enhancement as written in the subsequent license renewal application (SLRA) is not clear regarding the specific criteria that will be followed by the AMP enhancement to demonstrate that the aging effects will be adequately managed during the subsequent period of extended operation. The enhancement is clarified to indicate how the existing procedure will be consistent with the corrective actions recommended by the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report (NUREG-2191) when leakage is detected/identified, and the recommended increased inspections.

Accordingly, SLRA Table 16-3 in Appendix A and Section B.2.3.9 in Appendix B are revised to indicate that the enhancement regarding requirements for leakage monitoring, sample expansion and additional inspections if inspection results do not meet acceptance criteria will be as described in NUREG-2191, Chapter XI.M18, Element 7.

The PBN Bolting Integrity AMP states that periodic system walkdowns and inspections are performed at least once per refueling cycle to provide reasonable assurance that indications of loss of preload (leakage), cracking, and loss of material are identified before leakage becomes excessive. The word excessive is not defined and could be interpreted differently from the intent of the guidance in the GALL-SLR (i.e., results in a loss of intended function). The word excessive is replaced with a term that demonstrates compliance with the guidance in the GALL-SLR.

Accordingly, SLRA Section 16.2.2.9 in Appendix A and Section B.2.3.9 in Appendix B are revised to indicate that the purpose of the inspections is to prevent a loss of intended function rather than to prevent excessive leakage.

The PBN Bolting Integrity AMP commitment 13d) in Appendix A, Section 16.4, Table 16-3 is revised to match the 4th enhancement listed in Appendix B, Section B.2.3.9.

The PBN Bolting Integrity AMP does not explicitly discuss the use of volumetric exams for high strength bolting except in the commitments/enhancements portions of Appendices A/B respectively.

Accordingly, SLRA Section 16.2.2.9 in Appendix A and Section B.2.3.9 in Appendix B are revised to indicate the guidance for high strength closure bolting.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 2 of 10 At the two unit PBN site, reduced inspections for several aging management programs are credited per the guidance in NUREG-2191 because the units and operating experience are similar. Accordingly, SLRA Section B.1.4 is updated to provide the justification for the similarities.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 3 of 10 SLRA Appendix A, Section 16.2.2.9, 3rd paragraph, page A-18 is revised as follows:

This AMP supplements the inspection activities required by ASME Code Section XI for ASME Code Class 1, 2 and 3 bolting. For ASME Code Class 1, 2, and 3, and non ASME Code class bolts, periodic system walkdowns and inspections are performed at least once per refueling cycle to provide reasonable assurance that indications of loss of preload (leakage), cracking, and loss of material are identified before leakage becomes excessive a loss of the components intended functions can occur. Visual inspection methods and the frequency of inspection are selected to provide reasonable assurance that actions are taken to prevent significant age related degradation. Identified leaking bolted connections will be monitored at an increased frequency in accordance with the PBN corrective action program (CAP).

Inspections within the scope of the ASME Code follow procedures consistent with the ASME Code.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 4 of 10 SLRA Appendix A, Section 16.2.2.9, a new paragraph is added between what is currently the last and the second to last paragraphs, page A-19 as follows:

For component joints that are not normally pressurized, the aging effects associated with closure bolting will be managed by checking the torque to the extent that the closure bolting is not loose.

High strength closure bolting [actual measured yield strength greater than or equal to 150 ksi (1,034 MPa)] may be subject to SCC. For all closure bolting greater than 2 inches in diameter (regardless of code classification) with actual yield strength greater than or equal to 150 ksi (1,034 MPa) and closure bolting for which yield strength is unknown, volumetric examination in accordance to that of ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, is performed (e.g., acceptance standards, extent and frequency of examination). Specified bolting material properties (e.g., design and procurement specifications, fabrication and vendor drawings, material test reports) may be used to determine if the bolting exceeds the threshold to be classified as high strength.

Indications of aging are evaluated in accordance with Section XI of the ASME Code.

Leaking joints do not meet acceptance criteria.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 5 of 10 SLRA Appendix A, Section 16.4, Table 16-3, Commitment 13 d) on page A-69 and Commitment 13 g) on page A-70 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 13 Bolting Integrity XI.M18 Continue the existing PBN Bolting Integrity AMP, including enhancement to: No later than 6 months prior (16.2.2.9) a) Enhance plant procedures to replace references to NP-5067 Volumes 1 to the SPEO, i.e.:

and 2 and EPRI TR-104213 with EPRI Reports 1015336 and 1015337 PBN1: 04/05/2030 and incorporate the guidance as appropriate; PBN2: 09/08/2032 b) Enhance plant procedures to ensure MoS2 lubricant will not be used for pressure retaining bolting; c) Enhance plant procedures to ensure bolting material with a yield strength greater than or equal to 150 ksi (1,034 MPa) or for which yield strength is unknown will not be used in pressure retaining bolting. If closure bolting greater than 2 inches in diameter (regardless of code classification) with actual yield strength greater than or equal to 150 ksi (1,034 MPa) or for which yield strength is unknown is used, volumetric examination will be required in accordance to that of ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1 acceptance standards, extent, and frequency of examination; d) Create a new plant procedure to perform alternative means of testing and inspection for closure bolting where leakage is difficult to detect (e.g.,

piping systems that contain air or gas or submerged bolting) . The acceptance criteria for the alternative means of testing will be no indication of leakage from the bolted connections. Required inspections will be performed on a representative sample of the population (defined as the same material and environment combination) of bolt heads and threads over each 10-year period of the SPEO. The representative sample will be 20% of the population (up to a maximum of 19 per unit);

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 6 of 10 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 13 Bolting Integrity XI.M18 e) Enhance plant procedures to ensure that bolted joints that are not readily No later than 6 months prior (16.2.2.9) visible during plant operations and refueling outages will be inspected to the SPEO, i.e.:

when they are made accessible and at such intervals that would provide PBN1: 04/05/2030 reasonable assurance the components intended functions are PBN2: 09/08/2032 maintained. Plant procedures for visual inspections and examinations will be revised to include the bolting integrity program in their scope; f) Enhance plant procedures to project, where practical, identified degradation until the next scheduled inspection. Results will be evaluated against acceptance criteria to confirm that the timing of subsequent inspections will maintain the components intended functions throughout the SPEO based on the projected rate of degradation. For sampling-based inspections, results will be evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components intended functions throughout the SPEO based on the projected rate and extent of degradation.

Adverse results will be evaluated to determine if an increased sample size or inspection frequency is required; g) Enhance plant procedures to include the requirementsguidance for leakage monitoring, sample expansion and additional inspections if inspection results do not meet acceptance criteria as described in NUREG-2191, Chapter XI.M18, Element 7.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 7 of 10 SLRA Section B.1.4, page B-10 is revised as follows:

As described above, the existing OE process at PBN, in conjunction with the PBN CAP, has proven to be effective in learning from adverse conditions and events, and improving programs that address age-related degradation.

In addition, for multi-unit sites where sample size is not based on their percentage of the population and the inspections are conducted periodically (not one-time inspections),

reduced inspections for several aging management programs are acceptable. In order to conduct the reduced number of inspections, operating conditions at each unit must be demonstrated to be similar enough to provide representative inspection results. Based on the following, the units and operating experience at PBN are similar such that a reduced number of inspections can be credited x PBN Units 1 and 2 were both approved for extended power uprate on May 03, 2011.

x Operating experience has not indicated a trend of out-of-spec water chemistry conditions that would differentiate one unit from the other. Action Request keyword searches water chem, MIC, micro, amoni, dezinc, and de-zinc yield no plant operating experience that indicates long term or repeated out-of-spec water chemistry conditions.

x Lake Michigan is the source for raw water systems at PBN with no differences between the units. Action Request keyword searches for MIC and microb cross referenced with raw, Service Water, ICW, Fire Protection, and Waste Disposal yielded no trends of increased MIC degradation between Units 1 and 2 for raw water systems.

x Per PBN Technical Specifications 3.8.3, diesel generators are tested at the same frequency.

x Treated water systems common to both units have the same chemistry requirements and operate at similar temperatures

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 8 of 10 SLRA Appendix B, Section B.2.3.9, 5th paragraph, page B-82 is revised as follows:

This AMP supplements the inspection activities required by ASME Code Section XI for ASME Code Class 1, 2 and 3 bolting. For ASME Code Class 1, 2, and 3, and non ASME Code class bolts, periodic system walkdowns and inspections are performed at least once per refueling cycle to provide reasonable assurance that indications of loss of preload (leakage), cracking, and loss of material are identified before leakage becomes excessivea loss of the components intended functions can occur.

Visual inspection methods and the frequency of inspection are selected to manage such effects to prevent significant age related degradation. Identified leaking bolted connections will be monitored at an increased frequency in accordance with the CAP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 9 of 10 SLRA Appendix B, Section B.2.3.9, new paragraph is added between what is currently the last and the second to last paragraph, page B-83:

For component joints that are not normally pressurized, the aging effects associated with closure bolting will be managed by checking the torque to the extent that the closure bolting is not loose.

High strength closure bolting [actual measured yield strength greater than or equal to 150 ksi (1,034 MPa)] may be subject to SCC. For all closure bolting greater than 2 inches in diameter (regardless of code classification) with actual yield strength greater than or equal to 150 ksi (1,034 MPa) and closure bolting for which yield strength is unknown, volumetric examination in accordance to that of ASME Code Section XI, Table IWB-2500-1, Examination Category B-G-1, is performed (e.g., acceptance standards, extent and frequency of examination). Specified bolting material properties (e.g., design and procurement specifications, fabrication and vendor drawings, material test reports) may be used to determine if the bolting exceeds the threshold to be classified as high strength.

Indications of aging are evaluated in accordance with Section XI of the ASME Code.

Leaking joints do not meet acceptance criteria.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 9 Page 10 of 10 SLRA Appendix B, Section B.2.3.9, Enhancements subsection, Enhancement 7. Corrective Actions, page B-85 is revised as follows:

7. Corrective Actions Enhance plant procedures and include in the new procedure the requirementsguidance for leakage monitoring, sample expansion and additional inspections if inspection results do not meet acceptance criteria as described in NUREG-2191, Chapter XI.M18, Element 7.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 1 of 13 Steam Generator: Revised Further Evaluation, AMR Results, and AMP Affected SLRA Sections: Table 2.3.1-5, Section 3.1.2.2.11, Table 3.1-1, Table 3.1.2-5, Section 16.2.2.20, Table 16-3, Section B.2.3.10, Section B.2.3.20 SLRA Page Numbers: 2.3-13, 3.1-17, 3.1-18, 3.1-32, 3.1-49, 3.1-50, 3.1-99, 3.1-101, 3.1-102, 3.1-107, 3.1-110, A-27, A-70, A-84, B-89, B-91, B-92, and B-154 Description of Change:

Steam generator internal components consisting of the feedwater feedring, feedwater support structure and feedwater j-nozzles have an intended function of Direct flow in addition to Structural integrity (attached). Accordingly, SLRA Table 2.3.1-5 and Table 3.1.2-5 are revised to include Direct flow as an applicable intended function. In addition, Note D is changed to note B for the feedwater feedring and support structure for the wall thinning due to flow accelerated corrosion line because the component type is consistent with GALL-SLR item IV.D1.RP-49 The steam generators for PBN Unit 1 are assumed to not be bounded by the industry analyses contained in EPRI 3002002850 related to the steam generator divider plate primary water assemblies fabricated of Alloy 600 type materials. PBN commits to performing a one-time inspection of the divider plate prior to the subsequent period of extended operation. Accordingly, SLRA Section 3.1.2.2.11, Table 3.1-1 Item 025, Section 16.2.2.20, Table 16-3 Item 14 and 24, Section B.2.3.10, and Section B.2.3.20 are revised to clarify that the PBN Unit 1 steam generators are assumed to not be bounded by analyses in EPRI 3002002850 and commits to performing a one-time inspection to verify the effectiveness of the PBN Water Chemistry and Steam Generators AMPs and to verify the absence of primary water stress corrosion cracking (PWSCC) in the divider plate assemblies.

The blowdown piping nozzles and secondary side shell penetrations are susceptible to wall thinning due to flow accelerated corrosion and loss of material due to erosion. Accordingly, SLRA Table 3.1.2-5, Table 3.1-1 Item 072, and Table 3.1-1 Item 074 are revised to clarify that the Steam Generators and Water Chemistry AMPs will manage wall thinning due to flow accelerated corrosion and loss of material for blowdown piping nozzles and secondary side shell penetrations.

Loss of material for the new transition cone welds is managed by the Water Chemistry and One-Time Inspection AMPs. Accordingly, SLRA Table 3.1.2-5 is revised to remove the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD AMP as managing loss of material for the new transition cone welds and plant specific note 2 is added to state that loss of material for the new transition cone welds is managed by the Water Chemistry and One-Time Inspection AMPs.

The Steam Generators AMP described in SLRA Section B.2.3.10 has an exception to element 1 of the GALL-SLR Steam Generators AMP. Accordingly, SLRA Section B.2.3.10 is revised to clarify that the exception for the Steam Generators AMP is related to element 1.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 2 of 13 SLRA Table 2.3.1-5, page 2.3-13 is revised as follows:

Table 2.3.1-5 Steam Generator Components Subject to Aging Management Review Component Type Component Intended Function(s)

Anti-vibration bars Structural support Blowdown piping nozzles and secondary side shell Pressure boundary penetrations Channel head drain coupling and Alloy 152 weld filler Pressure boundary (U1)

Channel head with primary nozzles Pressure boundary Divider plate Direct flow Feedwater nozzle Pressure boundary Feedwater feedring and support structure Structural integrity (attached)

Direct flow Feedwater J-nozzles Structural integrity (attached)

Direct flow Lower shell Pressure boundary Moisture separators Direct flow Primary manway bolting Pressure boundary Primary manway cover Pressure boundary Primary nozzle safe end Alloy 82/182 welds (U2) Pressure boundary Primary nozzle safe ends Pressure boundary Primary side Alloy 690 vent nozzles (U2) Pressure boundary Secondary closure bolting (excluding U1 inspection Pressure boundary port)

Secondary closures Pressure boundary Seismic lugs Structural support Steam flow limiter Throttle Steam generator components with fatigue analysis Pressure boundary Steam outlet nozzle Pressure boundary Support pads Structural support Transition cone Pressure boundary Transition cone welds (new welds) Pressure boundary Transition cone welds (U1 original welds) Pressure boundary Tube bundle wrapper and wrapper support system Direct flow Structural support Tube plugs Pressure boundary Tube support plates Structural support Tubesheet Pressure boundary Tube-to-tubesheet weld (U2) Pressure boundary Upper and lower shell, elliptical head and transition Pressure boundary cone U-tubes Pressure boundary Heat transfer

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 3 of 13 SLRA Section 3.1.2.2.11, pages 3.1-17 and 3.1-18 are revised as follows:

PBN Unit 1 has an Alloy 600 divider plate assemblies and the EPRI analysis is applicable. The industry analysis (EPRI TR-3002002850) are currently being evaluated as part of the existing steam generators AMP for the current period of extended operation to determine whether it is bounding is conservatively assumed to not be bounding for PBN.

If the analysis is determined to be bounding, the Steam Generators AMP will be revised to address primary water stress corrosion cracking in the divider plate for the current period of extended operation and carried forward through the SPEO. A plant specific AMP is not necessary.

If the analyses are determined to not be bounding, a As such, the Oone-Ttime Iinspection AMP will be implemented for SLR to verify the effectiveness of the Water Chemistry (B.2.3.2) and Steam Generators (B.2.3.10) AMPs and that there is no presence of PWSCC in the divider plate assemblies. The volumetric examinations will be performed by qualified personnel and the techniques used will be capable of detectingon of primary water stress corrosion cracking in the divider plate assemblies and associated welds.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 4 of 13 SLRA Table 3.1-1, pages 3.1-32, 3.1-49, and 3.1-50 are revised as follows:

Table 3.1-1: Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Component Aging Effect/Mechanism Aging Management Further Evaluation Discussion Number Program (AMP)/TLAA Recommended 3.1-1, 025 Steel (with nickel alloy cladding) Cracking due to primary AMP XI.M2, "Water Yes (SRP-SLR Not applicable.

or nickel alloy steam generator water SCC Chemistry," and AMP Sections 3.1.2.2.11.1 Consistent with NUREG-primary side components: XI.M19, and 2191. The PBN Water divider plate and tube-to-tube "Steam Generators." In 3.1.2.2.11.2) Chemistry (B.2.3.2) and sheet welds exposed to reactor addition, a plant- specific Steam Generators coolant program is to be (B.2.3.10) AMPs will be evaluated. used to manage primary water SCC in the Unit 1 divider plate assemblies.

The One Time Inspection (B.2.3.20) AMP is used to verify the effectiveness of the Water Chemistry and Steam Generators AMPs in accordance with EPRI Report 3002002850 regarding primary water SCC in the divider plate.

Further evaluation is documented in subsection 3.1.2.2.11.

3.1-1, 072 Steel steam generator tube Loss of material due to AMP XI.M19, "Steam No Consistent with support plate, tube bundle general, pitting, crevice Generators," and AMP NUREG-2191 The Steam wrapper, supports and mounting corrosion, erosion, XI.M2, "Water Generators (B.2.3.10) and hardware exposed to secondary ligament cracking due to Chemistry" (corrosion Water Chemistry (B.2.3.2) feedwater or steam corrosion based aging effects and AMPs are used to manage mechanisms only) loss of material due to general, pitting, and crevice corrosion, erosion, and ligament cracking due to corrosion in the steam generator tube bundle

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 5 of 13 Table 3.1-1: Summary of Aging Management Evaluations for the Reactor Vessel, Internals, and Reactor Coolant System Item Component Aging Effect/Mechanism Aging Management Further Evaluation Discussion Number Program (AMP)/TLAA Recommended wrapper, moisture separators, and tubesheet along with the blowdown piping nozzles and secondary side shell penetrations exposed to secondary feedwater or steam.

3.1-1, 074 Steel steam generator upper Wall thinning due to AMP XI.M19, "Steam No Consistent with assembly and separators flow- accelerated corrosion Generators," and AMP NUREG-2191. The Steam including feedwater inlet ring XI.M2, Generators (B.2.3.10) and and support exposed to "Water Chemistry" Water Chemistry (B.2.3.2) secondary feedwater or steam AMPs are used to manage wall thinning due to flow-accelerated corrosion in the feedwater ring and moisture separators along with the blowdown piping nozzles and secondary side shell penetrations exposed to secondary feedwater or steam.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 6 of 13 SLRA Table 3.1.2-5, pages 3.1-99, 3.1-101, 3.1-102, 3.1-107, and 3.1-110 are revised as follows:

Table 3.1.2-5: Steam Generators - Summary of Aging Management Evaluation Aging Effect Intended Aging Management NUREG-2191 Table 1 Component Type Material Environment Requiring Notes Function Program Item Item Management Blowdown piping Pressure Carbon Treated water Wall thinning Steam Generators IV.D1.RP-49 3.1-1, 074 D nozzles and boundary steel - FAC (B.2.3.10) secondary side Water Chemistry shell (B.2.3.2) penetrations Blowdown piping Pressure Carbon Treated water Loss of Steam Generators IV.D1.RP-161 3.1-1, 072 D nozzles and boundary steel material (B.2.3.10) secondary side Water Chemistry shell (B.2.3.2) penetrations Feedwater Structural Carbon Treated water Cracking Steam Generators IV.D1.RP-384 3.1-1, 071 D feedring and integrity steel (U1) >140°F Steam (B.2.3.10) support structure (attached) Water Chemistry Direct flow (B.2.3.2)

Feedwater Structural Carbon Treated water Loss of Steam Generators IV.D1.RP-226 3.1-1, 071 D feedring and integrity steel (U1) Steam material (B.2.3.10) support structure (attached) Water Chemistry Direct flow (B.2.3.2)

Feedwater Structural Carbon Treated water Wall thinning - Steam Generators IV.D1.RP-49 3.1-1, 074 BD feedring and integrity steel (U1) Steam FAC (B.2.3.10) support structure (attached) Water Chemistry Direct flow (B.2.3.2)

Feedwater Structural Low-alloy Treated water Cracking Steam Generators IV.D1.RP-384 3.1-1, 071 D feedring and integrity steel (U2) >140°F Steam (B.2.3.10) support structure (attached) Water Chemistry Direct flow (B.2.3.2)

Feedwater Structural Low-alloy Treated water Loss of Steam Generators IV.D1.RP-226 3.1-1, 071 D feedring and integrity steel (U2) Steam material (B.2.3.10) support structure (attached) Water Chemistry Direct flow (B.2.3.2)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 7 of 13 Table 3.1.2-5: Steam Generators - Summary of Aging Management Evaluation Aging Effect Intended Aging Management NUREG-2191 Table 1 Component Type Material Environment Requiring Notes Function Program Item Item Management Feedwater j- Structural Nickel alloy Treated water Cracking Steam Generators IV.D1.RP-384 3.1-1, 071 D nozzle integrity >140°F Steam (B.2.3.10)

(attached) Water Chemistry Direct flow (B.2.3.2)

Feedwater j- Structural Nickel alloy Treated water Loss of Steam Generators IV.D1.RP-226 3.1-1, 071 D nozzle integrity Steam material (B.2.3.10)

(attached) Water Chemistry Direct flow (B.2.3.2)

Transition cone Pressure Carbon Treated water Loss of ASME Section XI IV.D1.RP-368 3.1-1, 012 A welds (new welds) boundary steel material Inservice Inspection, B Subsections IWB, IWC, E, 2 and IWD (B.2.3.1)

Water Chemistry (B.2.3.2)

One-Time Inspection (B.2.3.20)

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

B. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP has exceptions to NUREG-2191 AMP description.

C. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item.

AMP is consistent with NUREG-2191 AMP description.

D. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item.

AMP has exceptions to NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 8 of 13 SLRA Table 3.1-1, pages 3.1-32, 3.1-49, and 3.1-50 revision continued:

Plant Specific Notes

1. Per Section 3.1.2.2.11, the Unit 1 divider plate aging effect of cracking is managed by the Steam Generators (B.2.3.10), Water Chemistry (B.2.3.2),

and One-Time Inspection (B.2.3.20) AMPs.

2. Per Section 3.1.2.2.2, loss of material in the new transition cone welds is managed by the Water Chemistry (B.2.3.2) and One-Time Inspection (B.2.3.20) AMPs.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 9 of 13 SLRA Section 16.2.2.20, page A-27 is revised as follows:

The PBN One-Time Inspection AMP will also perform inspections on the Unit 1 steam generator divider plate assemblies and the steam generator circumferential transition cone field welds on both units in order to verify the effectiveness of the PBN Water Chemistry and Steam Generator AMPs and verify the absence of PWSCC in the divider plate assemblies.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 10 of 13 SLRA Table 16-3, pages A-70 and A-84 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging Management NUREG-2191 Commitment Implementation Program or Activity Section Schedule (Section) 14 Steam Generators XI.M19 Continue the existing PBN Steam Generators AMP, including No later than 6 months (16.2.2.10) enhancement to: prior to the SPEO, i.e.:

a) If the The Unit 1 steam generator divider plate assemblies PBN1: 04/05/2030 are assumed to not be bounded by industry analyses EPRI PBN2: 09/08/2032 3002002850, and PBN will perform a one-time inspections of the Unit 1 steam generator divider plate assemblies prior to the SPEO to confirm that the Water Chemistry and Steam Generator AMPs have mitigated the occurrence of primary water stress corrosion cracking.

24 One-Time Inspection XI.M32 Continue the existing PBN One-Time Inspection AMP, including No later than 6 months (16.2.2.20) enhancement to: prior to the SPEO, or no a) Perform visual exams or other appropriate NDE exams to later than the last verify the effectiveness of the PBN Lubricating Oil Analysis refueling outage prior to AMP for managing the effects of aging of various the SPEO i.e.:

components in systems containing lubricating oil. PBN1: 04/05/2030 b) For steel components exposed to water environments that PBN2: 09/08/2032 do not include corrosion inhibitors as a preventive action Perform the one time (e.g., treated water, treated borated water, raw water, waste inspections no earlier water), verify that long-term loss of material due to general than 10 years prior to the corrosion will not cause a loss of intended function [e.g., SPEO and no later than 6 pressure boundary, leakage boundary (spatial), structural months prior to the integrity (attached)]. Long-term loss of material due to SPEO.

general corrosion for steel components need not be managed if one of the following two conditions is met: (i) the environment for the steel components includes corrosion inhibitors as a preventive action; or (ii) wall thickness measurements on a representative sample of each

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 11 of 13 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging Management NUREG-2191 Commitment Implementation Program or Activity Section Schedule (Section) environment will be conducted between the 50th and 60th year of operation.

c) Perform one-time volumetric inspections on each of the steam generator transition cone field welds on both units.

This one-time volumetric inspection on each steam generator transition cone field weld is intended to cover essentially 100% of the total weld length.

d) Perform one-time inspections of the Unit 1 steam generator divider plate assemblies. The inspections will be capable of detecting primary water stress corrosion cracking in the divider plate assemblies and associated welds, verify the effectiveness of the Water Chemistry and Steam Generators AMPs and verify the absence of PWSCC in the divider plate assemblies.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 12 of 13 SLRA Section B.2.3.10, pages B-89, B-91, and B-92 are revised as follows:

Inspections of the Unit 1 divider plates are may be required for the SPEO.

Nickel-alloy divider plates could experience PWSCC as described in the SRP-SLR.

The analysis performed by the industry in EPRI TR 3002002850 (Reference 1.6.64) is applicable as PBN Unit 1 steam generators which have alloy-600 divider plates.

The industry analyses are currently being evaluated to determine whether they are bounding for PBN and will be completed prior to the SPEO. If the evaluation is are conservatively assumed to not be bounding and, PBN will perform a one-time inspection of the divider plates to confirm the effectiveness of the actions currently in place in the Water Chemistry and Steam Generators AMPs to manage PWSCC (Water Chemistry AMP and the visual inspections performed for the existing Steam Generator AMP). Under the current practice, the divider plate assemblies are visually inspected during every primary-side inspection.

Exceptions to NUREG-2191 The tube-to-tubesheet welds of the PBN Unit 1 steam generators are exempt from inspection and monitoring per the NRC safety evaluation report for permanent Alternate Repair Criteria (H*) for steam generator tubes (Reference ML17159A778) which represents an exception to Element 1, Scope of Program.

Enhancements The PBN Steam Generators AMP will be enhanced as follows for alignment with NUREG-2191. Enhancements are to be implemented no later than six months prior to entering the SPEO.

Element Affected Enhancement

3. Parameters If theThe Unit 1 steam generator divider plate assemblies are Monitored or conservatively assumed to not be bounded by industry analyses EPRI Inspected 3002002850,. As such, PBN will perform a one-time inspection of the Unit 1 steam generator divider plate assemblies prior to the SPEO to confirm the Water Chemistry and Steam Generator AMPs are effective in mitigating PWSCC.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 10 Page 13 of 13 SLRA Section B.2.3.20, page B-154 is revised as follows:

Element Enhancement Affected

1. Scope of Program x Include verification of the effectiveness of the PBN Lubricating Oil Analysis AMP for managing the effects of aging of various components in systems containing lubricating oil.

x For steel components exposed to water environments that do not include corrosion inhibitors as a preventive action (e.g., treated water, treated borated water, raw water, waste water), include verification that long-term loss of material due to general corrosion will not cause a loss of intended function [e.g.,

pressure boundary, leakage boundary (spatial), structural integrity (attached)]. Long-term loss of material due to general corrosion for steel components need not be managed if one of the following two conditions is met: (i) the environment for the steel components includes corrosion inhibitors as a preventive action; or (ii) wall thickness measurements on a representative sample of each environment will be conducted between the 50th and 60th year of operation.

x Perform one-time volumetric inspections on each of the steam generator transition cone field welds on both units. This one-time volumetric inspection on each steam generator transition cone field weld is intended to cover essentially 100% of the total weld length.

x Perform one-time inspections of the Unit 1 steam generator divider plate assemblies. The inspections will be capable of detecting primary water stress corrosion cracking in the divider plate assemblies and associated welds and confirm the effectiveness of the Water Chemistry and Steam Generator AMPs.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 11 Page 1 of 3 Water Chemistry AMP: Clarified the Implementation Schedule Affected SLRA Sections: Table 16-3-6 (Appx A, Sect. 16.4), Table B-4 (Appx B, Sect. B.2.1)

SLRA Page Numbers: A-65, B-18 Description of Change:

The PBN Water Chemistry AMP will implement Heating Steam Systems monitoring in accordance with the industry standards and perform a one-time inspection to verify the effectiveness of monitoring the Heating Steam Systems.

The SLRA is revised to provide additional clarification on the implementation schedule of the commitments in Table 16-3. Additionally, Table B-4 is updated to include the enhancements required for the PBN Water Chemistry AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 11 Page 2 of 3 SLRA Appendix A, Section 16.4, Table 16-3, page A-65 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 6 Water XI.M2 Continue the existing PBN Water Chemistry AMP, including enhancements to: No later than 6 months prior Chemistry a) Incorporate monitoring the critical chemistry parameters for the Heating to the SPEO, i.e.:

(16.2.2.2) Steam System in accordance with industry standards, specifically ASME PBN1: 04/05/2030 standard ISBN-0-7918-1204-9, Consensus on Operating Practices for the PBN2: 09/08/2032 Control of Feedwater and Boiler Water Chemistry in Modern Industrial Implement the AMP 5 Boilers. years prior to the SPEO b) Perform a one-time inspection to verify the effectiveness of monitoring the and start the one-time critical chemistry parameters for the Heating Steam Systems in accordance inspections no earlier than with industry standards, specifically ASME stands ISBN-0-7918-1204-9, 5 years prior to the SPEO.

Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 11 Page 3 of 3 SLRA Appendix B, Section B.2.1, Table B-4, page B-18 is revised as follows:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 1 of 6 Inspection of Overhead Heavy Load Handling Systems AMP: Code Clarifications Affected SLRA Sections: Appendix A (Sections 16.2.2.13, 16.4 (Table 16-3), and 16.5) and Appendix B (Section B.2.3.13)

SLRA Page Numbers: A-21, A-75, A-115, B-114, B-115 Description of Change:

Guidance provided in American National Standards Institute (ANSI) Standard B30.2-1976 served as a benchmark for NUREG-0612 and governs activities specified in the Point Beach Nuclear Plant (PBN) Inspection of Overhead Heavy Load Handling Systems Aging Management Program (AMP), which is currently implemented as part of the PBN Structures Monitoring Program. By alignment with guidance provided in the 2005 version of American Society of Mechanical Engineers (ASME) Safety Standard B30.2, certain elements of the existing AMP will be enhanced to demonstrate consistency with the NUREG-2191 Section XI.M23 AMP.

Other standards in the ASME B30 series are identified as developmental references for rigging and material handling operations at PBN; however, these standards are not applied in the context of managing aging effects for NUREG-0612 load handling systems within the scope of subsequent license renewal. Likewise, mentioning that load handling systems also fall within the scope of the maintenance rule (10 CFR 50.65) is extraneous. Therefore, alluding to such other standards and regulations is unnecessary to demonstrate consistency with the NUREG-2191 Section XI.M23 AMP elements at PBN. Accordingly, Appendix A (Sections 16.2.2.13, Table 16-3 in Section 16.4, and Section 16.5) and Appendix B (Section B.2.3.13) are revised to remove the unnecessary phrasing and unused references.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 2 of 6 SLRA Appendix A, Section 16.2.2.13, page A-21 is revised as follows:

16.2.2.13 Inspection of Overhead Heavy Load Handling Systems The PBN Inspection of Overhead Heavy Load Handling Systems AMP (referred to herein as the PBN XI.M23 AMP) is an existing AMP that is currently implemented as part of the PBN Structures Monitoring Program. The PBN XI.M23 AMP was evaluated as a portion of the PBN Structures Monitoring AMP in the initial license renewal application. The PBN XI.M23 AMP is evaluated separately in the SLRA and it is compared to the NUREG-2191,Section XI.M23 program. This AMP evaluates the effectiveness of maintenance monitoring activities for cranes and hoists that are within the scope of SLR. This AMP also addresses the inspection and monitoring of crane-related structures and components to provide reasonable assurance that the handling system does not affect the intended function of nearby safety-related equipment. This AMP includes periodic visual inspections and examination of accessible surfaces to detect loss of material due to corrosion, deformation, and wear, cracking, and indications of loss of preload for load handling bridges, structural members, structural components, and bolted connections. This AMP also includes corrective actions as required based on these inspections. This AMP relies on the guidance in NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants,"

ASME B30.2, Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist)., and other appropriate standards in the ASME B30 series. These cranes also comply with the maintenance rule requirements provided in 10 CFR 50.65 (Reference 1.6.46).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 3 of 6 SLRA Appendix A, Section 16.4, Table 16-3, page A-75 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) c) Align procedures with the 2005 Edition of ASME B30.2, or other applicable industry standard in the ASME B30 series, to ensure that the correct acceptance criteria and corrective actions are used to evaluate (and repair, if necessary) any visual indication of loss of material, deformation, or cracking, and any visual sign of loss of bolting preload for NUREG-0612 load handling systems. Aligning with the 2005 Edition of ASME B30.2 also ensures that visual inspections are performed at the required frequency. According to ASME B30.2, inspections are performed within the following intervals:

x Periodic visual inspections by a designated person are required and documented yearly for normal service applications per paragraph 2-2.1.1.

x A crane that is used in infrequent service, which has been idle for a period of 1 year or more, shall be inspected before being placed in service in accordance with the requirements listed in paragraph 2-2.1.3 (i.e., periodic inspection).

d) Update the governing procedure to state that any visual indication of loss of material, deformation, or cracking, and any visual sign of loss of bolting preload for NUREG 0612 load handling systems is evaluated according to the 2005 Edition of ASME B30.2 or other applicable industry standard in the ASME B30 series.

e) Update the governing procedure to state that repairs made to NUREG 0612 load handling systems are performed as specified in the 2005 Edition of ASME B30.2 or other appropriate standard in the ASME B30 series.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 4 of 6 SLRA Appendix A, Section 16.5, page A-115 is revised as follows:

70. ASME, Boiler & Pressure Vessel Code,Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components", Subsections IWA, IWB, IWC, IWD, IWE, IWF, IWL, and Appendix L, American Society of Mechanical Engineers, New York, New York: The American Society of Mechanical Engineers. 2008.

71. ASME, Safety Standard B30.2, Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist), American Society of Mechanical Engineers, New York, New York, 2005.

72. Not used.ASME, Safety Standard B30.11, Monorails and Underhung Cranes, American Society of Mechanical Engineers, New York, New York, 2004.

73. ASTM, ASTM D 5163-08, Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants, American Society for Testing and Materials, West Conshohocken, Pennsylvania, 2008.

74. ASTM, ASTM E 185-82, Standard Practice for Conducting Surveillance Tests of Light-Water Cooled Nuclear Power Reactor Vessels. American Society for Testing Materials, Philadelphia, Pennsylvania, (Versions of ASTM E 185 to be used for the various aspects of the reactor vessel surveillance program are as specified in 10 CFR Part 50, Appendix H), 1982.

75. CMAA, CMAA-70, Crane Manufacturers Association of America, Inc., 197594.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 5 of 6 SLRA Section B.2.3.13, page B-114 and B-115 are revised as follows:

B.2.3.13 Inspection of Overhead Heavy Load Handling Systems Program Description The PBN Inspection of Overhead Heavy Load Handling Systems AMP is an existing AMP that was evaluated as a portion of the PBN Structures Monitoring AMP (Section B.2.3.34) in the initial license renewal application. The PBN Inspection of Overhead Heavy Load Handling Systems AMP is evaluated separately in the subsequent license renewal application and it is compared to the NUREG-2191,Section XI.M23 program.

Light load handling systems related to refueling at PBN include the reactor cavity manipulator cranes and the spent fuel pool bridge crane. These systems are not within the scope of subsequent license renewal because - as described in SLRA Section 2.4.15 - they do not have the potential to impact safety related components during normal plant operation.

The PBN Inspection of Overhead Heavy Load Handling Systems AMP evaluates the effectiveness of maintenance monitoring activities for cranes and hoists that are within the scope of SLR. This AMP addresses the inspection and monitoring of crane-related structures and components to provide reasonable assurance that the handling system does not affect the intended function of nearby safety-related equipment. Many crane systems and components are not within the scope of this AMP because they perform an intended function with moving parts or with a change in configuration, or they are subject to replacement based on qualified life.

The PBN Inspection of Overhead Heavy Load Handling Systems AMP includes periodic visual inspections to detect loss of material due to general corrosion and wear, deformed or cracked bridges, structural members, and structural components; and loss of material due to general corrosion, cracking, and loss of preload on bolted connections. NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, provides specific guidance on the control of overhead heavy load cranes. The activities to manage aging effects specified in this AMP utilize the guidance provided in American Society of Mechanical Engineers (ASME) Safety Standard B30.2, Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist)., and other appropriate standards in the ASME B30 series.

In addition, monitoring and maintenance of bridges, structural members, and structural components of load handling systems follow the maintenance rule requirements provided in Title 10 of the Code of Federal Regulations (10 CFR) 50.65 for other crane types.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 12 Page 6 of 6 SLRA Section B.2.3.13, page B-115 is revised as follows:

Element Affected Enhancement

6. Acceptance Criteria Update the PBN Inspection of Overhead Heavy Load Handling Systems AMP governing procedure to state that any visual indication of loss of material, deformation, or cracking, and any visual sign of loss of bolting preload for NUREG-0612 load handling systems is evaluated according to the 2005 Edition of ASME B30.2 or other applicable industry standard in the ASME B30 series.

7. Corrective Actions Update the PBN Inspection of Overhead Heavy Load Handling Systems AMP governing procedure to state that repairs made to NUREG-0612 load handling systems are performed as specified in the 2005 Edition of ASME B30.2 or other appropriate standard in the ASME B30 series.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 13 Page 1 of 3 Fire Protection AMP: Clarified Enhancement Affected SLRA Sections: Section 16.4, Table 16-3, Commitment 19 g), B.2.3.15 SLRA Page Numbers: A-77, B-124 Description of Change:

The Point Beach (PBN) Fire Protection aging management program (AMP) requires an enhancement be made to plant procedures to include inspecting, monitoring, and trending of oil collection channels, trenches, and skids credited to mitigate the spread of combustible liquids for cracking and loss of material at least once every 18 months. The acceptance criteria is revised to be no indication of cracking or loss of material. The enhancement and commitment listed in the subsequent license renewal application (SLRA) does not explicitly state all of these requirements. The enhancement and the commitment in the SLRA are clarified to indicate every aspect that is required to be included in the PBN Fire Protection AMP.

Accordingly, SLRA Table 16-3 in Appendix A and Section B.2.3.15 in Appendix B are revised to indicate the additional requirements of the enhancement/commitment as detailed below:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 13 Page 2 of 3 SLRA Appendix A, Section 16.4, Table 16-3, Commitment 19 g), page A-77 is revised as follows:

No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 19 Fire Protection XI.M26 Continue the existing PBN Fire Protection AMP, including enhancement to: No later than 6 months prior (16.2.2.15) a) Enhance plant procedures to specify that penetration seals will be to the SPEO, i.e.:

inspected for indications of increased hardness, shrinkage and loss of PBN1: 04/05/2030 strength, PBN2: 09/08/2032 b) Enhance plant procedures to specify that any loss of material to the fire damper assembly is unacceptable, c) Enhance plant procedures to specify that well-sealed and robustly secured components and fully enclosed cable tray covers credited to prevent internal fires from propagating outside of the component, and fire proofing material sprayed onto structural steel will be inspected for loss of material, cracking, and changes to elastomer properties as appropriate, d) Enhance plant procedures to add spalling and scaling to the degradation effects for which masonry block walls are inspected, e) Enhance plant procedures to indicate that personnel performing FP inspections will be qualified to do so, f) Enhance plant procedures to state that at least 10% of each type of seal will be visually inspected every 18 months, g) Enhance plant procedures to include inspecting, monitoring, and trending of oil collection channels, trenches, and skids credited to mitigate the spread of combustible liquids for cracking and loss of material at least once every 18 months. The acceptance criteria will be no indication of cracking or loss of material, h) Enhance plant procedures to specify that well-sealed and robustly secured components and fully enclosed cable tray covers credited to prevent internal fires from propagating outside of the component, and fire proofing material sprayed onto structural steel will be inspected every 4.5 years (33% of the population every 18 months),

i) Enhance plant procedures to specify that the dry chemical fire extinguishing systems will be inspected semi-annually,

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 13 Page 3 of 3 SLRA Appendix B, Section B.2.3.9, Enhancements subsection, portion shown on page B-124 is revised as follows:

Element Affected Enhancement

1. Scope of Program Enhance plant procedures to specify that any loss of material

3. Parameters Monitored or to the fire damper assembly is unacceptable.

Inspected

4. Detection of Aging Effects

5. Monitoring and Trending

6. Acceptance Criteria

1. Scope of Program Enhance plant procedures to specify that well-sealed and

3. Parameters Monitored or robustly secured components and fully enclosed cable tray Inspected covers credited to prevent internal fires from propagating

4. Detection of Aging outside of the component, and fire proofing material sprayed Effects onto structural steel will be inspected for loss of material,

5. Monitoring and Trending cracking, and changes to elastomer properties as appropriate.

6. Acceptance Criteria

1. Scope of Program Enhance plant procedures to add spalling and scaling to the

3. Parameters Monitored or degradation effects for which masonry block walls are Inspected inspected.

4. Detection of Aging Effects

5. Monitoring and Trending

6. Acceptance Criteria

1. Scope of Program Enhance plant procedures to include inspecting, monitoring,

3. Parameters Monitored and trending of oil collection channels, trenches, and skids or Inspected credited to mitigate the spread of combustible liquids for

4. Detection of Aging cracking and loss of material at least once every 18 months.

Effects The acceptance criteria will be no indication of cracking or

5. Monitoring and Trending loss of material.

6. Acceptance Criteria

4. Detection of Aging Enhance plant procedures to indicate that personnel Effects preforming FP inspections will be qualified to do so.

4. Detection of Aging Enhance plant procedures to state that at least 10 percent of Effects each type of seal will be visually inspected every 18 months.

4. Detection of Aging Enhance plant procedures to specify that well-sealed and Effects robustly secured components and fully enclosed cable tray covers credited to prevent internal fires from propagating outside of the component, and fire proofing material sprayed onto structural steel will be inspected every 4.5 years (33% of the population every 18 months).

4. Detection of Aging Enhance plant procedures to specify that the dry chemical fire Effects extinguishing systems will be inspected semi-annually.

5. Monitoring and Trending Enhance plant procedures to specify that the dry chemical fire extinguishing system inspections will be monitored and trended.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 1 of 29 Fire Water System: Revised Further Evaluation, AMR Results, and AMP Affected SLRA Sections: Table 3.3-1, 114; Table 3.3.2-6; Appendix A, Table 16-3 (Item 20);

Appendix B, Section B.2.3.16 SLRA Page Numbers: pages 3.3-52, 3.3-179, 3.3-180, 3.3-181, 3.3-184, A-77, A-78, A-79, B-129, B-130, B-131, and B-132 Description of Change:

Components that are copper alloy >15% Zn are susceptible to stress corrosion cracking if ammonia-based compounds are allowed to accumulate. On the external surfaces of piping and piping components, the potential exists for this aging effect to affect copper alloy >15% Zn components. However, on the internal surfaces of piping and piping components, ammonia-based compounds do not have the potential to accumulate, so cracking is not an applicable aging effect for internal air, condensation and gas environments. SLRA Table 3.3-1 item 114 is updated to clarify that cracking is not an applicable aging effect for internal surfaces of copper alloy components.

The portion of the gray cast iron fire hydrants in the fire protection system exposed to concrete and soil are subject to the loss of material aging effect. SLRA Table 3.3.2-6 is revised to state that loss of material for gray cast iron fire hydrants in the fire protection system that are exposed to concrete and soil is an applicable aging effect managed by the Buried and Underground Piping and Tanks and Selective Leaching AMPs.

Copper alloy and copper alloy > 15% Zn nozzles in the fire protection system are exposed to outdoor air internally and externally. SLRA Table 3.3.2-6 is revised to state that the copper alloy

> 15% Zn nozzles exposed to outdoor air externally in the fire protection system are subject to cracking managed by the External Surfaces Monitoring of Mechanical Components AMP. The internal surfaces of the copper alloy and copper alloy > 15% Zn nozzles exposed to outdoor air are potentially subject to flow blockage that could affect the spray function and are managed by the Fire Water System AMP. Internal surfaces of the copper alloy > 15% Zn nozzles are not subject to cracking because ammonia-based compounds do not have the potential to accumulate.

The gray cast iron pump casings exposed to raw water in the fire protection system are potentially subject to the wall thinning due to erosion aging effect. SLRA Table 3.3.2-6 is revised to state that wall thinning due to erosion of gray cast iron pump casings exposed to raw water in the fire protection system is an applicable aging effect managed by the Fire Water System AMP.

The fire water accumulator tank is not exposed to concrete externally. Therefore, the respective SLRA table item is left as-is.

In SLRA Table 3.3.2-6, the line for component type valve body from the original SLRA submittal listed NUREG-2191 item VII.C1.A-473b but credits the Fire Water System AMP B.2.3.16 to manage aging with a Note E. NUREG-2191 states that item VII.C1.A-473b is for piping, piping components, and heat exchangers components constructed of copper alloy (>15% Zn or >8%

Al) exposed to an environment of raw water and should be managed by the XI.M20 AMP, Open-Cycle Cooling Water System. Since the XI.M38 AMP, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, provides the most detailed guidance for managing stress corrosion cracking of piping components exposed to raw water, the Fire Water

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 2 of 29 System AMP is updated to include this guidance as well as include guidance on the number of components sampled during each 10-year period of the SPEO. SLRA Table 3.3.2-6, Item 3.3-1, 160 will remain as-is and continue to credit the PBN Fire Water System AMP for managing cracking of copper alloy >15% zinc valve bodies exposed to raw water. SLRA Appendix A, Table 16-3 (Item 20), and Appendix B (Section B.2.3.16), Commitments table, are updated to include a method suitable for identifying SCC of copper alloy >15% zinc valve bodies exposed to raw water (Commitment k).

The PBN Fire Water System AMP in the original SLRA submittal had some editorial inconsistencies between the Commitments listed in Appendix A, Table 16-3 (Item 20) and the Appendix B (Section B.2.3.16) enhancements table. Specifically, Commitments 20.c, d, g, and i did not align with the respective enhancements for Elements 4, 5, 6, and 7. Therefore, the SLRA is updated to resolve these discrepancies.

With respect to existing AMP actions, the fire protection system pressure is continuously monitored through alarm setpoints (as shown in the fire pump specification, instrumentation/electrical diagrams, and alarm response procedure), corrosion/degradation rates are calculated, and a 12.5 percent mill/manufacturing tolerance is used when evaluating wall thickness. Section B.2.3.16 is revised to include these clarifications.

With respect to enhancements, the PBN Fire Water System AMP in the original SLRA submittal did not clearly identify a commitment to document and trend the deposits associated with flushing-related tests and inspections (e.g., scale or foreign material). Therefore, the SLRA is updated to clearly state in Appendix A, Table 16-3 (Item 20) and the Section B.2.3.16 enhancements table that such deposits will be documented and trended after the respective flush is complete (Commitment j). Since the enhancements table lacked clarity with respect to enhancements associated with NUREG-2191 Table XI.M27-1, an additional table has been added to include the respective clarity.

Finally, additional clarifications are provided for the operating experience (OE) description of the fire water piping systems susceptible to the wet-dry cycle. The clarifications state that the warehouse #2 fire water piping system was opened and inspected in 2014 and had no flow blockage and little to no internal wear. An additional action request was issued to perform future inspections of warehouse #2 dry system branches as applicable. A low point on the pre-action system for the gas turbine building and low voltage auxiliary transformers was also subsequently drained and internally inspected. Two to three gallons of water were drained and the piping was observed to have a normal amount of internal wear/corrosion. A recent walkdown determined there were several additional low points, therefore, a new action request was issued to perform future inspections of the gas turbine building and low voltage auxiliary transformers dry system branches as applicable.

Accordingly, SLRA Table 3.3-1, Item 114; Table 3.3.2-6; Appendix A, Table 16-3 (Item 20); and Appendix B, Section B.2.3.16, are revised.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 3 of 29 SLRA Table 3.3-1, page 3.3-52 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 114 Copper alloy piping, None None No Consistent with NUREG-2191. This piping components line item is also applied to heat exposed to air, exchanger components. There are no condensation, gas aging effects that require management for copper piping, piping components, and heat exchanger components exposed to gas or air that would affect the pressure boundary intended function. Ammonia-based compounds cannot accumulate inside of piping and piping components, so cracking is not an applicable aging effect for internal surfaces.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 4 of 29 SLRA Table 3.3.2-6, page 3.3-179 is revised as follows:

Table 3.3.2-6: Fire Protection System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Fire hydrant Pressure Gray cast Air - indoor Loss of Fire Water System VII.G.AP-149 3.3-1, A boundary iron uncontrolled material (B.2.3.16) 063 (ext)

Fire hydrant Pressure Gray cast Air - outdoor Loss of Fire Water System VII.G.AP-149 3.3-1, A boundary iron (ext) material (B.2.3.16) 063 Fire hydrant Pressure Gray cast Concrete Loss of Buried and Underground VII.I.AP-198 3.3-1, A boundary iron material Piping and Tanks 109 Fire hydrant Pressure Gray cast Raw water (int) Long-term One-Time Inspection VII.G.A-532 3.3-1, A boundary iron loss of (B.2.3.20) 193 material Fire hydrant Pressure Gray cast Raw water (int) Loss of Fire Water System VII.G.AP-149 3.3-1, A boundary iron material (B.2.3.16) 063 Flow blockage Fire hydrant Pressure Gray cast Raw water (int) Wall thinning - Fire Water System VII.C1.A-409 3.3-1, E, 1 boundary iron erosion (B.2.3.16) 126 Fire hydrant Pressure Gray cast Soil Loss of Buried and Underground VII.I.AP-198 3.3-1, A boundary iron material Piping and Tanks 109 Fire hydrant Pressure Gray cast Soil Loss of Selective Leaching VII.G.A-02 3.3-1, A boundary iron material 072

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 5 of 29 SLRA Table 3.3.2-6, pages 3.3-180 and 3.3-181, is revised as follows to add the following rows:

Table 3.3.2-6: Fire Protection System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Nozzle Pressure Copper alloy Air - outdoor None None VII.J.AP-144 3.3-1, A boundary (ext) 114 Nozzle Pressure Copper alloy Air - outdoor Cracking External Surfaces VIII.H.S-454 3.4-1, A boundary > 15% Zn (ext) Monitoring of Mechanical 106 Components (B.2.3.23)

Nozzle Pressure Copper alloy Air - outdoor None None VII.J.AP-144 3.3-1, A boundary (int) 114 Nozzle Pressure Copper alloy Air - outdoor None None VII.J.AP-144 3.3-1, A boundary > 15% Zn (int) 114 Nozzle Spray Copper alloy Air - outdoor Flow Fire Water System VII.G.A-404 3.3-1, A (int) blockage (B.2.3.16) 131 Nozzle Spray Copper alloy Air - outdoor Flow Fire Water System VII.G.A-404 3.3-1, A

> 15% Zn (int) blockage (B.2.3.16) 131

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 6 of 29 SLRA Table 3.3.2-6, page 3.3-184 is revised as follows:

Table 3.3.2-6: Fire Protection System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Pump casing Pressure Gray cast Air - indoor Loss of External Surfaces VII.I.A-77 3.3-1, A boundary iron uncontrolled material Monitoring of Mechanical 078 (ext) Components (B.2.3.23)

Pump casing Pressure Gray cast Raw water (int) Long-term One-Time Inspection VII.G.A-532 3.3-1, A boundary iron loss of (B.2.3.20) 193 material Pump casing Pressure Gray cast Raw water (int) Loss of Selective Leaching VII.G.A-51 3.3-1, A boundary iron material (B.2.3.21) 072 Pump casing Pressure Gray cast Raw water (int) Loss of Fire Water System VII.G.A-33 3.3-1, A boundary iron material (B.2.3.16) 064 Flow blockage Pump casing Pressure Gray cast Raw water (int) Wall thinning Fire Water System VII.C1.A-409 3.3-1, E, 1 boundary iron - erosion (B.2.3.16) 126

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 7 of 29 SLRA Appendix A, Section 16.4, Table 16-3 (Item 20), pages A-77, A-78, and A-79 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 20 Fire Water System XI.M27 Continue the existing PBN Fire Water System AMP activities, including No later than 6 months prior (16.2.2.16) enhancement to: to the SPEO, or no later a) Update the governing AMP procedure to clearly state which procedures than the last refueling perform visual inspections for detecting loss of material. Such visual outage prior to the SPEO inspections will require using an inspection technique capable of detecting i.e.:

surface irregularities that could indicate an unexpected level PBN1: 04/05/2030 of degradation due to corrosion and corrosion product deposition. Where PBN2: 09/08/2032 such irregularities are detected, follow up volumetric wall thickness Implement the AMP and examinations shall be performed. start inspections and tests b) Update the governing AMP procedure to clearly state which procedures no earlier than 5 years prior perform volumetric wall thickness inspections. Volumetric inspections to the SPEO.

shall be conducted on the portions of the water based fire protection system components that are periodically subjected to flow but are normally dry.

c) Update existing procedures and create new procedures to perform testing and visual inspections in accordance with the surveillance requirements, including methods and intervals, from NUREG-2191 Section XI.M27, Element 4, and Table XI.M27-1 of NUREG-2191 based on NFPA 25, 2011 Edition.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 8 of 29 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) d) Update the governing AMP procedure and trending procedure to state that where practical, degradation identified is projected until the next scheduled inspection. Results are evaluated against acceptance criteria to confirm that the timing of subsequent inspections will maintain the components intended functions throughout the SPEO based on the projected rate of degradation. Results of flow testing, flushes, and wall thickness measurements are monitored and trended by either the Engineering or Fire Protection Department per instructions of the specific test/inspection procedure. Degradation identified by flow testing, flushes, and inspections is evaluated. If the condition of the piping/component does not meet acceptance criteria, then a condition report is written per the PBN corrective action program and the component is evaluated for repair/replacement. For sampling based inspections, results are evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components intended functions throughout the SPEO based on the projected rate and extent of degradation.

e) Update the governing AMP procedure to identify the procedure that performs the continuous monitoring and evaluation of the fire water system discharge pressure.

f) Update the governing AMP procedure to state that results of flow testing (e.g., buried and underground piping, fire mains, and sprinkler), flushes, and wall thickness measurements are monitored and trended.

Degradation identified by flow testing, flushes, and inspections is evaluated.

g) Update the governing AMP procedure to state that the minimum design wall thicknesses of the in scope piping must be maintained.

h) Update the governing AMP procedure to point to the inspection procedures which inspect the wall thicknesses and compare to the minimum design thicknesses.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 9 of 29 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) i) Update the existing flow testing and flushing procedures and develop a new main drain test procedure to state that if a flow test or a main drain test does not meet acceptance criteria due to current or projected degradation, then additional tests are conducted. The number of increased tests is determined in accordance with the PBN corrective action program; however, there are no fewer than two additional tests for each test that did not meet acceptance criteria. The additional inspections are completed within the interval (i.e., 5 years, annual) in which the original test was conducted. 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. Since PBN is a multi-unit site, additional tests include inspections at all of the units with the same material, environment, and aging effect combination.

j) Update spray and sprinkler system flushing procedures to enable trending of data. Specifically, the existing flushing procedures will be revised to document and trend deposits (scale or foreign material). Recommended methods for trending deposits may include the following as feasible:

x Inspectors will take photographs of deposits.

x Inspectors will measure the weight of the deposits.

x Inspectors will measure elapsed time taken to complete a flush (i.e., the time required for the flushing water to turn an acceptable color)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 10 of 29 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section)

The documentation above will be maintained by the AMP owner for comparing and trending inspection/test results. Existing flushing procedures, as well as new flushing procedures, will include steps to compare the amount of deposits to the previous inspections results, and if the trend is negative or if the projected solids for the next inspection/test/flush are anticipated to exceed an acceptable amount that would impact the system intended function, then the PBN Corrective Action Program will be utilized to drive improvement.

Additionally, identified deposits will be evaluated for potential impact on downstream components, such as sprinkler heads or spray nozzles.

k) Update the governing AMP procedure to clearly state which procedures perform surface examinations or ASME Code,Section XI, VT-1 visual examinations for identifying SCC within copper alloy (>15% Zn) valve bodies. The internal inspections will be performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. At a minimum, in each 10-year period during the SPEO, a representative sample of 20% of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 19 components per population at each unit is inspected. Where practical, the inspections will focus on the bounding or lead components most susceptible to aging.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 11 of 29 SLRA Section B.2.3.16, page B-129 is revised as follows:

x All fire hose stations are flow tested/flushed at least every three years, although some hoses and stations are tested more frequently. Hose stations are also visually inspected on a monthly interval.

The PBN Fire Water System AMP also utilizes preventive actions which include chemical treatment via a chlorination system that injects oxidizing biocide, silt dispersant, and bio detergent into the service water and fire water systems to control silt deposition, microbiologically-influenced corrosion (MIC), and macroscopic biofouling from biota such as mussels.

To address potential loss of material, cracking, and flow blockage, the PBN Fire Water System AMP monitors several fire water system parameters. The ability to maintain required system pressures, flow rates, and required internal conditions (i.e.,

no fouling or sediment blockage) is required to be tested annually. These tests also verify that the diesel-driven and the electric motor-driven fire pumps are performing adequately and meet their design requirements. Occurrences of pipe/component leakage are also visually identified during these tests. Visual examinations of cementitious materials are not applicable, since no cementitious materials are used in the PBN fire water system.

The fire protection system pressure is continuously monitored through alarm setpoints. Test results from the various surveillance tests are evaluated. Periodic full flow flushing of the main fire system underground piping is performed to assure that the system function is maintained. Any degradation identified either by visual inspections or as a result of testing is reported, evaluated, and corrected through the PBN corrective action program. Guidance for determining a rate of corrosion/degradation is provided in the service water and fire protection inspection program procedures. Acceptance criteria are defined in the PBN Fire Water System AMP procedures used to perform the respective tests and inspections. A 12.5 percent mill/manufacturing tolerance is used, so that when a measured wall thickness drops below 87.5 percent of nominal thickness, corrective action is initiated to compare the thickness to the construction code minimum wall thickness and evaluate the need for additional corrective actions.

If an obstruction inside piping or sprinklers is detected during pipe inspections, the material is removed and the inspection results are entered into the PBN corrective action program for further evaluation. An evaluation is conducted to determine if deposits need to be removed to determine if loss of material has occurred. When loose fouling products that could cause flow blockage in the sprinklers is detected, a flush is conducted in accordance with the guidance in NFPA 25 Appendix D.5, Flushing Procedures. If any projected inspection results will not meet acceptance criteria prior to the next scheduled inspection, inspection frequencies are adjusted as determined by the PBN corrective action program.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 12 of 29 SLRA Section B.2.3.16, pages B-130 and B-131, are revised as follows:

no earlier than 5 years prior to the SPEO. The inspections and tests are to be completed no later than six months prior to entering the SPEO or no later than the last refueling outage prior to the SPEO.

Element Affected Enhancement

3. Parameters Update the governing AMP procedure to clearly state which Monitored or procedures perform visual inspections for detecting loss of material.

Inspected Such visual inspections will require using an inspection technique capable of detecting surface irregularities that could indicate an unexpected level of degradation due to corrosion and corrosion product deposition. Where such irregularities are detected, follow-up volumetric wall thickness examinations shall be performed.

3. Parameters Update the governing AMP procedure to clearly state which Monitored or procedures perform volumetric wall thickness inspections.

Inspected Volumetric inspections shall be conducted on the portions of the water-based fire protection system components that are periodically subjected to flow but are normally dry.

3. Parameters Update the governing AMP procedure to clearly state which Monitored or procedures perform surface examinations or ASME Code, Inspected Section XI, VT-1 visual examinations for identifying SCC within copper alloy (>15% Zn) valve bodies. The internal inspections will be performed during the periodic system and component surveillances or during the performance of maintenance activities when the surfaces are made accessible for visual inspection. At a minimum, in each 10-year period during the SPEO, a representative sample of 20% of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 19 components per population at each unit is inspected. Where practical, the inspections will focus on the bounding or lead components most susceptible to aging.

4. Detection of Aging Update existing procedures and create new procedures to perform Effects testing and visual inspections in accordance with the surveillance requirements, including methods and intervals, from NUREG-2191 Section XI.M27, Element 4, and Table XI.M27-1 based on NFPA 25, 2011 Edition. incorporate the surveillance requirements stated in NUREG-2191,Section XI.M27, Element 4 and Table XI.M27-1 based on NFPA 25, 2011 edition.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 13 of 29 SLRA Section B.2.3.16, pages B-130 and B-131 revision continued:

Element Affected Enhancement

5. Monitoring and Update the governing AMP procedure and trending procedure to Trending state that where practical, degradation identified is projected until the next scheduled inspection. Results are evaluated against acceptance criteria to confirm that the timing of subsequent inspections will maintain the components intended functions throughout the SPEO based on the projected rate of degradation.

Results of flow testing, flushes, and wall thickness measurements are monitored and trended by either the Engineering or Fire Protection Department per instructions of the specific test/inspection procedure. Degradation identified by flow testing, flushes, and inspections is evaluated. If the condition of the piping/component does not meet acceptance criteria, then a condition report is written per the PBN corrective action program and the component is evaluated for repair/replacement. For sampling-based inspections, results are evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components intended functions throughout the SPEO based on the projected rate and extent of degradation.

5. Monitoring and Update the governing AMP procedure to identify the procedure that Trending performs the continuous monitoring and evaluation of the fire water system discharge pressure.

5. Monitoring and Update the governing AMP procedure to state that results of flow Trending testing (e.g., buried and underground piping, fire mains, and sprinkler), flushes, and wall thickness measurements are monitored and trended. Degradation identified by flow testing, flushes, and inspections is evaluated.

5. Monitoring and Update spray and sprinkler system flushing procedures to Trending enable trending of data. Specifically, the existing flushing procedures will be revised to document and trend deposits (scale or foreign material). Recommended methods for trending deposits may include the following as feasible:

x Inspectors will take photographs of deposits.

x Inspectors will measure the weight of the deposits.

x Inspectors will measure elapsed time taken to complete a flush (i.e., the time required for the flushing water to turn an acceptable color).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 14 of 29 SLRA Section B.2.3.16, pages B-130 and B-131 revision continued:

Element Affected Enhancement The documentation above will be maintained by the AMP owner for comparing and trending inspection/test results. Existing flushing procedures, as well as new flushing procedures, will include steps to compare the amount of deposits to the previous inspections results, and if the trend is negative or if the projected solids for the next inspection/test/flush are anticipated to exceed an acceptable amount that would impact the system intended function, then the PBN Corrective Action Program will be utilized to drive improvement. Additionally, identified deposits will be evaluated for potential impact on downstream components, such as sprinkler heads or spray nozzles.

6. Acceptance Update the governing AMP procedure to state that the minimum Criteria design wall thicknesses of the in-scope piping must be maintained.

6. Acceptance Update the governing AMP procedure to point to the inspection Criteria procedures which inspect the wall thicknesses and compare to the minimum design thicknesses.

7. Corrective Actions Update the existing flow testing and flushing procedures and develop a new main drain test procedure to state that if a flow test or a main drain test does not meet acceptance criteria due to current or projected degradation, then additional tests are conducted. The number of increased tests is determined in accordance with the PBN corrective action program; however, there are no fewer than two additional tests for each test that did not meet acceptance criteria.

The additional inspections are completed within the interval (i.e., 5 years, annual) in which the original test was conducted. 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. Since PBN is a multi-unit site, additional tests include inspections at all of the units with the same material, environment, and aging effect combination.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 15 of 29 SLRA Section B.2.3.16, page B-131 is revised as follows to include a table after the enhancements table that provides additional detail on the enhancements based on NUREG-2191, Table XI.M27-1:

The following table provides additional detail on the enhancements based on NUREG-2191 Table XI.M27-1.

Description NFPA 25 Required Enhancements Section Sprinkler Systems Sprinkler 5.2.1.1 The relevant procedures are currently performed either on a refueling outage inspections interval (every 18 months), annually, or quarterly, which meets the interval requirements of NUREG-2191 Table XI.M27-1 Note 10.

The relevant procedures will be enhanced to incorporate the requirements of NFPA 25 Section 5.2.1.1 to ensure that sprinklers are visually inspected from the floor level and meet the acceptance criteria, which include no signs of leakage, corrosion, foreign materials, paint (unless painted by manufacturer), physical damage, loading, and loss of fluid in glass bulb heat responsive elements. Additionally, sprinklers shall be installed in the correct orientation (e.g., upright, pendent, or sidewall). Any sprinkler that does not meet these criteria shall be replaced.

Note that the acceptance criteria related to glass bulb heat responsive elements only apply to the procedures that inspect closed head sprinklers (wet system and pre-action system), rather than open head nozzles.

Sprinkler 5.3.1 A new procedure will be prepared and implemented to incorporate the testing following sprinkler testing instructions of NFPA 25, Section 5.3.1 subsections. Steps with asterisks have additional clarifying information in NFPA 25, Annex A. The required steps and information are as follows:

5.3.1.1*: Where required by this section, sample sprinklers shall be submitted to a recognized testing laboratory acceptable to the authority having jurisdiction for field service testing.

5.3.1.1.1: Where sprinklers have been in service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested.

5.3.1.1.1.1: Test procedures shall be repeated at 10-year intervals.

5.3.1.1.1.2: Sprinklers manufactured prior to 1920 shall be replaced.

5.3.1.1.1.3*: Sprinklers manufactured using fast-response elements that have been in service for 20 years shall be replaced, or representative samples shall be tested and then retested at 10-year intervals.

5.3.1.1.1.4*: Representative samples of solder-type sprinklers with a temperature classification of extra high [325°F (163°C)] or greater that are exposed to semi-continuous to continuous maximum allowable ambient temperature conditions shall be tested at 5-year intervals.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 16 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section 5.3.1.1.1.5: Where sprinklers have been in service for 75 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory acceptable to the authority having jurisdiction for field service testing and repeated at 5-year intervals.

5.3.1.1.1.6*: Dry sprinklers that have been in service for 10 years shall be replaced or representative samples shall be tested and then retested at 10-year intervals.

5.3.1.1.2*: Where sprinklers are subjected to harsh environments, including corrosive atmospheres and corrosive water supplies, on a 5-year basis, either sprinklers shall be replaced or representative sprinkler samples shall be tested.

5.3.1.1.3: Where historical data indicate, longer intervals between testing shall be permitted.

5.3.1.2*: A representative sample of sprinklers for testing per NFPA 25, Section 5.3.1.1.1, shall consist of a minimum of not less than four sprinklers or 1 percent of the number of sprinklers per individual sprinkler sample, whichever is greater.

5.3.1.3: Where one sprinkler within a representative sample fails to meet the test requirement, all sprinklers within the area represented by that sample shall be replaced.

5.3.1.3.1: Manufacturers shall be permitted to make modifications to their own sprinklers in the field with listed devices that restore the original performance as intended by the listing, where acceptable to the authority having jurisdiction.

If loose deposits are identified in the piping, and the evaluation determines that the deposits must be removed, then the piping is required to be flushed repeatedly, in accordance with NFPA 25 Annex D.5, until it is determined that either no deposits are left or that the remaining deposits pose no blockage threat. Areas where excessive deposits are found will undergo more thorough volumetric wall testing to ensure minimum wall thickness is met.

Standpipe and Hose Systems Flow tests 6.3.1 The relevant flow test procedures will be enhanced to ensure the following requirements of NFPA 25, Section 6.3.1 and subsections are met:

6.3.1: Flow Tests.

6.3.1.1*: A flow test shall be conducted [at least] every 5 years at the hydraulically most remote hose connections of each zone of an automatic standpipe system to verify the water supply still provides the design pressure at the required flow.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 17 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section 6.3.1.2: Where a flow test of the hydraulically most remote outlet(s) is not practical, the authority having jurisdiction shall be consulted for the appropriate location for the test.

6.3.1.3: All systems shall be flow tested and pressure tested at the requirements for the design criteria in effect at the time of the installation.

6.3.1.3.1: The actual test method(s) and performance criteria shall be discussed in advance with the authority having jurisdiction.

6.3.1.4: Standpipes, sprinkler connections to standpipes, or hose stations equipped with pressure reducing valves or pressure regulating valves shall have these valves inspected, tested, and maintained in accordance with the requirements of NFPA-25, Chapter 13.

6.3.1.5: A main drain test shall be performed on all standpipe systems with automatic water supplies in accordance with the requirements of NFPA-25, Chapter 13.

6.3.1.5.1: The test shall be performed at the low point drain for each standpipe or the main drain test connection where the supply main enters the building (when provided).

6.3.1.5.2: [Not applicable per NUREG-2191 Table XI.M27-1 Note 9, which states that calibration of measuring and test equipment (i.e., pressure gauges provided for flow tests) can conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.]

Private Fire Service Mains Underground 7.3.1 The relevant test procedure will be enhanced to ensure the following and exposed requirements from NFPA 25, Section 7.3.1 and subsections are met:

piping flow 7.3.1*: Underground and Exposed Piping Flow Tests. Underground and tests exposed piping shall be flow tested to determine the internal condition of the piping at minimum 5-year intervals.

7.3.1.1: Flow tests shall be made at flows representative of those expected during a fire, for the purpose of comparing the friction loss characteristics of the pipe with those expected for the particular type of pipe involved, with due consideration given to the age of the pipe and to the results of previous flow tests.

7.3.1.2: Any flow test results that indicate deterioration of available water flow and pressure shall be investigated to the complete satisfaction of the authority having jurisdiction to ensure that the required flow and pressure are available for fire protection.

7.3.1.3: Where underground piping supplies individual fire sprinkler, standpipe, water spray, or foam-water sprinkler systems and there are no means to conduct full flow tests, tests generating the maximum available flows shall be permitted.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 18 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section Per NUREG-2191 Table XI.M27-1 Note 9, calibration of measuring and test equipment is conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.

Hydrants 7.3.2 The relevant test procedure performs fire hydrant testing/ flushing every 12 months which meets the interval requirements of NUREG-2191, Table XI.M27-1, Note 10. This test ensures that the hydrants and their respective piping systems are functioning properly. This procedure will be enhanced to clarify the other requirements of NFPA 25, Section 7.3.2 subsections:

7.3.2.1: Each hydrant shall be opened fully and water flowed until all foreign material has cleared.

7.3.2.2: Flow shall be maintained for not less than 1 minute. [Procedure already performs this.]

7.3.2.3: After operation, dry barrel and wall hydrants shall be observed for proper drainage from the barrel.

7.3.2.4: Full drainage shall take no longer than 60 minutes.

7.3.2.5: Where soil conditions or other factors are such that the hydrant barrel does not drain within 60 minutes, or where the groundwater level is above that of the hydrant drain, the hydrant drain shall be plugged and the water in the barrel shall be pumped out.

7.3.2.6: Dry barrel hydrants that are located in areas subject to freezing weather and that have plugged drains shall be identified clearly as needing pumping after operation.

If loose deposits are identified in the piping, and the evaluation determines that the deposits must be removed, then the piping is required to be flushed repeatedly, in accordance with NFPA 25 Annex D.5, until it is determined that either no deposits are left or that the remaining deposits pose no blockage threat. Areas where excessive deposits are found will undergo more thorough volumetric wall testing to ensure minimum wall thickness is met.

Per NUREG-2191 Table XI.M27-1 Note 9, calibration of measuring and test equipment is conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.

Fire Pumps Suction 8.3.3.7 N/A screens

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 19 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section Water Storage Tanks Exterior 9.2.5.5 A new procedure will be created to perform visual inspection of the fire inspections water accumulator tank and the supporting structures painted or coated exterior surfaces for signs of degradation on a refueling outage interval, which is in accordance with NFPA 25, Section 9.2.5.5, and NUREG-2191 Table XI.M27-1 Note 10.

Interior 9.2.6, A new procedure will be prepared and implemented to perform an interior inspections inspection of the fire water accumulator tank and/or an existing preventive 9.2.7 maintenance activity will be enhanced to meet the NFPA 25, Sections 9.2.6 and 9.2.7 requirements. This procedure will incorporate the following instructions for the interior inspections of water storage tanks from NUREG-2191, Table XI.M27-1, and NFPA 25, Sections 9.2.6, 9.2.7, and subsections.

Steps with asterisks have additional clarifying information in NFPA 25, Annex A. The required steps and information are as follows:

9.2.6.1.1*: The interior of steel tanks without corrosion protection shall be inspected every 3 years. [Note A.9.2.6.1.1 discusses interior paint/coating, which is a type of corrosion protection applied to the tank.]

9.2.6.1.2: [Not applicable since the tank the fire water accumulator tank interior does have corrosion protection; an interior black galvanized finish.]

9.2.6.2: Where interior inspection is made by means of underwater evaluation, silt shall first be removed from the tank floor.

9.2.6.3: The tank interior shall be inspected for signs of pitting, corrosion, spalling, rot, other forms of deterioration, waste materials and debris, aquatic growth, and local or general failure of interior coating.

9.2.6.4: Steel tanks exhibiting signs of interior pitting, corrosion, or failure of coating shall be tested in accordance with NFPA 25, Section 9.2.7.

9.2.6.5*: Tanks on ring-type foundations with sand in the middle shall be inspected for evidence of voids beneath the floor. [This inspection can be performed by looking for dents on the tank floor. Additionally, walking on the tank floor and looking for buckling of the floor will identify problem areas.]

9.2.6.6: The heating system and components including piping shall be inspected.

9.2.6.7: The anti-vortex plate shall be inspected for deterioration or blockage.

9.2.7: Tests During Interior Inspection. Where a drained interior inspection of a steel tank is required by 9.2.6.4, the following tests shall be conducted:

(1) [Not applicable per NUREG-2191 Table XI.M27-1 Note 4.]

(2) [Not applicable per NUREG-2191 Table XI.M27-1 Note 4.]

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 20 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section (3) Nondestructive ultrasonic readings shall be taken to evaluate the wall thickness where there is evidence of pitting or corrosion.

(4) [Not applicable per NUREG-2191 Table XI.M27-1 Note 4.]

(5) Tank bottoms shall be tested for metal loss and/or rust on the underside by use of ultrasonic testing where there is evidence of pitting or corrosion.

Removal, visual inspection, and replacement of random floor coupons shall be an acceptable alternative to ultrasonic testing.

(6) Tanks with flat bottoms shall be vacuum-box tested at bottom seams in accordance with test procedures found in NFPA 22, Standard for Water Tanks for Private Fire Protection.

NUREG-2191 Table XI.M27-1 Note 4 is in regard to NFPA 25 Sections 9.2.6.4 and 9.2.7: When degraded coatings are detected, the acceptance criteria and corrective action recommendations in GALL-SLR Report AMP XI.M42 are followed in lieu of Section 9.2.7 (1), (2), and (4). When interior pitting or general corrosion (beyond minor surface rust) is detected, tank wall thickness measurements are conducted as stated in NFPA 25 Section 9.2.7 (3) in the vicinity of the loss of material. Vacuum box testing as stated in Section 9.2.7 (6) is conducted when pitting, cracks, or loss of material is detected in the immediate vicinity of welds.

Additionally, per NUREG-2191 Table XI.M27-1, calibration of measuring and test equipment is conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 21 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section Water Spray Fixed Systems Strainers 10.2.1.6, These functional test procedures are performed at least every 18 months (after each (based on the refueling outage interval, but not necessarily during refueling system 10.2.1.7, outages), which meets the interval requirements of NUREG-2191, Table actuation) 10.2.7 XI.M27-1, Note 10.

The relevant procedures will be enhanced to meet the inspection, flushing, and parts replacement and repair requirements of NFPA 25, Sections 10.2.1.7, 10.2.7, and associated subsections. These enhancements include flushing the mainline strainers until clear after each operation or flow test, inspecting and cleaning the strainers in accordance with the manufacturers instructions, and replacing or repairing damaged or corroded parts.

10.2.1.6: Nozzle strainers [where applicable] shall be removed, inspected, and cleaned during the flushing procedure for the mainline strainer.

10.2.1.7: Mainline strainers shall be removed and inspected [at least] every 5 years for damaged and corroded parts.

10.2.7* Strainers.

10.2.7.1: Mainline strainers (basket or screen) shall be flushed until clear after each operation or flow test.

10.2.7.2: Individual water spray nozzle strainers [where applicable] shall be removed, cleaned, and inspected after each operation or flow test.

10.2.7.3: All strainers shall be inspected and cleaned in accordance with the manufacturers instructions.

10.2.7.4: Damaged or corroded parts shall be replaced or repaired.

Operation 10.3.4.3 The relevant functional test procedures are performed at least every 18 test months (based on the refueling outage interval, but not necessarily during (refueling refueling outages), which meets the interval requirements of NUREG-2191, outage Table XI.M27-1, Note 10. The procedures test open head spray nozzles with interval) water and meet the NFPA 25, Section 10.3.4.3.1 requirement by ensuring that spray patterns are not impeded by plugged nozzles, that nozzles are correctly positioned, and that obstructions do not prevent discharge patterns from wetting surfaces to be protected. The procedures also meet the requirements of NFPA 25, Section 10.3.4.3.2 to retest systems after cleaning if obstructions are found.

10.3.4.3* Discharge Patterns.

10.3.4.3.1* The water discharge patterns from all of the open spray nozzles shall be observed to ensure that patterns are not impeded by plugged nozzles, to ensure that nozzles are correctly positioned, and to ensure that obstructions do not prevent discharge patterns from wetting surfaces to be protected.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 22 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section 10.3.4.3.1.1 Where the nature of the protected property is such that water cannot be discharged, the nozzles shall be inspected for proper orientation and the system tested with air to ensure that the nozzles are not obstructed.

10.3.4.3.2 Where obstructions occur, the piping and nozzles shall be cleaned and the system retested.

The procedures will be annotated to credit existing steps for the above NFPA requirements and enhanced to state that if loose deposits are identified in the piping, and the evaluation determines that the deposits must be removed, then the piping is required to be flushed repeatedly, in accordance with NFPA 25 Annex D.5, until it is determined that either no deposits are left or that the remaining deposits pose no blockage threat. Areas where excessive deposits are found will undergo more thorough volumetric wall testing to ensure minimum wall thickness is met.

Foam Water Sprinkler Systems Strainers 11.2.7.1 N/A Operational 11.3.2.6 N/A Test Discharge patterns Storage Visual N/A tanks inspection for internal corrosion Valves and System-Wide Testing Main drain 13.2.5 Existing fire water system flow testing/flushing procedures will be revised to test incorporate the following instructions and requirements for the fire main drain test from NFPA 25, Section 13.2.5 and subsections. Steps with asterisks have additional clarifying information in NFPA 25, Annex A. These functional test procedures are performed at least every 18 months (based on the refueling outage interval, but not necessarily during refueling outages),

which meets the interval requirements of NUREG-2191, Table XI.M27-1, Note 10.

The required steps and information are as follows:

13.2.5*: A main drain test shall be conducted [at least on a refueling outage interval (i.e., every 18 months)] at each water-based fire protection system riser to determine whether there has been a change in the condition of the water supply piping and control valves and any time the control valve is closed and reopened at system riser.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 23 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section 13.2.5.1: In systems where the sole water supply is through a backflow preventer and/or pressure reducing valves, the main drain test of at least one system downstream of the device shall be conducted on a quarterly basis.

13.2.5.2: When there is a 10 percent reduction in full flow pressure when compared to the original acceptance test or previously performed tests, the cause of the reduction shall be identified and corrected if necessary.

Per NUREG-2191 Table XI.M27-1, the following notes also apply:

x Items in areas that are inaccessible because of safety considerations such as those raised by continuous process operations, radiological dose, or energized electrical equipment are inspected during each scheduled shutdown but not more often than every refueling outage interval.

x Calibration of measuring and test equipment is conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.

Obstruction Investigation Obstruction, 14.2, A new procedure will be prepared and implemented to incorporate the Internal following instructions and requirements for internal inspection of piping and Inspection of 14.3 obstruction investigation from NFPA 25, Sections 14.2, 14.3, and Piping subsections. Steps with asterisks have additional clarifying information in NFPA 25, Annex A. The required steps and information are as follows:

14.2: Internal Inspection of Piping.

14.2.1: Except as discussed in 14.2.1.1 and 14.2.1.4 below, an inspection of piping and branch line conditions shall be conducted every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material.

14.2.1.1: Alternative nondestructive examination methods [that can ensure that flow blockage will not occur] shall be permitted.

14.2.1.2: Tubercules or slime, if found, shall be tested for indications of microbiologically influenced corrosion (MIC).

14.2.1.3*: If the presence of sufficient foreign organic or inorganic material is found to obstruct pipe or sprinklers, an obstruction investigation shall be conducted as described in Section 14.3.

14.2.1.4: Non-metallic pipe shall not be required to be inspected internally.

14.2.1.5: In dry pipe systems and pre-action systems, the sprinkler removed for inspection shall be from the most remote branch line from the source of water that is not equipped with the inspectors test valve.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 24 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section 14.2.1.6*: Inspection of a cross main is not required where the system does not have a means of inspection.

14.2.2*: In buildings having multiple wet pipe systems, every other system shall have an internal inspection of piping every 5 years as described in 14.2.1 above.

14.2.2.1: During the next inspection frequency required by 14.2.1 above, the alternate systems not inspected during the previous inspection shall have an internal inspection of piping as described in 14.2.1.

14.2.2.2: If the presence of foreign organic and/or inorganic material is found in any system in a building during the 5 year internal inspection of piping, all systems shall have an internal inspection.

14.3: Obstruction Investigation and Prevention.

14.3.1*: An obstruction investigation shall be conducted for system or yard main piping wherever any of the following conditions exist:

(1) Defective intake for fire pumps taking suction from open bodies of water (2) The discharge of obstructive material during routine water tests (3) Foreign materials in fire pumps, in dry pipe valves, or in check valves (4)*Foreign material in water during drain tests or plugging of inspectors test connection(s)

(5) Plugged sprinklers (6) Plugged piping in sprinkler systems dismantled during building alterations (7) Failure to flush yard piping or surrounding public mains following new installations or repairs (8) A record of broken public mains in the vicinity (9) Abnormally frequent false tripping of a dry pipe valve(s)

(10) A system that is returned to service after an extended shutdown (greater than 1 year)

(11) There is reason to believe that the sprinkler system contains sodium silicate or highly corrosive fluxes in copper systems (12) A system has been supplied with raw water via the fire department connection (13) Pinhole leaks

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 25 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

(14) A 50 percent increase in the time it takes water to travel to the inspectors test connection from the time the valve trips during a full flow trip test of a dry pipe sprinkler system when compared to the original system acceptance test.

14.3.2*: Systems shall be examined for internal obstructions where conditions exist that could cause obstructed piping.

14.3.2.1: If the condition has not been corrected or the condition is one that could result in obstruction of the piping despite any previous flushing procedures that have been performed, the system shall be examined for internal obstructions every 5 years.

14.3.2.2: Internal examination shall be performed at the following four points:

(1) System valve (2) Riser (3) Cross main (4) Branch line 14.3.2.3: Alternative nondestructive examination methods [that can ensure that flow blockage will not occur] shall be permitted.

14.3.3*: If an obstruction investigation indicates the presence of sufficient material to obstruct pipe or sprinklers, a complete flushing program shall be conducted by qualified personnel. [For obstruction investigation flushing procedures, see NFPA 25 Annex D.5.]

If loose deposits are identified in the piping, and the evaluation determines that the deposits must be removed, then the piping is required to be flushed repeatedly, in accordance with NFPA 25 Annex D.5, until it is determined that either no deposits are left or that the remaining deposits pose no blockage threat. Areas where excessive deposits are found will undergo more thorough volumetric wall testing to ensure minimum wall thickness is met.

Per NUREG-2191 Table XI.M27-1, the following notes also apply:

x Items in areas that are inaccessible because of safety considerations such as those raised by continuous process operations, radiological dose, or energized electrical equipment are inspected during each scheduled shutdown but not more often than every refueling outage interval.

x Calibration of measuring and test equipment is conducted in accordance with plant-specific procedures in lieu of NFPA 25 requirements.

Additionally, the new procedure will specify that portions of water-based fire protection system components that have been wetted but are normally dry, such as dry-pipe or preaction sprinkler system piping and valves, are subjected to augmented testing and inspections beyond those of NUREG-2191 Table XI.M27-1. The augmented tests and inspections are conducted on piping segments that cannot be drained or piping segments that allow water to collect:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 26 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section x In each 5-year interval, beginning 5 years prior to the SPEO, either conduct a flow test or flush sufficient to detect potential flow blockage, or conduct a visual inspection of 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect.

x In each 5-year interval of the SPEO, 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect is subject to volumetric wall thickness inspections.

Measurement points are obtained to the extent that each potential degraded condition can be identified (e.g., general corrosion, MIC). The 20 percent of piping that is inspected in each 5-year interval is in different locations than previously inspected piping.

x If the results of a 100-percent internal visual inspection are acceptable, and the segment is not subsequently wetted, no further augmented tests or inspections are necessary.

General General N/A The relevant procedure will be revised to ensure the following actions are performed:

x Inspections and tests shall be performed by personnel qualified in accordance with site procedures and programs to perform the specified task. The inspections and tests shall follow site procedures that include inspection parameters for items such as lighting, distance offset, presence of protective coatings, and cleaning processes.

x Sprinkler heads shall either be replaced or tested in accordance with NFPA 25 prior to exceeding their 50 year service life. If the sprinkler heads are not replaced, the required testing will be repeated at 10 year intervals.

x If the environmental (e.g., type of water, flowrate, temperature) and material that exist on the interior surface of the underground and buried fire protection piping are similar to the conditions that exist within the above grade fire protection piping, the results of the inspections of the above grade fire protection piping will be extrapolated to evaluate the condition of buried and underground fire protection piping for the purpose of identifying inside diameter loss of material.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 27 of 29 SLRA Section B.2.3.16, page B-131 revision continued:

Description NFPA 25 Required Enhancements Section General N/A The relevant procedure will be revised to incorporate the methodology for extending fire protection surveillance frequencies consistent with EPRI Report 1006756, NEIL Loss Control Standards, and NRC guidance as follows:

x The data collection guidelines in the procedure follow the NEIL guidelines for historic reliability calculations and that the number of years prior to the SPEO, from which data would be collected for modifying test and inspection frequencies, is determined based on the current surveillance intervals under evaluation. Surveillances up to quarterly require 2 years of data, surveillances performed in the range of quarterly up to annually require 3 years of data, and surveillances performed in the range of annually require up to fuel cycle require 5 years of data.

x The data collection guidelines include the bounding recommendations for sample size from EPRI Report 1006756. To modify test and inspection frequencies, a minimum sample size of 100 independent samples is recommended. This amount of data will ensure low uncertainty and avoid excessive failure sensitivity. A sample size of 100 is a desired lower limit, but the analysis can be done with fewer points if a small number of components are involved.

x The use of performance data to modify surveillance intervals is based on the current length of the surveillance interval. The fire water accumulator tank external visual inspection interval can be changed (lengthened) upon successful evaluation of past inspection results and concurrence by NEIL. Performance data will not be used to modify the following surveillances, since their prescribed intervals are greater than two times the refueling interval: fire water accumulator tank volumetric and internal tests and inspections, underground flow tests, and inspections of normally dry but periodically wetted piping that will not drain due to the respective piping configuration.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 28 of 29 SLRA Section B.2.3.16, page B-132 is revised as follows:

determined to be a buildup of corrosion products.

(Reference ML113050425).

x In March 2012, the staff and licensee personnel found that a portion of the internally galvanized piping of a 6-inch preaction sprinkler system could not be properly drained because the drainage points were located on a smaller diameter pipe that tied into the side of the 6-inch pipe. A boroscopic inspection of the lower portions of the pipe showed that it contained residual water, that the galvanizing had been removed, and that significant quantities of corrosion products were present whereas in the upper dry portions, the galvanized coating was still intact. (Information Notice 2013-06).

Plant Specific Operating Experience Between 2010 and 2020, several action requests (ARs) were initiated to evaluate and/or correct degradation or programmatic issues related to the PBN fire water system.

x In November 2012, the north and south fire protection supply headers were constantly submerged in water and exhibited surface corrosion at the above ground to below ground transition pits inside the pumphouse. A determination was made that the exterior should be examined, then cleaned and coated and a work order was initiated to perform the corrective action. In January 2019, water was once again identified in these fire protection piping chases, and another work order was initiated to pump out the chase and perform a repair.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 14 Page 29 of 29 x In March 2013, in response to an NRC Information Notice, IN 2013-06, involving the loss of function of fire protection sprinkler systems with the potential for air-water interactions at a different plant, an AR was initiated.

Based on the review of NRC IN 2013-06, there were two location fire water piping systems susceptible to the wet-dry cycle that could not be tested for flow blockage through the nozzles (the gas turbine building and low voltage auxiliary transformers suppression system and the warehouse

2 suppression system) and these locations piping systems were evaluated. The warehouse #2 suppression system was opened and inspected by a work order in April 2014 and the internal piping was determined to be satisfactory with little to no wear within the piping and no head blockage. An additional action request was issued to perform future inspections of warehouse #2 dry system branches as applicable.

A section of normally dry pre-action piping was determined to potentially have water causing internal corrosion at a low point. As a result of the evaluation, a preventive maintenance activity was generated to routinely inspect the branch section of piping. A low point on the pre-action system for the gas turbine building and low voltage auxiliary transformers was subsequently drained and internally inspected. Two to three gallons of water were drained and the piping was observed to have a normal amount of internal wear/corrosion. A recent walkdown determined there were several additional low points, therefore, a new action request was issued to perform future inspections of the gas turbine building and low voltage auxiliary transformers dry system branches as applicable.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 15 Page 1 of 3 Outdoor and Large Atmospheric Metallic Storage Tanks: Clarified Enhancement for Inspecting Refueling Water Storage Tanks Affected SLRA Sections: Table 16-3 (Appendix A, Section 16.4), B.2.3.17 SLRA Page Numbers: A-80, B-136 Description of Change:

The PBN Outdoor and Large Atmospheric Metallic Storage Tanks AMP will perform both internal and external surface examinations of the Refueling Water Storage Tanks (RWSTs).

The exterior surface examinations of the of the Refueling Water Storage Tanks (RWSTs) are addressed by the following enhancement bullet:

x Direct periodic (10-year) surface examination of an RWSTs external surface for evidence of cracking, with insulation removed, at the locations most susceptible to degradation and leakage.

In order to clearly align with GALL-SLR Section XI.M29, the PBN Outdoor and Large Atmospheric Metallic Storage Tanks AMP is updated to clarify that the enhancement for inspecting an RWSTs nonwetted surface includes internal visual inspections as well as internal surface examinations.

Accordingly, SLRA Section 16.4, Table 16-3 (Item 21), and Section B.2.3.17 are revised to clarify that the inspections of an RWSTs nonwetted surface includes internal visual inspections and internal surface examinations.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 15 Page 2 of 3 SLRA Appendix A, Section 16.4, Table 16-3 (Item 21), page A-80 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Management Section Schedule Program or Activity (Section) o PBN One-Time Inspection AMP; o PBN Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks AMP.

x Direct periodic (every refueling outage) visual inspection of FOST to concrete caulking/sealants, with mechanical manipulation as appropriate.

x Direct periodic (10-year) surface examination of an RWSTs external surface for evidence of cracking, with insulation removed, at the locations most susceptible to degradation and leakage.

x Direct periodic (10-year) bottom thickness measurement of an RWST and the RMWT using low-frequency electromagnetic testing (LFET) techniques with follow-on ultrasonic testing (UT) examination, as necessary, at discrete tank locations identified by LFET.

x Direct periodic (10-year) visual inspections and surface examinations of an RWSTs internal nonwetted surface for evidence or loss of material and cracking. If evidence of cracking is identified, then a surface examination is also performed to determine the extent of the cracking. For the RMWT, direct periodic (10-year) visual inspections of the RMWT interior above the diaphragm for evidence of loss of material.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 15 Page 3 of 3 SLRA Section B.2.3.17, page B-136 is revised as follows:

Element Affected Enhancement o PBN Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks AMP.

x Direct periodic (every refueling outage) visual inspection of FOST to concrete caulking/sealants, with mechanical manipulation as appropriate.

x Direct periodic (10-year) surface examination of an RWSTs external surface for evidence of cracking, with insulation removed, at the locations most susceptible to degradation and leakage.

x Direct periodic (10-year) bottom thickness measurement of an RWST and the RMWT using low-frequency electromagnetic testing (LFET) techniques with follow-on ultrasonic testing (UT) examination, as necessary, at discrete tank locations identified by LFET.

x Direct periodic (10-year) visual inspections and surface examinations of an RWSTs internal nonwetted surface for evidence or loss of material and cracking. If evidence of cracking is identified, then a surface examination is also performed to determine the extent of the cracking. For the RMWT, direct periodic (10-year) visual inspections of the RMWT interior above the diaphragm for evidence of loss of material.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 16 Page 1 of 3 Selective Leaching AMR Results: Added Ductile Iron Piping Affected SLRA Sections: 3.3.2.1.6 and Table 3.3.2-6 SLRA Page Numbers: 3.3-8, 3.3-9 and 3.3-183 Description of Change:

Ductile iron piping is installed at Point Beach in the fire protection system. Section 3.3.2.1.6 of the SLRA is updated to include ductile iron. SLRA Table 3.3.2-6 is revised to include ductile iron exposed to uncontrolled indoor air, outdoor air, concrete, raw water, and soil.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 16 Page 2 of 3 SLRA Section 3.3.2.1.6, pages 3.3-8 and 3.3-9 are revised as follows:

3.3.2.1.6 Fire Protection Materials The materials of construction for the fire protection system components are:

Carbon steel

CASS

Coating (cementitious)

Copper alloy

Copper alloy >15% Zn

Ductile iron

Glass

Gray cast iron

Neoprene

Stainless steel

Steel

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 16 Page 3 of 3 SLRA Table 3.3.2-6, page 3.3-183 is revised as follows:

Table 3.3.2-6: Fire Protection System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Piping Pressure Ductile iron Air - indoor Loss of External Surfaces VII.I.A-77 3.3-1, A boundary uncontrolled material Monitoring of Mechanical 078 (ext) Components (B.2.3.23)

Piping Pressure Ductile iron Air - outdoor Loss of External Surfaces VII.I.A-77 3.3-1, A boundary (ext) material Monitoring of Mechanical 078 Components (B.2.3.23)

Piping Pressure Ductile iron Concrete (ext) Loss of Buried and Underground VII.I.AP-198 3.3-1, B boundary material Piping and Tanks 109 (B.2.3.27)

Piping Pressure Ductile iron Raw water (int) Long-term One-Time Inspection VII.G.A-532 3.3-1, A boundary loss of (B.2.3.20) 193 material Piping Pressure Ductile iron Raw water (int) Loss of Selective Leaching VII.G.A-51 3.3-1, A boundary material (B.2.3.21) 072 Piping Pressure Ductile iron Raw water (int) Loss of Fire Water System VII.G.A-33 3.3-1, A boundary material (B.2.3.16) 064 Flow blockage Piping Pressure Ductile iron Raw water (int) Wall thinning Fire Water System VII.C1.A-409 3.3-1, E, 1 boundary - erosion (B.2.3.16) 126 Piping Pressure Ductile iron Soil (ext) Cracking Buried and Underground VII.I.A-425 3.3-1, B boundary Piping and Tanks 144 (B.2.3.27)

Piping Pressure Ductile iron Soil (ext) Loss of Buried and Underground VII.I.AP-198 3.3-1, B boundary material Piping and Tanks 109 (B.2.3.27)

Piping Pressure Ductile iron Soil (ext) Loss of Selective Leaching VII.G.A-02 3.3-1, A boundary material (B.2.3.21) 072

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 17 Page 1 of 3 One-Time Inspection Small Bore Piping AMP: Clarified to Add a New Procedure to the Existing Program Affected SLRA Sections: B.2.3.22 SLRA Page Numbers: B-165, B-168 Description of Change:

The PBN ASME Code Class 1 Small-Bore Piping AMP is an existing AMP. Even though enhancements to this AMP include the creation of a new procedure, this program is existing at PBN and has been implemented as augmented inspections through the ASME Section XI, Inservice Inspection AMP.

The PBN ASME Code Class 1 Small-Bore Piping AMP is updated to clarify that this AMP is both an existing program but also requires a new, stand-alone procedure to implement separate from the ISI AMP. Accordingly, SLRA Section B.2.3.22 will be revised to include this clarification.

In addition, the operating experience discussion in Section B.2.3.22 is revised to address a revision to Information Notice (IN) 2007-21, published December 11, 2020, which identified flow-induced vibration that caused abrasive wear between stainless steel reflective metal insulation end caps and ASME Class 1 piping.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 17 Page 2 of 3 SLRA Section B.2.3.22, page B-165 is revised as follows:

B.2.3.22 ASME Code Class 1 Small-Bore Piping Program Description The PBN ASME Code Class 1 Small-Bore Piping AMP is an existing condition monitoring program for detecting cracking in small-bore, ASME Code Class 1 piping.

This AMP previously augmenteds the ISI program specified by ASME Code,Section XI, Sections IWB, IWC, and IWD (Section B.2.3.1) for first license renewal, and will be enhanced to create a new procedure in support of subsequent license renewal., for certain ASME Code Class 1 piping that is less than 4 inches nominal piping size (NPS) and greater than or equal to 1 inch NPS, and manages the effects of SCC and cracking due to thermal or vibratory fatigue loading. This AMP manages the effects of SCC and cracking due to thermal or vibratory fatigue loading for certain ASME Code Class 1 piping that is less than 4 inches nominal pipe size (NPS) and greater than or equal to 1 inch NPS, inspects ASME Code Class 1 small-bore piping locations that are susceptible to cracking and inspects full penetration (butt) and partial penetration (socket) welds. This AMP also includes measures to verify that degradation is not occurring, thereby confirming that there is no need to manage age-related degradation.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 17 Page 3 of 3 SLRA Section B.2.3.22, page B-168 is revised as follows:

The results of the destructive examination for the cold leg drain pipe concluded that the crack-like indications were defects associated with tearing or deformation of the inner surface that occurred during fabrication. The cracks were not induced by thermal fatigue.

x Peach Bottom Atomic Power Station (PBAPS): One Class 1 small-bore piping crack and leak at a socket weld on Unit 3 in 2005 (LER 03-05-03),

and another Class 1 small-bore piping crack and leak at a socket weld on Unit 3 in 2017 (LER 3-17-001). There have been no other Class 1 small-bore piping cracking or leak issues during the Unit 3 operating history.

There have been no Class 1 small-bore piping cracking or leak issues during the Unit 2 operating history.

x Information Notice (IN) 2007-21 Supplement 1, Piping wear due to interaction of flow-induced vibration and reflective metal insulation was published December 2020. The supplement to this IN updated abrasive wear between stainless steel reflective metal insulation (RMI) end caps and ASME Class 2 piping found in Catawba to also include industry OE from other sites that identified similar RMI fretting of Class 1 piping. PBN evaluated this recent industry OE in February 2021, concluding that RMI is used on Class 1 piping, when required, per the insulation design specification.

The specification states Insulation shall be installed, designed, and attached such that normal vibration will not cause deterioration or damage. However, given this recent industry OE, the initial phase of dispositioning this issue at PBN involves a walkdown and inspection of containment piping to determine where RMI is located and to open and inspect areas of concern. Unit 1 is scheduled for inspection during the Spring 2022 refueling outage, and Unit 2 is scheduled for inspection during the Fall 2021 refueling outage.

Since any cracking or leakage from Class 1 reactor coolant pressure boundary components would be required to be reported to the NRC per 10 CFR 50.73(a)(2), a review of all License Event Reports (LERs) was performed using keyword searches (crack and Class 1). The review identified 30 LERs, 4 of which were actually related to Class 1 small-bore piping from the past 20 years.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 1 of 8 Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components:

Revised Further Evaluation, AMR Results, and AMP Affected SLRA Sections: Table 3.2.2-3, Table 3.3-1, Table 3.3.2-5, 16.2.2.25, B.2.3.25 SLRA Page Numbers: 3.2-69, 3.3-41, 3.3-80, 3.3-158, A-30, B-184 Description of Change:

Eddy current testing is performed on the residual heat removal (RHR) heat exchanger tubes due to plant specific operating experience. Subsequent license renewal application (SLRA)

Table 3.2.2-3 is revised to include cracking as an aging effect in addition to loss of material for aging effects that are managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program (AMP).

Steel piping is exposed to condensation in the Auxiliary Systems. Item number 3.3-1, 055 is revised to clarify that this item is not used for steel piping in the Auxiliary Systems. Those components are addressed by item number 3.3-1, 249.

There are no elastomer, fiberglass, or high density polyethylene (HDPE) piping and piping components exposed to waste water in the Auxiliary Systems. However, there are metallic piping and piping components exposed to waste water. Item number 3.3-1, 258 has been revised to clarify that this item number is not used for metallic piping and piping components exposed to waste water. Those components are addressed by item numbers 3.3-1, 091 and 3.3-1, 095.

The boric acid waste evaporator heat exchanger service water side could experience flow blockage that could affect the service water system. SLRA Table 3.3.2-5 is revised to include flow blockage as an applicable aging effect for the end bell, tubesheet, and tubes.

The Point Beach (PBN) Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP manages cracking in the copper alloy (>15% zinc) waste gas compressor heat exchanger tubes and tubesheets, and orifices exposed to a waste water environment. The PBN Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP, as described in SLRA Section B.2.3.25 of Appendix B and Section 16.2.2.25 of Appendix A, specifically mentions that the program manages cracking in stainless steel and aluminum components, and does not mention that the program also manages cracking of copper alloy components. Accordingly, SLRA Section 16.2.2.25 in Appendix A and Section B.2.3.25 in Appendix B are being revised to include copper alloy (> 15 percent zinc) as a material being managed for cracking.

The PBN Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP manages loss of material in the RHR heat exchanger tubes using eddy current testing (ECT) based on plant specific operating experience (Table 3.2.2-3; Plant Specific Note 1; pages 3.2-70 and 3.2-80 of the PBN SLRA). The PBN Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP, as described in SLRA Section 16.2.2.25 of Appendix A, specifically mentions that surface examinations or American Society of Mechanical Engineers (ASME) Code Section XI VT-1 examinations will be conducted to detect cracking of stainless

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 2 of 8 steel and aluminum components. ECT is a method for performing surface examinations.

Accordingly, SLRA Section 16.2.2.25 in Appendix A is being revised to include loss of material among the aging effects that are managed with surface examinations or ASME Code Section XI VT-1 examinations.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 3 of 8 SLRA Table 3.2.2-3, page 3.2-69 is revised as follows to add the following row:

Table 3.2.2-3: Residual Heat Removal - Summary of Aging Management Evaluation Component Intended Function Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Type Requiring Management Item Item Management Program Heat Pressure Stainless Treated Cracking Inspection of V.D1.E-12 3.2-1, 020 E, 1 exchanger boundary steel borated water Internal Surfaces (RHR tubes) >140°F (int) in Miscellaneous Piping and Ducting Components (B.2.3.25)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 4 of 8 SLRA Table 3.3-1, page 3.3-41 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 055 Steel piping, piping Loss of material due to AMP XI.M38, No Not applicable.

components, tanks general, pitting, crevice "Inspection of Internal There are no steel piping, piping exposed to corrosion Surfaces in Miscellaneous components, tanks exposed to condensation Piping and Ducting condensation in the Auxiliary Systems.

Components" Not used.

Steel piping exposed to condensation in the Auxiliary Systems is addressed by line item 3.3-1, 249.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 5 of 8 SLRA Table 3.3-1, page 3.3-80 is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 258 Metallic, elastomer, Flow blockage due to AMP XI.M38, No Not applicable.

fiberglass, HDPE fouling "Inspection of Internal There are no metallic, elastomer, piping, piping Surfaces in Miscellaneous fiberglass, HDPE piping, piping components exposed Piping and Ducting components exposed to waste water in to waste water Components" the Auxiliary Systems.

Not used.

There are no elastomer, fiberglass, or HDPE piping or piping components exposed to waste water in the Auxiliary Systems.

There are metallic components exposed to waste water and are address by line items 3.3-1, 091 and 3.3-1, 095.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 6 of 8 SLRA Table 3.3.2-5, page 3.3-158 is revised as follows:

Table 3.3.2-5: Service Water System - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Function Requiring Management Item Item Management Program Heat exchanger Pressure Stainless Raw water (int) Loss of material Inspection of Internal VII.C1.A-727 3.3-1, 134 A (boric acid waste boundary steel Flow blockage Surfaces in evaporator vacuum Miscellaneous Piping system end bell, and Ducting tubesheet, tubes) Components (B.2.3.25)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 7 of 8 SLRA Appendix A, Section 16.2.2.25, page A-30 is revised as follows:

16.2.2.25. Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components The PBN Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP is a new AMP that will manage loss of material, cracking, reduction of heat transfer due to fouling, flow blockage, and hardening or loss of strength of polymeric materials. Applicable environments will include air, gas, condensation, diesel exhaust, water, fuel oil, and lubricating oil. Some inspections and activities within the scope of the new AMP were previously performed by the PBN Periodic Surveillance and Preventive Maintenance Program.

The AMP will consist of visual inspections of accessible internal surfaces of piping, piping components, ducting, heat exchanger components, polymeric and elastomeric components, and other components. Surface examinations or ASME Code Section XI VT-1 examinations will be conducted to detect cracking and loss of material of stainless steel, copper alloy (>15 percent zinc), and aluminum components. Aging effects associated with items (except for elastomers) within the scope of the PBN Open-Cycle Cooling Water AMP, the PBN Closed Treated Water Systems AMP, and the PBN Fire Water System AMP are not managed by this AMP.

This AMP will not manage components in which recurring internal corrosion is evident based on a search of site-specific OE conducted during the SLRA development.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 18 Page 8 of 8 SLRA Section B.2.3.25, page B-184 is revised as follows:

Inspections not conducted in accordance with ASME Code Section XI requirements are conducted in accordance with plant-specific procedures including inspection parameters such as lighting, distance, offset and surface conditions. Acceptance criteria are such that the component will meet its intended function until the next inspection or the end of the SPEO. Qualitative acceptance criteria are clear enough to reasonably assure a singular decision is derived based on observed conditions.

Corrective actions are performed as required based on the inspections results.

This AMP is also used to manage cracking due to stress corrosion cracking (SCC) in aluminum, copper alloy (>15 percent zinc), and stainless steel (SS) components exposed to aqueous solutions and air environments containing halides. This AMP is not used to manage components where visual inspection of internal surfaces is not possible unless specific volumetric inspections are performed as noted above.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 1 of 18 Buried and Underground Piping and Tanks: Revised Further Evaluations, AMR Results, and AMP Affected SLRA Sections: Section 3.3.2.1.8; Table 3.3-1; Table 3.3.2-6; Table 3.3.2-8; Section 16.2.2.27 (Appendix A); Table 16-3 (Appendix A, Section 16.4); Section B.2.3.23; Section B.2.3.27 SLRA Page Numbers: 3.3-12, 3.3-42, 3.3-51, 3.3-177, 3.3-183, 3.3-190, 3.3-222, A-32, A-91, A-96, A-97, A-98, A-99, B-174, B-196, B-197, B-198, B-199 Description of Change:

The emergency diesel generator (EDG) fuel oil storage tanks are located in the underground vault portion of the diesel generator building and the emergency fuel oil storage tank is partially located in the fuel oil pumphouse and partially buried. Therefore, none of these tanks are in contact with an air-to-soil interface. Subsequent License Renewal Application (SLRA) Section 3.3.2.1.8 is revised to include underground as an applicable environment for all of these tanks and concrete is added as an external environment for the emergency fuel oil storage tank for the portion of the tank that touches concrete before it transitions from underground to buried.

SLRA Tables 3.3-1 and Table 3.3.2-8 are revised to reflect that the underground portion of the EDG fuel oil storage tanks and emergency fuel oil tank are subject to loss of material and are managed by the Buried and Underground Piping and Tanks Aging Management Program (AMP). The concrete portion of the emergency fuel oil storage tank is subject to loss of material and cracking and is managed by the Buried and Underground Piping and Tanks AMP.

Fire protection supply piping has been found to be submerged at the above ground to below ground transition pits inside the pumphouse. This condition has been reoccurring so an external raw water environment is added to the ductile iron piping and carbon steel bolting in the fire protection system in SLRA Table 3.3.2-6.

The Buried and Underground Piping and Tanks AMP Commitments need to acknowledge that a change in future plant-specific conditions can result in a change to the applicability of the currently selected NUREG-2191 Table XI.M41-2 Preventive Action Category, which would require a higher number of inspections. In order to clearly align with NUREG-2191 Section XI.M41, the Buried and Underground Piping and Tanks AMP Appendix A and Appendix B Commitments and enhancements are updated to clarify that although Preventive Action Category C is currently applicable, a change in plant-specific conditions would result in a reevaluation of the Preventive Action Category.

The cathodic protection system acceptance criteria alternative to the -850 mV instant-off criterion required additional clarification or removal. Based on further review, the alternative acceptance criteria will not be used for SLR. Therefore, the SLRA is updated to clarify the cathodic protection system acceptance criteria and remove discussion of the alternative cathodic protection system acceptance criteria.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 2 of 18 To ensure excessive voltage from the cathodic protection system does not damage the buried piping, an additional Commitment is added to utilize a limiting critical potential of -1,200 mV for non-aluminum buried piping, similar to that recommended for aluminum in NACE SP0169-2007, Control of External Corrosion on Underground or Submerged Metallic Piping Systems, Section 6.2.3.2.1. Therefore, the SLRA is revised to include a limiting critical potential of -1,200 mV for non-aluminum buried piping.

A typographical error within the Appendix B enhancements table for the Buried and Underground Piping and Tanks AMP is now corrected. To make the SLRA enhancements consistent with the listed exception, the SLRA enhancement is updated to list NACE SP0169-2013 rather than NACE SP0169 2016.

Accordingly, SLRA Sections 3.3.2.1.8, 16.2.2.27, B.2.3.23, and B.2.3.27 and Tables 3.3-1, 3.3.2-6, 3.3.2-8, and 16-3 are being revised to ensure the material-environment-aging effect combinations associated with buried and underground piping and tanks are adequately managed, to ensure cathodic protection acceptance criteria and voltage are clear and appropriate, and to ensure that no discrepancies exist between the AMP exception and enhancements.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 3 of 18 Section 3.3.2.1.8, page 3.3-12 is revised as follows:

Environments The emergency power system components are exposed to the following environments:

Air - dry

Air - indoor uncontrolled

Air - outdoor

Concrete

Diesel exhaust

Fuel oil

Lubricating oil

Raw water

Soil

Treated water

Underground

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 4 of 18 SLRA Table 3.3-1, pages 3.3-42 and 3.3-51 are revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 064 Steel, copper alloy Loss of material due to AMP XI.M27, No Consistent with NUREG-2191. The piping, piping general (steel; copper "Fire Water System" Fire Water System (B.2.3.16) AMP is components exposed alloy in raw water and used to manage loss of material and to raw water, treated raw water (potable) flow blockage of steel and copper alloy water, raw water only), pitting, crevice piping and piping components exposed (potable) corrosion, MIC; flow to raw water. In addition, the External blockage due to fouling Surfaces Monitoring of Mechanical (raw water; raw water Components (B.2.3.23) AMP is used (potable) for steel only) to manage loss of material for the piping that may be subject to periodic submergence.

3.3-1, 109 Steel piping, piping Loss of material due to AMP XI.M41, "Buried No Consistent with NUREG-2191 with components, closure general, pitting, crevice and Underground Piping and exception. The Buried and bolting exposed to corrosion, MIC (soil Tanks" Underground Piping and Tanks soil, concrete, only) (B.2.3.27) AMP is used to manage loss underground of material in steel piping, piping components, and closure bolting exposed to soil, underground, or concrete.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 5 of 18 SLRA Table 3.3.2-6, pages 3.3-177, 3.3-183, and 3.3-190 are revised as follows:

Table 3.3.2-6: Fire Protection System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Bolting Mechanical Carbon steel Raw water (ext) Loss of Bolting Integrity (B.2.3.9) VII.I.A-423 3.3-1, A closure material 142 Bolting Mechanical Carbon steel Raw water (ext) Loss of Bolting Integrity (B.2.3.9) VII.I.AP-124 3.3-1, A closure preload 015 Piping Pressure Ductile iron Raw water (ext) Loss of External Surfaces VII.G.A-33 3.3-1, E, 3 boundary material Monitoring of Mechanical 064 Components (B.2.3.23)

Piping Pressure Ductile iron Raw water (ext) Loss of Selective Leaching VII.G.A-51 3.3-1, A boundary material (B.2.3.21) 072 Plant Specific Notes

1. The Fire Water System (B.2.3.16) AMP is used to manage the wall thinning due to erosion aging effect for components exposed to raw water.

2. The Fire Water System (B.2.3.16) AMP is used to manage the cracking aging effect for copper alloy >15% Zn components exposed to raw water .

3. The External Surfaces Monitoring of Mechanical Components (B.2.3.23) AMP is used to manage loss of material for the piping that may be subject to periodic submergence.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 6 of 18 SLRA Table 3.3.2-8, page 3.3-222 is revised as follows:

Table 3.3.2-8: Emergency Power System - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging NUREG-2191 Table 1 Notes Type Function Requiring Management Item Item Management Program Tank (EDG fuel Pressure Carbon steel Underground Loss of Buried and VII.I.AP-284 3.3-1, 109 B oil storage) boundary (ext) material Underground Piping and Tanks (B.2.3.27)

Tank Pressure Carbon steel Concrete (ext) Cracking Buried and VII.I.A-425 3.3-1, 144 B (emergency fuel boundary Underground oil storage) Piping and Tanks (B.2.3.27)

Tank Pressure Carbon steel Concrete (ext) Loss of Buried and VII.I.AP-198 3.3-1, 109 B (emergency fuel boundary material Underground oil storage) Piping and Tanks (B.2.3.27)

Tank Pressure Carbon steel Underground Loss of Buried and VII.I.AP-284 3.3-1, 109 B (emergency fuel boundary (ext) material Underground oil storage) Piping and Tanks (B.2.3.27)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 7 of 18 SLRA Appendix A, Section 16.2.2.27, page A-32, is revised as follows:

composed of metallic (carbon steel, low-alloy steel, and cast iron) materials that are within the scope of Subsequent License Renewal in the service water, fuel oil, and fire water systems. Loss of material is monitored by visual inspection of the exterior and wall thickness measurements of the piping. Wall thickness is determined by an NDE technique such as UT.

The AMP 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 will be conducted. For steel components, where the The acceptance criteria for the effectiveness of the cathodic protection is other than determined by meeting a -850 mV instant off potential acceptance criterion (i.e.,

the electrodes polarized half-cell potential taken immediately after stopping the cathodic protection current), loss of material rates are measured.

Visual inspections of external surfaces of buried components are performed to check for evidence of coating/wrapping damage, loss of material, and cracking. The periodicity of these inspections will be based on plant OE and opportunities for inspection such as scheduled maintenance work but will be performed at a minimum of once every 10 years during the SPEO. Inspections are conducted by qualified individuals. Where the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that 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 rate is extrapolated to the end of the SPEO, an increase in the sample size is conducted.

Based on the PBN excellent plant OE and the combination of good soil conditions, preventive design features in place, and inspections, the buried steel piping at PBN would meets the criteria for Preventive Action Category C. However, if these conditions were to change, the Preventive Action Category would require reevaluation and could potentially change. Thus, the number of inspections for each 10-year inspection period, commencing 10 years prior to the SPEO, based on the inspection quantities identified in GALL-SLR Table XI.M41-2 (adjusted for a 2-unit plant site) is two, so long as the Preventive Action Category C remains applicable.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 8 of 18 SLRA Appendix A, Section 16.4, Table 16-3 (Item 27), page A-91 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) p) Revise procedure(s) to include the following information:

x Component surfaces that are insulated and exposed to condensation (because the in-scope component is operated below the dew point),

and insulated outdoor components, are periodically inspected every 10 years during the SPEO.

x For all outdoor components and any indoor components exposed to periodic submergence or condensation (because the in-scope component is operated below the dew point), inspections are conducted of each material type (e.g., steel, SS, copper alloy, aluminum) and environment (e.g., raw water, air outdoor, air accompanied by leakage) where periodic submergence, condensation or moisture on the surfaces of the component could occur routinely or seasonally. In some instances, significant moisture can accumulate under insulation during high humidity seasons, even in conditioned air. A minimum of 20% of the in-scope piping length, or 20% of the surface area for components whose configuration does not conform to a 1-foot axial length determination (e.g., valve, accumulator, tank) is inspected after the insulation is removed.

Alternatively, any combination of a minimum of 25 1-foot axial length sections and components for each material type is inspected.

Inspection locations should focus on the bounding or lead components most susceptible to aging because of time in service, severity of operating conditions (e.g., amount of time that condensate would be present on the external surfaces of the component), and lowest design margin. Inspections for cracking due to SCC in aluminum components need not be conducted if it has been determined that SCC is not an applicable aging effect.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 9 of 18 SLRA Appendix A, Section 16.4, Table 16-3 (Item 31), page A-96 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Activity Section (Section) 31 Buried and XI.M41 Continue the existing PBN Buried and Underground Piping and Tanks AMP, No later than 6 months prior Underground Piping including enhancement to: to the SPEO, or no later and Tanks a) Ensure that the cathodic protection system will meet the requirements of than the last refueling (16.2.2.27) GALL-SLR Section XI.M41, including the polarized potential criteria of outage prior to the SPEO NUREG 2191 (i.e., -850 mV instant-off). PBN takes an exception to the i.e.:

NUREG-2191 requirement of meeting the cathodic protection requirements PBN1: 04/05/2030 of NACE SP0169-2007. Instead, PBN is committed to meeting the PBN2: 09/08/2032 cathodic protection system requirements of NACE SP0169-2013 (with the Implement the AMP and exception of Section 6, Criteria and Other Considerations for Cathodic start the one-time and Protection). The information from NACE SP0169-2007 shall be used 10-year interval inspections instead of NACE SP0169-2013 for Section 6. The cathodic protection no earlier than 10 years system for non-aluminum buried piping shall also include a limiting prior to the SPEO.

critical potential of -1,200 mV, similar to that stated in NACE SP0169-2007, Section 6.2.3.2.1. Additionally, the cathodic protection system shall also include annual system monitoring.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 10 of 18 SLRA Appendix A, Section 16.4, Table 16-3 (Item 31), page A-97 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) g) Perform inspections of buried and underground piping and tanks will be conducted in accordance with NUREG-2191 Table XI.M41-2 Category C steel, unless a reevaluation of future OE and soil conditions determines that another Preventive Action Category is more applicable. The inspections will be distributed evenly among the units.

Since PBN is a two-unit site, the inspection quantities are 50% greater than NUREG-2191 Table XI.M41-2 and are rounded up to the nearest whole inspection. Thus, the number of inspections for each 10-year inspection period, commencing 10 years prior to the SPEO and continuing during the SPEO, in accordance with Preventive Action Category C, is as follows:

x Buried Piping: The smaller of 0.5% of the piping length or two 10-foot segments.

x Buried Tank: One inspection for tank T-072.

x Underground Tanks: Monitor annular space of double walled tanks T-175A and T-175B for leakage.

When the inspections for a given material type is based on percentage of length and results in an inspection quantity of less than 10 feet, then 10 feet of piping is inspected. If the entire run of piping of that material type is less than 10 feet in total length, then the entire run of piping is inspected.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 11 of 18 SLRA Appendix A, Section 16.4, Table 16-3 (Item 31), page A-98 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) k) Perform the examinations of the buried portion of tank T-072 from either the external surface of the tank using visual techniques or from the internal surface of the tank using volumetric techniques. A minimum of 25% of the buried surface is examined. ThisThe inspected area includes at least some of both the top and bottom of the tank. If the tank is inspected internally by volumetric methods, the method must be capable of determining tank wall thickness and general and pitting corrosion and qualified at PBN to identify loss of material that does not meet acceptance criteria. The double wall tanks, T-175A and T-175B shall be examined by monitoring the annular space for leakage.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 12 of 18 SLRA Appendix A, Section 16.4, Table 16-3 (Item 31, page A-99) is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging Management NUREG-2191 Commitment Implementation Schedule Program or Activity Section (Section) s) Utilize the Table XI.M41-3 acceptance criteria (i.e., -850 mV instant-off) for pipe to soil potential when using a saturated copper/copper sulfate (CSE).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 13 of 18 SLRA Section B.2.3.23, page B-174 is revised as follows:

Element Affected Enhancement x Revise procedure(s) to specify alternative methods for detecting moisture inside piping insulation (such as thermography, neutron backscatter devices, and moisture meters) are to be used for inspecting piping jacketing that is not installed in accordance with plant-specific procedures (such as no minimum overlap, wrong location of seams, etc.). Revise procedure(s) to include the following information:

o Component surfaces that are insulated and exposed to condensation (because the in-scope component is operated below the dew point),

and insulated outdoor components, are periodically inspected every 5

4. Detection of Aging years during the SPEO.

Effects o For all outdoor components and any indoor components exposed to periodic submergence or condensation (because the in-scope component is operated below the dew point), inspections are conducted of each material type (e.g., steel, SS, copper alloy, aluminum) and environment (e.g., raw water, air outdoor, air accompanied by leakage) where periodic submergence, condensation or moisture on the surfaces of the component could occur routinely or seasonally. In some instances, significant moisture can accumulate under insulation during high humidity seasons, even in conditioned air. A minimum of 20 percent of the in-scope piping length, or 20 percent of the surface area

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 14 of 18 SLRA Section B.2.3.27, page B-196 is revised as follows:

Enhancements The PBN Buried and Underground Piping and Tanks AMP will be enhanced as follows, for alignment with NUREG-2191. This AMP is to be implemented and its inspections and tests begin no earlier than 10 years prior to the SPEO. The inspections and tests are to be completed no later than six months prior to entering the SPEO or no later than the last RFO prior to the SPEO.

Element Affected Enhancement

2. Preventive Actions PBN manuals, procedures, etc. will be enhanced to:

x State that the cathodic protection system will meet the requirements of GALL SLR Section XI.M41, including the polarized potential criteria of NUREG 2191 (i.e., -850 mV instant-off). PBN takes an exception to the NUREG-2191 requirement of meeting the cathodic protection requirements of NACE SP0169-2007. Instead PBN is committed to meeting the cathodic protection system requirements of NACE SP0169 2013 (with the exception of Section 6, Criteria and Other Considerations for Cathodic

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 15 of 18 SLRA Section B.2.3.27, page B-197 is revised as follows:

Element Affected Enhancement Protection). The information from NACE SP0169 2007 will be used instead of NACE SP0169 2016 for Section 6. The cathodic protection system for non-aluminum buried piping shall also include a limiting critical potential of -1,200 mV, similar to that stated in NACE SP0169-2007, Section 6.2.3.2.1. Additionally, the cathodic protection system will also include annual system monitoring.

x State that new or replaced backfill shall meet the requirements of NACE SP0169-2007 Section 5.2.3 or NACE RP0285-2002, Section 3.6.

3. Parameters PBN manuals, procedures, etc. will be enhanced to:

Monitored or x Perform visual inspection of the external surfaces of controlled Inspected low strength material backfill, where such backfill is used, to detect potential cracks that could admit groundwater to the surface of the component.

x Clarify when a volumetric examination should be performed and clarify when pit depth gages or calipers may be used for measuring wall thickness. These techniques may be used as long as: (a) they have been determined to be effective for the material, environment, and conditions (e.g., remote methods) during the examination; and (b) they are capable of quantifying general wall thickness and the depth of pits.

x Clarify that cracking inspections for steel utilize a method that has been determined to be capable of detecting cracking.

Coatings that: (a) are intact, well-adhered, and otherwise sound for the remaining inspection interval; and (b) exhibit small blisters that are few in number and completely surrounded by sound coating bonded to the substrate do not have to be removed.

Inspections for cracking are conducted to assess the impact of cracks on the pressure boundary function of the component.

x Clarify that pipe-to-soil potential and the cathodic protection current are monitored for steel piping and tanks in contact with soil to determine the effectiveness of cathodic protection systems.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 16 of 18 SLRA Section B.2.3.27, page B-197 revision continued:

Element Affected Enhancement

4. Detection of Aging PBN manuals, procedures, etc. will be enhanced to:

Effects x Clarify that inspections of buried and underground piping and tanks will be conducted in accordance with NUREG-2191 Table XI.M41-2 Category C steel, unless a reevaluation of future OE and soil conditions determines that another Preventive Action Category is more applicable . The inspections will be distributed evenly among the units. Since PBN is a two-unit site, the inspection quantities are 50%

greater than NUREG-2191 Table XI.M41-2 and are rounded up to the nearest whole inspection. Thus, the number of inspections for each 10-year inspection period, commencing 10 years prior to the SPEO and continuing during the SPEO, in accordance with Preventive Action Category C, is as follows:

x Buried Piping: The smaller of 0.5% of the piping length or two 10-foot segments.

x Buried Tank: One inspection for tank T-072.

x Underground Tanks: Monitor the annular space of double walled tanks T-175A and T-175B for leakage.

When the inspections for a given material type is based on percentage of length and results in an inspection quantity of less

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 17 of 18 SLRA Section B.2.3.27, page B-198 is revised as follows:

Element Affected Enhancement than 10 feet, then 10 feet of piping is inspected. If the entire run of piping of that material type is less than 10 feet in total length, then the entire run of piping is inspected.

x Clarify that the visual inspections will be supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed.

x State that PBN site-specific conditions can result in transitioning to a higher number of inspections than originally planned at the beginning of a 10-year interval as specified in NUREG-2192, Section 4.a of XI.M41.

x Clarify the guidance for piping inspection location selection as follows: (a) a risk ranking system software incorporates inputs that include coating type, coating condition, cathodic protection efficacy, backfill characteristics, soil resistivity, pipe contents, and pipe function; (b) opportunistic examinations of nonleaking pipes may be credited toward examinations if the location selection criteria are met; and (c) the use of guided wave ultrasonic examinations may not be substituted for the required inspections.

x Select one of the alternatives to visual examination of piping from NUREG-2191 pages XI.M41-9 and XI.M41-10.

x Clarify that examinations of the buried portion of tank T-072 are conducted from the external surface of the tank using visual techniques or from the internal surface of the tank using volumetric techniques. A minimum of 25% of the buried surface is examined. ThisThe inspected area includes at least some of both the top and bottom of the tank.

If the tank is inspected internally by volumetric methods, the method must be capable of determining tank wall thickness and general and pitting corrosion and qualified at PBN to identify loss of material that does not meet acceptance criteria. The double wall tanks, T-175A and T-175B shall be examined by monitoring the annular space for leakage.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 19 Page 18 of 18 SLRA Section B.2.3.27, page B-199 is revised as follows:

Element Affected Enhancement

6. Acceptance PBN manuals, procedures, etc. will be enhanced to:

Criteria x For coated piping or tanks, there is either no evidence of coating degradation, or the type and extent of coating degradation is evaluated as insignificant by an individual: (a) possessing a NACE Coating Inspector Program Level 2 or 3 inspector qualification; (b) who has completed the Electric Power Research Institute Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course; or (c) a coatings specialist qualified in accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Revision 2, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.

x Measured wall thickness is evaluated using trend data and projected to continue to meet minimum wall thickness requirements through the end of the SPEO.

x No evidence that backfill caused damage to the respective component coatings or the surface of the component (if not coated).

x Cracks in cementitious backfill that could admit groundwater to the surface of the component are not acceptable.

x Criteria for pipe-to-soil potential when using a saturated copper/copper sulfate (CSE) reference electrode is as stated in NUREG-2191 Table XI.M41-3 (i.e., -850 mV instant-off).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 20 Page 1 of 3 Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and Tanks AMP: Clarified an Exception and Inspection Frequency Affected SLRA Sections: B.2.3.28 SLRA Page Numbers: B-207, B-212 Description of Change:

The Point Beach (PBN) Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program includes an exception for inspection of the internal coatings on the emergency diesel generator (EDG) fuel oil storage tanks. The basis for the exception does not address how the fuel oil chemistry program will ensure that a loss of coating integrity will be identified / managed such that transport of coating materials to downstream components will not result in downstream effects such as reduction in flow, reduction in pressure, or reduction of heat transfer.

In order to more clearly demonstrate the acceptability of the PBN exception the PBN Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks aging management program (AMP) will be updated to include additional bases discussions regarding fuel oil sampling and filter operations.

Additionally, explicit direction will be added to indicate that the inspection frequency for the component cooling water (CCW) heat exchangers will not be reduced based solely because of the plants entry into the subsequent period of extended operation, as could be inferred by the inspection intervals identified in Table XI.M42-1.

Accordingly, subsequent license renewal application (SLRA) Section B.2.3.28 in Appendix B is being revised to address the additional bases for the exception as follows:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 20 Page 2 of 3 SLRA Section B.2.3.28, Exception to NUREG-2191, page B-207 is revised as follows:

The internal coating applied to the T-175A and T-175B EDG Fuel Oil Storage Tanks will be inspected opportunistically as opposed to periodically. This exception is consistent with the PBN Fuel Oil Chemistry AMP, which takes an exception to the requirement to periodically drain, clean, and inspect T-175A and T-175B. The T-175A and T-175B internal coatings will be inspected opportunistically when an internal inspection of the tanks is deemed necessary based on the results of fuel oil sample analysis or as recommended by the system engineer. This exception is justified based on acceptable inspection and wall thickness testing of other fuel oil tanks made of the same material, indicating that no appreciable material loss has occurred in more than 40 years of service as discussed in the Fuel Oil Chemistry AMP. Internal inspections of the buried fuel oil tanks are not required by the plant Technical Specifications. Flaking, peeling, or delamination of the internal coating would be identified as particulates suspended in the fuel oil samples that are taken quarterly. Coating particulates could also be identified in the fuel oil filters, which have pressure indicators that would identify if the filters were becoming clogged prior to the potential loss of function of the downstream components. In addition, dDue to the double wall tank design, regular leak chase monitoring is utilized and such monitoring is capable of identifying through wall leaks. Per ML15127A291, this leak chase monitoring was used as justification for relief from a VT-2 visual inspection normally required by the 2007 Edition with 2008 Addenda of ASME Code,Section XI, Table IWD 2500-1 (Examination Category D-B, Item D2.10). The exterior aging management of these underground tanks is within the scope of the PBN Buried and Underground Piping and Tanks AMP (Section B.2.3.27).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 20 Page 3 of 3 SLRA Section B.2.3.28, page B-212 is revised as follows:

The CCW heat exchangers are periodically inspected to monitor the condition of the internal coatings and will continue to be periodically inspected during the SPEO. The inspection frequency of the CCW heat exchangers will not be reduced prior to or upon entering the SPEO unless the results from subsequent inspections of the internal coatings of the heat exchangers justify changing the inspection interval as determined by the plants corrective action program and Table XI.M42-1, Note 5 of NUREG-2191.

OE will be reviewed such that if there is an indication that the effects of aging are not being adequately managed, a corrective action will be initiated to either enhance the AMP or implement new AMPs, as appropriate. In addition, AMP effectiveness will be assessed at least every five years per NEI 14-12.

The PBN Internal Coatings/Lining for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks AMP is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry OE, including research and development, such that the effectiveness of the AMP is evaluated consistent with the discussion in NUREG-2191, Appendix B.

Conclusion The PBN Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks AMP will provide reasonable assurance that the effects of aging will be adequately managed so that the intended function(s) of components within the scope of the AMP will be maintained consistent with the CLB during the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 1 of 23 Irradiated Concrete and Reactor Vessel Supports: Revised Further Evaluation, AMR Results, and AMP Affected SLRA Sections: Section 3.5.2.1.1, Section 3.5.2.2.2.6, Table 3.5.2.2-2, Section 3.5.2.2.2.7, Table 3.5.2.2-3, Table 3.5.2.2-4, Table 3.5.2.2-6, Section 3.5.4, Table 3.5.2-1, Section 16.2.2.34, Table 16-3, B.2.3.34 SLRA Page Numbers: 3.5-3, 3.5-35, 3.5-36, 3.5-37, 3.5-38, 3.5-39, 3.5-40, 3.5-41, 3.5-42, 3.5-43, 3.5-44, 3.5-45, 3.5-88, 3.5-93, 3.5-95. 3.5-96, A-36, A-105, B-239 Description of Change:

Changes are made to SLRA sections 3.5.2.1.1 and 3.5.2.2.2.6, Table 3.5.2-1, Section 16.2.2.30, Table 16-3 and Section B.2.3.34 to address aging management of the potential for localized distortion of the reactor cavity liner plate due to radiation induced volumetric expansion (RIVE) of the underlying concrete. Additional changes are made to Section 3.5.2.2.2.6 and Table 3.5.2.2-2 to correct radiation exposure values on the biological shield wall (BSW), to provide further discussion on reactor cavity temperatures and provide justification for why the BSW would remain in place under the combination of RIVE and design basis loading conditions.

With regard to SLRA Section 3.5.2.2.2.7 and associated tables, additional details are provided regarding the reactor vessel support configuration and thermal growth, references to the PBN EPU LAR and SER are added, and updates to the operating experience section are provided.

The revisions presented in this attachment do not reflect revisions being presented in other attachments unrelated to irradiation of concrete and steel including Attachment 24, ASME Section XI, Subsection IWF AMP, Attachment 27, Structures Monitoring AMP and Attachment 29, Containment AMR. Additional updates are also provided by Westinghouse.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 2 of 23 Section 3.5.2.1.1, page 3.5-3 is revised as follows:

Aging Effects Requiring Management The following aging effects associated with the Containment structure and internal structural components require management:

x Cracking x Cumulative fatigue damage x Distortion (reactor cavity liner) x Increase in porosity and permeability x Loss of bond x Loss of coating or lining integrity x Loss of leak tightness x Loss of material x Loss of mechanical function x Loss of mechanical properties x Loss of preload x Loss of prestress x Loss of sealing x Loss of strength (also cited as reduction of strength)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 3 of 23 Section 3.5.2.2.2.6 and Table 3.5.2.2-2, page 3.5-35 beginning at the third paragraph are revised as follows:

Westinghouse calculated the maximum neutron fluence (E > 0.1 MeV), gamma dose and displacements per iron atom (dpa) for the end of the SPEO on the BSW, and RV support components based on the reactor models and radiation transport calculations performed for the PBN SLR RV neutron exposure (Section 4.2). These calculations were performed on a fuel-cycle-specific basis at PBN Units 1 and 2 for 72 EFPY, and unlike what was done for the initial license renewal, future projections for PBN SLR included a 10 percent positive bias on the peripheral and re-entrant corner assemblies on the projection fuel cycle. Peripheral assemblies have one or more faces exposed to the core baffle plates and re-entrant corner assemblies have one corner exposed the core baffle plates.

The 10 percent positive bias applied to the projection cycle peripheral and re-entrant corner assembly relative powers is intended to account for normal, cycle-to-cycle variations that have been observed in past PBN core designs and are expected to occur in future ones as well. Note that, with the exception of the extended power uprate (EPU), there have been no changes in plant operating conditions, fuel design, or fuel management since the initial license renewal that have resulted in a continuous increase (or decrease) in cycle-to-cycle exposure rates.

Provided in Table 3.5.2.2-2 are the results of the calculations from Westinghouse:

Table 3.5.2.2-2 End of SPEO Exposures for PBN Concrete Neutron Fluence Component Gamma Dose (rads)2 (n/cm2)

BSW 5.16 5.23 x 1019 2.35 2.39 x 1010 PSW1 < 1.0 x 1019 < 1 x 1010 Note

1. SW fluence exposures were determined using the fluence results for the BSW and RV supports, and gamma dose was determined considering gamma attenuation through the BSW and gamma distribution as a function of active fuel height. This Iincludes the attachment points of the RV supports to the PSW at the ring girder and the reactor vessel nozzle areas.

2. Gamma doses determined by Westinghouse include gammas from fission, neutron interactions with the BSW concrete, and neutron interactions with materials other than the BSW concrete.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 4 of 23 Section 3.5.2.2.2.6, page 3.5-36 beginning at the second paragraph is revised as follows:

Reference 3.5.4.5 uses attenuation ratio to determine the point into the concrete where the fluence will reach the NUREG-2192 neutron fluence damage threshold of 1 x 1019 n/cm2. The attenuation ratio is defined as (threshold fluence)/(incident fluence at the surface of the concrete). Based on the relatively high w/c ratio of 0.6 (wet concrete) for PBN, Tthe information in Reference 3.5.4.5 is representative bounding of the PBN concrete in relation to 2-loop PWR fluence attenuation in the concrete model, use of Portland cement, and use of crushed dolomite aggregate.

For the PBN BSW, the attenuation ratio was determined to be equal to 1/5.16, which is equal to 0.19. Using the equation in Reference 3.5.4.5, for the neutron fluence attenuation curve, neutron fluence would reach the damage threshold in NUREG-2192 at 3.35 inches into the BSW. However, an additional evaluation was required to address radiation induced volumetric expansion (RIVE) from neutron fluence exposure on the BSW. As a result of the calculated swelling stress in the BSW due to RIVE at the end of the SPEO, the concrete from the inside surface to a depth of 3.92 inches into the BSW would be affected. To account for the RIVE effect, the structural evaluation of the BSW considered the concrete from the inside surface to a depth of 3.92 inches to have zero strength. As an additional conservatism, this zero-strength was applied to the entire vertical surface of the BSW corresponding to the active nuclear fuel region. All liner plates including those covering the top and bottom of the BSW are welded together, resulting in a continuous plate structure supported on concrete with angle sections typically 2 ft apart from each other. The maximum RIVE effect zone of 3.92 inches is applicable only to a limited number of anchors around the mid-height of the BSW. The rest of the anchors remain effective.

Consequently, the overall integrity of the BSW liner is not adversely affected by the RIVE effects.

Additional factors to confirm the BSW and liner would remain in place considering the RIVE neutron fluence effects and design basis loading conditions are as follows:

x Actual RIVE distribution: a) use of ACI code concrete strain at ultimate capacity (0.003); b) use of the EPRI normalized neutron flux profile. RIVE is very limited within 2 inches at the center allowing most of the liner anchorage to be effective.

x The structural steel liner will continue to maintain its configuration away from the impacted area. Note the steel rebar does not lose its cover at the impacted point based on the second bullet above. This rebar is mostly for shrinkage and temperature effects and will continue to perform that function.

x The corbels are significant concrete structures and are not impacted by the RIVE effect. As such, they will continue to support the configuration.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 5 of 23 Section 3.5.2.2.2.6, page 3.5-37 beginning at the first paragraph is revised as follows:

The conservatisms in the above evaluation were as follows:

Exposures were based on 72 EFPY which is more than the actual expected projected best estimate EFPY based on a 95% capacity factor of ~69 EFPY.

Future projections included a 10 percent positive bias on the peripheral and re-entrant corner assemblies on the projection fuel cycle.

Irradiation effects were assumed to apply to the entire vertical surface of the BSW corresponding to the active fuel region, whereas actual fluence and gamma dose would be much less at the top and bottom regions of the fuel.

The loss of strength in the BSW concrete as a result of gamma dose incident on the BSW was assumed to apply to the full thickness to the point where the gamma dose falls below the NUREG-2192 damage threshold, when in reality the gamma dose effect would reduce in an approximate linear fashion from the outside surface.

The latest research data presented in Reference 3.5.4.5 indicates that the threshold for damage to concrete from gamma dose may be higher than 1 x 1010 rads.

With regard to the effect of gamma heating, heating from radiation was considered and described in Reference 3.5.4.5. A base case was analyzed with what were considered limiting conditions for thermal conductivity, radiation levels, rebar location, air gap (between the reactor vessel and the primary shield wall inner surface) temperature, air gap flow, and outside wall temperature. As presented in Reference 3.5.4.5, Ffor a 150ºF air temperature in the air gap, the calculated maximum temperature in the concrete was 168ºF at a depth of approximately 6 inches from the inside surface of the concrete. The containment ventilating systems at PBN 150ºF air temperature in the air gap for the EPRI report is well above the required <105oF maintain containment ambient design temperatures, including those in the reactor cavity, to <105oF for the containment ventilating systems at PBN (Section 5.3.1.1 of the UFSAR). Accordingly, the evaluation in Reference 3.5.4.5 is bounding, and thus gamma heating is not considered an issue for the PBN BSW and PSW concrete.

Other factors regarding temperatures in the reactor cavity are as follows:

x The reactor coolant piping which penetrates the PSW is insulated to ensure ambient temperatures remain within design limits.

x Temperature assumptions were based on the normal operating temperature of the fluid in the RV nozzle of approximately 613°F and cooling of approximately 100°F for each inch away from the heat source. These temperature assumptions are consistent with previous structural analyses.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 6 of 23 Section 3.5.2.2.2.6, page 3.5-37 revision continued:

Therefore, the BSW and PSW will continue to satisfy the design criteria considering the long-term radiation effects and a plant specific AMP or enhancements to an existing AMP are not required. The BSW and PSW will continue to be inspected as part of the Structures Monitoring (B.2.3.34) AMP, with specific attention to the potential for localized distortion of the cavity liner plate as a result of the RIVE effect on the underlying concrete.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 7 of 23 Section 3.5.2.2.2.7, page 3.5-38 is revised as follows:

3.5.2.2.2.7 Expected Further Evaluation for Loss of Fracture Toughness due to Irradiation Embrittlement of Reactor Vessel (RV) Supports from NRC Review of the First Three SLRAs Loss of fracture toughness due to irradiation embrittlement from accumulated neutron fluence and gamma dose could occur in BWR and PWR structural support components (including associated weldments and bolted connections),

located in the vicinity of the Reactor Vessel (RV), made of steel material exposed to low-temperature, low-flux radiation in an air-indoor uncontrolled environment.

These components include the RV steel supports, neutron shield tank, steel structural support components of reactor shield wall and sacrificial shield wall, or other steel structural support components located in the vicinity of the RV. The irradiation aging effect could result in reducing or compromising the structural integrity of the above steel structural components. Further evaluation is recommended to determine if a plant-specific aging management program (AMP) or plant-specific enhancements to selected GALL-SLR AMPs is needed to manage the aging effects due to irradiation embrittlement in these steel structural support components located in the vicinity of the RV for the subsequent period of extended operation. Loss of function due to radiation exposure (neutron and/or gamma) of related non-steel (except concrete) components (e.g., Lubrite or other lubricant/coating in support sliding feet) that may have been used in RV supports and are important to capability to perform its function should also be evaluated and dispositioned, with supporting technical information, on a plant-specific basis for the subsequent period of extended operation. The acceptance criteria for a plant-specific program or program enhancements are described in BTP RLSB-1 (Appendix A.1 of NUREG-2192 (SRP-SLR).

The PBN Units 1 and 2 RV support structure, which is identical for both units, consists of a six-sided structural steel welded ring girder supported at each apex by

~19 foot long steel columns which pass through the BSW extending downward to the interior concrete structure below the RV. The columns are 12-inch diameter schedule 120 A53 steel pipe with welded flanges at both ends. The six columns of the support structure are bolted at the top to the ring girder and pinned at the bottom to the floor anchor. Three of the columns are totally surrounded by the BSW, and the other three are partially surrounded by the BSW. The center of each segment of the ring girder provides lateral and rotational restraint by structural members embedded in the PSW concrete.

The RV has six supports pads, one at each of the four RV primary loop nozzles, and two additional gusset-braced support pads that are welded directly to the RV. Each RV support bears on a support shoe, which is fastened to the support structure. The support shoe is a structural member that transmits the support loads to the supporting structure. It is designed to restrain vertical, lateral, and rotational movement of the RV but to allow for thermal growth by permitting radial sliding on the bearing plates at each support. For thermal growth, there is relative motion between the RV nozzles, shim plates and support shoes, and no lubricants are used on these sliding surfaces.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 8 of 23 Section 3.5.2.2.2.7 and Table 3.5.2.2-3, page 3.5-39 are revised as follows:

Table 3.5.2.2-3 PBN Design Reactor Vessel Support Loads per Support (kips)

(References 3.5.4.7 and 3.5.4.8)

Loading and Load Combination(1) Vertical (N) Horizontal (V)

Deadweight 192 0 Thermal 123 0.3 OBE Seismic 110 89 SSE Seismic 160 177 LOCA 153 51 Normal Combination 315 0.3 Upset Combination 425 89.3 Faulted 1 Combination 475 177.3 Faulted 2 Combination 628 228.3 Notes

1. Normal = Deadweight + Thermal Upset = Normal + OBE Seismic Faulted-1 = Normal + SSE Seismic Faulted-2 = Normal + SSE Seismic + LOCA

2. The RCS primary equipment supports are designed and qualified in accordance with the American Institute of Steel Construction (AISC)

"Specification for the Design of Structural Steel for Buildings." (1963).

The load cases, load combinations, and the applicable allowable stress limits are summarized in UFSAR, Table A.5-3, Control Room Building Section, N-S The RV supports load and load combinations are less than the appropriate allowable load limits, as presented in Table 3.5.2.2-4, Summary of RPV Support Component Stress Interaction Ratios, below. These interaction ratios have been updated from the ones in References 3.5.4.7 and 3.5.4.8 based on an issue identified and corrected by Westinghouse when performing the critical flaw size analyses for SLR.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 9 of 23 Section 3.5.2.2.2.7 and Table 3.5.2.2-4, page 3.5-40 are revised as follows:

Table 3.5.2.2-4 Summary of RPV Support Component Stress Interaction Ratios (Reference 3.5.4.6)

Controlling Interaction Ratios (<100%)

Support Component Normal Upset Faulted 1 Faulted 2 Screw Shear 18.19% 29.56% 30.23% 35.05%

RV Shoe Shoe Net Tension 0.05% 14.22% 14.12% 18.18%

Box Beam 76.41% 66.99% 68.68% 90.21%

Support Structure Pipe Column 78.51% 99.54% 75.82% 99.86%

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 10 of 23 Section 3.5.2.2.2.7, page 3.5-41 is revised as follows:

Maximum projected neutron exposures (E > 0.1 MeV) in terms of fluence and displacements per iron atom of the PBN RV support structures are provided in Table 3.5.2.2-5:

Table 3.5.2.2-5 72 EFPY dpa Exposures and Fluence for PBN RV Support Components Fluence Component Displacements per Iron n/cm2 Atom (dpa) (E > 0.1 MeV)

Support Column 1 - maximum 5.84E-03 1.48E+19 Support Column 1 - top of support foot 2.70E-05 8.28E+16 Support Column 1 - bottom of column 2.27E-05 6.76E+16 Support Column 2 - maximum 5.69E-04 1.49E+18 41Support Column 2 - top of support foot 2.74E-05 8.40E+16 Support Column 2 - bottom of column 2.51E-05 7.49E+16 Ring Girder - inside bottom edge 3.35E-03 9.26E+18 Ring Girder - inside top edge 1.15E-03 3.40E+18 Ring Girder - outside bottom edge 1.14E-03 3.09E+18 Ring Girder - outside top edge 3.43E-04 1.06E+18 Column 2 above is one of three columns totally surrounded by the BSW, and Column 1 is one of three columns partially surrounded by the BSW.

A detailed fracture mechanics evaluation was performed for Point Beach Units 1 and 2 in WCAP-18554-P/NP (Reference 3.5.4.6) to evaluate the structural steel RV supports. In the WCAP-18554 report, The postulated critical flaw sizes for various RV support components were determined by setting the applied stress intensity factor equal to fracture toughness and back-calculating the flaw size. The postulated critical flaw sizes were then compared to the ASME Section XI allowable flaw sizes. This comparison approach is allowable per Section 4.3.4.1 of NUREG-1509. In most cases, the postulated critical flaw sizes are larger than the Section XI allowable flaw sizes by a large margin; thereby concluding that the PBN reactor vessel support components continue to be structurally stable (i.e., flaw tolerant) considering 80 years of radiation or embrittlement effects on the supports. No as-found indications have been detected in the PBN supports to date based on the ASME Section XI IWF inspection program. The postulated critical flaw sizes for PBN RV support components at the end of the SPEO (72 EFPY ) are presented in Table 3.5.2.2-6 below:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 11 of 23 Section 3.5.2.2.2.7 and Table 3.5.2.2-6, page 3.5-42 is revised as follows:

(1)

Table 3.5.2.2 Summary of Postulated Critical Flaw Sizes for 72 EFPY (Table 8-1 of WCAP -18554-P/NP Reference 3.5.4.6)

Loading Postulated Critical Flaw Size (a/t, flaw depth over thickness)

Condition (see Notes below) Box Ring I-Beam Shear Brace: Shear Brace: Bolts at Box Pin at Bottom Support Leveling Column Girder Web (2) Bolt Shear Key Ring Girder of Column Shoe Box Screw Base Plate (t = 1) Flange(2) (t = 1) (OD = 1.6012) (t = 2) (OD = 1.6012) (OD = 3.994) (t = 7.96) (OD = 3.54) (t = 2)

(t = 1.5)

Normal 3.8 % 65.4 % 16.4 % 80.0 %

59.6 % 2.2 %(3) 3.8 %(3) 99.8 % 99.9 % 16.9 %

Upset 1.8 % 42.2 % 21.3 % 80.0 %

62.9 % 2.4 %(3) 3.4 %(3) 51.5 % 99.5 % 4.8 % (3)

Faulted-1 1.3 % 28.1 % 12.4 % 80.0 %

57.0 % 2.2 %(3) 3.0 %(3) 41.5 % 98.3 % 3.4 % (3)

Faulted-2 0.7 % 21.6 % 9.5 % 80.0 %

44.4 % 1.9 %(3) 2.8 %(3) 37.4 % 97.2 % 2.1 % (3)

Section XI 3.1 % 3.7 % 4.3 % 9.4 % 3.1 % 9.4 % 0.20 % 1.9 % 4.2 % 3.6 %

Allowable Flaw Size (a/t)

Notes

1. The results provided in this table are based on Table 8-1 of WCAP-18554-P/NP (Reference 3.5.4.6). The postulated critical flaw sizes are determined by setting applied stress intensity factor equal to fracture toughness and back-calculating flaw size.

2. This location considers welding residual stress equal to 110 ksi (yield strength + 10 ksi).

3. These postulated critical flaw sizes are less than the Section XI allowable flaw sizes. See further discussion below.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 12 of 23 Section 3.5.2.2.2.7, page 3.5-43 is revised as follows:

Further discussion Ffor the three limiting PBN RV support components with postulated critical flaw sizes less than or close to the Section XI allowable flaw sizes (box ring girder flange, I-beam web, and bolts at the box ring girder and pins at the base of the column) the critical flaw sizes would have been discovered and repaired/replaced prior to installation as are described below.

For the box ring girder flange and I-beam web, postulated critical flaw sizes were compared against the requirements in AWS D2.0 Quality of Welds which notes that no cracks in welds would have been allowed during initial fabrication. Thus, Tthe box ring girder and I-beam welds would be free from indications after initial fabrication and after an extended period of time since crack growth mechanisms are not present at the RV supports. Thus, these critical flaw sizes were deemed to be acceptable. The results provided in Table 3.5.2.2-6 are for the most limiting postulated flaw cases.

However, various postulated cases were also analyzed in Sections 7.2 and 7.3 (see Tables 7-2 and 7-3) of WCAP-18554-P/NP (Reference 3.5.4.6) to determine the flaw tolerance of different flaw configurations and aspect ratios. These additional flaw sizes demonstrate more favorable results for the critical flaw sizes based on more appropriate postulated aspect ratios and flaw configurations. Also provided in Sections 7.2 and 7.3 (see Tables 7-2 and 7-3) of WCAP-18554-P/NP is the change in the magnitude of critical flaw sizes based on the change in embrittlement from 42, 60, and 72 EFPY. The effect of the change in neutron embrittlement over time was determined to be negligible on the critical flaw sizes (less than 5% average change in flaw sizes); therefore, the supports have sufficient flaw tolerance to not be impacted by neutron embrittlement from the original design life of 40 years to the SLR period of 80 years (see discussions in Sections 7.2, 7.3 and 8.2 of WCAP-18554-P/NP).

As discussed in Sections 7.2 and 7.3 of WCAP-18554-P/NP, the primary reason for the small postulated critical flaw sizes for the ring girder flange and I-beam web are due to the use of conservative welding residual stresses in the fracture mechanics evaluations. Similar to the ring girder flange and I-beam web welds, the welds at the top of the long column would also have high welding residual stresses. All of these welds (i.e. ring girder flange and I-beam welds, and the top of the column weld) are constructed with the same weld metal to join the T-1 base metal, and therefore, the post-weld heat treatment is not performed per the design specification to prevent degradation and cracking of the weld. The welds at the top of the long column are not analyzed in WCAP-18554-P/NP, but these welds will have the same level of stresses, fracture toughness, and geometry to the ring girder flange and I-beam web welds; thus, the critical flaw sizes for the top of the column weld will be of the same order of magnitude as the ring girder flange and I-beam welds.

The resulting postulated critical flaw sizes as determined in Table 3.5.2.2-6 (per WCAP-18554-P/NP) are based on the use of overly conservative inputs. Due to the complexity of the RV supports, some of these conservatisms had to be considered in the evaluations. However, in Section 7 (pages 7-2 and 7-3) of WCAP-18554-P/NP (Reference 3.5.4.6) a detailed discussion of conservatisms and plant-specific considerations are provided, such as modeling of the

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 13 of 23 Section 3.5.2.2.2.7, page 3.5-43 revision continued:

supports, conservatism in dpa calculations, consideration of minimum temperature, use of minimum fracture toughness requirements, and use of conservative stresses and stress combinations.

The bulk material temperature as discussed in Section 5.1.2 of WCAP-18554-P/NP is also conservative, as the minimum operating temperature at the ring girder locations would be higher than those provided in Table 5-2 of WCAP-18554-P/NP. The temperature assumptions were based on the normal operating temperature of the fluid in the nozzle of approximately 613°F and then assuming cooling of approximately 100°F for each inch away from the heat source. The temperature assumptions are consistent with previous structural analyses. For fracture mechanics toughness calculations, a lower temperature is conservative.

Thus, the use of all of these conservatisms resulted in the small critical flaw sizes for the fracture mechanics evaluations. However, to reiterate, the small postulated critical flaw sizes do not change by more than 5% over the time period from 40 to 60 years and then from 60 to 80 years (see discussions in Sections 7.2, 7.3 and 8.2 of WCAP-18554-P/NP); thus, the flaw tolerance of these components is sufficiently high and is insignificantly impacted by neutron embrittlement during long term operation. Furthermore, the ASME Section XI inspections performed by Point Beach Units 1 and 2 of the RPV supports have not shown any relevant indications, cracking, gross deformation or corrosion that would result in the degradation or loss of capacity of the load bearing members of the RV supports.

For the box ring girder bolts, the postulated critical flaw size is less than the ASME Section XI allowable flaw size. However, ASTM A-490-76 standards state that bolts with transverse discontinuities (circumferential flaws) are considered defective and would have been replaced prior to use. The bolts at the box ring girder would be free from indications after initial fabrication of the supports and after an extended period of time since crack growth mechanisms are not present at the RV supports. Thus, these critical flaw sizes are deemed to be acceptable. for a complete 360° continuous flaw are shown to be limiting in Table 3.5.2.2-6 (per WCAP-18554-P/NP). However, Section 7.6 of WCAP-18554-P/NP provides results for a more realistic case for a semi-circular flaw in a bolt. The results in Table 7-6 of WCAP-18554-P/NP tabulate more reasonable critical flaw sizes for the semi-circular flaw when compared against ASME Section XI allowable flaw sizes. The bolts were designed to Point Beach supports design specification and ASTM A-490-64 standards. Both of these standards have general workmanship and quality assurance requirements to discard any defective bolts during the fabrication of the bolts and also during the installation of the supports. Thus, the bolts at the box ring girder are assumed to be free of defects after initial installation of the supports and after an extended period of time since crack growth mechanisms are not present at the RV supports. Also per Table 7-6 of WCAP-18554-P/NP, the change in the magnitude of critical flaw sizes for bolts based on the neutron embrittlement from 42 to 72 EFPY is negligible (less than 5% average change in flaw sizes); therefore, the bolts have sufficient flaw tolerance to not be impacted

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 14 of 23 Section 3.5.2.2.2.7, page 3.5-43 revision continued:

by neutron embrittlement (see discussions in Sections 7.6 and 8.2 of WCAP-18554-P/NP). As discussed previously, a detailed discussion of conservatisms and plant-specific considerations are provided on pages 7-2 and 7-3 of WCAP-18554-P/NP (Reference 3.5.4.6). More specifically for the bolts, the use of conservative stresses and stress combinations lead to the small critical flaw sizes. Other conservatisms include dpa calculations, consideration of minimum temperature and use of minimum fracture toughness requirements. Nonetheless, the results in Table 7-6 of WCAP-18554-P/NP demonstrate reasonable critical flaw sizes for the semi-circular flaw which are larger than the ASME Section XI allowable flaw sizes. Thus, based on the above discussions for the bolts, the calculated postulated critical flaw sizes are acceptable for the 80 year life for Point Beach. Furthermore, based on the ASME Section XI inspections to date, none of the support bolts have been found to be defective nor replaced since the original installation of the supports. Thus, the operating history of the bolts at Point Beach RPV supports have demonstrated to be satisfactory and there has been no loss of functionality or capacity of the load bearing members of the bolted connections.

For the pins at the bottom on the column, the postulated critical flaws are calculated to be small as shown in Table 3.5.2.2-6 (per WCAP-18554-P/NP).

However, as discussed in Section 5.1.1.5 and Table 5-1 of WCAP-18554-P/NP, the pins are sufficiently far away from the core to not be impacted by neutron irradiation damage. There is insignificant change in dpa from 40 years to 80 years (see Tables 5-1 & 5-5 of WCAP-18554-P/NP), which results in no change in shift in NDTT, embrittlement and fracture toughness over this time period. As a result, there is no change in the calculated critical flaw sizes for the pins during this time period (see Table 7-7 of WCAP-18554-P/NP). Therefore, the level of flaw tolerance remains the same from 40 years to 80 years. Thus, it can be concluded that there is no impact of neutron irradiation of the pins at this region, since there is very low levels of dpa at the bottom of the support columns to cause any concern for flaw stability in the pins.

Therefore, Bbased on the above discussions above of the conservatisms in the plant specific analysis and the subsequent postulated critical flaw size results, the RV supports at PBN Units 1 and 2 are can be concluded to be structurally stable (i.e., flaw tolerant) considering 80 calendar years (72 EFPY) of radiation embrittlement effects. Additionally, there is sufficient level of flaw tolerance demonstrated to justify continuing the current visual examination (VT-3) of the RV structural steel supports as part of the PBN ASME Section XI, Subsection IWF Inservice Inspection (B.2.3.31) Program.

Operating Experience Section 4.3.1.1 of NUREG-1509 states that physical examination of the RV supports is essential to the evaluation. The purpose of the examination is to detect visible signs of degradation of the supports, including, but not limited to, rust, corrosion, cracks or permanent deformation of the members. Figure 4-2 of NUREG-1509 identifies

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 15 of 23 Section 3.5.2.2.2.7, page 3.5-43 revision continued:

evaluate existing physical condition as one of the key inputs to the preliminary evaluation. Examinations performed to date on the PBN RV supports as part of the current PBN ASME Section XI, Subsection IWF Inservice Inspection Program consist of VT-3 visual inspections.

Based on the ISI examination, discoloration at the base plate and bolts was observed; however the Point Beach NDE Level III have reviewed and concluded that this discoloration was due to staining from cavity seal leakage from the reactor vessel flange during outage (this leakage is not present after plant start-up). NDE Level III concluded that while there was some light surface corrosion, there was no degradation of the base plate or associated bolting. Any degradation would have to be evaluated by the design team at Point Beach and reanalysis of the AISC margins for the structural steel components (base plate, bolts, and nuts) would be needed. To date, there had been no re-design or analysis needed for this region of the support. As such, Point Beach has concluded that the discoloration is not related to general corrosion or degradation of the support; furthermore, there was no loss of capacity of the load bearing members at the lower base plate, nuts, and bolts. Therefore, no degradation or reduced load carrying capability due to corrosion is required to be considered in the fracture evaluation of the RPV supports.

These support inspections are summarized below with the specifics provided on the portal:

Unit 1 VT-3 inspections of accessible portions of the Unit 1 PBN RV supports were performed in 2005, 2007 and 20162010. These inspections were performed on all accessible areas to the extent possible. The VT-3 inspection data sheets from the 2010 inspections indicated acceptable results meeting the acceptance criteria of IWF-3410 and did not identify any areas requiring further evaluation. Additionally, there was no observed degradation or loss of material due to corrosion which would affect the ability of the RV supports to perform their intended function.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 16 of 23 Section 3.5.2.2.2.7, page 3.5-44 is revised as follows:

The acceptance criteria specified in IWF-3410 is as follows:

(a) Component support conditions which are unacceptable for continued service shall include:

(1) Deformations or structural degradations of fasteners, springs, clamps, or other items; (2) Missing detached, or loosened support items; (3) Arc strikes, weld spatter, paint, scoring, roughness, or general corrosion on close tolerance machined or sliding surfaces; (4) Improper hot or cold settings of spring supports and constant load supports; (5) Misalignment of supports; (6) Improper clearances of guides and stops.

(b) Except as noted in IWF-3410(a), the following are examples of non-relevant conditions:

(1) Fabrication marks (e.g., from punching, layout, bending, rolling, and machining);

(2) Chipped or discolored paint; (3) Weld spatter on other than close tolerance machined or sliding surfaces; (4) Scratches and surface abrasion marks; (5) Roughness or general corrosion which does not reduce the load bearing capacity of the support; (6) General conditions acceptable by the material Design, and/or Construction Specifications.

Unit 2 VT-3 inspections of accessible portions of the Unit 2 PBN RV supports were performed in 2006, 2008 and 20152009. These inspections were performed on all accessible areas to the extent possible. The VT-3 inspection data sheets from the 2009 inspections indicated acceptable results meeting the acceptance criteria of IWF-3410 and did not identify any areas requiring further evaluation. Additionally, there was no observed degradation or loss of material due to corrosion which would affect the ability of the RV supports to perform their intended function.

Based on these results, a plant specific AMP or enhancements to an existing AMP are not required to manage loss of fracture toughness due to irradiation embrittlement of the RV supports at PBN.

In addition to the above, potential exposure of the RV supports to boric acid is managed by the boric acid corrosion AMP (B.2.3.4). During two of the inspections noted above, boric acid staining was identified on the RV supports due to leakage from the reactor cavity seal ring and sand box covers during refueling. The boric acid was cleaned and no degradation was observed on the RV supports.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 17 of 23 Section 3.5.4, page 3.5-45 is revised as follows:

3.5.4. References 3.5.4.1. Westinghouse LTR-REA-20-28-NP, Revision 0, Reactor Vessel, Reactor Vessel Supports, and Concrete Bioshield Exposure Data in Support of the Point Beach Unit 2 Subsequent License Renewal (SLR) Time-Limited Aging Analysis (TLAA), July 31, 2020 (Enclosure 4, Attachment 1).

3.5.4.2. Westinghouse Report WCAP-18124-NP-A, Revision 0, Fluence Determination with RAPTOR-M3G and FERRET, July 2018.

3.5.4.3. EPRI Report No. 3002002676, Expected Condition of Reactor Cavity Concrete After 80-Years of Radiation Exposure, Electric Power Research Institute, Charlotte, NC, March 2014.

3.5.4.4. PNNL 15870, Revision 1 Compendium of Material Composition Date for Radiation Transport Modelling, April 2006.

3.5.4.5. EPRI Report No. 3002011710, Irradiation Damage of the Concrete Biological Shield Wall for Aging Management, EPRI, Palo Alto, CA, May 2018.

3.5.4.6. WCAP-18554-P/NP, Revision 1, Fracture Mechanics Assessment of Reactor Pressure Vessel Structural Steel Supports for Point Beach Units 1 and 2, September 2020 (Enclosure 4, Attachment 2 and Enclosure 5, Attachment 2).

3.5.4.7 Point Beach Nuclear Plant, Units 1 and 2, Dockets 50-266 and 50-301, Renewed License Nos. DPR-24 and DPR-27, License Amendment Request 261 Extended Power Uprate, April 7, 2009, (ADAMS Accession No. ML110750120).

3.5.4.8 Point Beach, Units 1 and 2 - Safety Evaluation: Extended Power Uprate (TAC Nos. ME1044 and ME1045), May 3, 2011, (ADAMS Accession No. ML110450159).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 18 of 23 Table 3.5.2-1, page 3.5-88 is revised as follows:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Notes Type Function Requiring Program 2191 Item Management Item Liners (refueling Direct flow Stainless Air - indoor Cracking Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4 cavity) and Fire barrier steel uncontrolled (B.2.3.34) covers (sand box, Pressure Unit 1 sump A boundary strainer) Radiation shielding Liners (reactor Radiation Steel Air - indoor Loss of material Structures Monitoring VII.A1.A-94 3.3-1, 111 C cavity) shielding uncontrolled Distortion (B.2.3.34)

Structural support Liners (reactor Radiation Steel Air with borated Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C cavity) shielding water leakage (B.2.3.4)

Structural support Liner plate Pressure Steel Air - indoor Cumulative fatigue TLAA - Section 4.6, II.A3.C-13 3.5-1, 009 A boundary uncontrolled damage Containment Liner Plate, Structural Metal Containments, and support Penetrations Fatigue Analysis

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 19 of 23 Table 3.5.2-1, page 3.5-93 is revised as follows:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Notes Type Function Requiring Program 2191 Item Management Item Radiant energy Fire barrier Stainless Air - indoor Cracking Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4 shields steel uncontrolled (B.2.3.34)

RV supports Structural Steel Air - indoor Loss of fracture ASME Section XI, N/A N/A H, 11 and bolting support uncontrolled toughness Subsection IWF (B.2.3.31)

RC Class 1 Structural Steel Air - indoor Loss of material ASME Section XI, III.B1.1.T-24 3.5-1, 091 B, 8 supports support uncontrolled Subsection IWF (B.2.3.31)

RC Class 1 Structural Steel Air with borated Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C supports support water leakage (B.2.3.4)

RC Class 1 Structural High-strength Air with borated Loss of Material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C support bolting support steel water leakage (B.2.3.4)

RC Class 1 Structural High-strength Air - indoor Loss of preload ASME Section XI, III.B1.1.TP- 3.5-1, 087 B, 8 support bolting support steel uncontrolled Subsection IWF 229 (B.2.3.31)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 20 of 23 Table 3.5.2-1, pages 3.5-95 and 3.5-96 are revised as follows:

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item.

AMP is consistent with NUREG-2191 AMP description.

B. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item.

AMP has exceptions to NUREG-2191 AMP description.

C. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

D. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP has exceptions to NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program.

F. Material not in NUREG-2191 for this component.

H. Aging effect not in NUREG-2191 for this component, material, and environment combination.

I. Aging effect in NUREG-2191 for this component, material and environment combination is not applicable.

Plant Specific Notes

11. The loss of fracture toughness aging effect is managed by the ASME Section XI, Subsection IWF (B.2.3.31) AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 21 of 23 Revise Section 16.2.2.34, page A-36 as follows:

16.2.2.34. Structures Monitoring The PBN Structures Monitoring AMP is an existing AMP that consists of periodic visual inspection and monitoring of the condition of concrete and steel structures, structural components, component supports, and structural commodities to ensure that aging degradation (such as those described in ACI 349.3R, ACI 201.1R, SEI/ASCE 11, and other documents) will be detected, the extent of degradation determined and evaluated, and corrective actions taken prior to loss of intended functions. Specific attention is given to the potential for localized distortion of the reactor cavity liner plate as a result of the radiation induced volumetric expansion (RIVE) effect on the underlying concrete. Structures are monitored on an interval not to exceed 5 years.

Inspections also include seismic joint fillers, elastomeric materials; steel edge supports and bracings associated with masonry walls, and periodic evaluation of ground water chemistry and opportunistic inspections for the condition of below grade concrete. Quantitative results (measurements) and qualitative information from periodic inspections are trended with sufficient detail, such as photographs and surveys for the type, severity, extent, and progression of degradation, to ensure that corrective actions can be taken prior to a loss of intended function. The acceptance criteria are derived from applicable consensus codes and standards. For concrete structures, the program includes personnel qualifications and quantitative evaluation criteria of ACI 349.3R.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 22 of 23 Table 16-3, page A-105 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 38 Structures XI.S6 Continue the existing PBN Structures Monitoring AMP, including enhancement to: No later than 6 months prior Monitoring a) Revise inspection procedures to include guidance and acceptance criteria to the SPEO, i.e.:

(16.2.2.34) on inspections of stainless steel and aluminum components for pitting and PBN1: 04/05/30 crevice corrosion, and evidence of cracking due to SCC. Perform an PBN2: 09/08/32 evaluation if stainless steel or aluminum surfaces exhibit evidence of SCC, pitting, or crevice corrosion.

b) Revise implementing procedures to address preventive actions to ensure proper selection and storage of high strength bolting in accordance with Section 2 of the Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts.

c) Revise inspection procedures to additionally inspect for the following items:

x Increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation in concrete structures.

x Loss of material and loss of strength for elastomers.

x Pitting and crevice corrosion, and evidence of cracking due to SCC for stainless steel and aluminum components x Confirmation of the absence of water in-leakage through concrete.

d) Localized distortion of the reactor cavity liner due to radiation induced volumetric expansion of the underlying concrete.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 21 Page 23 of 23 Section B.2.3.34, page B-239 is revised as follows:

Enhancements The following enhancements will be implemented no later than six months prior to entering the SPEO. There are no new inspections to be implemented for SLR.

Element Affected Enhancement Update the governing AMP procedure and other

3. Parameters Monitored applicable procedures to additionally inspect the or Inspected following elements:

x Concrete Structures will be inspected for increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

x Elastomer will also be inspected for loss of material and loss of strength.

x Pitting and crevice corrosion and evidence of cracking due to SCC for stainless steel and aluminum components x Concrete will be monitored to confirm the absence of water in-leakage Localized distortion of the reactor cavity liner due to radiation induced volumetric expansion of the underlying concrete.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 1 of 48 Plant Structures: Clarified Scoping, Screening and AMR Results Affected Subsequent License Renewal Application (SLRA) Sections:

A. Sections 2.4.5, 2.4.6, 2.4.7, 2.4.10, 2.4.11, and 2.4.12; Table 2.4-10; Section 3.5.2.1.10; and Table 3.5.2-10.

B. Table 2.4-11; Section 3.5.2.1.11; and Table 3.5.2-11.

C. Section 2.4.15 and Table 3.5.2-15.

D. Table 3.3-1.

E. Tables 2.4-10 and 3.3-1; Sections 3.5.2.1.14 and 3.5.2.2.2.4; and Tables 3.5.2-10 and 3.5.2-14.

F. Table 3.5-1 (editorial).

G. Table 3.5-1.

H. Table 3.5.2-13.

I. Tables 3.5.2-8 and 3.5.2-11.

J. Tables 3.5.2-2, 3.5.2-4, 3.5.2-6, 3.5.2-8, 3.5.2-11, and 3.5.2-13.

SLRA Page Numbers:

A. 2.4-13, 2.4-14, 2.4-16, 2.4-21, 2.4-22, 2.4-23, 2.4-25, 3.5-12, and 3.5-126 to 3.5-128.

B. 2.4-24, 3.5-13, 3.5-32, 3.5-130, and 3.5-131.

C. 2.4-30, and 3.5-141.

D. 3.3-51, 3.5-121, 3.5-122.

E. 2.4-22, 3.3-80, 3.3-82, 3.3-83; 3.5-16, 3.5-32, 3.5-78, 3.5-127, 3.5-139, and 3.5-140.

F. 3.5-46 (and Table headers on 3.5-46 to 3.5-78) (editorial).

G. 3.5-72.

H. 3.5-76, and 3.5-136 to 3.5-138.

I. 3.5-77, 3.5-78, 3.5-121, 3.5-122, 3.5-130, 3.5-131, and 3.5-136 to 3.5-138.

J. 3.5-69, 3.5.99, 3.5-100, 3.5-106, 3.5-114, 3.5-115, 3.5-130, 3.5-131, and 3.5-136 to 3.5-138.

Description of Changes:

SLRA Section 2.4 and 3.5 text and tables (1) are revised, sequentially in the order of their appearance in the SLRA, to clarify:

A. Façade, Fuel Oil Pumphouse, Gas Turbine Building, Turbine Buildings, Yard Structures and 13.8kV Switchgear Building boundary discussions.

B. Yard manhole cover component type and materials.

C. Listing of overhead load handling systems in the scope of SLR and addition of cross references to Aging Management Program (AMP).

D. Stainless steel vs carbon steel new fuel storage racks (to align Table 3.5-1, item 111

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 2 of 48 with the intended component of NUREG-2191,Section VII.A1).

E. Fire barrier materials and aging effects F. AMP Summary table applicability G. Structural bolting in the spent fuel pool managed by Water Chemistry and One-Time Inspection rather than Water Chemistry and ASME Section XI, Subsection IWF.

H. Galvanized steel structural component alignment with Table 3.5-1 as there are galvanized steel supports for ASME Class 2, 3 components that are managed by ASME Section XI, Subsection IWF instead of Structures Monitoring.

I. Aluminum and stainless steel susceptible to loss of material and cracking and alignment with Table 3.5-1.

J. Plant specific notes for -

o Epoxy grout/anchors being same as other grout/anchors, o Management of components with fire barrier and other functions by other AMPs, and o Management of other functions than fire barrier by the Fire Protection AMP.

(1) Corresponding changes to SLRA Tables 2.4-1 and 3.5.2-1 are reflected in Attachment #29 for Containment AMR, Liner/Penetration Fatigue, ASME Section XI, Subsection IWE AMP and Clarifications).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 3 of 48 SLRA Section 2.4.5 (page 2.4-13) is revised as follows:

Containment concrete dome through steel base plates secured to the domes with anchor bolts and structural steel.

Boundary Each Façade Structure boundary includes the structural components that comprise the Façade. There are no significant differences between the current boundary and those identified as part of the original PBN license renewal are limited to joint and penetration seals conservatively included in the current boundary.

Structure Intended Functions Nonsafety-related functions that could affect safety-related functions (10 CFR 54.4(a)(2)):

1) Attached to and enclose the containment structures, and houses the reactor makeup water tank, as well as main steam and feedwater piping. The structures provide no physical protection from design basis external hazards. They provide weather protection for equipment and personnel and improve the architectural treatment of the plant.

UFSAR References 5.1 6.2 10.2 A.5 Subsequent License Renewal Drawing The subsequent license renewal drawing for the façade structures is LR-C-3.

Components Subject to AMR Table 2.4-5 lists the Façade Structures component types that require AMR and their associated component intended functions.

Table 3.5.2-5 provides the results of the AMR.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 4 of 48 SLRA Section 2.4.6 (page 2.4-14) is revised as follows:

2.4.6 Fuel Oil Pumphouse Structure Description The Fuel Oil Pumphouse (FOPH) Structure is a rectangular, safety related, seismic Class I structure constructed from reinforced concrete and concrete masonry block. This building is an independent structure with no other structures in its immediate vicinity. The FOPH building houses nonsafety-related mechanical and electrical equipment, including the Gas Turbine Fuel Oil Supply Pump, which is required for Gas Turbine Generator (G05) operation. G05 is relied upon as the Alternate AC (AAC) power source during a station blackout (SBO) and is relied upon to supply power to safe shutdown loads through the alternate shutdown equipment during a fire in 4160 V switchgear.

The FOPH Structure consists of several areas on two levels. Below grade, the building consists of reinforced concrete floor (basemat), walls, and ceiling.

Above grade, the building is predominately concrete masonry block, except for the reinforced concrete floor and stairwell enclosure and the concrete slab roof. The building's basemat is at elevation 5-feet, the intermediate floor is at elevation 25-feet-6-inches, and the concrete roof is at elevation 35-feet-4-inches (nominal).

Boundary The Fuel Oil Pumphouse Structure boundary includes all the structural components that comprise the Fuel Oil Pumphouse. The differences between the current boundary and those identified as part of the original PBN license renewal areis limited to joint and penetration seals and above-grade masonry (block) conservatively included in the current boundary.

Structure Intended Functions Fire protection, Station Blackout functions (10 CFR 54.4(a)(3)):

Provide support and protection for the Gas Turbine Fuel Oil Supply Pump (P105) and associated components, which is required for G05

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 5 of 48 SLRA Section 2.4.7 (page 2.4-16) is revised as follows:

2.4.7 Gas Turbine Building Structure Description The Gas Turbine Building (GTB) Structure is a rectangular, nonsafety-related, seismic Class 3 structure that is constructed from prefabricated metal wall and roof panels attached to a structural steel frame. The building's structural steel frame is supported by a reinforced concrete basemat and foundation. The building is an independent structure with no other buildings in its immediate vicinity. The GTB houses nonsafety-related G05 and its associated mechanical and electrical equipment. G05 is relied upon as the AAC power source during an SBO and is relied upon to supply power to safe shutdown loads through the alternate shutdown equipment during a fire in 4160 V switchgear.

The GTB consists of a single compartment. The building's basemat, building elevation 0-feet-0-inches and foundation footings consist of reinforced concrete supported on compacted subgrade. Equipment foundations are integral with the building's basemat. The building's roof is at building elevation 16-feet-11-inches (nominal).

Boundary The Gas Turbine Building Structure boundary includes all the structural components that comprise the Gas Turbine Building for operation of G05 and its associated electrical and mechanical equipment. The differences between the current boundary and those identified as part of the original PBN license renewal areis that joint and penetration seals and miscellaneous structural components are conservatively included in the current boundary.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 6 of 48 SLRA Section 2.4.10 (page 2.4-21) is revised as follows:

Boundary The Turbine Building Unit 1/2 Structure boundary includes all the structural components that comprise the Turbine Building. There are no significant differences between the current boundaries and those identified as part of the original PBN license renewal are that joint and penetration seals are conservatively included in the current boundary.

Structure Intended Functions Nonsafety-related components that could affect safety-related functions (10 CFR 54.4(a)(2)):

(1) Provide support to safety related and nonsafety-related SSCs, whose failure could adversely affect safety related functions. These TB SSCs include items such as the buildings support for the safety related Main Steam and Feedwater valves, overhead crane (NUREG-0612),

Non-Vital Switchgear Area north wall HELB shield (Unit 2 only), and CR ventilation air intake ducting (Control Room habitability).

Fire protection functions (10 CFR 54.4(a)(3)):

(1) Contains SSCs relied upon in safety analyses or plant evaluations that perform a function directly supporting the sites implementation of Fire Protection regulations.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 7 of 48 SLRA Table 2.4-10 (page 2.4-22) is revised as follows:

Components Subject to AMR Table 2.4-10 lists the Turbine Building Structure component types that require AMR and their associated component intended functions.

Table 3.5.2-10 provides the results of the AMR.

Table 2.4-10 Turbine Building Structure Subject to Aging Management Review Component Intended Component Type Function(s)

Concrete basemat, foundation Structural support Concrete exterior walls and roof Structural support Concrete interior walls and ceilings, and floors Fire barrier Shelter, protection Structural support Masonry (block) walls Fire barrier Structural support Rollup door Fire barrier Structural steel and miscellaneous structural components Structural support Structural bolting Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 8 of 48 SLRA Section 2.4.11 (page 2.4-23) is revised as follows:

Boundary The yard structures boundary includes all the in-scope structural components that comprise the yard. There are no significant differences between the current boundaries and those identified as part of the original PBN license renewal effort, except for masonry walls that are conservatively included in the current boundary.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 9 of 48 SLRA Table 2.4-11 (page 2.4-24) is revised as follows:

Components Subject to AMR Table 2.4-11 lists the Yard Structures component types that require AMR and their associated component intended functions.

Table 3.5.2-11 provides the results of the AMR.

Table 2.4-11 Yard Structures Subject to Aging Management Review Component Intended Component Type Function(s)

Berm Fire barrier Concrete foundations (tanks and components) Structural support Concrete duct banks, manholes, trenches Shelter, protection Structural support Manholes Fire barriers Manway insulation boardshole covers (insulated) Structural support Miscellaneous structural components Fire Barrier Shelter, protection Structural Support Structural bolting Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 10 of 48 SLRA Section 2.4.12 (page 2.4-25) is revised as follows:

Boundary The 13.8 kV Switchgear Building Structure boundary includes all the structural components that comprise the 13.8 kV Switchgear Building. The differences between the current boundary and those identified as part of the original PBN license renewal are the conservative inclusion of the roof, and miscellaneous structural components that are an integral part of the buildings construction in the current boundary, along with joint and penetration seals that permit differential movement.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 11 of 48 SLRA Section 2.4.15 (page 2.4-30) is revised as follows:

addition, the potential radiological consequences for the postulated fuel handling accident as described in UFSAR Chapter 14.2.1 are well within the dose guidelines of 10 CFR 100.

The NUREG-0612 load handling systems include the cranes that were designed to comply with EOCI-61, which was superseded by CMAA-70: Containment Cranes, the Auxiliary Building Main Crane, and the Turbine Building MainOverhead Crane.

This system also includes the following overhead handling systems used to handle heavy loads in the area of the reactor vessel or in other areas where their accidental drop may damage safe shutdown systems:

x Circulating Water Pumphouse Monorails (N-S and E-W),

x Reactor Pressure Vessel Head Monorails, x Containment Buttress Jib Cranes, x Main Shop Crane, x Jib Crane Over Core Instrumentation Seal Tables, x Emergency Diesel Generator G03 and G04 Cranes and Monorails (Diesel Generator Building),

x Steam Generator Blowdown Heat Exchanger Cranes (both units), and x Unit 2 Turbine Building Truck Bay Jib Crane.

The special lifting devices identified in scope are the RCP Motor Lifting Devices, and the Reactor Vessel Head and Internals Lifting Rigs, Reactor Vessel 8-Stud Carrier Assembly, and Special Lifting Devices for Dry Cask Storage.

The specific components comprising this system are the structural members (bridge and trolley) of these heavy load cranes and lifting devices, including the crane rails and hardware.

All of Tthese load-handling systems listed above were identified to have the potential for a heavy load drop, which could result in damage to safe shutdown equipment. The remainder of the cranes, hoists, and lifting devices at PBN are excluded due to their load carrying capacity (being less than that of a heavy load) or their lack of proximity to safe shutdown equipment.

Boundary The Cranes, Hoists, and Lifting Devices boundary includes all the structural components that comprise the Cranes, Hoists, and Lifting Devices that meet NUREG-0612. The boundary is limited to the load-bearing components that structurally support the heavy loads in a passive manner. This includes the bridge and trolley items such as structural beams, girders, and rails. There are no significant differences between the current boundary and those identified as part of the original PBN license renewal.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 12 of 48 SLRA Table 3.3-1 item 111 (page 3.3-51) is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 111 Steel structural steel Loss of material due to AMP XI.S6, No Consistent with NUREG-2191.

exposed to air - general, pitting, crevice "Structures Monitoring" The Structure Monitoring AMP is used indoor uncontrolled corrosion to manage loss of material in structural steel exposed to uncontrolled indoor air. This line item is used to evaluate structural items in Section 3.5.Not Applicable New Fuel storage racks at PBN are stainless steel and addressed in item 3.5.1, 100.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 13 of 48 SLRA Table 3.3-1, item 255 (page 3.3-80) is revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 255 Any material fire Loss of material due to AMP XI.M26, No Consistent with NUREG-2191.

damper assemblies general, pitting, crevice "Fire Protection" exposed to air corrosion; cracking The Fire Protection (B.2.3.15) AMP is due to SCC; used to manage loss of material hardening, loss of cracking, loss of strength, and strength, shrinkage shrinkage in fire damper assemblies.

due to elastomer This line item is used to evaluate degradation structural items in Section 3.5.

Fire barrier penetration seals, including those associated with fire damper assemblies, are addressed in item 3.3-1, 057.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 14 of 48 SLRA Table 3.3-1, items 263, 267, 268 and 269 (pages 3.3-82, and 3.3-83) are revised as follows:

Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 263 Polymeric piping, Hardening or loss of AMP XI.M36, No Not applicable.

piping components, strength due to "External Surfaces There are no polymeric components in ducting, ducting polymeric degradation; Monitoring of Mechanical the Auxiliary systems The Structures components, seals loss of material due to Components," or AMP Monitoring (B.2.3.34) AMP is exposed to air, peeling, delamination, XI.M38, credited with managing blistering, condensation, raw wear; cracking or "Inspection of Internal cracking, hardening, loss of water, raw water blistering due to Surfaces in Miscellaneous material, and loss of strength of (potable), treated exposure to ultraviolet Piping and Ducting polymer manhole cover components water, waste water, light, ozone, radiation, Components" exposed to air - outdoor in the yard, underground, or chemical attack; instead of the External Surfaces concrete, soil flow blockage due to Monitoring of Mechanical fouling Components (B.2.3.23).

3.3-1, 265 Steel heat exchanger Reduction of heat XI.M30, Fuel Oil No Not applicable.

radiator tubes transfer due to fouling Chemistry, and XI.M32, There are no steel heat exchanger exposed to fuel oil One-Time Inspection radiator tubes exposed to fuel oil in the Auxiliary Systems.

3.3-1, 266 Steel heat exchanger Reduction of heat XI.M30, Fuel Oil No Not applicable.

radiator tubes transfer due to fouling Chemistry, There are no steel heat exchanger exposed to fuel oil radiator tubes exposed to fuel oil in the Auxiliary Systems.

3.3-1, 267 Subliming compound Loss of material, AMP XI.M26, Fire No Not applicable Consistent with fireproofing/fire change in material Protection NUREG-2191.

barriers (Thermolag , properties, cracking, There are no subliming compounds Darmatt', 3M' delamination, and (Thermo-lag, Darmatt', 3M' Interam', and other separation Interam', and other similar materials) similar materials) exposed to air in the Auxiliary Systems exposed to air The Fire Protection (B.2.3.15) AMP is used to manage cracking /

delamination, loss of material, change in material properties, and separation for 3M' Interam' fire stops and wraps exposed to air.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 15 of 48 Table 3.3-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.3-1, 268 Cementitious coating Loss of material, AMP XI.M26, Fire No Consistent with NUREG-2191.

fireproofing/fire change in material Protection The Fire Protection (B.2.3.15) AMP is barriers (Pyrocrete, properties, cracking, used to manage change in material BIO' K-10 Mortar, delamination, and properties, cracking / delamination, Cafecote, and other separation similar materials) loss of material, and separation for exposed to air cementitious fire barriers exposed to air.

3.3-1, 269 Silicate Loss of material, AMP XI.M26, Fire No Consistent with NUREG-2191.

fireproofing/fire change in material Protection The Fire Protection (B.2.3.15) AMP is barriers (Marinite, properties, cracking, used to manage change in material Kaowool', delamination, and properties, cracking / delamination, Cerafiber, Cera separation loss of material, and separation for blanket, or other calcium silicate board, ceramic, fiber similar materials) (board, and mat) fire stops and wraps exposed to air exposed to air.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 16 of 48 SLRA Section 3.5.2.1.10 (page 3.5-12) is revised as follows:

3.5.2.1.10 Turbine Building (Unit 1 and 2) Structure Materials The materials of construction for the turbine building structural components are:

Concrete (reinforced)

Concrete block

Stainless steel

Steel (including galvanized steel)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 17 of 48 SLRA Section 3.5.2.1.11 (page 3.5-13) is revised as follows:

3.5.2.1.11 Yard Structures Materials The materials of construction for yard structure components are:

Aluminum

Concrete (reinforced)

Concrete block

Earth

Polymer

Stainless Steel

Steel (including galvanized steel and cast iron)

Styrofoam Environment The yard structure components are exposed to the following environments:

Air - outdoor

Air with borated water leakage

Soil

Water - flowing Aging Effects Requiring Management The following aging effects associated with the yard structure components require management:

Blistering

Cracking

Distortion

Hardening

Increase in porosity and permeability

Loss of bond

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 18 of 48 SLRA Section 3.5.2.1.14 (page 3.5-16) is revised as follows:

3.5.2.1.14 Fire Barrier Commodity Materials The materials of construction for the fire barrier commodity are:

3M' Interam'

Aluminum

Calcium silicate board (including fire retardant coatings)

Ceramic fiber (including board and mat)

Cementitious (spray-on fireproofing)

Elastomer

Stainless steel

Steel Environment The fire barrier commodity is exposed to the following environments:

Air - indoor uncontrolled

Air with borated water leakage Aging Effects Requiring Management The following aging effects associated with the fire barrier commodity require management:

Change in material properties

Cracking / delamination

Hardening

Loss of material

Loss of strength

Separation

Shrinkage

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 19 of 48 SLRA Section 3.5.2.2.2.4 (page 3.5-32) is revised as follows:

used, the SLRA states the specific alloy or temper used for the applicable in-scope components.

Cracking due to SCC and loss of material due to pitting and crevice corrosion is possible in stainless steel and aluminum structural components exposed to any air, condensation, or underground environment where sufficient halides (e.g., chlorides) and moisture are present, and for tank foundation anchor bolts where water may collect. The air environment for stainless steel new fuel storage racks, (refueling cavity) liner, sandbox and ECCS strainer covers, supports or anchorage or aluminum manwayhole covers, fire barrier penetration seals and fire wraps, or insulation jacketing is not expected to be aggressive enough, in rural Wisconsin, to cause cracking or localized loss of material for stainless steel or aluminum exposed to indoor or outdoor air in the presence of wetting.

In addition, stainless steel structural components are limited in number in comparison to the amount of stainless-steel mechanical components and there are no aluminum supports. Furthermore, there has been no site operating experience of cracking or localized corrosion of stainless steel or aluminum SSCs. As such, cracking due to SCC and loss of material due to pitting and crevice corrosion is conservatively an applicable aging effect at PBN for stainless steel and aluminum and is managed with the External Surfaces Monitoring of Mechanical Components (B.2.3.23) AMP, which will interface with the Structures Monitoring (B.2.3.34) AMP, the Fire Protection (B.2.3.15) AMP and the ASME Section XI, Subsection IWE (B.2.3.29) AMP if degradation is detected in the mechanical components.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 20 of 48 SLRA Table 3.5-1 (page 3.5-46) and subsequent Header Rows are revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 001 Concrete: dome; wall; Cracking and distortion AMP XI.S2, Yes (SRP-SLR PBN does not rely on a de-watering basemat; ring girders; due to increased stress "ASME Section 3.5.2.2.1.1) system to control settlement. However, the buttresses, concrete levels from settlement.Section XI, Structures Monitoring (B.2.3.34) AMP and elements, all Subsection IWL, the ASME Section XI, Subsection IWL and/or AMP (B.2.3.30) AMP inspections would identify XI.S6, "Structures cracking or distortion due to differential settlement of the containment.

Monitoring" Further evaluation is documented in Section 3.5.2.2.1.1.

3.5-1, 002 Concrete: foundation; Reduction of foundation AMP XI.S6, Yes (SRP-SLR Not applicable.

subfoundation strength and cracking "Structures Section 3.5.2.2.1.1) due to differential Monitoring PBN does not rely upon a de-watering settlement and erosion system to control settlement; and is not of porous concrete constructed of porous concrete.

subfoundation Further evaluation is documented in Section 3.5.2.2.1.1.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 21 of 48 SLRA Table 3.5-1 item 071 (page 3.5-69) is revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 071 Masonry walls: all Loss of material AMP XI.S5, No Consistent with NUREG-2191.

(spalling, scaling) and "Masonry Walls" The Masonry Walls (B.2.3.33) AMP is cracking due to credited with managing cracking of freeze- thaw masonry walls due to freeze-thaw.Not applicable.

Freeze thaw of masonry walls is addressed in item number 3.3-1, 179.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 22 of 48 SLRA Table 3.5-1, item 085 (page 3.3-72) is revised as follows:

Table 3.5-1: Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Aging Management Further Evaluation Discussion Number Effect/Mechanism Program (AMP)/TLAA Recommended 3.5-1, 085 Structural bolting Loss of material due to AMP XI.M2, No Consistent with NUREG-2191 as pitting, crevice "Water Chemistry," and AMP clarified and with exception for Water corrosion XI.S3, Chemistry.

"ASME Section XI, The Water Chemistry (B.2.3.2) AMP Subsection IWF" and One-Time Inspection ASME Section XI, Subsection IWF (B.2.3.301)

AMP are credited with managing loss of material for stainless steel structural bolting exposed to threated borated water in the spent fuel pool.

The ASME Section XI, Subsection IWF (B.2.3.31) AMP addresses bolting specific considerations regarding lubricants and storage.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 23 of 48 SLRA Table 3.5-1 item 095 (page 3.5-76) is revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 095 Galvanized steel support None None No Not used.

members; welds; bolted Galvanized steel is included with steel connections; support component supports addressed in items anchorage to building 3.5-1, 091, and 3.5-1, 092.

structure

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 24 of 48 SLRA Table 3.5-1, items 099 and 100 (pages 3.5-77 and 3.5-78) is revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 099 Aluminum, stainless steel Loss of material due to AMP XI.M32, Yes (SRP-SLR Not used.

support members; welds; pitting and crevice "One-Time Section 3.5.2.2.2.4) Loss of material and cracking of stainless bolted connections; support corrosion, cracking due Inspection," AMP steel and aluminum supports and other anchorage to building to SCC XI.S3, structural components isare addressed structure in item 3.5-1, 100.

"ASME Section XI, Subsection IWF,"

or AMP XI.M36, "External Surfaces Monitoring of Mechanical Components 3.5-1, 100 Aluminum, stainless steel Loss of material due to AMP XI.M32, Yes (SRP-SLR Consistent with NUREG-2191, as clarified.

support members; welds; pitting and crevice "One-Time Section 3.5.2.2.2.4) The External Surfaces Monitoring of bolted connections; support corrosion, cracking due Inspection," AMP Mechanical Components (B.2.3.23) AMP is anchorage to building to SCC XI.S6, credited with managing loss of material structure "Structures and cracking of stainless steel and Monitoring," or aluminum insulation jacketing. The AMP XI.M36, Structures Monitoring (B.2.3.34) AMP is credited with managing loss of material "External and cracking of stainless steel new fuel Surfaces Monitoring of storage racks (refueling cavity) liners, Mechanical sandbox, anchorages and ECCS strainer Components" covers, as well as aluminum manhole covers exposed to air. The ASME Section XI, Subsection IWE (B.2.3.29)

AMP is credited with managing loss of material for the stainless steel transfer

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 25 of 48 Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program tube. The Fire Protection (B.2.3.15) AMP is credited with managing loss of material in stainless steel fire barrier penetrations, and rollup door as well as aluminum (foil) and stainless steel (bands) used in fire wraps.

Further evaluation is documented in Section 3.5.2.2.2.4.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 26 of 48 SLRA Table 3.5.2-2 (pages 3.5-99 and 3.5-100) is revised as follows:

Table 3.5.2-2: Circulating Water Pumphouse Structure - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG Table 1 Notes Type Function Requiring Program 2191 Item Item Management Concrete: Direct flow Concrete Air - outdoor Cracking Structures Monitoring III.A6.TP-110 3.5-1, A, 1 forebay structure Flood barrier (reinforced) Groundwater/soil Loss of material (B.2.3.34) 049 and pump bay Shelter, (inaccessible) protection Structural support Concrete: Fire barrier Concrete Water - flowing Loss of material Inspection of III.A6.T-20 3.5-1, A internal columns, Heat sink (reinforced) Water-Control Structures 056 floors, and walls Structural Associated with Nuclear support Power Plants (B.2.3.35)

Concrete: Fire barrier Concrete Air - indoor Cracking Fire Protection VII.G.A-90 3.3-1, A, 2 internal columns, Heat sink (reinforced) uncontrolled Loss of material (B.2.3.15) and 060 floors, and walls Structural Air - outdoor Structures Monitoring support (B.2.3.34)

Fire rated doors Fire barrier Steel Air - indoor Loss of material Fire Protection VII.G.A-21 3.3-1, A uncontrolled (B.2.3.15) 059 Air - outdoor Miscellaneous Missile barrier Steel Air - indoor Loss of material Structures Monitoring III.B5.TP-43 3.5-1, A structural Flood barrier uncontrolled (B.2.3.34) 092 components Structural support Structural bolting Structural Steel Air - indoor Loss of material Inspection of III.A6.TP-221 3.5-1, A support uncontrolled Water-Control Structures 083 Air - outdoor Associated with Nuclear Water - flowing or Power Plants (B.2.3.35) standing

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 27 of 48 Table 3.5.2-2: Circulating Water Pumphouse Structure - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG Table 1 Notes Type Function Requiring Program 2191 Item Item Management Structural bolting Structural Steel Air - indoor Loss of preload Structures Monitoring III.A6.TP-261 3.5-1, A support uncontrolled (B.2.3.34) 088 Air - outdoor Water - flowing or standing General Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

Plant Specific Notes

1. Whereas the NUREG-2191/2192 item calls for a plant-specific AMP, PBN credits an existing AMP based on SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance.

2. Fire Protection AMP in conjunction with the Structures Monitoring AMP is focused on fire barriers internal to the structure recognizing that exterior barriers have additional functions that are managed by the Structures Monitoring AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 28 of 48 SLRA Table 3.5.2-4 (pages 3.5-106) is revised as follows:

Table 3.5.2-4: Diesel Generator Building Structure - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG Table 1 Notes Type Function Requiring Program 2191 Item Item Management Fire rated doors Fire barrier Steel Air - indoor Loss of material Fire Protection VII.G.A-21 3.3-1, A Structural uncontrolled (B.2.3.15) 059 support Air - outdoor

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 29 of 48 SLRA Table 3.5.2-6 (pages 3.5-114 and 3.5-115) is revised as follows:

Table 3.5.2-6: Fuel Oil Pumphouse Structure - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging NUREG Table 1 Item Notes Type Function Requiring Management 2191 Item Management Program Concrete: Flood barrier Concrete Air - indoor Cracking Structures III.A3.TP28 3.51, 067 A exterior walls and Missile barrier (reinforced) uncontrolled Increase in Monitoring roof (accessible) Shelter, Air - outdoor porosity and (B.2.3.34) protection permeability Structural Loss of material support Concrete: Flood barrier Concrete Air - indoor Cracking Structures III.A3.TP204 3.51, 043 A, 3 exterior walls and Missile barrier (reinforced) uncontrolled Monitoring roof Shelter, Air - outdoor (B.2.3.34)

(inaccessible) protection Structural support Concrete: interior Fire barrier Concrete Air - indoor Cracking Fire Protection VII.G.A-90 3.3-1, 060 A, 4 walls, ceilings, Missile barrier (reinforced) uncontrolled Loss of material (B.2.3.15) and and roof Shelter, Structures protection Monitoring Structural (B.2.3.34) support Masonry (block) Fire barrier Concrete Air - outdoor Cracking Masonry Walls III.A3.T-12 3.5-1, 070 A, 4 walls Shelter, block (B.2.3.33) protection Structural support Masonry (block) Fire barrier Concrete Air - outdoor Cracking Fire III.A3.TP-34V 3.5-1, 0713.3-1, A, 4 walls Shelter, block Loss of material Protection II.G.A-626 179 protection (B.2.3.15)

Structural Masonry Walls support (B.2.3.33)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 30 of 48 Table 3.5.2-6: Fuel Oil Pumphouse Structure - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging NUREG Table 1 Item Notes Type Function Requiring Management 2191 Item Management Program Structural bolting Structural Steel Air - indoor Loss of preload Structures III.A3.TP-261 3.5-1, 088 A support uncontrolled Monitoring (B.2.3.34)

Structural bolting Structural Steel Air - indoor Loss of material Structures III.A3.TP-248 3.5-1, 080 A support uncontrolled Monitoring (B.2.3.34)

Structural bolting Structural Steel Air - outdoor Loss of material Structures III.A3.TP-274 3.5-1, 082 A support Monitoring (B.2.3.34)

Structural steel Structural Steel Air - indoor Loss of material Structures III.A3.TP-302 3.5-1, 077 A and support uncontrolled Monitoring miscellaneous (B.2.3.34) structural components Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

Plant Specific Notes

1. Rainfall tends to wash surfaces. However, times of significant precipitation or areas of water collection/flowing such as ground/wall interfaces are conservatively susceptible to leaching.

2. Groundwater is considered to be water-flowing.

3. Whereas the NUREG-2191/2192 item calls for a plant-specific AMP, PBN credits an existing AMP consistent with SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance.

4. Fire Protection AMP in conjunction with the Structures Monitoring AMP is focused on fire barriers internal to the structure recognizing that exterior barriers have additional functions that are managed by the Structures Monitoring AMP or a related AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 31 of 48 SLRA Table 3.5.2-8 (pages 3.5-121 and 3.5-122) is revised as follows:

Table 3.5.2-8: Primary Auxiliary Building Structure - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Aging NUREG Table 1 Notes Requiring Management 2191 Item Item Management Program Concrete: exterior Structural support Concrete Air - indoor Cracking Structures III.A3.TP204 3.51, A, 3 walls and roof Shelter, protection (reinforced) uncontrolled Monitoring 043 (inaccessible) Missile barrier Air - outdoor (B.2.3.34)

Flood barrier Concrete: interior Fire barrier Concrete Air - indoor Cracking Fire Protection VII.G.A-90 3.3-1, A, 4 walls, ceiling, and Missile barrier (reinforced) uncontrolled Loss of material (B.2.3.15) and 060 floors Shelter, protection Structures Structural support Monitoring (B.2.3.34)

Fire rated doors Fire barrier Steel Air - indoor Loss of material Fire Protection VII.G.A-21 3.3-1, A, 5 Flood barrier uncontrolled (B.2.3.15) 059 Louver and Shelter,protection Steel Air - outdoor Loss of material Structures III.B2.TP-6 3.5-1, A exhaust hoods Monitoring 093 (B.2.3.34)

Masonry (block) Fire barrier Concrete Air - indoor Cracking Fire Protection VII.G.A-626 3.3-1, A walls Structural support block uncontrolled Loss of material (B.2.3.15) and 179 Masonry Walls (B.2.3.33)

Masonry (block) Structural support Concrete Air - indoor Cracking Masonry Walls III.A3.T-12 3.5-1, A walls block uncontrolled (B.2.3.33) 070 Structural steel Structural support Steel Air with borated Loss of material Boric Acid III.B1.1.TP-3 3.5-1, A and miscellaneous water leakage Corrosion 089 structural (B.2.3.4) components Structural steel Structural support Steel Air - indoor Loss of material Structures III.A3.TP-302 3.5-1, A and miscellaneous uncontrolled Monitoring 077 structural (B.2.3.34) components

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 32 of 48 Table 3.5.2-8: Primary Auxiliary Building Structure - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Aging NUREG Table 1 Notes Requiring Management 2191 Item Item Management Program New fuel storage Structural support Stainless steel Air - indoor Cracking Structures III.B3.T-37b 3.5-1, AC racks uncontrolled Loss of material Monitoring 100 (B.2.3.34)

Penetration seals Fire barrier Elastomer Air - indoor Hardening Fire Protection VII.G.A-19 3.3-1, A, 5 Flood barrier uncontrolled Loss of strength (B.2.3.15) 057 Shrinkage Penetration seals Fire barrier Elastomer Air - indoor Loss of sealing Structures III.A6.TP-7 3.5-1, A Flood barrier uncontrolled Monitoring 072 (B.2.3.34)

Structural bolting Structural support Steel Air - indoor Loss of preload Structures III.A3.TP-261 3.5-1, A uncontrolled Monitoring 088 (B.2.3.34)

Structural bolting Structural support Steel Air - indoor Loss of material Structures III.A3.TP-248 3.5-1, A uncontrolled Monitoring 080 (B.2.3.34)

Structural bolting Structural support Steel Air - outdoor Loss of material Structures III.A3.TP-274 3.5-1, A Monitoring 082 (B.2.3.34)

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

C. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

Plant Specific Notes

1. Rainfall tends to wash surfaces. However, times of significant precipitation or areas of water collection/flowing such as ground/wall interfaces are conservatively susceptible to leaching.

2. Groundwater is considered to be water-flowing.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 33 of 48 SLRA Table 3.5.2-8 (pages 3.5-121 and 3.5-122) revision continued:

3. Whereas the NUREG-2191/2192 item calls for a plant-specific AMP, PBN credits an existing AMP consistent with SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance.

4. Fire Protection AMP, in conjunction with the Structures Monitoring AMP, is focused on fire barriers internal to the structure recognizing that exterior barriers have additional functions that are managed by the Structures Monitoring AMP.

5. Management of the fire barrier function also manages the component as a flood barrier.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 34 of 48 SLRA Table 3.5.2-10 (pages 3.5-126 to 3.5-128) is revised as follows-Table 3.5.2-10: Turbine Building Structure - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG2191 Table 1 Notes Function Requiring Management Item Item Management Program Concrete: exterior Structural Concrete Air - indoor Cracking Structures III.A3.TP25 3.51, A walls and roof support (reinforced) uncontrolled Monitoring 054 (accessible) Air - outdoor (B.2.3.34)

Concrete: exterior Structural Concrete Water - flowing Increase in porosity Structures III.A3.TP24 3.51, A, 1 walls and roof support (reinforced) and permeability Monitoring 063 (accessible) Loss of strength (B.2.3.34)

Concrete: exterior Structural Concrete Air - indoor Cracking Structures III.A3.TP26 3.51, A walls and roof support (reinforced) uncontrolled Loss of bond Monitoring 066 (accessible) Air - outdoor Loss of material (B.2.3.34)

Concrete: exterior Structural Concrete Air - outdoor Cracking Structures III.A3.TP23 3.51, A walls and roof support (reinforced) Loss of material Monitoring 064 (accessible) (B.2.3.34)

Concrete: exterior Structural Concrete Air - indoor Increase in porosity Structures III.A3.TP28 3.51, A walls and roof support (reinforced) uncontrolled and permeability Monitoring 067 (accessible) Air - outdoor Cracking (B.2.3.34)

Loss of material Concrete: exterior Structural Concrete Air - indoor Cracking Structures III.A3.TP204 3.51, A, 3 walls and roof support (reinforced) uncontrolled Monitoring 043 (inaccessible) Air - outdoor (B.2.3.34)

Concrete: interior Fire barrier, Concrete Air - indoor Cracking Fire Protection VII.G.A-90 3.3-1, A walls, and ceilings, Shelter, (reinforced) uncontrolled Loss of material (B.2.3.15) and 060 and floors protection Structures Structural Monitoring support (B.2.3.34)

Masonry (block) Fire barrier Concrete Air - indoor Cracking Fire Protection VII.G.A-626 3.3-1, A walls Structural block uncontrolled Loss of material (B.2.3.15) and 179 support Masonry Walls (B.2.3.33)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 35 of 48 Table 3.5.2-10: Turbine Building Structure - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG2191 Table 1 Notes Function Requiring Management Item Item Management Program Rollup door Fire barrier Stainless Air - indoor Cracking Fire Protection III.B3.T-37b 3.5-1, E, 4 Steel uncontrolled Loss of material (B.2.3.15) 100 Rollup door Fire barrier Stainless Air - outdoor Cracking Fire Protection III.B3.T-37b 3.5-1, E, 4 Steel Loss of material (B.2.3.15) 100 Rollup door Fire barrier Steel Air - indoor Loss of material Fire Protection VII.G.A-21 3.3-1, A uncontrolled (B.2.3.15) 059 Rollup door Fire barrier Steel Air - outdoor Loss of material Fire Protection VII.G.A-21 3.3-1, A (B.2.3.15) 059 Structural steel and Structural Steel Air - indoor Loss of material Structures III.A3.TP-302 3.5-1, A miscellaneous support uncontrolled Monitoring 077 structural (B.2.3.34) components Structural bolting Structural Steel Air - indoor Loss of preload Structures III.A3.TP-261 3.5-1, A support uncontrolled Monitoring 088 (B.2.3.34)

Structural bolting Structural Steel Air - indoor Loss of material Structures III.A3.TP-248 3.5-1, A support uncontrolled Monitoring 080 (B.2.3.34)

Structural bolting Structural Steel Air - outdoor Loss of material Structures III.A3.TP-274 3.5-1, A support Monitoring 082 (B.2.3.34)

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 36 of 48 SLRA Table 3.5.2-10 (pages 3.5-126 to 3.5-128) revision continued:

Plant Specific Notes

1. Rainfall tends to wash surfaces. However, times of significant precipitation or areas of water collection/flowing such as ground/wall interfaces are conservatively susceptible to leaching.

2. Groundwater is considered to be water-flowing.

3. Whereas the NUREG-2191/2192 item calls for a plant-specific AMP, PBN credits an existing AMP consistent with SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance.

4. Stainless steel fire barriers that are exposed to Air - indoor uncontrolled or Air - outdoor during normal plant operation are inspected under the Fire Protection AMP, that coordinates with the Externals Surfaces Monitoring of Mechanical Components AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 37 of 48 SLRA Table 3.5.2-11 (pages 3.5-130 and 3.5-131) is revised as follows:

Table 3.5.2-11: Yard Structures - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG2191 Table 1 Notes Function Requiring Management Item Item Management Program Concrete Structural support Concrete Soil Cracking Structures III.A3.TP29 3.51, 067 A Foundations (reinforced) Increase in Monitoring (inaccessible) porosity and (B.2.3.34) permeability Loss of material Manholes Fire barrier Concrete Air - outdoor Cracking Fire Protection VII.G.A-626 3.3-1, 179 A, 6 Block Loss of material (B.2.3.15) and Masonry Walls (B.2.3.33)

Manholes Fire barrier Concrete Soil Cracking Structures III.A3.TP30 3.51, 044 C, 3 Block Distortion Monitoring (B.2.3.34)

Manhole coverway Structural StyrofoamPol Air - outdoor Blistering, Structures VII.I.A-797a -3.3-1, JE, 7 insulation boards supportShelter, ymer Cracking, Monitoring 263 protection Hardening, Loss (B.2.3.34) of material, Loss of strength Manhole cover Shelter, Aluminum Air - outdoor Loss of material Structures III.B5.T-37b 3.5-1, 100 C protection Cracking Monitoring (B.2.3.34)

Manhole cover Shelter, Galvanized Air - outdoor Loss of material Structures III.A3.TP-302 3.5-1, 077 A protection steel Monitoring (B.2.3.34)

Miscellaneous Fire barrier Steel Air - outdoor Loss of material Structures III.A3.TP-302 3.5-1, 077 A structural Shelter, protection Monitoring components Structural support (B.2.3.34)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 38 of 48 Table 3.5.2-11: Yard Structures - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging NUREG2191 Table 1 Notes Function Requiring Management Item Item Management Program Miscellaneous Structural support Stainless Air - outdoor Loss of material Structures III.B5.T-37b 3.5-1, 100 A structural steel Cracking Monitoring components (B.2.3.34)

Miscellaneous Structural support Aluminum Air - outdoor Loss of material Structures III.B5.T-37b 3.5-1, 100 A structural Cracking Monitoring components (B.2.3.34)

Miscellaneous Fire barrier Steel Air with borated Loss of material Boric Acid III.B1.1.TP-3 3.5-1, 089 A structural Shelter, protection water leakage Corrosion components Structural support (B.2.3.4)

Structural bolting Structural support Steel Air - outdoor Loss of preload Structures III.A3.TP-261 3.5-1, 088 A Monitoring (B.2.3.34)

Structural bolting Structural support Steel Air - outdoor Loss of material Structures III.A3.TP-248 3.5-1, 080 A Monitoring (B.2.3.34)

Structural bolting Structural support Steel Air - outdoor Loss of material Structures III.A3.TP-274 3.5-1, 082 A Monitoring (B.2.3.34)

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

C. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program J. Neither the component nor the material and environment combination is evaluated in NUREG-2191.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 39 of 48 SLRA Table 3.5.2-11 (pages 3.5-130 and 3.5-131) revision continued:

Plant Specific Notes

1. Groundwater is considered to be water- flowing.

2. Rainfall tends to wash surfaces. However, times of significant precipitation or areas of water collection/flowing such as ground/wall interfaces are conservatively susceptible to leaching.

3. Consistent with the currently renewed licenses, concrete block manholes are underground and exposed to soil.

4. Berm surrounding the fuel oil storage tanks provides a fire barrier.

5. Whereas the NUREG-2191/2192 item calls for a plant-specific AMP, PBN credits an existing AMP consistent with SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance.

6. Fire Protection AMP in conjunction with the Structures Monitoring AMP is focused on certain fire barriers in the yard recognizing that other barriers in the yard have additional functions that are managed by the Structures Monitoring AMP or related AMP.

7. Polystyrene (polymer) inserts in yard manhole covers that have ports allowing for inspection may be susceptible to degradation though exposure to heat or sunlight is limited and are inspected by the Structures Monitoring AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 40 of 48 SLRA Table 3.5.2-13 (pages 3.5-136 to 3.5-138) is revised as follows:

Table 3.5.2-13: Component Supports Commodity Group - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Item Notes Type Function Requiring Program Item Management Anchorage / Structural Steel Air - indoor Loss of preload Structures III.A3.TP-261 3.5-1, 088 A, 2 embedment support uncontrolled Monitoring (B.2.3.34)

Anchorage / Structural Stainless Air - indoor Loss of material Structures III.B3.T-37b 3.5-1, 100 A embedment Support steel uncontrolled Monitoring (B.2.3.34)

Anchorage / Structural Steel Air - outdoor Loss of material Structures III.B3.TP-248 3.5-1, 080 A embedment support Monitoring (B.2.3.34)

Anchorage / Structural Steel Air with Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 A embedment support borated water (B.2.3.4) leakage ASME Class 2 Structural High-strength Air - indoor Cracking ASME Section XI, III.B1.1.TP-41 3.5-1, 068 B, 1 and 3 structural support steel uncontrolled Subsection IWF bolting (B.2.3.31)

ASME Class 2 Structural Steel Air - indoor Loss of preload ASME Section XI, III.B1.2.TP-229 3.5-1, 087 B, 1 and 3 structural support uncontrolled Subsection IWF bolting (B.2.3.31)

ASME Class 2 Pipe whip Steel Air with Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 B, 1 and 3 supports restraint borated water (B.2.3.4)

Structural leakage support ASME Class 2 Pipe whip Steel Air - indoor Loss of material ASME Section XI, III.B1.1.T-24 3.5-1, 091 B, 1, 3 and 3 supports restraint uncontrolled Subsection IWF Structural (B.2.3.31) support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 41 of 48 Table 3.5.2-13: Component Supports Commodity Group - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Item Notes Type Function Requiring Program Item Management ASME Class 2 Structural Steel Air - indoor Loss of ASME Section XI, III.B1.2.T-28 3.5-1, 057 A, 4 and 3 supports support uncontrolled mechanical Subsection IWF (hangers, function (B.2.3.31) guides, stops)

Building concrete Structural Concrete Air - indoor Reduction in Structures III.B2.TP-42 3.5-1, 055 A at locations of support (reinforced) uncontrolled concrete anchor Monitoring expansion and capacity (B.2.3.34) grouted anchors; grout pads for support base plates Building concrete Structural Concrete Air - outdoor Reduction in Structures III.B2.TP-42 3.5-1, 055 A at locations of support (reinforced) concrete anchor Monitoring expansion and capacity (B.2.3.34) grouted anchors; grout pads for support base plates Building concrete Structural Grout Air - outdoor Reduction in Structures III.B2.TP-42 3.5-1, 055 A, 2 at locations of support concrete anchor Monitoring expansion and capacity (B.2.3.34) grouted anchors; grout pads for support base plates

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 42 of 48 Table 3.5.2-13: Component Supports Commodity Group - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Item Notes Type Function Requiring Program Item Management Building concrete Structural Grout Air - indoor Reduction in Structures III.B2.TP-42 3.5-1, 055 A, 2 at locations of support uncontrolled concrete anchor Monitoring expansion and capacity (B.2.3.34) grouted anchors; grout pads for support base plates Component Structural Stainless Air - indoor Cracking Structures III.B2.T-37b 3.5-1, 100 A supports support steel uncontrolled Loss of material Monitoring Air - outdoor (B.2.3.34)

Component Structural Steel Air - indoor Loss of material Structures III.B4.T-43 3.5-1, 092 A supports support uncontrolled Monitoring Air - outdoor (B.2.3.34)

Component Structural Steel Air with Loss of material Boric Acid Corrosion III.B4.T-25 3.5-1, 089 A supports support borated water (B.2.3.4) leakage Electrical Shelter, Steel Air with Loss of material Boric Acid Corrosion III.B3.T-25 3.5-1, 089 A Enclosures - protection borated water (B.2.3.4)

Panels, boxes, Structural leakage cabinets, support

consoles, raceways Electrical Shelter, Steel Air - indoor Loss of material Structures III.B3.T-43 3.5-1, 092 A Enclosures - protection uncontrolled Monitoring Panels, boxes, Structural (B.2.3.34) cabinets, support

consoles, raceways

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 43 of 48 Table 3.5.2-13: Component Supports Commodity Group - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Item Notes Type Function Requiring Program Item Management Insulation Insulation Stainless Air - outdoor Cracking External Surfaces III.B2.T-37c 3.5-1, 100 C Jacket Steel Loss of material Monitoring of integrity Mechanical Components (B.2.3.23)

Insulation Insulation Aluminum Air - outdoor Cracking External Surfaces III.B2.T-37c 3.5-1, 100 C Jacket Loss of material Monitoring of integrity Mechanical Components (B.2.3.23)

Insulation Insulation Stainless Air - indoor Cracking External Surfaces III.B2.T-37c 3.5-1, 100 C Jacket Steel uncontrolled Loss of material Monitoring of integrity Mechanical Components (B.2.3.23)

Insulation Insulation Aluminum Air - indoor Cracking External Surfaces III.B2.T-37c 3.5-1, 100 C Jacket uncontrolled Loss of material Monitoring of integrity Mechanical Components (B.2.3.23)

Pipe restraints Pipe whip Steel Air with Loss of material Boric Acid Corrosion III.B2.T-25 3.5-1, 089 A and HVAC duct restraint borated water (B.2.3.4) supports Structural leakage support Pipe restraints Pipe whip Steel Air - indoor Loss of material Structures III.B2.TP-43 3.5-1, 092 A and HVAC duct restraint uncontrolled Monitoring supports Structural (B.2.3.34) support Structural bolting Structural Steel Air - indoor Loss of preload Structures III.A3.TP-261 3.5-1, 088 A support uncontrolled Monitoring (B.2.3.34)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 44 of 48 Table 3.5.2-13: Component Supports Commodity Group - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Item Notes Type Function Requiring Program Item Management Structural bolting Structural Steel Air - indoor Loss of material Structures III.B3.TP-248 3.5-1, 080 A support uncontrolled Monitoring (B.2.3.34)

Structural bolting Structural Steel Air - outdoor Loss of material Structures III.A3.TP-274 3.5-1, 082 A support Monitoring (B.2.3.34)

Structural bolting Structural High-strength Air - indoor Cracking Structures III.B1.1.TP-41 3.5-1, 068 E support steel uncontrolled Monitoring (B.2.3.34)

Vibration isolation Structural Non-metallic; Air - indoor Reduction or loss ASME Section XI, III.B1.1.T-33 3.5-1, 094 B elements support Elastomer uncontrolled of isolation Subsection IWF function (B.2.3.31)

Vibration isolation Structural Non-metallic; Air - indoor Reduction or loss Structures III.B4.TP-44 3.5-1, 094 A elements support Elastomer uncontrolled of isolation Monitoring function (B.2.3.34)

Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

B. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP has exceptions to NUREG-2191 AMP description C. Component is different, but consistent with material, environment, aging effect and aging management program listed for NUREG-2191 line item.

AMP is consistent with NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program.

Plant Specific Notes

1. RCS Class 1 major equipment supports are addressed in Table 3.5.2-1.

2. Includes epoxy grout/anchors, which are subject to the same aging effects.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 45 of 48 SLRA Table 3.5.2-13 (pages 3.5-136 to 3.5-138) revision continued:

3. Galvanized steel ASME Class 2 and 3 supports are considered same as carbon steel supports.

4. Passive portions of constant and variable spring hangers (e.g., attachment to structure).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 46 of 48 SLRA Table 3.5.2-14 (pages 3.5-139, 3.5-140) is revised as follows:

Table 3.5.2-14: Fire Barrier Commodity Group - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Requiring Aging NUREG Table Notes Function Management Management 2191 Item 1 Item Program Fire barrier Fire Calcium Silicate Air - indoor Cracking / delamination Fire Protection VII.G.A-807 3.3-1, A, 1 penetration seals barrier Board, fire retardant uncontrolled Loss of material (B.2.3.15) 269 coatings Change in material properties Separation Fire barrier Fire barrier Elastomer Air - indoor Hardening Fire Protection VII.G.A-19 3.3-1, A penetration seals uncontrolled Loss of strength (B.2.3.15) 057 Shrinkage Fire barrier Fire barrier Stainless Steel Air - indoor Loss of material Fire Protection III.B2.T-37c 3.5-1, E, 2 penetration seals uncontrolled Cracking (B.2.3.15) 100 Fire damper and Fire barrier Steel Air - indoor Loss of material Fire Protection VII.G.A-789 3.3-1, A louver frames uncontrolled Cracking (B.2.3.15) 255 Loss of strength Shrinkage Fire damper and Fire barrier Steel Air with Loss of material Boric Acid III.B1.1.TP-3 3.5-1, A louver frames borated water Corrosion 089 leakage (B.2.3.4)

Fireproofing Fire barrier Cementitious Air - indoor Cracking / delamination Fire Protection VII.G.A-8065 3.3-1, A, 1 uncontrolled Loss of material (B.2.3.15) 268 Change in material properties Separation Fire stops and Fire 3M' Interam' Air - indoor Cracking / delamination Fire Protection VII.G.A-805 3.3-1, A, 1 wraps barrier uncontrolled Loss of material (B.2.3.15) 267 Change in material properties Separation Fire stops and Fire Aluminum Air - indoor Loss of material Fire Protection III.B2.T-37c 3.5-1, E, 2 wraps barrier uncontrolled Cracking (B.2.3.15) 100 Fire stops and Fire Stainless Steel Air - indoor Loss of material Fire Protection III.B2.T-37c 3.5-1, E, 2 wraps barrier uncontrolled Cracking (B.2.3.15) 100

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 47 of 48 Table 3.5.2-14: Fire Barrier Commodity Group - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Requiring Aging NUREG Table Notes Function Management Management 2191 Item 1 Item Program Fire stops and Fire barrier Calcium Silicate Air - indoor Cracking / delamination Fire Protection VII.G.A-8076 3.3-1, A, 1 wraps Board, fire retardant uncontrolled Loss of material (B.2.3.15) 269 coatings Change in material properties Separation Fire stops and Fire barrier Ceramic Fiber, Air - indoor Cracking / delamination Fire Protection VII.G.A-8076 3.3-1, A, 1 wraps Board, Mat uncontrolled Loss of material (B.2.3.15) 269 Change in material properties Separation Generic Notes A. Consistent with component, material, environment, aging effect and aging management program listed for NUREG-2191 line item. AMP is consistent with NUREG-2191 AMP description.

E. Consistent with NUREG-2191 material, environment, and aging effect but a different aging management program is credited or NUREG-2191 identifies a plant-specific aging management program.

Plant Specific Notes

1. Consistent with SLR-ISG-Mechanical-2020-XX, Updated Aging Management Criteria for Mechanical Portions of Subsequent License Renewal Guidance.

2. Stainless steel and aluminum that is are exposed to air - indoor uncontrolled during normal plant operation are inspected under the Fire Protection (B.2.3.15) AMP that coordinates with the Externals Surfaces Monitoring of Mechanical Components AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 22 Page 48 of 48 SLRA Table 3.5.2-15 (page 3.5-141) is revised as follows:

Table 3.5.2-15: Cranes, Hoists, and Lifting Devices - Summary of Aging Management Evaluation Component Type Intended Material Environment Aging Effect Aging Management NUREG2191 Table 1 Notes Function Requiring Program Item Item Management Bridge and Trolley Structural Steel Air - indoor Cumulative TLAA - Section 4.7.6, VII.B.A-06 3.3-1, 001 A Framing, Crane support uncontrolled fatigue damage Fatigue of Cranes (Crane Rails, Monorails, Cycle Limits)

Lifting Devices Bridge and Trolley Structural Steel Air with borated Loss of Boric Acid Corrosion III.B1.1.TP-3 3.5-1, 089 A Framing support water leakage material (B.2.3.4)

Bridge and Trolley Structural Steel Air - indoor Loss of Inspection of Overhead VII.B.A-07 3.3-1, 052 A Framing support uncontrolled material Heavy Load Handling Systems (B.2.3.13)

Crane Rails Structural Steel Air with borated Loss of Boric Acid Corrosion III.B1.1.TP-3 3.5-1, 089 A support water leakage material (B.2.3.4)

Crane Rails Structural Steel Air - indoor Loss of Inspection of Overhead VII.B.A-07 3.3-1, 052 A support uncontrolled material Heavy Load Handling Systems (B.2.3.13)

Lifting Devices Structural Steel Air with borated Loss of Boric Acid Corrosion III.B1.1.TP-3 3.5-1, 089 A support water leakage material (B.2.3.4)

Lifting Devices Structural Steel Air - indoor Loss of Inspection of Overhead VII.B.A-07 3.3-1, 052 A support uncontrolled material Heavy Load Handling Systems (B.2.3.13)

Monorails Structural Steel Air with borated Loss of Boric Acid Corrosion III.B1.1.TP-3 3.5-1, 089 A support water leakage material (B.2.3.4)

Monorails Structural Steel Air - indoor Loss of Inspection of Overhead VII.B.A-07 3.3-1, 052 A support uncontrolled material Heavy Load Handling Systems (B.2.3.13)

Rail Hardware Structural Steel Air with borated Loss of Boric Acid Corrosion III.B1.1.TP-3 3.5-1, 089 A support water leakage material (B.2.3.4)

Rail Hardware Structural Steel Air - indoor Cracking Inspection of Overhead VII.B.A-730 3.3-1, 199 A support uncontrolled Loss of Heavy Load Handling material Systems (B.2.3.13)

Loss of preload

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 23 Page 1 of 3 Tendon Prestress: Clarified the 80-Year Prestress Calculation to be Used Affected SLRA Sections: Table 16-3 (Appendix A, Section 16.4, Commitment 3.b)), B.2.2.3 SLRA Page Numbers: A-64, A-65, and B-34, B-35 Description of Change:

The Point Beach Nuclear concrete containment tendon prestress analysis has been projected to the end of the Subsequent Period of Extended Operation. Additionally, the Concrete Containment Unbonded Tendon Prestress AMP Tendon Prestress AMP (Section B.2.2.3) and ASME Section XI, Subsection IWL AMP (Section B.2.3.30) will manage the effects of aging related to prestress forces on the containment tendon prestressing system so that the intended function will be adequately managed for the SPEO.

Current acceptance limits for each scheduled IWL inspection interval have been established and the 60-year projections are used with them.

SLRA Table 16-3 Appendix A, Section 16.4, Commitment 3.b), and Section B.2.2.3 are revised to clarify that the 80-year prestress calculation will be used.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 23 Page 2 of 3 SLRA Appendix A, Section 16.4, Table 16-3, pages A-64, and A-65 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 3 Concrete X.S1 Continue the PBN Concrete Containment Unbonded Tendon Prestress AMP, No later than 6 months prior Containment including enhancement to: to the SPEO, i.e.:

Unbonded Tendon PBN1: 04/05/30 Prestress a) Formalize the update of prestress calculations and trend lines after each scheduled physical inspection, which includes monitoring of PBN2: 09/08/32 (16.2.1.3) tendon forces, in accordance with RG 1.35.1.

b) Include the 80-year prestress calculation with or in place of the current, 60-year, acceptance limits in the program plan for each scheduled IWL inspection interval during the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 23 Page 3 of 3 SLRA Section B.2.3.35, page B-34, and B-35 are revised as follows:

Enhancements The following enhancements will be implemented no later than six months prior to entering the SPEO. There are no new inspections to be implemented for SLR.

Element Affected Enhancement

5. Monitoring and Trending Formalize the update of prestress calculations and trend lines after each scheduled physical inspection, which includes monitoring of tendon forces, in accordance with RG 1.35.1.

6. Acceptance Criteria Include the 80-year prestress calculation with or in place of the current, 60-year, acceptance limits in the program plan for each IWL inspection interval during the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 1 of 10 ASME Section XI, Subsection IWF AMP: Clarified Discussions for the Enhancement, Exception, Code Classes, and OE Affected Subsequent License Renewal Application (SLRA) Sections: Table 16-3 (Appendix A, Section 16.4), B.2.3.31 SLRA Page Numbers: A-103, B-225 through B-234 Description of Change:

The Point Beach Nuclear ASME Section XI, Subsection IWF AMP takes exception to NUREG-2191 with respect to the scope of the program, as ASME Class MC supports are excluded from the ASME Section XI, Subsection IWF AMP scope. To improve the justification for the exception the SLRA is modified to clearly state the ASME Section XI, Subsection IWE AMP manages the aging of the Class MC supports.

An enhancement was specified for the ASME Section XI, Subsection IWF AMP, related to control of high strength bolting. In addition to the bolting material types listed in the enhancement, ASTM F2280 twist off bolts will also require the same controls. To ensure the appropriate controls are in place in the event ASTM F2280 material twist off bolts are used in the future, this material type is added to the enhancement and commitment 32(d).

The program description includes the proper selection of lubricants to prevent or minimize cracking in high strength bolting. This description is clarified to state that molybdenum disulfide lubricants are not used.

Commitment 35(a) in Table 16-3 contained the ambiguous phrase that could indicate. To eliminate ambiguity, the words that could is being deleted.

Commitment 35(d) in Table 16-3 referred to NSSS supports. This term is corrected to refer to ASME Class 1, 2 or 3 supports to more accurately match the scope of the ASME Section XI, Subsection IWF AMP.

The operating experience discussion is also clarified to state that effectiveness reviews have been performed during the Period of Extended Operation and will continue to be performed during the Subsequent Period of Extended Operation.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 2 of 10 SLRA Table 16-3 (Page A-102 and A-103) is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 35 ASME Section XI, XI.S3 d) Augment existing procedures to specify that for structural bolting No later than 6 months prior Subsection IWF consisting of ASTM A325, ASTM F1852, ASTM F2280 and/or ASTM to the SPEO, or no later (16.2.2.31) A490 bolts, the preventive actions for storage, lubricants, and stress than the last refueling corrosion cracking potential discussed in Section 2 of RCSC (Research outage prior to the SPEO, Council for Structural Connections) publication Specification for i.e.:

Structural Joints Using ASTM A325 or A490 Bolts, will be used. PBN1: 04/05/30 Additionally, molybdenum disulfide thread lubricants will not be PBN2: 09/08/32 used.

Start the one-time e) Augment existing procedures to specify that bolting within the scope of inspections no earlier than this program is inspected for loss of integrity of bolted connections due to five years prior to the self-loosening. SPEO.

f) Augment existing procedures to specify that elastomeric or polymeric vibration isolation elements are monitored for cracking, loss of material, and hardening.

g) Perform and document a one-time inspection of an additional 5% of the sample populations for Class 1, 2, and 3 piping supports. The additional supports will be selected from the remaining population of IWF piping supports and will include components that are most susceptible to age-related degradation.

h) Augment existing procedures to include tactile inspection (feeling, prodding) of elastomeric vibration isolation elements to detect hardening if the vibration isolation function is suspect.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 3 of 10 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) i) Augment existing procedures to specify that, for NSSS ASME Class 1, 2, or 3 component supports, high-strength bolting greater than one inch nominal diameter, volumetric examination comparable to that of ASME Code,Section XI, Table IWB2500-1, Examination Category B-G-1 will be performed to detect cracking in addition to the VT3 examination. In each 10-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 25 bolts.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 4 of 10 SLRA Section B.2.3.31 (pages B225-B234) are revised as follows; Program Description The PBN ASME Section XI, Subsection IWF AMP is an existing AMP that consists of periodic visual examination of ASME Code Section XI Class 1, 2, and 3 supports for ASME piping and components for signs of degradation such as corrosion; cracking, deformation; misalignment of supports; missing, detached, or loosened support items; loss of integrity of welds; improper clearances of guides and stops; and improper hot or cold settings of spring supports and constant load supports. Bolting for Class 1, 2, and 3, piping and component supports is also included and inspected for corrosion, loss of integrity of bolted connections due to self-loosening, and material conditions that can affect structural integrity. This program will use the edition and addenda of ASME Section XI required by 10 CFR 50.55a, as reviewed and approved by the NRC staff for aging management under 10 CFR 54.

Alternatives to these requirements that are aging management related will be submitted to the NRC in accordance with 10 CFR 50.55a prior to implementation.

The ASME Section XI, Subsection IWF AMP provides inspection and acceptance criteria and meets the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, 2007 edition with addenda through 2008, and 10 CFR 50.55a(b)(2) for Class 1, 2, and 3 piping and components and their associated supports. The primary inspection method employed is visual examination. NDE indications are evaluated against the acceptance standards of ASME Code Section XI. Examinations that reveal indications are evaluated. Examinations that reveal flaws or relevant conditions that exceed the referenced acceptance standard, are expanded to include additional examinations during the current outage. The scope of inspection for supports is based on sampling of the total support population. The sample size varies depending on the ASME Code Class. The largest sample size is specified for the most critical supports (ASME Code Class 1). The sample size decreases for the less critical supports (ASME Code Class 2 and 3).

This AMP emphasizes proper selection of bolting material, lubricants, and installation torque or tension to prevent or minimize loss of bolting preload of structural bolting and cracking of high strength bolting. As noted below in the enhancement discussion, the AMP also includes the preventive actions for storage requirements of high-strength bolts and ensuring that molybdenum disulfide thread lubricants are not used for structural bolting. The requirements of ASME Code Section XI, Subsection IWF are supplemented to include volumetric examination of high strength bolting for cracking. This AMP will also include a one-time inspection within 5 years prior to the SPEO of an additional 5 percent of piping supports from the remaining IWF population that are considered most susceptible to age-related degradation.

Inspections of elastomeric vibration isolation elements to detect hardening are also included if the vibration isolation function is suspect.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 5 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

NUREG-2191 Consistency The PBN ASME Section XI, Subsection IWF AMP, with enhancements, will be consistent with one exception to NUREG-2191,Section XI.S3, ASME Section XI, Subsection IWF.

Exceptions to NUREG-2191 Inspection of supports for Class MC components under ASME Section XI, Subsection IWF is not required by 10 CFR 50.55a and PBN does not include such inspections in its IWF ISI program. This is an exception to the AMP described in Section XI.S3 of NUREG-2191, whose scope of program addresses Class MC supports. Inspection of the steel containment liner and its integral attachments (including Class MC supports) is included in the scope of the PBN ASME Section XI, Subsection IWE AMP. Applicable portions of the containment polar crane rail supports are inspected under the PBN Inspection of Overhead Heavy Load Handling Systems AMP (Section B.2.3.13), which is currently implemented as part of the PBN Structures Monitoring Program (Section B.2.3.34). Supports for each Units Containment dome truss (referred to as the construction truss in the SLR AMR for the Containment Building Structure) and the trusses themselves (which have been lowered from contact with the Containment dome) are inspected under the PBN Structures Monitoring AMP. This represents a continuation of the CLB aging management approach for these components that was approved previously by the staff. Therefore, PBN meets the intent of this NUREG-2191 program element.

Enhancements The PBN ASME Section XI, Subsection IWF AMP will be enhanced as follows for alignment with NUREG-2191. The one-time inspection will be started no earlier than five years prior to the SPEO. The enhancements will be implemented and one-time inspection completed no later than six months prior to entering the SPEO.

Element Affected Enhancement

1. Scope of Program Augment existing procedures to evaluate the acceptability of inaccessible areas (e.g., portions of supports encased in concrete, buried underground, or encapsulated by guard pipe) when conditions in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas.

1. Scope of Program Augment existing procedures to include vibration isolation elements of ASME Section XI Class 1, 2, and 3 supports within the ISI Program scope.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 6 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

Element Affected Enhancement

2. Preventive Actions Augment existing procedures to specify that whenever replacement of bolting is required, bolting material, installation torque or tension, and use of lubricants and sealants are in accordance with the guidelines of EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, EPRI TR-104213, Bolted Joint Maintenance

& Application Guide, and the additional recommendations of NUREG-1339, Resolution of Generic Safety Issue 29:

Bolting Degradation or Failure in Nuclear Power Plants.

2. Preventive Actions Augment existing procedures to specify that for structural bolting molybdenum disulfide thread lubricants are not used and for bolting consisting of ASTM A325, ASTM F1852, ASTM F2280 and/or ASTM A490 bolts, the preventive actions for storage, lubricants, and stress corrosion cracking potential discussed in Section 2 of RCSC (Research Council for Structural Connections) publication Specification for Structural Joints Using ASTM A325 or A490 Bolts, will be used.

3. Parameters Monitored or Augment existing procedures to specify that bolting within the Inspected scope of this program is inspected for loss of integrity of bolted connections due to self-loosening.

3. Parameters Monitored or Augment existing procedures to specify that elastomeric or Inspected polymeric vibration isolation elements are monitored for cracking, loss of material, and hardening.

4. Detection of Aging Effects Perform and document a one-time inspection of an additional 5% of the sample populations for Class 1, 2, and 3 piping supports. The additional supports will be selected from the remaining population of IWF piping supports and will include components that are most susceptible to age-related degradation.

4. Detection of Aging Effects Augment existing procedures to include tactile inspection (feeling, prodding) of elastomeric vibration isolation elements to detect hardening if the vibration isolation function is suspect.

4. Detection of Aging Effects Augment existing procedures to specify that, for NSSS ASME Class 1, 2 or 3 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 subsequent period of extended operation, 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 25 bolts.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 7 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

Element Affected Enhancement

5. Monitoring and Trending Augment existing procedures to increase or modify the component support inspection population when a component is repaired to as-new condition by including another support that is representative of the remaining population of supports that were not repaired.

6. Acceptance Criteria Augment existing procedures to specify that the following conditions are also unacceptable: loss of material due to corrosion or wear; debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces as intended in the design basis of the support; cracking or sheared bolts, including high-strength bolts, and anchors; loss of material, cracking, and hardening of elastomeric or polymeric vibration isolation elements that could reduce the vibration isolation function; and cracks.

Operating Experience Industry Operating Experience Degradation of threaded bolting and fasteners has occurred from boric acid corrosion, SCC, and fatigue loading (U.S. Nuclear Regulatory Commission (NRC)

Inspection and Enforcement Bulletin (IEB) 82-02, Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of PWR Plants, NRC Generic Letter 91-17, Generic Safety Issue 79, Bolting Degradation or Failure in Nuclear Power Plants). SCC has occurred in high-strength bolts used for nuclear steam supply system component supports (EPRI NP-5769). NRC Information Notice 2009-04, Age-Related Constant Support Degradation describes deviations in the supporting forces of mechanical constant supports, from code allowable load deviation, due to age-related wear on the linkages and increased friction between the various moving parts and joints within the constant support, which can adversely affect the analyzed stresses of connected piping systems.

NRC Information Notice 80-36, Failure of Steam Generator Support Bolting notified utilities of the potential for stress corrosion cracking (SCC) of high strength component support bolts. High strength (>150 ksi yield) component support bolting is used at PBN in supports associated with NSSS components (i.e., Steam Generator, Reactor Coolant Pump, and Reactor Vessel supports). PBN uses the ISI program to evaluate and monitor crack initiation and growth due to SCC, if present, in high strength low alloy steel bolts used in NSSS component supports.

INPO OE # 312397 described an industry event where control rod drive mechanism (CRDM) Supports were not added to the ISI Program, and IWF exams were not being performed. This OE was reviewed at PBN and found to be applicable to both

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 8 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

Units. Examinations of the CRDM supports were performed in the 2014 Fall Outage for Unit 1 and in the 2015 Fall Outage for Unit 2. Exams of the CRDM supports were added to the ISI database to ensure they would be examined in future intervals.

These examples provide objective evidence that industry operating experience is being reviewed and evaluated to confirm that station testing procedures are effective to maintain containment integrity.

Plant Specific Operating Experience Per the requirements of ASME Code Section XI, IWA-6000 and ASME Code Case N-532-5, PBN submits an Owners Activity Report (OAR) summarizing inservice inspections performed for each outage. OARs from 2014 to 2019 were reviewed for results applicable to IWF. The most common relevant condition discovered by the ASME Section XI, Subsection IWF ISI program at PBN has been loose fasteners in supports. To date, these examinations have been effective in managing aging effects for ASME Class 1, 2, and 3 component supports.

NRC Post-Approval site Inspections described in License Renewal Phases 2 and 4 Inspection Reports for Units 1 and 2 were reviewed regarding the PBN ASME Section XI, Subsection IWF AMP. This included a review of commitments for each unit associated with the ASME Code Section XI, Subsection IWF AMP. The inspectors confirmed that the ASME Section XI, Subsection IWF AMP and committed program enhancements were in place.

On June 30th, 2013 and on March 31, 2014, the NRC completed inspections of PBN Units 1 and 2. The resulting integrated inspection reports were reviewed regarding the PBN ASME Section XI, Subsection IWF AMP with no relevant findings identified.

The quarterly PBN ASME Section XI, Subsection IWF AMP health reports are also developed and trended. All quarterly health reports for 2015 through the first quarter of 2020 demonstrate that the PBN ASME Section XI, Subsection IWF AMP has effectively managed aging effects for ASME Class 1, 2, and 3 component supports The following review of site-specific OE demonstrates how PBN is managing aging effects associated with the PBN ASME Section XI, Subsection IWF AMP.

x During a VT-3 examination of a Unit 1 RHR pipe support in October of 2017, two jam nuts were identified to be missing and the rod between the spring and pipe clamp was misaligned. The condition was reviewed by a structural engineer and noted to be within guidance. Based on an evaluation that the rod was stable, it had not rotated, and there was no mechanism that could cause the threaded rod to unscrew from either fitting the current condition was judged to be acceptable as-is.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 9 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

x A VT-3 examination of one of the Unit 1 Containment Spray Pumps in August of 2017 noted porosity in one of the welds. The noted porosity was judged to be from original construction, with no observable indications of other damage to the weld. The porosity was not widespread through the weld and the reduction in weld capacity was judged to be minimal. As a result, it was determined that the impact on overall structural integrity would be negligible.

The vibration engineer was also consulted, and it was determined that the vibration levels recorded during periodic testing were acceptable with adequate margin. This condition was judged acceptable as-is.

x During as-left VT-3 examination on three Unit 2 RC constant supports in October of 2018, it was noted that the travel indicator on all three supports was not in between the hot and cold positions expected. It was determined that the travel indicator was positioned approximately at the cold marking which was consistent with the plant configuration at the time (Mode 5). As RCS temperature increases, the spray line would displace vertically into the expected range. The supports were judged to remain acceptable and capable of performing intended design functions. No adverse conditions were noted that would indicate any transient occurred for this section of piping.

x During a VT3 examination of the Unit 1 resistance temperature detector (RTD) Bypass Piping Support in April of 2019, a grinding cut was recorded across the horizontal channel, above the diagonal brace. It was noted that there was some paint inside of the grinding cut indicating that it was not new.

A calculation related to a previous modification was reviewed and it was concluded the damage was a result of the previous modification.

follow-on field walkdown notes identified damage/insufficient welds as part of the restoration of the removed members to the original configuration and capacity. The noted indication occurred along the horizonal section of channel that was previously removed. As part of the previous modification a repair was implemented by welding a plate over the existing damaged members, spanning beyond the cut locations. The support was analyzed and demonstrated to serve as an acceptable structural member for the applied loading without taking credit for the damaged components (other than lateral bracing of the plate for buckling concerns). As a result, the indication had no effect on the capacity of the support since the members were still adequate for the purpose of providing lateral bracing to the plate. The support was considered acceptable in the existing configuration.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 24 Page 10 of 10 SLRA Section B.2.3.31 (pages B225-B234) revision continued:

Considering the condition of the connecting welds and associated members, a repair was implemented by welding a plate over the existing damaged members, spanning beyond the cut locations, which was analyzed and demonstrated to serve as an acceptable structural member for the applied loading without taking credit for the damaged components (other than lateral bracing of the plate for buckling concerns). As a result, it was judged that the indication had no effect on the capacity of the support, since the members were still adequate for the purpose of providing lateral bracing to the plate.

The support was considered acceptable in the existing configuration.

These examples demonstrate that the inspections executed under the PBN ASME Section XI, Subsection IWF AMP and the follow-on use of the CAP are effective in evaluating degraded conditions and implementing activities to maintain component intended function.

To assess effectiveness of AMPs credited for subsequent license renewal, the AMPs are have been reviewed against the criteria provided in NEI 14-12 during the PEO and will continue to be reviewed throughout the SPEO. The most recent effectiveness review of the ASME Section XI, Subsections IWF AMP was performed in 2018. The effectiveness review covered the applicable ten program elements with particular attention on the detection of aging effects (element 4), corrective action (element 7), and operating experience (element 10). The effectiveness review found that this program continues to be effectively implemented. Full AMP effectiveness reviews are performed at least every five years.

The positive trending of PBN reviews of the AMP, initiation of corrective actions, and subsequent corrective actions prior to loss of intended function, demonstrates that the PBN ASME Section XI, Subsection IWF AMP remains effective. Additionally, the OE relative to the PBN ASME Section XI, Subsection IWF AMP provides objective evidence that the existing program will effectively monitor and manage degradation of components within the scope of the AMP.

OE will be reviewed during the SPEO such that if there is an indication that the aging effects are not being adequately managed, a corrective action will be initiated to either enhance the AMP or implement new AMPs, as appropriate. In addition, AMP effectiveness will be assessed at least every five years per NEI 14-12.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 25 Page 1 of 3 10 CFR 50 Appendix J AMP: Clarified List of Programs which Manage Aging Effects for Containment Boundary Components Affected SLRA Sections: B.2.3.32 SLRA Page Numbers: B-231 through B-232 Description of Change:

The PBN 10 CFR Part 50, Appendix J AMP description is clarified to list other related programs which manage aging effects for containment boundary components where Type B or C local leak rate testing is not performed to better describe the program scope consistent with the discussion in NUREG-2191 Section XI.S4.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 25 Page 2 of 3 SLRA Section B.2.3.32 (pages B-231 through B-232) is revised as follows:

B.2.3.32 10 CFR Part 50, Appendix J Program Description The PBN 10 CFR Part 50, Appendix J AMP is an existing AMP that was formerly part of the ASME Section XI, Subsections IWE and IWL Inservice Inspection AMP. The PBN 10 CFR Part 50, Appendix J AMP is a performance monitoring program that monitors the leakage rates through the containment system, its shell or liner, associated welds, penetrations, isolation valves, fittings, and other access openings to detect degradation of the containment pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria.

This AMP is implemented in accordance with the 10 CFR Part 50, Appendix J, NEI 94-01 (Reference ML12221A202), Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, and ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements. Additionally, this AMP is subject to the requirements of 10 CFR Part 54. PBN technical specifications were updated in 2018 to replace RG 1.163 with NEI 94-01 Revision 3-A and the conditions and limitations specified in NEI 94-01 Revision 2-A as discussed in the Appendix J Testing Program. This AMP credits the existing program required by 10 CFR Part 50, Appendix J.

The PBN containment system consists of a containment structure (containment), and a number of electrical, mechanical, equipment hatch, and personnel air lock penetrations. As described in 10 CFR Part 50, Appendix J, periodic containment leak rate tests are required to ensure that (a) leakage through these containments or systems and components penetrating these containments does not exceed allowable leakage rates specified in the PBN technical specification (TS) and (b) integrity of the containment structure is maintained during its service life. Appendix J of 10 CFR Part 50 provides two options, Option A and Option B, to meet the requirements of a containment leak rate test (LRT) program. PBN uses the performance-based approach, Option B.

The monitored parameters are leakage rates through the containment shell, containment liner, penetrations, associated welds, access openings, and associated pressure boundary components. Three types of tests (Type A, Type B, and Type C) are performed at PBN as specified by 10 CFR Part 50, Appendix J, Option B. Type A integrated leak rate tests (ILRT) determine the overall containment integrated leakage rate, at the calculated peak containment internal pressure related to the design basis loss of coolant accident. Type B (containment penetration leak rate) tests detect local leaks and measure leakage across each pressure-containing or leakage-limiting boundary of containment penetrations. Type C (containment isolation valve leak rate) tests detect local leaks and measure leakage across containment isolation valves installed in containment penetrations or lines penetrating the containment.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 25 Page 3 of 3 SLRA Section B.2.3.32 (pages B-231 through B-232) revision continued:

For containment pressure boundary components that do not receive scheduled Type B or Type C tests, the following programs manage applicable aging effects::

x ASME Section IX, Subsection IWE AMP (B.2.3.39) for the penetration assemblies; x Boric Acid Corrosion AMP (B.2.3.4) for susceptible materials; x External Surfaces Monitoring of Mechanical Components AMP (B.2.3.23);

x Fatigue Monitoring AMP (B.2.2.1);

x Closed Treated Water Systems AMP for internal surface of pertinent components; x Flow-Accelerated Corrosion AMP (B.2.3.8) for the internal surface of susceptible components in high temperature systems; x Water Chemistry AMP (B.2.3.2) for internal surface of pertinent components; as verified by the One-Time Inspection AMP (B.2.3.20) for internal surface of pertinent components.

Additionally, 10 CFR Part 50, Appendix J, requires a general visual inspection of the accessible interior and exterior surfaces of the containment structures and components to be performed prior to any Type A test and at periodic intervals between tests based on the performance of the containment system. The PBN 10 CFR Part 50, Appendix J AMP meets this requirement with its visual inspection procedures. Additionally, the PBN 10 CFR Part 50, Appendix J AMP inspections may be performed in conjunction with the PBN AMP associated with ASME Code Section XI, Subsections IWE and IWL, to ensure that all evidence of structural deterioration that may affect the containment structure leakage, integrity, or the performance of the Type A test is identified. Furthermore, the combination of Type B Appendix J LLRTs, general visual examinations and ASME Section IX, Subsection IWE AMP (B.2.2.3.39) inspections will be supplemented by surface or enhanced visual examinations of non-piping penetrations (hatches, electrical penetrations etc.) subject to cyclic loading to detect potential cracking.

When leakage rates do not meet the acceptance criteria, an evaluation is performed to identify the cause of the unacceptable performance and appropriate corrective actions are taken.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 26 Page 1 of 4 Masonry Walls AMP: Clarified an Enhancement Affected SLRA Sections: Table 16-3 (Appendix A, Section 16.4), B.2.3.33 SLRA Page Numbers: A-104, B-236 Description of Change:

The PBN Masonry Walls AMP Element 3 (Parameters Monitored or Inspected) includes an enhancement to monitor and inspect for spalling, scaling, shrinkage and/or separation as well as loss of material at the mortar joints, and gaps between the supports and masonry walls that could potentially impact the intended function or potentially invalidate its evaluation basis. The enhancement in Element 6 (Acceptance Criteria) only lists acceptance criteria related to cracks and gaps between supports and masonry walls.

In order to clearly align with the GALL-SLR XI.S5 Masonry Walls AMP, the enhancement in Element 6 of the PBN Masonry Walls AMP is updated to include acceptance criteria related to all of the aging effects that are included in NUREG-2191 Section XI.S5 Element 6 (Acceptance Criteria).

In addition, an incorrect cross-reference/link in SLRA Section B.2.3.33 is deleted.

Accordingly, SLRA Table 16-3 (Appendix A, Section 16.4) and Section B.2.3.33 are revised to clarify the enhancement and delete the incorrect cross-reference/link.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 26 Page 2 of 4 SLRA Appendix A, Section 16.4, Table 16-3, page A-104 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 37 Masonry Walls XI.S5 Continue the existing PBN Masonry Walls AMP, including enhancement to: No later than 6 months prior (16.2.2.33) a) Revise implementing procedures to also monitor and inspect for spalling, to the SPEO, i.e.:

scaling, shrinkage and/or separation as well as loss of material at the PBN1: 04/05/30 mortar joints, and gaps between the supports and masonry walls that PBN2: 09/08/32 could potentially impact the intended function or potentially invalidate its evaluation basis.

b) Revise implementing procedures to also include specific monitoring, measurement, and trending of widths and lengths of cracks and of gaps between supports and masonry walls.

c) Revise implementing procedures to ensure degraded conditions (shrinkage and/or separation, cracking of masonry walls, cracking or loss of material at the mortar joints, also include specific assessment of the acceptability of crack widths and lengths and gaps between supports and masonry walls) are assessed against the evaluation basis to confirm that the degradation has not invalidated the original evaluation assumptions or impacted the capability to perform the intended functions.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 26 Page 3 of 4 SLRA Section B.2.3.33, page B-236 is revised as follows:

Element Affected Enhancement

3. Parameters Monitored or Inspected Revise implementing procedures to also monitor and inspect for spalling, scaling, shrinkage and/or separation as well as loss of material at the mortar joints, and gaps between the supports and masonry walls that could potentially impact the intended function or potentially invalidate its evaluation basis.

5. Monitoring and Trending Revise implementing procedures to also include specific monitoring, measurement, and trending of widths and lengths of cracks and of gaps between supports and masonry walls.

6. Acceptance Criteria Revise implementing procedures to ensure degraded conditions (shrinkage and/or separation, cracking of masonry walls, cracking or loss of material at the mortar joints, also include specific assessment of the acceptability of crack widths and lengths and gaps between supports and masonry walls) are assessed against the evaluation basis to confirm that the degradation has not invalidated the original evaluation assumptions or impacted the capability to perform the intended functions.

Operating Experience Industry Operating Experience Since 1980, masonry walls that perform an intended function have been systematically identified through licensee programs in response to NRC IEB 80-11, NRC Generic Letter 87-02, and 10 CFR 50.48. NRC IN 87-67 documented lessons learned from the NRC IEB 80-11 program and provided recommendations for administrative controls and periodic inspection to provide reasonable assurance that the evaluation basis for each safety-significant masonry wall is maintained.

NUREG-1522 documents instances of observed cracks and other deterioration of masonry-wall joints at nuclear power plants. Whether conducted as a stand-alone program or as a part of structures monitoring, a masonry wall AMP that incorporates

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 26 Page 4 of 4 SLRA Section B.2.3.33, page B-236 revision continued:

the recommendations delineated in NRC IN 87-67 provides reasonable assurance that the intended functions of masonry walls within the scope of license renewal are maintained for the SPEO.

Plant Specific Operating Experience Annual Summary reports are maintained for the Structures Monitoring Program, which includes the inspection and repair activities for masonry walls. These summary reports record conditions requiring evaluation or corrective action by building and status of the corrective action implemented for each degradation. The PBN Structures Monitoring AMP (Section B.2.3.34) contains an overview of the annual summary reports.

The following review of plant-specific OE demonstrates how PBN is managing aging effects associated with the PBN Masonry Walls AMP (Section B.2.3.34).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 1 of 6 Structures Monitoring AMP: Clarified Procedures and Enhancements and Added Enhancements Affected SLRA Sections: Table 16-3 (Appendix A, Section 16.4), B.2.3.34 SLRA Page Numbers: A-105, A-106, B-239, B-240 Description of Change:

Changes affecting scoping and screening of plant structures and/or structural components are included in Attachment 22, Plant Structures Scoping and Screening.

Updates to the PBN Structures Monitoring AMP include:

1) The implementing procedure for the PBN Structures Monitoring AMP currently requires that the responsible engineer to be a registered professional engineer or a degreed civil engineer from an accredited college or university with two years minimum experience in structural engineering for nuclear structures.

The guidance in NUREG-2191 (GALL-SLR)Section XI.S6 states that the qualifications of inspection and evaluation personnel specified in ACI (American Concrete Institute) 349.3R are acceptable for inspection of concrete structures.

ACI 349.3R requires the responsible engineer to be either: a licensed professional engineer, knowledgeable in the design, evaluation, and in-service inspection of concrete structures and performance requirements of nuclear safety-related structures; or a civil or structural engineering graduate with at least 10 years experience in the design, construction, and inspection of concrete structures, and with knowledge of the performance requirements of nuclear safety-related structures and potential degradation processes.

The PBN Structures Monitoring AMP is updated to include a new enhancement in Section B.2.3.34 and a new commitment in Table 16-3 (Appendix A, Section 16.4) to align the qualification requirements in the implementing procedure with the requirements in ACI 349.3R.

2) The implementing procedure for the PBN Structures Monitoring AMP currently allows for accessible areas subject to similar conditions (material, environment, etc.) to be evaluated in lieu of inaccessible areas. In order to more closely align with GALL-SLR Section XI.S6, the PBN Structures Monitoring AMP is updated to include a new enhancement to clarify that accessible areas subject to similar conditions may be inspected in lieu of inaccessible areas, and to include guidance for evaluating the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to the inaccessible areas.

3) SLRA Section B.2.3.34 includes an enhancement to Element 2 regarding monitoring of concrete when in-leakage or groundwater infiltration is identified. SLRA Table 16-3 (Appendix A, Section 16.4) contains a similar commitment (Commitment # 38(e)) but does not include all of the details that are in the enhancement in Section B.2.3.34. For clarity, the commitment in Table 16-3 is revised to include the same details as the enhancement in Section B.2.3.34.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 2 of 6

4) An enhancement is added to ensure that baseline inspections have been established for all structures within the scope of SLR prior to entering the subsequent period of extended operation.

5) An enhancement is added to include polystyrene foam that is mounted to the underside of manhole covers in the scope of the PBN Structures Monitoring AMP.

6) SLRA Section B.2.3.34 includes and enhancement to Element 2 regarding preventive actions to ensure bolting integrity is maintained. SLRA Table 16-3 (Appendix A, Section 16.4) contains a similar commitment (Commitment # 38(b)) but does not include all of the details that are in the enhancement in Section B.2.3.34. For clarity, the commitment in Table 16-3 is revised to include the same details as the enhancement in Section B.2.3.34.

Accordingly, SLRA Table 16-3 and Section B.2.3.34 are revised to update the program enhancements.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 3 of 6 SLRA Table 16-3 (Appendix A, Section 16.4), pages A-105 and A-106 are revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 38 Structures XI.S6 Continue the existing PBN Structures Monitoring AMP, including enhancement to: No later than 6 months prior Monitoring a) Revise inspection procedures to include guidance and acceptance criteria to the SPEO, i.e.:

(16.2.2.34) on inspections of stainless steel and aluminum components for pitting and PBN1: 04/05/30 crevice corrosion, and evidence of cracking due to SCC. Perform an PBN2: 09/08/32 evaluation if stainless steel or aluminum surfaces exhibit evidence of SCC, pitting, or crevice corrosion.

b) Revise inspection procedure scope to include polystyrene foam that is mounted to the underside of manhole covers as an elastomer material.

c)b)Revise implementing procedures to addressinclude preventive actions to ensure bolting integrity for replacement and maintenance activities by specifying proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high strength bolting. Also, ensure proper selection and storage of high strength bolting in accordance with Section 2 of the Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts.

d)c)Revise inspection procedures to additionally inspect for the following items:

x Increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation in concrete structures.

x Loss of material and loss of strength for elastomers.

x Pitting and crevice corrosion, and evidence of cracking due to SCC for stainless steel and aluminum components.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 4 of 6 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) x Confirmation of the absence of water in-leakage through concrete.

e)d)Revise inspection procedures to include guidance on MEB inspection for loss of material (external bus duct enclosure surfaces and structural supports) and elastomer degradation (exterior housing gaskets, boots, and sealants).

f)e) Clarify that if ground water leakage is identified then engineering evaluation, more frequent inspections, or destructive testing of affected concrete (to validate properties and determine pH) are required. When leakage volumes allow, assessments may include analysis of the leakage pH, along with mineral, chloride, sulfate, and iron content in the water.

g) Revise inspection procedure to specify that the responsible engineer (RE) shall be a registered professional engineer with knowledge in the design, evaluation, and in-service inspection of concrete structures and performance requirements of nuclear safety-related structures; or a degreed civil or structural engineer with at least ten years experience in the design, construction, and inspection of concrete structures, with knowledge of the performance requirements of nuclear safety-related structures and potential degradation processes.

h) Revise inspection procedure to specify that accessible areas subject to similar conditions (material, environment, etc.) may be inspected in lieu of inaccessible areas, and include guidance for evaluating the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to the inaccessible areas.

i) Ensure quantitative baselines have been established for all structures within the scope of LR prior to entering the SPEO.

j)f) Revise inspection procedure to include the following acceptance criteria:

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 5 of 6 SLRA Section B.2.3.34, pages B-239 and B-240 are revised as follows:

Element Affected Enhancement

1. Scope Update the governing AMP procedure and other applicable procedures to add stainless steel and aluminum as a material that is inspected for pitting and crevice corrosion, and evidence of cracking due to SCC.

Update the governing AMP procedure scope to include polystyrene foam that is mounted to the underside of manhole covers as an elastomer material.

2. Preventive Actions Update the governing AMP procedure and other applicable procedures to include preventive actions to ensure bolting integrity for replacement and maintenance activities by specifying proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high strength bolting. Also, ensure proper selection and storage of high strength bolting in accordance with Section 2 of the Research Council for Structural Connections publication, Specification for Structural Joints Using High Strength Bolts.

3. Parameters Monitored or Update the governing AMP procedure and other applicable Inspected procedures to additionally inspect the following elements:

x Concrete Structures will be inspected for increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

x Elastomer will also be inspected for loss of material and loss of strength.

x Pitting and crevice corrosion and evidence of cracking due to SCC for stainless steel and aluminum components x Concrete will be monitored to confirm the absence of water in-leakage

4. Detection of Aging Effects Update the governing AMP procedure and other applicable procedures to include guidance on inspections for pitting and crevice corrosion, and evidence of cracking due to SCC for stainless steel and aluminum components.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 27 Page 6 of 6 SLRA Section B.2.3.34, pages B-239 and B-240 revision continued:

Element Affected Enhancement Update the governing AMP procedure and other applicable procedures to include guidance on MEB inspection for loss of material (external bus duct enclosure surfaces and structural supports) and elastomer degradation (exterior housing gaskets, boots, and sealants).

Update the governing AMP procedure and other applicable procedures to clarify that if ground water leakage is identified then engineering evaluation, more frequent inspections, or destructive testing of affected concrete (to validate properties and determine pH) are required. When leakage volumes allow, assessments may include analysis of the leakage pH, along with mineral, chloride, sulfate and iron content in the water.

Update the governing procedure to specify that the responsible engineer (RE) shall be a registered professional engineer with knowledge in the design, evaluation, and in-service inspection of concrete structures and performance requirements of nuclear safety-related structures; or a degreed civil or structural engineer with at least ten years experience in the design, construction, and inspection of concrete structures, with knowledge of the performance requirements of nuclear safety-related structures and potential degradation processes.

Revise inspection procedure to specify that accessible areas subject to similar conditions (material, environment, etc.) may be inspected in lieu of inaccessible areas, and include guidance for evaluating the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to the inaccessible areas.

5. Monitoring and Trending Ensure quantitative baselines have been established for all structures within the scope of LR prior to entering the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 28 Page 1 of 4 Water Control Structures AMP: Added an Enhancement and Revised OE Affected SLRA Sections: Table 16-3 (Appendix A, Section 16.4), B.2.3.35 SLRA Page Numbers: A-106, B-245, B-246 Description of Change:

The PBN Water-Control Structures AMP is implemented by the same governing procedure that also implements the PBN Structures Monitoring AMP. The PBN Structures Monitoring AMP, as described in SLRA Section B.2.3.34, contains an enhancement to the implementing procedure to include preventive actions to provide reasonable assurance that structural bolting integrity is maintained. The PBN Water-Control Structures AMP did not include a similar enhancement, and instead credited the PBN Structures Monitoring AMP for managing preventive actions for bolting within the scope of the program.

In order to more clearly align with GALL-SLR Section XI.S7, the PBN Water-Control Structures AMP is updated to include an enhancement to address preventive actions for bolting.

Accordingly, SLRA Table 16-3 (Appendix A, Section 16.4) and Section B.2.3.35 are revised to include the additional enhancement.

In addition, the operating experience discussion in Section B.2.3.35 is revised to address leakage that was recently identified in the Circulating Water Pumphouse (CWPH).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 28 Page 2 of 4 SLRA Appendix A, Section 16.4, Table 16-3, page A-106 is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 39 Water-Control XI.S7 Continue the existing PBN Water-Control Structures AMP, including enhancement No later than 6 months prior Structures to: to the SPEO, i.e.:

(16.2.2.35) a) Revise implementing procedures to include preventive actions to PBN1: 04/05/30 ensure bolting integrity for replacement and maintenance activities PBN2: 09/08/32 by specifying proper selection of bolting material and lubricants, and appropriate install ation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting. For structural bolting consisting of ASTM A325, ASTM A490, ASTM F1852 and/or ASTM F2280 bolts, the preventive actions for storage, lubricant selection, and bolting and coating material selection discussed in Section 2 of the Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts, will be used.

b)a) Revise the implementing procedure to also monitor concrete to confirm the absence of water leakage.

c)b) Revise the implementing procedure to include provisions for special inspections immediately following the occurrence of significant natural phenomena, such as large floods, earthquakes, tornadoes, or intense local rainfalls.

d)c) Revise the implementing procedure to clarify that if water leakage is identified, then engineering evaluation, more frequent inspections, or destructive testing of affected concrete (to validate properties and determine pH) are required.

e)d) Revise the implementing procedure to indicate that loose bolts and nuts are unacceptable unless they are determined to be acceptable by engineering evaluation or subject to corrective actions.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 28 Page 3 of 4 SLRA Section B.2.3.35, page B-246 is revised as follows:

Enhancements The following enhancements will be implemented no later than six months prior to entering the SPEO. There are no new inspections to be implemented for SLR.

Element Affected Enhancement

2. Preventive Actions Revise implementing procedures to include preventive actions to ensure bolting integrity for replacement and maintenance activities by specifying proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting. For structural bolting consisting of ASTM A325, ASTM A490, ASTM F1852 and/or ASTM F2280 bolts, the preventive actions for storage, lubricant selection, and bolting and coating material selection discussed in Section 2 of the Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts, will be used.

3. Parameters Monitored or Revise the implementing procedure to also monitor concrete Inspected to confirm the absence of water leakage.

4. Detection of Aging Effects Revise the implementing procedure to include provisions for special inspections immediately following the occurrence of significant natural phenomena, such as large floods, earthquakes, tornadoes, or intense local rainfalls.

4. Detection of Aging Effects Revise the implementing procedure to clarify that if water leakage is identified, then engineering evaluation, more frequent inspections, or destructive testing of affected concrete (to validate properties and determine pH) are required.

6. Acceptance Criteria Revise the implementing procedure to indicate that loose bolts and nuts are unacceptable unless they are determined to be acceptable by engineering evaluation or subject to corrective actions.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 28 Page 4 of 4 SLRA Section B.2.3.35, page B-245 is revised as follows:

x In 2018, underwater cracks were identified in the forebay walls and floor. An evaluation determined that the identified cracks were existing and had been present for some time. Pressure washing was used to track and clean the crack, which thereby removed some of the spalled concrete, giving the appearance of new cracks. The observations were entered into the Structures Monitoring Program to be tracked and trended, so that the areas will be revisited during future inspections.

x In 2021, leakage was identified in the CWPH roof at the Diesel-Driven Fire Pump (DDFP) Exhaust Pipe. The leakage was dripping onto the DDFP starting batteries but was not affecting the battery terminals. The leakage was originating from the flashing around the DDFP exhaust stack. A drip catch was installed for temporary mitigation.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 1 of 33 Containment Structure: AMR, Penetration Fatigue and IWE AMP Changes Affected SLRA Sections: Table 2.4-1, Section 3.5.2.2.1.3, Sections 3.5.2.2.1.5 and 3.5.2.2.1.6, Table 3.5-1, Table 3.5.2-1, Table 4.1.5-3, Section 4.6, Section 16.2.2.29, Table 16-3 (Appendix A, Section 16.4), and Section B.2.3.29 SLRA Page Numbers: 2.4-5, 2.4-6, 3.5-20, 3.5-21 to 3.5-23, 3.5-48, 3.5-49, 3.5-53, 3.5-79, 3.5-80, 3.5-82 to 3.5-85, 3.5-87, 3.5-88, 3.5-91, 3.5-92, 3.5-93, 3.5-94, 3.5-96, 4.1-7, 4.6-3, A-33, A-100 to A-102, and B-213 to B-215 Description of Changes:

SLRA Sections 2.4.1 and 3.5 text and tables as well as related Sections 4.6, Appendix A (16.2.2.29) and Appendix B (B.2.3.29) are revised, in the order of their appearance in the SLRA, to clarify:

x Radiant energy shields are no longer credited.

x Enhancements from LR commitments #71 and #72 are in effect (and continued through the life of the plant).

x No fatigue waiver could be located for stainless steel penetration assemblies and fuel transfer tube assemblies. As such, the penetrations that involve dissimilar metal welds are susceptible to a cyclic load cracking aging effect. These penetrations that are for high temperature systems are also susceptible to a cracking due to SCC aging effect.

x Sliding surfaces are managed by ASME Section XI, Subsection IWF AMP.

x Row added for galvanized steel Class 1 piping supports.

x Plant specific note for components that are part of the Containment pressure boundary or internal to Containment and also have a fire barrier function as evaluated in the Fire Protection Program Design Document x Fatigue waiver is for steel penetrations only.

x Additional details on supplemental examinations, Commitments 33(d), 33(e) and 33(f).

x Review of PBN operating experience has not identified any findings that would trigger supplemental inspections of the containment liner

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 2 of 33 SLRA Table 2.4-1 (pages 2.4-5 and 2.4-6) is revised as follows:

Table 2.4-1 Containment Structure and Internal Structural Components Subject to Aging Management Review Component Type Intended Function(s)

Air lock, equipment hatches and accessories Fire barrier Pressure boundary Concrete Foundation / Basemat Direct flow Pressure boundary Structural support Concrete Walls, Buttresses, Dome and Ring Girder Fire barrier Flood barrier Missile barrier Pressure boundary Shelter, protection Structural support Concrete Internal Columns, Beams, Slabs and Walls Fire barrier Flood barrier Missile barrier Shelter, protection Structural support Concrete Tendon Gallery Walls Shelter, protection Construction truss Structural support H-Piles Structural support Fuel transfer tube (including penetration sleeves, Fire barrier expansion joints and blind flange) Pressure boundary Radiation shielding Structural support Liners (refueling cavity), and covers (sand box, Unit 1 Fire barrier sump A strainer) Pressure boundary Radiation shielding Liners (reactor cavity) Radiation shielding Structural support Liner plate (containment) Direct flow Fire barrier Pressure boundary Structural support Liner plate and keyway channels Direct flow Pressure boundary Structural support Liner plate anchors and attachments Pressure boundary Structural support Liner plate moisture barrier (sealing compound) Shelter, protection Miscellaneous structural components1 Structural support Penetration assemblies (elastomer) Pressure boundary Structural support 1

Miscellaneous structural components inside Containment include ladders, stairs, handrails, gratings such as Unit 1 flow diverters, platforms, and the RV core barrel support stand.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 3 of 33 SLRA Table 2.4-1 (pages 2.4-5 and 2.4-6) revision continued:

Table 2.4-1 Containment Structure and Internal Structural Components Subject to Aging Management Review Component Type Intended Function(s)

Penetration assemblies (Electrical) Fire barrier Pressure boundary Structural support Penetration assemblies (Mechanical) Pressure boundary Structural support Penetration sleeves (Electrical) Pressure boundary Structural support Penetration sleeves (Mechanical) Pressure boundary Structural support Pressure-retaining bolting Pressure boundary Structural support Primary shield wall (and biological shield wall) Radiation shielding Shelter, protection Structural support Radiant energy shields Fire barrier RC Class 1 supports Structural support RC Class 1 support bolting Structural support Reactor cavity seal ring Pressure boundary Refueling components (containment upender, davit arm) Structural support Service Level I coatings Maintain adhesion Sliding surfaces Structural support Tendons (post-tensioning system) Structural support Tendon anchorage and attachments Pressure boundary Structural support Thermal Insulation (high temperature penetrations) Insulate (thermal)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 4 of 33 SLRA Section 3.5.2.2.1.3 (page 3.5-20) is revised as follows:

manage this aging effect. If corrosion is significant, recoating of the torus is recommended. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR).

3) Loss of material due to general, pitting, and crevice corrosion could occur in steel torus ring girders and downcomers of Mark I containments, downcomers of Mark II containments, and interior surface of suppression chamber shell of Mark III containments. The existing program relies on ASME Code Section XI, Subsection IWE to manage this aging effect. Further evaluation is recommended of plant-specific programs to manage this aging effect if corrosion is significant. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of this SRP-SLR).

PBN is a PWR, therefore, torus corrosion in a BWR, items 2) and 3) above, is not applicable. For item 1 above, corrosion in inaccessible areas of the steel liner plate at PBN was addressed as part of the initial license renewal effort. At the time, liner corrosion due to borated water leakage was identified in both units and ASME Code Subsection IWE augmented inspections performed. The bottom containment liner plate (floor) is covered by an eighteen-inch thick concrete floor (and is therefore considered inaccessible). PBN LR commitments #71 and #72 enhanced the ASME Section XI, Subsection IWE and IWL Inservice Inspection Program regarding acceptance criteria for liner thickness, an overall approach which the NRC staff found acceptable in detecting and correcting flaws in the containment liner plates.

These enhancements are in-effect (and continued through the life/license of the plant).

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 5 of 33 SLRA Sections 3.5.2.2.1.5 and 3.5.2.2.1.6 (pages 3.5-21 to 3.5-23) are revised as follows:

3.5.2.2.1.5 Cumulative Fatigue Damage Evaluations involving time-dependent fatigue, cyclical loading, or cyclical displacement of metal liner, metal plates, suppression pool steel shells (including welded joints) and penetrations (including personnel airlock, equipment hatch, control rod drive (CRD) hatch, penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of PWR and BWR containments and BWR vent header, vent line bellows, and downcomers may be TLAAs as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The evaluation of this TLAA is addressed in Section 4.6, Containment Liner Plates Metal Containments, and Penetrations Fatigue Analysis, and for cases of plant-specific components, in Section 4.7 Other Plant-Specific Time-Limited Aging Analyses, of this SRP-SLR. For plant-specific cumulative usage factor calculations, the method used is appropriately defined and discussed in the applicable TLAAs.

Cumulative fatigue damage for the PBN liner and piping (and ventilation) penetrations for the containment structure that do not include dissimilar metal welds (DMWs) is addressed in the Containment Liner Plate, Metal Containments, and Penetrations Fatigue TLAA, Section 4.6, for SLR.

However, a fatigue analysis or waiver for non-piping containment penetrations (i.e.,

equipment hatch, personnel locks, and electrical) and for piping penetrations that include DMWs, and fuel transfer tube and expansion joints could not be located in the existing documentation. As such, cumulative fatigue damage (cracking due to cyclic loading evidenced as cracking) for non-piping penetrations, piping penetrations with DMWs, and the fuel transfer tube/expansion joints will be managed for SLR by the ASME Section XI, Subsection IWE (B.2.3.29) AMP and 10 CFR Part 50, Appendix J (B.2.3.32) AMP. Also, cumulative fatigue damage cracking due to cyclic loading, evidenced as cracking, for high-temperature stainless steel system penetrations and for the transfer tube penetration assembly are addressed further in Section 3.5.2.2.1.6 below.

3.5.2.2.1.6 Cracking Due to Stress Corrosion Cracking Stress corrosion cracking (SCC) of stainless steel (SS) penetration sleeves, penetration bellows, vent line bellows, suppression chamber shell (interior surface), and dissimilar metal welds could occur in PWR and/or BWR containments. The existing program relies on ASME Code Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to manage this aging effect.

Further evaluation, including consideration of SCC susceptibility and applicable operating experience (OE) related to detection, is recommended of additional appropriate examinations/evaluations implemented to detect this aging effect for these SS components and dissimilar metal welds.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 6 of 33 SLRA Sections 3.5.2.2.1.5 and 3.5.2.2.1.6 (pages 3.5-21 to 3.5-23) revision continued:

Cracking due to SCC was also addressed as part of the initial license renewal effort.

Typical details for containment piping and fuel transfer penetrations are provided in the UFSAR [Figures 5.1-2, and 5.1-20]. These penetration assemblies (e.g.,

sleeves, flued heads, or caps), are carbon steel or stainless steel depending on the system. The fuel transfer penetration is also stainless steel. The fuel transfer penetration also includes bellows that function as barriers against leakage of refueling water from either the fuel transfer canal or refueling cavities inside containment. These bellows do not perform containment integrity functions.

Provision is made, by use of continuous leak chase channels, for test pressurizing all welds essential to the integrity of the penetration during plant operation.

Furthermore, stainless steel penetrations may involve dissimilar metal welds (DMWs) to the carbon steel liner plate or penetration sleeve. Carbon steel is not susceptible to SCC and stainless steel, as well as DMWs, require a high temperature (>140°F) and/or an aggressive chemical environment (e.g. exposure to chlorides, halides) for SCC. Stainless steel process pipe containment penetrations (CPP), some of which have multiple positions and services, include:

1(2)CPP-7, 8 - Residual Heat Removal

1(2)CPP Drain from Reactor Coolant Drain Tank

1(2)CPP Letdown

1(2)CPP-11, 29 - RCP Seal Water Return

1(2)CPP Cold Leg Injection

1(2)CPP N2 to Pressurizer Relief Tank

1(2)CPP Reactor Vessel Injection

1(2)CPP Charging

1(2)CPP Hot Leg Injection

1(2)CPP Hot Leg Sample

1(2)CPP Spare

1(2)CPP-31, 32 - Containment Pressure Transmitters

1(2)CPP Gas Analyzer Sample from Pressurizer Relief Tank

1(2)CPP-54, 55 - Containment Spray

1(2)CPP Drain from Containment Sump

1(2)CCP Fuel Transfer The containment bulk ambient temperature during normal plant operation is less than or equal to 120°F and localized temperatures at penetrations are less than 200°F by design, as clarified in Section 3.5.2.2.1.2 above. Stainless steel penetrations, and any DMWs, associated with high temperature systems are exposed to temperatures

>140°F and may be susceptible to SCC. These same stainless-steel penetrations, and any DMWs, as well as the fuel transfer tube assembly are also susceptible to

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 7 of 33 SLRA Sections 3.5.2.2.1.5 and 3.5.2.2.1.6 (pages 3.5-21 to 3.5-23) revision continued:

cyclic loading as described in Section 3.5.2.2.1.5 above. However, there has been no site OE of cracking of these stainless-steel penetrations, DMWs, or of the fuel transfer penetration.

Therefore, cracking of stainless-steel penetrations, and any DMWs, for containment penetrations associated with high-temperature systems will be managed by the ASME Section XI, Subsection IWE (B.2.3.29) AMP and 10 CFR Part 50, Appendix J (B.2.3.32) AMP. A supplemental one-time inspection of a representative sample of stainless-steel penetrations or DMWs associated with high-temperature stainless steel piping systems will be included as an enhancement to the ASME Section XI, Subsection IWE (B.2.3.29) AMP to provide confirmation that no additional examinations/evaluations are required. Consistent with the guidance of NUREG-2191, a representative sample size of 20 percent of the population at each unit will be inspected. Stainless steel lines penetrating the containment shell normally having high temperatures and normally in operation include: Letdown (1(2)CPP-10), Cold Leg Injection (1(2)CPP-3), Reactor Vessel Injection (1(2)CPP-22), Charging (1(2)CPP-26), Hot Leg Injection (1(2)CPP-27), and Hot Leg Sample (1(2)CPP-28); i.e., six (6) per unit. As a result, two (2) of the stainless-steel penetrations or DMWs associated with high-temperature stainless steel piping systems and plus the stainless-steel fuel transfer tube will be inspected on each unit (i.e., three (3) supplemental one-time inspections per unit). Additionally, if SCC is detected as a result of the supplemental one-time inspections, additional inspections will be conducted in accordance with the site's corrective action process as described for the ASME Section XI, Subsection IWE (B.2.3.29) AMP.

Furthermore, the high-temperature stainless steel system penetrations that are susceptible to SCC are also the leading indicators for cyclic loading of penetrations involving dissimilar metals, as the cycles would be more severe than for other stainless steel penetrations with lower normal operating temperatures. In addition, supplemental inspections performed by the ASME Section XI, Subsection IWE AMP (B.2.3.29) will detect evidence of cracking.

Therefore, the piping penetrations with DMWs and the fuel transfer tube assembly do not require separate inspection for cyclic loading unless cyclic load cracking is detected for non-piping penetrations.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 8 of 33 SLRA Table 3.5-1, items 009 and 010 (pages 3.5-48 and 3.5-49) are revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 006 This line item only applies to BWRs.

3.5-1, 007 This line item only applies to BWRs.

3.5-1, 008 Prestressing system: tendons Loss of prestress due TLAA, SRP-SLR Yes (SRP-SLR Consistent with NUREG-2191.

to relaxation: shrinkage; Section 4.5, - Section 3.5.2.2.1.4) Concrete containment tendon prestress creep; elevated "Concrete TLAA is addressed in Section 4.5.

temperature Containment Further evaluation is documented in Tendon Section 3.5.2.2.1.4.

Prestress" and/or SRP-SLR Section 4.7, "

Other Plant-Specific TLAA 3.5-1, 009 Metal liner, metal plate, Cumulative fatigue TLAA, SRP-SLR Yes (SRP-SLR Consistent with NUREG-2191 for liner and personnel airlock, equipment damage due to fatigue "Containment Section 3.5.2.2.1.5) most mechanical penetration assemblies as hatch, control rod drive (CRD) Liner Plate, Metal clarified below.

hatch, penetration sleeves; Containments, Containment Liner Plate, and Penetrations penetration bellows, steel and Penetrations Fatigue TLAA is addressed in Section 4.6.

elements: torus; vent line; Fatigue Analysis" Cyclic loading of Airlocks, Hatches and vent header; vent line Electrical Penetration assemblies are bellows; downcomers, addressed for item number 3.5-1, 027.

suppression pool shell; unbraced downcomers, steel Further evaluation is documented in elements: vent header; Section 3.5.2.2.1.5.

downcomers In addition, cracking (cyclic or SCC) of high-temperature mechanical penetration assemblies that are stainless steel or include dissimilar metal welds is addressed for item number 3.5-1, 010 as leading indicators for

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 9 of 33 Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program cyclic load cracking of other stainless steel/DMW piping penetrations.

3.5-1, 010 Penetration Sleeves Cracking due to SCC AMP XI.S1, Yes (SRP-SLR Consistent with NUREG-2191.

Penetration bellows ASME Section 3.5.2.2.1.6) The ASME Section XI, Subsection IWE Section XI, (B.2.3.29) AMP and 10 CFR Part 50, Subsection IWE, Appendix J (B.2.3.32) AMP manage cracking and AMP XI.S4, of stainless steel and dissimilar metal weld 10 CFR Part 50, piping penetration assemblies and the fuel Appendix J transfer tube assemblies exposed to an uncontrolled indoor air environment.

Further evaluation is documented in Section 3.5.2.2.1.6.

3.5-1, 011 Concrete (inaccessible Loss of material Plant-specific Yes (SRP-SLR Containment structure is located inside the areas): dome; wall; basemat; (spalling, scaling) and AMP or Section 3.5.2.2.1.7) façade building and protected from weather.

ring girders; buttresses cracking due to AMP XI.S2 However, PBN does experience freeze-thaw freeze- thaw ASME conditions in the winter. As such, the ASME Section XI, Subsection IWL (B.2.3.30) AMP Section XI, and Structures Monitoring (B.2.3.34) AMP, Subsection which includes opportunistic inspection of IWL, and/or inaccessible concrete, would identify any AMP XI.S6, degradation that would allow groundwater to Structures penetrate the containment basemat or Monitoring, adjacent tendon gallery walls.

enhanced as Further evaluation is documented in necessary Section 3.5.2.2.1.7.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 10 of 33 SLRA Table 3.5-1, item 027 (page 3.5-53) is revised as follows:

Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program 3.5-1, 024 Concrete (inaccessible Increase in porosity and AMP XI.S2, No Consistent with NUREG-2191.

areas): dome; wall; basemat; permeability; cracking; "ASME Section The ASME Section XI, Subsection IWL ring girders; buttresses, loss of material XI, Subsection (B.2.3.30) AMP supplemented by the concrete (accessible areas): (spalling, scaling) due IWL , "and/or Structures Monitoring (B.2.3.34) AMP dome; wall; basemat to aggressive chemical AMP XI.S6, manage increase in porosity and attack "Structures permeability, cracking, and loss of material Monitoring" (spalling, scaling) in inaccessible concrete areas exposed to uncontrolled indoor air.

3.5-1, 025 Item number 3.5-1, 025 is deleted in NUREG-2192.

3.5-1, 026 Moisture barriers (caulking, Loss of sealing due to AMP XI.S1, No Consistent with NUREG-2191.

flashing, and other sealants) wear, damage, erosion, "ASME Section The ASME Section XI, Subsection IWE tear, surface cracks, XI, Section IWE" (B.2.3.29) AMP manages loss of sealing or other defects other defects for the liner plate (and core hole) moisture barriers exposed to uncontrolled indoor air.

3.5-1, 027 Metal liner, metal plate, Cracking due to cyclic AMP XI.S1, No Consistent with NUREG-2191 as clarified airlock, equipment hatch, loading (CLB fatigue "ASME Section below.

CRD hatch; penetration analysis does not exist) XI, Section IWE,"

A fatigue analysis or waiver could not be sleeves; penetration bellows, and AMP XI.S4, located for airlock, hatch and electrical steel elements: torus; vent "10 CFR Part 50, penetration assemblies.

line; vent header; vent line Appendix J" bellows; downcomers, As such, the ASME Section XI, Subsection suppression pool shell IWE (B.2.3.29) AMP and 10 CFR Part 50 Appendix J (B.2.3.32) AMP manage cyclic loading of air lock, hatch, and electrical penetration assemblies. including copper alloy and steel accessories, exposed to uncontrolled indoor air.

Mechanical penetration assemblies, including ventilation and fuel transfer tube,

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 11 of 33 Table 3.5-1 Containment, Building Structures and Internal Structural Components/Commodities - Summary of Aging Management Programs Item Component Aging Effect Aging Further Evaluation Discussion Number Requiring Management Recommended Management Program that do not include dissimilar metal welds are addressed with item number 3.5-1, 009 above.

Mechanical penetration assemblies that include dissimilar metal welds, and the fuel transfer tube/expansion joints are addressed with item number 3.5-1, 010.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 12 of 33 SLRA Table 3.5.2-1 (pages 3.5-79 and 3.5-80) is revised as follows:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Air locks, Fire barrier Steel Air - indoor Cracking 10 CFR Part 50, II.A3.CP-37 3.5.1-027 A, 11 equipment Pressure uncontrolled Appendix J (B.2.3.32) hatches and boundary ASME Section XI, accessories Subsection IWE (B.2.3.29)

Air locks, Fire barrier Steel Air - indoor Loss of material 10 CFR Part 50, II.A3.C-16 3.5-1, 028 A, 11 equipment Pressure uncontrolled Appendix J (B.2.3.32) hatches and boundary ASME Section XI, accessories Subsection IWE (B.2.3.29)

Air locks, Fire barrier Steel Air - indoor Loss of leak 10 CFR Part 50, II.A3.CP-39 3.5-1, 029 A, 11 equipment Pressure uncontrolled tightness Appendix J (B.2.3.32) hatches and boundary ASME Section XI, accessories Subsection IWE (B.2.3.29)

Air locks, Fire barrier Steel Air with borated Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C, 11 equipment Pressure water leakage (B.2.3.4) hatches and boundary accessories Air locks, Fire barrier Copper alloy Air - indoor Cracking 10 CFR Part 50, II.A3.CP-37 3.5.1-027 F, 1, 11 equipment Pressure uncontrolled Appendix J (B.2.3.32) hatches and boundary ASME Section XI, accessories Subsection IWE (B.2.3.29)

Air locks, Fire barrier Copper alloy Air - indoor Loss of material 10 CFR Part 50, II.A3.C-16 3.5-1, 028 F, 1, 11 equipment Pressure uncontrolled Appendix J (B.2.3.32) hatches and boundary ASME Section XI, accessories Subsection IWE (B.2.3.29)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 13 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Air locks, Fire barrier Elastomer Air - indoor Loss of sealing 10 CFR Part 50, II.A3.CP-41 3.5-1, 033 A, 11 equipment Pressure uncontrolled Appendix J (B.2.3.32) hatches and boundary accessories Concrete Direct flow Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-33 3.5-1, 019 A Foundation / Pressure (reinforced) uncontrolled Subsection IWL Basemat boundary (B.2.3.30)

(accessible) Structural support Concrete Direct flow Concrete Air - indoor Cracking ASME Section XI, II.A1-CP-87 3.5-1, 016 A Foundation / Pressure (reinforced) uncontrolled Increase in Subsection IWL Basemat boundary porosity and (B.2.3.30)

(accessible) Structural permeability support Loss of material Concrete Direct flow Concrete Air - indoor Cracking Structures Monitoring II.A1.CP-51 3.5-1, 018 A, 2 Foundation / Pressure (reinforced) uncontrolled Loss of material (B.2.3.34)

Basemat boundary (accessible) Structural support Concrete Direct flow Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-68 3.5-1, 021 A Foundation / Pressure (reinforced) uncontrolled Loss of bond Subsection IWL Basemat boundary Loss of material (B.2.3.30)

(accessible) Structural support Concrete Direct flow Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-100 3.5-1, 024 A Foundation / Pressure (reinforced) uncontrolled Increase in Subsection IWL Basemat boundary Groundwater/soil porosity and (B.2.3.30)

(inaccessible) Structural permeability Structures Monitoring support Loss of material (B.2.3.34)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 14 of 33 SLRA Table 3.5.2-1 (pages 3.5-82 to 3.5-85) is revised as follows Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Concrete Walls, Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-33 3.5-1, 019 A, 11 Buttresses, Flood barrier (reinforced) uncontrolled Subsection IWL Dome, and Ring Missile (B.2.3.30)

Girders barrier (accessible) Pressure boundary Shelter, protection Structural support Concrete Walls, Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1-CP-87 3.5-1, 016 A, 11 Buttresses, Flood barrier (reinforced) uncontrolled Increase in Subsection IWL Dome, and Ring Missile porosity and (B.2.3.30)

Girders barrier permeability (accessible) Pressure Loss of material boundary Shelter, protection Structural support Concrete Walls, Fire barrier Concrete Air - indoor Cracking Structures Monitoring II.A1.CP-31 3.5-1, 018 A, 2, 11 Buttresses, Flood barrier (reinforced) uncontrolled Loss of material (B.2.3.34)

Dome, and Ring Missile Girder barrier (accessible) Pressure boundary Shelter, protection Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 15 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Concrete Walls, Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-68 3.5-1, 021 A, 11 Buttresses, Flood barrier (reinforced) uncontrolled Loss of bond Subsection IWL Dome, and Ring Missile Loss of material (B.2.3.30)

Girder barrier (accessible) Pressure boundary Shelter, protection Structural support Concrete Walls, Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-100 3.5-1, 024 A, 11 Buttresses, Flood barrier (reinforced) uncontrolled Increase in Subsection IWL Dome, and Ring Missile porosity and (B.2.3.30)

Girder barrier permeability Structures Monitoring (inaccessible) Pressure Loss of material (B.2.3.34) boundary Shelter, protection Structural support Concrete Walls, Fire barrier Concrete Air - indoor Cracking Structures Monitoring II.A1.CP-67 3.5-1, 012 A, 10, Buttresses, Flood barrier (reinforced) uncontrolled (B.2.3.34) 11 Dome, and Ring Missile Girder barrier (inaccessible) Pressure boundary Shelter, protection Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 16 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Concrete Walls, Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-97 3.5-1, 023 A, 11 Buttresses, Flood barrier (reinforced) uncontrolled Loss of bond Subsection IWL Dome, and Ring Missile Loss of material (B.2.3.30)

Girder barrier Structures Monitoring (inaccessible) Pressure (B.2.3.34) boundary Shelter, protection Structural support Concrete Internal Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-33 3.5-1, 019 A, 11 Columns, Beams, Flood barrier (reinforced) uncontrolled Subsection IWL Slabs, and Walls Missile (B.2.3.30)

(accessible) barrier Pressure boundary Shelter, protection Structural support Concrete Internal Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1-CP-87 3.5-1, 016 A, 11 Columns, Beams, Flood barrier (reinforced) uncontrolled Increase in Subsection IWL Slabs, and Walls Missile porosity and (B.2.3.30)

(accessible) barrier permeability Shelter, Loss of material protection Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 17 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Concrete Internal Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-68 3.5-1, 021 A, 11 Columns, Beams, Flood barrier (reinforced) uncontrolled Loss of bond Subsection IWL Slabs, and Walls Missile Loss of material (B.2.3.30)

(accessible) barrier Shelter, protection Structural support Concrete Internal Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-100 3.5-1, 024 A, 11 Columns, Beams, Flood barrier (reinforced) uncontrolled Increase in Subsection IWL Slabs, and Walls Missile porosity and (B.2.3.30)

(inaccessible) barrier permeability Structures Monitoring Shelter, Loss of material (B.2.3.34) protection Structural support Concrete Internal Fire barrier Concrete Air - indoor Cracking Structures Monitoring II.A1.CP-67 3.5-1, 012 A, 10, Columns, Beams, Flood barrier (reinforced) uncontrolled (B.2.3.34) 11 Slabs, and Walls Missile (inaccessible) barrier Shelter, protection Structural support Concrete Internal Fire barrier Concrete Air - indoor Cracking ASME Section XI, II.A1.CP-97 3.5-1, 023 A, 11 Columns, Beams, Flood barrier (reinforced) uncontrolled Loss of bond Subsection IWL Slabs, and Walls Missile Loss of material (B.2.3.30)

(inaccessible) barrier Structures Monitoring Shelter, (B.2.3.34) protection Structural support

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 18 of 33 SLRA Table 3.5.2-1 (page 3.5-87) is revised as follow:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Concrete Tendon Shelter, Concrete Air - indoor Cracking Structures Monitoring III.A3.TP-204 3.5-1, 043 A, 3, 10 Gallery Walls protection (reinforced) uncontrolled (B.2.3.34)

(inaccessible)

Concrete Tendon Shelter, Concrete Air - indoor Cracking Structures Monitoring III.A3.TP-26 3.5-1, 065 A, 3 Gallery Walls protection (reinforced) uncontrolled Loss of bond (B.2.3.34)

(inaccessible) Loss of material Concrete Tendon Shelter, Concrete Soil Cracking Structures Monitoring III.A3.TP-30 3.5-1, 044 A, 3 Gallery Walls protection (reinforced) (B.2.3.34)

(inaccessible)

Construction Structural Steel Air - indoor Loss of material Structures Monitoring III.A4.TP-302 3.5-1, 077 A Truss Support uncontrolled (B.2.3.34)

Construction Structural Steel Air with borated Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 A Truss Support water leakage (B.2.3.4)

H-Piles Structural Steel Groundwater/soil Loss of material Structures Monitoring III.A3.TP-219 3.5-1, 079 A support (B.2.3.34)

Fuel transfer tube Fire barrier Stainless Treated borated Loss of material One-Time Inspection VII.A2.AP-79 3.3-1, 125 D, 11 (including Pressure steel water (B.2.3.20) penetration boundary Water Chemistry sleeves, Radiation (B.2.3.2) expansion joints, shielding and blind flange)

Fuel transfer tube Fire barrier Stainless Air - indoor Cracking 10 CFR Part 50, II.A3.CP-38, 3.5-1, 010 A, 11 (including Pressure steel uncontrolled Appendix J (B.2.3.32) penetration boundary ASME Section XI, sleeves, Radiation Subsection IWE expansion joints, shielding (B.2.3.29) and blind flange)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 19 of 33 SLRA Table 3.5.2-1 (page 3.5-88) is revised as follows Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Fuel transfer tube Fire barrier Stainless Air - indoor Loss of material ASME Section XI, III.B3.T-37b 3.5-1, 100 E, 4 (including Pressure steel uncontrolled Subsection IWE penetration boundary (B.2.3.29) sleeves, Radiation expansion joints, shielding and blind flange)

Liners (refueling Direct flow Stainless Air - indoor Loss of material Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4, 11 cavity) and Fire barrier steel uncontrolled (B.2.3.34) covers (sand box, Pressure Unit 1 sump A boundary strainer) Radiation shielding Liners (refueling Direct flow Stainless Air - indoor Cracking Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4, 11 cavity) and Fire barrier steel uncontrolled (B.2.3.34) covers (sand box, Pressure Unit 1 sump A boundary strainer) Radiation shielding

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 20 of 33 SLRA Table 3.5.2-1 (page 3.5-91 and 3.5-92) is revised as follows:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Penetration Fire barrier Dissimilar Air - indoor Cracking 10 CFR Part 50, II.A3.CP-37 3.5-1, 027 A, 11 assemblies Pressure metal welds uncontrolled Appendix J (B.2.3.32)

(Electrical) boundary ASME Section XI, Structural Subsection IWE support (B.2.3.29)

Penetration Fire barrier Stainless Air - indoor Cracking 10 CFR Part 50, II.A3.CP-37 3.5-1, 027 A, 11 assemblies Pressure steel uncontrolled Appendix J (B.2.3.32)

(Electrical) boundary ASME Section XI, Structural Subsection IWE support (B.2.3.29)

Penetration Structural Steel Air - indoor Cumulative TLAA - Section 4.6, II.A3.C-13 3.5-1, 009 A, 12 sleeves support uncontrolled fatigue damage Containment Liner (Mechanical) Pressure Plate, Metal boundary Containments, and Penetrations Fatigue Analysis Penetration Structural Steel Air with borated Loss of Material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C assemblies support water leakage (B.2.3.4)

(Mechanical) Pressure boundary Penetration Structural Steel Air - indoor Loss of Material 10 CFR Part 50, II.A3.CP-36 3.5-1, 035 A assemblies support uncontrolled Appendix J (B.2.3.32)

(Mechanical) Pressure ASME Section XI, boundary Subsection IWE (B.2.3.29)

Penetration Structural Dissimilar Air - indoor Loss of Material 10 CFR Part 50, II.A3.CP-36 3.5-1, 035 A assemblies support metal welds uncontrolled Appendix J (B.2.3.32)

(Mechanical) Pressure ASME Section XI, boundary Subsection IWE (B.2.3.29)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 21 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Penetration Structural Dissimilar Air - indoor Cracking 10 CFR Part 50, II.A3.CP-38 3.5-1, 010 A, 6 assemblies support metal welds uncontrolled Appendix J (B.2.3.32)

(Mechanical) Pressure ASME Section XI, boundary Subsection IWE (B.2.3.29)

Penetration Structural Stainless Air - indoor Cracking 10 CFR Part 50, II.A3.CP-37 3.5-1, 027 A assemblies support steel uncontrolled Appendix J (B.2.3.32)

(Mechanical) Pressure ASME Section XI, boundary Subsection IWE (B.2.3.29)

Penetration Structural Stainless Air - indoor Cracking ASME Section XI, II.A3.CP-38 3.5-1, 010 A, 6 assemblies support steel uncontrolled Subsection IWE (Mechanical) Pressure (B.2.3.29) boundary 10 CFR Part 50, Appendix J (B.2.3.32)

Pressure Pressure Steel Air - indoor Loss of material ASME Section XI, II.A3.CP-148 3.5-1, 031 A retaining bolting boundary uncontrolled Subsection IWE Structural (B.2.3.29) support Pressure Pressure Stainless Air - indoor Loss of material ASME Section XI, II.A3.CP-148 3.5-1, 031 A retaining bolting boundary steel uncontrolled Subsection IWE Structural (B.2.3.29) support Pressure Pressure Steel Air - indoor Loss of preload 10 CFR Part 50, II.A3.CP-150 3.5-1, 030 A retaining bolting boundary uncontrolled Appendix J (B.2.3.32)

Structural ASME Section XI, support Subsection IWE (B.2.3.29)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 22 of 33 SLRA Table 3.5.2-1 (pages 3.5-93 and 3.5-94) is revised as follows:

Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management Pressure Pressure Stainless Air - indoor Loss of preload 10 CFR Part 50, II.A3.CP-150 3.5-1, 030 A retaining bolting boundary steel uncontrolled Appendix J (B.2.3.32)

Structural ASME Section XI, support Subsection IWE (B.2.3.29)

Primary shield Radiation Concrete Air - indoor Loss of Structures Monitoring III.A4.T-35 3.5-1, 097 A, 7, 10 wall (and Shielding (reinforced) uncontrolled mechanical (B.2.3.34) biological shield Shelter, properties wall) protection Reduction of Structural strength support Radiant energy Fire barrier Stainless Air with borated None None III.B5.TP-4 3.5-1, 098 C shields steel water leakage Radiant energy Fire barrier Stainless Air - indoor Loss of material Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4 shields steel uncontrolled (B.2.3.34)

Radiant energy Fire barrier Stainless Air - indoor Cracking Structures Monitoring III.B3.T-37b 3.5-1, 100 E, 4 shields steel uncontrolled (B.2.3.34)

RC Class 1 Structural Steel Air - indoor Loss of material ASME Section XI, III.B1.1.T-24 3.5-1, 091 B, 8 supports support uncontrolled Subsection IWF (B.2.3.31)

RC Class 1 Structural Steel Air with borated Loss of material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 C supports support water leakage (B.2.3.4)

RC Class 1 Structural Galvanized Air - indoor Loss of material ASME Section XI, III.B1.1.T-24 3.5-1, 091 B, 8 supports support steel uncontrolled Subsection IWF (B.2.3.31)

RC Class 1 Structural Galvanized Air with borated Loss of material Boric Acid III.B1.1.T-25 3.5-1, 089 A supports support steel water leakage Corrosion (B.2.3.4)

RC Class 1 Structural High-strength Air with borated Loss of Material Boric Acid Corrosion III.B1.1.T-25 3.5-1, 089 A support bolting support steel water leakage (B.2.3.4)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 23 of 33 Table 3.5.2-1: Containment Building Structure and Internal Structural Components - Summary of Aging Management Evaluation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 Table 1 Notes Type Function Requiring Program Item Item Management RC Class 1 Structural High-strength Air - indoor Loss of preload ASME Section XI, III.B1.1.TP-229 3.5-1, 087 B, 8 support bolting support steel uncontrolled Subsection IWF (B.2.3.31)

RC Class 1 Structural High-strength Air - indoor Cracking ASME Section XI, III.B1.1.TP-41 3.5-1, 068 B, 8 support bolting support steel uncontrolled Subsection IWF (B.2.3.31)

Reactor cavity Pressure Stainless Treated borated Loss of material One-Time Inspection VII.A2.A-99 3.3-1, 125 D seal ring Boundary steel water (B.2.3.20)

Water Chemistry (B.2.3.2)

Refueling Structural Stainless Treated borated Loss of material One-Time Inspection VII.A2.A-99 3.3-1, 125 D components support steel water (B.2.3.20)

(containment Water Chemistry upender, davit (B.2.3.2) arm)

Service Level I Maintain Coatings Air - indoor Loss of coating or Protective Coating II.A3.CP-152 3.5-1, 034 A coatings adhesion uncontrolled lining integrity Monitoring and Maintenance (B.2.3.36)

Sliding Surfaces Structural Lubrite Air - indoor Loss of Structures Monitoring III.B21.1.TP-46 3.5-1, 0745 A support uncontrolled mechanical (B.2.3.34) ASME 5 function Section XI, Subsection IWF (B.2.3.31)

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 24 of 33 SLRA Table 3.5.2-1 (page 3.5-96) is revised as follows:

Plant Specific Notes

1. Copper alloy is not addressed as a structural component in NUREG-2191. However, the environment, aging effects (cracking and loss of material) and aging management programs for steel air lock, hatch components are conservatively also applicable to the copper alloy airlock bushings.

2. PBN containments are located entirely inside the Façade building and are not associated with an air - outdoor environment. However, freeze-thaw conditions are still possible during winter months where water or groundwater collects as the Façade building is non-heated.

3. The tendon gallery adjacent to each PBN Units containment, inside the Façade building, is part of the containment basemat in the top few feet. The tendon galleries are not associated with an air - outdoor environment. However, freeze thaw conditions are still possible during winter months where water or groundwater collects as the Façade building is non-heated.

4. Structural stainless steel that is exposed to air - indoor uncontrolled during normal plant operation is inspected under the Structures Monitoring (B.2.3.34) AMP, or in the case of the transfer canal the ASME Section XI, Subsection IWE (B.2.3.29) AMP, the structural equivalent of the NUREG-2191 XI.M36, Externals Surfaces Monitoring of Mechanical Components AMP.

5. Liner moisture barriers are at the junction where the liner is embedded in the concrete slab and for the core holes in the concrete slab that allow inspection of the liner.

6. Penetration assemblies for high temperature stainless steel piping systems only for SCC, or as a leading indicator for cyclic loading of, whereas other mechanical penetration sleeves/assemblies with dissimilar metal welds are addressed for cumulative fatigue damage.

7. Primary shield wall, and attached biological shield wall, with a 1/4 inch steel liner surrounds the reactor cavity and the reactor vessel support structure passes through and is attached to it at certain points. Existing inspections, through the Structures Monitoring (B.2.3.34)

AMP, manage the condition of the shield wall.

8. As described in the RAI responses/supplements for the first 2 PWRs with renewed licenses for 80 years, thermalirradiation embrittlement of the steel reactor vessel support structure columns and beams requires analysis. Existing inspections, through the ASME Section XI, Subsection IWF (B.2.3.31) AMP, manages the condition of the reactor vessel support apart from irradiation embrittlement.

9. Insulation for main steam and feedwater penetrations are encased in steel penetration covers in the annulus and there are no plausible aging effects that could degrade the calcium silicate or amosite asbestos (with a silicate binder) insulation. Furthermore, temperature measurements for the penetrations are within UFSAR allowable.

10. Based on SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance, the existing Structures Monitoring (B.2.3.34) AMP is credited rather than a plant-specific AMP and is supplemented by the ASME Section XI, Subsection IWL (B.2.3.32) AMP as appropriate.

11. Component also provides a fire barrier function as evaluated in the Fire Protection Program Design Document that is physically equivalent to the structural functions managed under the associated Containment structural programs.

12. Steel mechanical (and ventilation) penetration assemblies are covered by a fatigue waiver, as described in Section 4.6.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 25 of 33 SLRA Table 4.1.5-3 (page 4.1-7) is revised as follows:

Table 4.1.5-3 Summary of Results PBN TLAAs TLAA Description Resolution Section 10 CFR 54.21(c)(1) Section REACTOR VESSEL NEUTRON EMBRITTLEMENT 4.2 Neutron Fluence Projections (iii) the effects of aging on the intended 4.2.1 function will be adequately managed for the SPEO Pressurized Thermal Shock (ii) projected to the end of the SPEO 4.2.2 Upper-Shelf Energy (ii) projected to the end of the SPEO 4.2.3 Adjusted Reference Temperature (ii) projected to the end of the SPEO 4.2.4 Pressure-Temperature Limits & (iii) the effects of aging on the intended 4.2.5 Low Temperature Overpressure function will be adequately managed Protection (LTOP) Setpoints for the SPEO METAL FATIGUE 4.3 Metal Fatigue of Class 1 Components (ii) projected to the end of the SPEO 4.3.1 (iii) the effects of aging on the intended function will be adequately managed for the SPEO ASME Code,Section III, Class I Component (iii) the effects of aging on the intended 4.3.2 Fatigue Waivers function will be adequately managed for the SPEO Metal Fatigue of Non-Class 1 Components (i) remains valid for the SPEO 4.3.3 Environmentally-Assisted Fatigue (ii) projected to the end of the SPEO 4.3.4 (iii) the effects of aging on the intended function will be adequately managed for the SPEO ENVIRONMENTAL QUALIFICATION (EQ) (iii) the effects of aging on the intended 4.4 OF ELECTRICAL EQUIPMENT function will be adequately managed for the SPEO CONCRETE CONTAINMENT TENDON (iii) the effects of aging on the intended 4.5 PRESTRESS function will be adequately managed for the SPEO CONTAINMENT LINER PLATE, METAL (i) remains valid for the SPEO, and 4.6 CONTAINMENTS, AND PENETRATIONS (iii) the effects of aging on the intended FATIGUE function will be adequately managed for the SPEO

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 26 of 33 SLRA Section 4.6 (page 4.6-3) is revised as follows:

and 254 tests). This number of normal service pressure fluctuations is significantly greater than the 80-year projected cycles listed in Table 2.1-3 of Structural Integrity Associated Report No. 2000088.401. Conditions (v) and (vi) represent bounding cycle values on the applicable fatigue curve and are applicable for the SPEO. Therefore, the Reference 4.8.29 analysis remains applicable for the SPEO and a fatigue analysis of the piping penetrations is not required.

PBN has been unable to locate the original fatigue analysis or confirm if a fatigue waiver exists for the PBN containment penetrations other than steel piping penetrations, piping penetrations with dissimilar metal welds, and for the expansions joints of the containment structure reactor fuel transfer tube. Therefore, consistent with NUREG-2192, Table 3.5-1, Item 3.5-1, 027, cracking due to cyclic loading of non-piping containment penetrations (i.e.

personnel airlocks, equipment hatch, personnel hatch, electrical penetrations, piping penetrations with dissimilar metal welds, and the expansions joints of the containment structure fuel transfer tube will be managed by the ASME Section XI, Subsection IWE AMP (Section B.2.3.29) and periodic supplemental surface examinations incorporated into and consistent with the frequency of the 10 CFR Part 50, Appendix J AMP (Section B.2.3.32).

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

The fatigue analyses associated with the containment liner plate and steel piping penetrations have been evaluated and determined to remain valid for the SPEO. The fatigue analyses associated with the containment personnel airlocks, equipment hatch, personnel hatch, electrical penetrations, piping penetrations with dissimilar metal welds, and expansions joints of the containment structure fuel transfer tube will be managed by the ASME Section XI, Subsection IWE AMP and the 10 CFR Part 50, Appendix J AMP.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 27 of 33 SLRA Section 16.2.2.29 (page A-33) is revised as follows:

The PBN ASME Section XI, Subsection IWE AMP is an existing AMP that was formerly part of the ASME Section XI, Subsections IWE and IWL Inservice Inspection AMP. This condition monitoring AMP is in accordance with ASME Code Section XI, Subsection IWE, and consistent with 10 CFR 50.55a, Codes and Standards, with supplemental recommendations. This program will use the edition and addenda of ASME Section XI required by 10 CFR 50.55a, as reviewed and approved by the NRC staff for aging management under 10 CFR 54. Alternatives to these requirements that are aging management related will be submitted to the NRC in accordance with 10 CFR 50.55a prior to implementation.

The AMP includes periodic visual, surface, and volumetric examinations, where applicable, of the steel liner of each concrete containment and their integral attachments for signs of degradation, damage, irregularities including discernable liner plate bulges, and for coated areas distress of the underlying metal shell or liner, and corrective actions. Acceptability of inaccessible areas of steel containment shell or concrete containment steel liner is evaluated when conditions found in accessible areas indicate the presence of, or could result in, flaws or degradation in inaccessible areas.

In addition, the program includes supplemental surface examination to detect cracking for specific pressure-retaining components including all non-piping penetrations (hatches, electrical penetrations, etc.) that are subject to cyclic loading but have no CLB fatigue analysis and are not subject to local leak rate testing.

If triggered by plant specific OE, a onetime supplemental volumetric examination will be performed by sampling randomly selected as well as focused locations susceptible to loss of thickness due to corrosion of containment shell or liner that is inaccessible from one side. Inspection results are compared with prior recorded results in acceptance of components for continued service.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 28 of 33 SLRA Table 16-3 (pages A-100 through A-103) is revised as follows:

Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) 33 ASME Section XI, XI.S1 Continue the existing PBN ASME Section XI, Subsection IWE AMP, including No later than 6 months prior Subsection IWE enhancement to: to the SPEO, or no later (16.2.2.29) a) Augment existing procedures to specify that whenever replacement of than the last refueling bolting is required, bolting material, installation torque or tension, and use outage prior to the SPEO, of lubricants and sealants are in accordance with the guidelines of EPRI i.e.:

NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, PBN1: 04/05/30 EPRI TR-104213, Bolted Joint Maintenance & Application Guide, and PBN2: 09/08/32 the additional recommendations of NUREG-1339, Resolution of Generic Start the one-time Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants.; inspections for cracking due b) Augment existing procedures to specify that for structural bolting to SCC no earlier than five consisting of ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the years prior to the SPEO.

preventive actions for storage, lubricants, and stress corrosion cracking potential discussed in Section 2 of RCSC (Research Council for Structural Connections) publication Specification for Structural Joints Using ASTM A325 or A490 Bolts, will be used.

c) Augment existing procedures to specify that pressure retaining bolting is inspected for loosening and material condition affecting leak tightness or structural integrity.

d) Augment existing procedures to implement periodic supplemental surface examinations (or other appropriate examination/evaluation methods) or enhanced visual examination at intervals no greater than other IWE inspections 10-years to detect cracking due to cyclic loading of all non-piping penetrations (hatches, electrical penetrations, etc.) that are subject to cyclic loading but have no current licensing bases fatigue analysis and are not subject to local leak rate testing.

e) Augment existing procedures to implement supplemental one-time surface examinations or enhanced visual examinations inspections, performed by qualified personnel using methods capable of detecting cracking due to SCC, comprising (a) a representative sample (two) of the stainless steel penetrations or dissimilar metal welds associated with high-temperature (temperatures above 140°F) stainless steel piping

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 29 of 33 Table 16-3 List of SLR Commitments and Implementation Schedule No. Aging NUREG-2191 Commitment Implementation Schedule Management Section Program or Activity (Section) systems in frequent use on each unit; and (b) the stainless steel fuel transfer tube on each unit. If SCC cracking is detected as a result of the supplemental one-time inspections, additional inspections will be conducted in accordance with the sites corrective action process. This will include 1 additional penetration with dissimilar metal welds associated with greater than 140 °F stainless steel piping systems for each unit until SCC is no longer detected. Periodic inspection of subject penetrations with dissimilar metal welds for cracking will be added to the PBN ASME Section XI, Subsection IWE AMP if necessary, depending on the inspection results.

f) Augment existing procedures to implement a one-time supplemental volumetric inspection of metal liner surfaces that samples randomly selected as well as focused locations susceptible to loss of thickness due to corrosion from the concrete side if triggered by plant-specific OE identified through code inspections after the date of issuance of the first renewed license for each unit. This sampling is conducted to demonstrate with 95% confidence, that 95% of accessible portion of the liner is not experiencing greater than 10% wall loss.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 30 of 33 SLRA Section B.2.3.29 (pages B-213 through B-215) is revised as follows:

B.2.3.29 ASME Section XI, Subsection IWE Program Description The PBN ASME Section XI, Subsection IWE AMP is an existing AMP that was formerly part of the ASME Section XI, Subsections IWE and IWL Inservice Inspection AMP. This AMP is performed in accordance with ASME Code Section XI, Subsection IWE, and consistent with 10 CFR 50.55a "Codes and Standards," with supplemental recommendations. This program will use the edition and addenda of ASME Section XI required by 10 CFR 50.55a, as reviewed and approved by the NRC staff for aging management under 10 CFR 54. Alternatives to these requirements that are aging management related will be submitted to the NRC in accordance with 10 CFR 50.55a prior to implementation.

This AMP includes periodic visual, surface, and volumetric examinations, where applicable, of the steel liner of each concrete containment and their integral attachments for signs of degradation, damage, irregularities including discernable liner plate bulges, and for coated areas distress of the underlying metal shell or liner, and corrective actions. Acceptability of inaccessible areas of steel containment shell or concrete containment steel liner is evaluated when conditions found in accessible areas indicate the presence of, or could result in, flaws or degradation in inaccessible areas.

If site-specific OE identified after the date of issuance of the first renewed license for each unit triggers the requirement to implement a one-time supplemental volumetric examination, then this inspection is performed by sampling randomly selected, as well as focused, liner locations susceptible to corrosion that are inaccessible from one side.

Guidance provided in EPRI TR-107514 will be considered for sampling determinations. The trigger for this one-time examination is site-specific occurrence or recurrence of liner corrosion (base metal material loss exceeding 10 percent of nominal plate thickness) that is determined to originate from the inaccessible (concrete) side.

Any such instance would be identified through code inspections performed since 10/05/10 for Unit 1 or 03/08/13 for Unit 2. Based on a review of current PBN operating experience, no such triggers have occurred.

Coated surfaces are visually inspected for evidence of conditions that indicate degradation of the underlying base metal. Coatings are a design feature of the base material and are not credited with managing loss of material. The PBN Protective Coating Monitoring and Maintenance AMP (Section B.2.3.36) is used for the monitoring and maintenance of protective containment coatings in relation to reasonable assurance of emergency core cooling system operability. Concrete portions of containments are inspected by the separate PBN ASME Section XI, Subsection IWL AMP (Section B.2.3.30).

Surface conditions are monitored through visual examinations to determine the existence of corrosion. Surfaces are examined for evidence of flaking, blistering,

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 31 of 33 SLRA Section B.2.3.29 (pages B-213 through B-215) revision continued:

peeling, discoloration, wear, pitting, excessive corrosion, arc strikes, gouges, surface discontinuities, dents, or other signs of surface irregularities. Pressure-retaining bolting is examined for loosening and material conditions that cause the bolted connection to affect either containment leak-tightness or structural integrity. Moisture barriers are visually inspected for degradation per Category E-A.

Cumulative fatigue damage for the PBN liner and steel piping (and ventilation) penetrations for the containment structures is addressed in the Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis TLAA for SLR (Section 4.6). Cracking due to cyclic loading of all non-piping penetrations (hatches, electrical penetrations, etc.) that are subject to cyclic loading but have no current licensing bases fatigue analysis will be managed by the 10 CFR Part 50, Appendix J AMP (Section B.2.3.32) and or supplemental surface examinations (or other appropriate examination/evaluation methods) or enhanced visual examinations using the ASME Section XI, Subsection IWE AMP. This AMP will also include supplemental one-time inspections within 5 years prior to the SPEO for a representative sample of stainless steel penetrations and dissimilar metal welds, including the fuel transfer tubes, that may be susceptible to cracking due to SCC and are leading indicators relative to cyclic loading.

Examinations and evaluations are performed in accordance with the requirements of ASME Section XI, Subsection IWE, which provides acceptance standards for the containment pressure boundary components. Areas identified with damage or degradation that exceed acceptance standards require an engineering evaluation or require correction by repair or replacement. Such areas are corrected by repair or replacement in accordance with IWE-3122 or accepted by engineering evaluation.

NUREG-2191 Consistency The PBN ASME Section XI, Subsection IWE AMP, with enhancements, will be consistent with the 10 elements of NUREG-2191,Section XI.S1, ASME Section XI, Subsection IWE as modified by SLR-ISG-Structures-2020-XX, Updated Aging Management Criteria for Structures Portions of the Subsequent License Renewal Guidance.

Exceptions to NUREG-2191 None.

Enhancements The PBN ASME Section XI, Subsection IWE AMP will be enhanced as follows for alignment with NUREG-2191. The one-time inspections for SCC will be started no earlier than five years prior to the SPEO. The enhancements will be implemented and one-time inspections completed no later than six months prior to entering the SPEO.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 32 of 33 SLRA Section B.2.3.29 (pages B-213 through B-215) revision continued:

Element Affected Enhancement

2. Preventive Actions Augment existing procedures to specify that whenever replacement of bolting is required, bolting material, installation torque or tension, and use of lubricants and sealants are in accordance with the guidelines of EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, EPRI TR-104213, Bolted Joint Maintenance & Application Guide, and the additional recommendations of NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants.

2. Preventive Actions Augment existing procedures to specify that for structural bolting consisting of ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the preventive actions for storage, lubricants, and stress corrosion cracking potential discussed in Section 2 of RCSC (Research Council for Structural Connections) publication Specification for Structural Joints Using ASTM A325 or A490 Bolts, will be used.

3. Parameters Monitored Augment existing procedures to specify that pressure retaining bolting or Inspected is inspected for loosening and material condition affecting leak tightness or structural integrity.

4. Detection of Aging Augment existing procedures to implement periodic supplemental Effects surface examinations (or other appropriate examination/evaluation methods) or enhanced visual examinations at intervals no greater than other IWE inspections 10-years to detect cracking due to cyclic loading of all non-piping penetrations (hatches, electrical penetrations, etc.) that are subject to cyclic loading but have no current licensing bases fatigue analysis and are not subject to local leak rate testing.

4. Detection of Aging Augment existing procedures to implement supplemental one-time Effects surface examinations or enhanced visual examinations inspections, performed by qualified personnel using methods capable of detecting cracking due to SCC, comprising (a) a representative sample (two) of the stainless steel penetrations or dissimilar metal welds associated with high-temperature (temperatures above 140°F) stainless steel piping systems in frequent use on each unit; and (b) the stainless steel fuel transfer tube on each unit. This will include 1 additional penetration with dissimilar metal welds associated with greater than 140 °F stainless steel piping systems for each unit until cracking is no longer detected.

Periodic inspection of subject penetrations with dissimilar metal welds will be added to the PBN ASME Section XI, Subsection IWE AMP if necessary, depending on the inspection results.

Point Beach Units 1 and 2 Docket Nos. 50-266 and 50-301 L-2021-081 Attachment 29 Page 33 of 33 SLRA Section B.2.3.29 (pages B-213 through B-215) revision continued:

Element Affected Enhancement

4. Detection of Aging Augment existing procedures to implement a one-time supplemental Effects volumetric inspection of metal liner surfaces that samples randomly selected as well as focused locations susceptible to loss of thickness due to corrosion from the concrete side if triggered by plant-specific OE identified through code inspections after the date of issuance of the first renewed license for each unit. This sampling is conducted to demonstrate with 95% confidence, that 95% of accessible portion of the liner is not experiencing greater than 10% wall loss.

7. Corrective Actions If SCC is detected as a result of the supplemental one-time inspections, additional inspections will be conducted in accordance with the sites corrective action process.

v t e Letter Sequence Supplement
EPID:L-2020-SLR-0002, Enclosure 4, Non-proprietary Reference Documents and Redacted Versions of Proprietary Reference Documents (Public Version) (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request, Request, Request Acceptance Supplement, Supplement, Supplement Administration Questions 10 November 2021 Answers Results Approval, Approval, Approval Other: L-2021-129, Ssubsequent License Renewal Application: Aging Management Requests for Confirmation Of/Additional Information (Rci/Rai) Set 1 Responses, L-2021-144, Subsequent License Renewal Application-Aging Management Requests for Additional Information (RAI) Set 2 Responses, L-2021-157, L-2021-157 Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 6 Responses, L-2021-172, Subsequent License Renewal Application - Aging Management Requirement for Additional Information Set 7, Response, L-2021-190, Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 2 Responses Revision 1, L-2021-199, Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 10 Responses, L-2021-200, Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 11 Response, L-2021-223, Subsequent License Renewal Application - Aging Management Requests for Additional Information (RAI) Set 12 Response, L-2021-224, Subsequent License Renewal Application - First Annual Update, L-2021-248, Subsequent License Renewal Application Aging Management Requests for Additional Information (RAI) Set 14 Response, ML21005A058, ML21015A214, ML21036A217, ML21208A447, ML21214A035, ML21302A019
MONTHYEAR2021-04-21 [Table View]

L-2021-081, Subsequent License Renewal Application - Aging Management Supplement 1

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