DCL-25-001, Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company

Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company

ML25002A050
Person / Time
Site:	Diablo Canyon   (DPR-080, DPR-082)
Issue date:	01/02/2025
From:	Zawalick M Pacific Gas & Electric Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML25002A048	List: DCL-25-001, Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company
References
DCL-25-001
Download: ML25002A050 (1)

Text

Enclosure 2 to this letter contains Proprietary Information -

Withhold Under 10 CFR 2.390 Maureen R. Zawalick Vice President Business and Technical Services Diablo Canyon Power Plant P.O. Box 56 Avila Beach, CA 93424 805.545.4242 Maureen.Zawalick@pge.com A member of the STARS Alliance Callaway Diablo Canyon Palo Verde Wolf Creek to this letter contains Proprietary Information -

Withhold Under 10 CFR 2.390 When separated from Enclosure 2, this document is decontrolled PG&E Letter DCL-25-001 10 CFR 54 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Diablo Canyon Units 1 and 2 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Response to Request for Additional Information by the Office of Nuclear Reactor Regulation Diablo Canyon Safety Review Pacific Gas and Electric Company Diablo Canyon Units 1 and 2 (Set 2)

References:

1. PG&E Letter DCL-23-118, License Renewal Application, dated November 7, 2023 (ADAMS Accession No. ML23311A154)

2. PG&E Letter DCL-24-092, Supplement and Annual Update: Diablo Canyon Power Plant License Renewal Application, Amendment 1, dated October 14, 2024 (ADAMS Accession No. ML24289A118)

3. NRC email Diablo Canyon LRA - Requests for Additional Information &

Clarifying Information Set #2, dated December 4, 2024 (ADAMS Accession No. ML24339B881)

Dear Commissioners and Staff:

In Reference 1, as supplemented by Reference 2, Pacific Gas and Electric Company (PG&E) submitted an application to the U.S. Nuclear Regulatory Commission (NRC) for the renewal of Facility Operating Licenses DPR-80 and DPR-82, for Diablo Canyon Power Plant (DCPP) Units 1 and 2, respectively. In Reference 3, the NRC issued requests for additional information (RAIs) and confirmation of information (RCI) to support the staff review of the DCPP License Renewal Application (LRA).

PG&E's responses to the RAIs and RCI are in Enclosure 1 to this letter, including resulting LRA amendments in Attachment A. For clarity, revisions to the LRA are Pacific Gas and Elecmc Company*

to this letter contains Proprietary Information -

Withhold Under 10 CFR 2.390 Document Control Desk PG&E Letter DCL-25-001 Page 2 A member of the STARS Alliance Callaway Diablo Canyon Palo Verde Wolf Creek to this letter contains Proprietary Information -

Withhold Under 10 CFR 2.390 When separated from Enclosure 2, this document is decontrolled provided with deleted text by red strikethroughs and inserted text by blue underline.

Bolded LRA text indicates portions that were previously amended by Reference 2.

Enclosures 2 and 3 provide proprietary and non-proprietary versions of WCAP-13039, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants, Revision 2, respectively. Enclosure 4 provides the affidavit for withholding proprietary Enclosure 2.

DCPP LRA, Appendix A, Table A-3, List of License Renewal Commitments and Implementation Schedules, provides the commitments made in the application.

This table is amended in Enclosure 1, Attachment A.

If you have any questions or require additional information, please contact Mr. Philippe Soenen at (805) 459-3701.

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

Executed on ____________________.

Sincerely, Maureen R. Zawalick Vice President, Business and Technical Services Enclosures cc:

Diablo Distribution cc/enc: Lauren Gibson, NRC License Renewal Branch Chief Brian Harris, NRC Senior Project Manager Mahdi O. Hayes, NRC Senior Resident Inspector Samson S. Lee, NRR Senior Project Manager John D. Monninger, NRC Region IV Deputy Administrator cc/enc (without Enclosure 2):

Anthony Chu, Chief, California Dept of Public Health Delphine Hou, California Department of Water Resources January 2, 2025 1

PG&E Letter DCL-25-001 PG&E Response to NRC Letter dated December 4, 2024 Request for Additional Information and Clarifying Information (Set 2) for the Diablo Canyon License Renewal Application PG&E Letter DCL-25-001 Page 1 of 29 RAI B.2.3.24 Regulatory Basis Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the U.S. Nuclear Regulatory Commission (NRC) staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

Program Element 3, Parameters Monitored or Inspected in the GALL-SLR Report AMP XI.M38 states, in part:

Periodic surface examinations are conducted if this program is being used to manage cracking in SS or aluminum components. Visual inspections for leakage or surface cracks are an acceptable alternative to conducting surface examinations to detect cracking if it has been determined that cracks will be detected prior to challenging the structural integrity or intended function of the component. [emphasis added]

Program Element 4, Detection of Aging Effects in the GALL-SLR Report AMP XI.M38 states, in part:

Periodic visual inspections or surface examinations are conducted on SS and aluminum to manage cracking every 10 years during the subsequent period of extended operation when applicable (e.g., see SRP-SLR Sections 3.2.2.2.4 and 3.2.2.2.8). One or more of the following three options may be used to implement the periodic visual inspections or surface examinations:

Surface examination conducted in accordance with plant-specific procedures.

ASME Code Section XI VT-1 inspections (including those inspections conducted on non-ASME Code components).

Visual inspections are conducted where it has been analytically demonstrated that surface cracks can be detected by leakage prior to a crack challenging the structural integrity or intended function of the component. The SLRA includes an overview of the analytical method, input variables, assumptions, basis for use of bounding analyses, and results. [emphasis added]

PG&E Letter DCL-25-001 Page 2 of 29 When using this option, cracks can be detected in gas-filled systems by methods such as, but not limited to: (a) for diesel exhaust piping, detecting staining on external surfaces of components; (b) for accumulators and piping connecting the accumulators to components, monitoring and trending accumulator pressures or refill frequency; and (c) soap bubble testing when systems are pressurized. The SLRA includes the specific methods used. [emphasis added]

In LRA Section B.2.3.24, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components the justification for exception 2 states, in part:

Visual inspections for leakage or surface cracks are an acceptable alternative to conducting surface examination to detect cracking if it has been determined that cracks will be detected prior to challenging the structural integrity or intended function of the component. In addition, the NRC previously found these methods acceptable for managing cracking of copper alloy (>15% Zn or >8% Al) components (Reference ML22054A108).

The NRC staff notes that:

1. The initial SLRA submission referenced in ML22054A108 was revised by a supplement (ML21111A155) to clarify that only surface examinations or ASME Code Section XI VT-1 inspections would be used to detect cracking and loss of material of stainless steel, copper alloy (>15 percent zinc), and aluminum components.

2. The Diablo Canyon LRA did not include an analytical demonstration that surface cracks can be detected by leakage prior to a crack challenging the structural integrity or intended function of the component. Also, the LRA did not include a description of the specific methods that would be used when implementing visual inspections instead of surface examinations or ASME Code Section XI VT-1 inspections.

Issue The NRC staff is unclear on whether the applicant intends to use visual inspections in lieu of surface examinations or ASME Code Section XI VT-1 inspections to detect cracking and loss of material of stainless steel, copper alloy (>15% Zn or >8% Al), and aluminum components.

Request Please discuss whether visual inspections in lieu of surface examinations or ASME Code Section XI VT-1 inspections will be used to detect cracking and loss of material in stainless steel, copper alloy (>15% Zn or >8% Al), and aluminum components. If that is the intention of exception 2, please provide the specific methods that will be used and an overview of the analytical method(s), input variables, assumptions, basis for use of the bounding analyses, and the results.

PG&E Letter DCL-25-001 Page 3 of 29 PG&E Response to RAI B.2.3.24:

The Diablo Canyon Power Plant (DCPP) Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Aging Management Program (AMP) described in License Renewal Application (LRA) Section B.2.3.24 is consistent with NUREG-1801, Revision 2 (as modified by LR-ISG-2012-02), XI.M38, and NUREG-2191, XI.M38, where it indicates loss of material using XI.M38 only requires visual inspection. In particular, Element 3 of XI.M38 in NUREG-1801 states, Parameters monitored or inspected include visible evidence of loss of material in metallic components. Element 4 of XI.M38 of NUREG-2191 states that, Internal visual inspections used to assess loss of material are capable of detecting surface irregularities that could be indicative of an unexpected level of degradation due to corrosion and corrosion product deposition.

Pacific Gas and Electric Company (PG&E) will not use visual inspections in lieu of surface examinations or American Society of Mechanical Engineers (ASME) Code Section XI VT-1 inspections to detect cracking. Therefore, in Enclosure 1, Attachment A, PG&E revises LRA Section B.2.3.24 to remove the option of visual inspections in lieu of surface examinations or ASME Code Section XI VT-1 inspections to detect cracking in stainless steel, aluminum, and copper alloy (>15% Zn or >8% Al) components.

RAI 4.3.2-1 Regulatory Basis Pursuant to 10 CFR 54.21(c), the LRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) the analyses have been projected to the end of the period of extended operation, or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

Background

LRA Section 4.3.2.12 addresses the TLAA for the primary loop piping in relation to the leak-before-break (LBB) analysis. The LRA indicates that the effects of thermal aging in cast austenitic stainless steel (CASS) materials depend on time (i.e., after a prolonged exposure to high temperatures, the thermal aging effects achieve a saturation level, after which further exposure to high temperatures do not affect the material properties of CASS).

LRA Section 4.3.2.12 also explains that, since the LBB analysis documented in the WCAP-13039 report relied on fully aged reference material (i.e., with the properties at the saturation levels), the analyses do not have a material property time-dependency that would require further evaluation for license renewal and, therefore, the fracture mechanics analysis is not a TLAA in accordance with 10 CFR 54.3(a)(3) (

Reference:

WCAP-13039, Technical Justification for Eliminating Large Primary Loop Pipe Rupture PG&E Letter DCL-25-001 Page 4 of 29 as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants, November 1991).

Issue The staff noted that Table 4-7 of WCAP-13039 describes the fracture toughness values (e.g., J Ic and T mat values) used in the existing LBB analysis for various material heats. In contrast to the statement in LRA Section 4.3.2.12, the fracture toughness values in WCAP-13039, Table 4-7 are equivalent to the 40-year fracture toughness values listed in WCAP-13039, Appendix B, Tables B-1 and B-2 (DCPP Units 1 and 2, respectively) rather than saturated fracture toughness values.

In addition, the staff noted that for location 10 in the cross-over leg (elbow fabricated with CF8M material, heat number 13930-5), the fracture toughness values (e.g., J Ic and T mat values) used in WCAP-13039, Table 4-7 and related fracture mechanics analysis are greater than the saturated facture toughness values estimated in accordance with NUREG/CR-4513, Revision 2.

Request

1. Resolve the apparent inconsistency regarding the use of saturated fracture toughness values between LRA Section 4.3.2.12 and WCAP-13039, Table 4-7. As part of the response, clarify why LRA Section 4.3.2.12 indicates that the existing LBB analysis uses the saturated fracture toughness values in contrast with WCAP-13039, Tables 4-7, B-1 and B-2 that indicate that the LBB analysis uses the 40-year fracture toughness values.

2. If the inconsistency discussed in Request 1 above cannot be resolved, revise LRA Section 4.3.2.12 and related FSAR supplement as needed to discuss a TLAA addressing the time-dependency of the fracture toughness of CASS materials and the TLAA disposition.

3. Given that the fracture toughness values for location 10 used in WCAP-13039, Table 4-7 and related fracture mechanics analysis are greater than the saturated fracture toughness values per NUREG/CR-4513, Revision 2, provide justification for why the fracture toughness values used in WCAP-13039 is adequate for the fracture mechanics analysis for the location. If such justification cannot be made, provide additional information to demonstrate that the fracture mechanics analysis for location 10 based on the saturated fracture toughness values per NUREG/CR-4513, Revision 2 is acceptable.

4. Given that the fracture toughness estimation in accordance with NUREG/CR-4513, Revision 2 considers the effects of the casting method (i.e., static or centrifugal casting), clarify whether the elbows evaluated in the LBB analysis are static or centrifugal cast elbows.

PG&E Letter DCL-25-001 Page 5 of 29 PG&E Response to RAI 4.3.2-1:

1. WCAP-13039 has been updated to Revision 2, in which NUREG/CR-4513, Revision 1, and NUREG/CR-4513, Revision 2 plus Errata, was utilized to calculate the saturated fracture toughness properties (e.g., JIc, Jmax, and Tmat values). To address the lower saturated fracture toughness material properties, Revision 2 of WCAP-13039 also revised the fracture mechanics evaluations considering the significant reduction in faulted loads. The results of WCAP-13039, Revision 2, show that the critical locations for the limiting CASS elbows still meet the required margins to credit LBB for 60-year plant life.

2. In Enclosure 1, Attachment A, PG&E revises LRA Table 4.1-2 and Sections 4.3.2.12, 4.9, and A.3.2.1.9 to address the time-dependency aspects of WCAP-13039, Revision 2. WCAP-13039-P, Revision 2, is provided in Enclosure 2 and WCAP-13039-NP, Revision 2, is provided in Enclosure 3 for NRC review and approval.

3. See response to item 1 regarding the revised fracture toughness properties and fracture mechanics evaluation.

4. The elbows on both DCPP Unit 1 and Unit 2 are statically cast.

RAI B.2.3.41-1 Regulatory Basis 10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

LRA Section B.2.3.41 describes the new Periodic Inspections for Selective Leaching program as plant-specific. The applicant identified two populations (i.e., materials and environment combinations) where selective leaching is occurring and provided the Periodic Inspections for Selective Leaching program to manage loss of material due to selective leaching for these populations. The two populations being managed using this PG&E Letter DCL-25-001 Page 6 of 29 plant-specific AMP are: (a) gray cast iron components exposed to soil; and (b) aluminum-bronze components exposed to raw water. With the issuance of GALL-SLR Report AMP XI.M33, Selective Leaching, the staff provided a framework to manage loss of material due to selective leaching through periodic inspections, as opposed to the GALL-LR Report AMP XI.M33 framework which recommends one-time inspections to demonstrate that this aging effect is not occurring. In addition, the staff noted the applicant developed the Periodic Inspections for Selective Leaching program based on the guidance provided in GALL-SLR Report AMP XI.M33. Therefore, the staff compared the program elements included in LRA Section B.2.3.41 to the corresponding program elements of GALL-SLR Report AMP XI.M33.

As amended by letter dated October 14, 2024 (ML24289A118), the detection of aging effects program element in LRA Section B.2.3.41 states the following (in part):

[t]here are less than 35 valves and associated gray cast iron piping for each Unit that are in a soil environment (applies to the Fire Protection System and Makeup Water System). In accordance with the recommendations set forth by NUREG-2191, for sample populations with less than 35 components, DCPP will perform one destructive examination for this population during each inspection period at each Unit GALL-SLR Report AMP XI.M33 recommends two destructive examinations are performed in each 10-year period at each unit for sample populations with greater than 35 susceptible components. When inspections are conducted on piping, a 1-foot axial length section is considered as one inspection.

Issue It is the staffs understanding that there are greater than 35 gray cast iron components exposed to soil, when considering that a 1-foot axial length section of piping is considered one component. Based on this, the staff seeks clarification with respect to why two destructive examinations will not be performed for this population.

Request Clarify if there are greater than 35 gray cast iron components exposed to soil, when considering that a 1-foot axial length section of piping is considered one component. If there is, state the basis for performing one destructive examination for this population during each inspection period at each unit. Alternatively, revise the LRA (as appropriate) to reflect that two destructive examinations will be performed for this population during each inspection period at each unit.

PG&E Response to RAI B.2.3.41-1:

GALL-SLR,Section XI.M33 states, When inspections are conducted on piping, a 1-foot axial length section is considered as one inspection. Other AMP guidance was PG&E Letter DCL-25-001 Page 7 of 29 reviewed for more clarity on what the NRC considers one component when counting piping in a sample-based program with other (non-piping) components. None make this distinction, unless based on percent of piping length or surface area like in Section XI.M36, XI.M41, or XI.M42 programs. In the absence of additional guidance on defining the number of components within a material/environment sample population that includes multiple component types, PG&E considers the entirety of a piping identification number to be a single component.

For this program and specific material/environment combination (i.e., buried gray cast iron), there are 15 total piping lines currently counted as one component each in the sample population. Of these 15 lines, 10 piping segments supply fire water to hydrants and are each less than 11 feet in length and 5 piping segments supply fire water to transformer deluge systems and are each approximately 5 feet in length.

Maintaining these segments as single components, rather than breaking them into multiple, 1-foot components, ensures appropriate sampling of the population without over-counting the piping segments. This approach aligns with the intent of the recommendation to treat a 1-foot axial length section as one inspection, ensuring sufficient coverage of the piping component while not counting multiple feet of piping segments to meet the required number of inspections. Therefore, treating each piping segment as a single component is technically justifiable, prudent for implementation purposes, and provides reasonable assurance the in-scope piping is being managed for potential selective leaching.

If a piping segment is selected for inspection, a 1-foot axial length of that segment will constitute one inspection. Per LRA Section B.2.3.41, Element 4, of this plant-specific program, Inspections, where possible, focus on the bounding or lead components most susceptible to aging based on time-in-service and severity of operating conditions for each population. Given the close proximity (short length) and expected uniform conditions of the entire piping line, there would be no reason to select a specific 1-foot section over another based on time-in-service or operating conditions. Therefore, PG&E concludes there would be no valuable information obtained by treating each 1-foot segment as a separate component, resulting in multiple inspections on a piping line.

In accordance with the recommendations set forth by NUREG-2191, for sample populations with fewer than 35 components, the DCPP Periodic Inspections for Selective Leaching AMP in LRA Section B.2.3.41 states that DCPP will perform one destructive examination for this population during each inspection period at each Unit.

RAI B.2.3.26-1 Regulatory Basis:

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s)

PG&E Letter DCL-25-001 Page 8 of 29 will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

As amended by letter dated October 14, 2024 (ML24289A118), LRA Table 3.5.2.1.14 states that hardening, loss of strength, and loss of material for elastomeric expansion joints exposed to a buried environment will be managed by the Buried and Underground Piping and Tanks program. The AMR items cite generic note J.

As amended by letter dated October 14, 2024, LRA Section B.2.3.26, Buried and Underground Piping and Tanks, states [t]he DCPP Buried and Underground Piping and Tanks AMP is an existing program that manages cracking, loss of material, hardening and loss of strength (for elastomers only), and change in surface conditions of buried and underground components in the auxiliary saltwater (ASW) system, diesel generator fuel transfer system, fire protection system, and the makeup water system[v]isual inspections monitor the condition of protective coatings and wrappings and directly assess the surface condition of components with no protective coatings or wraps.

LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation, provides guidance with respect to managing hardening and loss of strength for elastomeric components using GALL-LR Report AMP XI.M36, External Surfaces Monitoring of Mechanical Components. The guidance specifies that (a) physical manipulation is used to augment visual inspections to confirm the absence of elastomer hardening and loss of strength; and (b) that the sample size for physical manipulation should be at least 10 percent of available surface area.

Issue It is unclear to the staff why physical manipulation (i.e., pressing, flexing and bending) of at least 10 percent of available surface area is not used to augment visual inspections of the buried elastomeric expansion joints.

PG&E Letter DCL-25-001 Page 9 of 29 Request State the basis for why physical manipulation of at least 10 percent of available surface area is not used to augment visual inspections of the buried elastomeric expansion joints. Alternatively, revise the LRA (as appropriate) to reflect that physical manipulation of at least 10 percent of available surface area will be used to augment visual inspections of the buried elastomeric expansion joints.

PG&E Response to RAI B.2.3.26-1:

In evaluating the elastomeric expansion joints in a buried environment for this response (LRA Table 3.3.2-3), it was determined that the expansion joint pressure boundary is carbon steel with only an elastomer gasket. As discussed in LRA Section 2.1.5.6, gaskets are considered consumables. Because the gaskets are not relied on for pressure boundary, they do not require aging management review. Therefore, in, Attachment A, PG&E revises LRA Table 3.3.2-3 to delete the buried elastomer expansion joint lines. The carbon steel pressure boundary portion of the expansion joints is captured by existing lines in LRA Table 3.3.2-3 under the component type piping, piping components.

Based on the changes to LRA Table 3.3.2-3, there are no elastomer components being managed by the DCPP Buried and Underground Piping and Tanks AMP. In Enclosure 1, Attachment A, PG&E revises LRA Sections A.2.2.26 and B.2.3.26 to eliminate the need to manage hardening, loss of strength, and loss of material for elastomers by the DCPP Buried and Underground Piping and Tanks AMP.

RAI B.2.3.36 Regulatory Basis 10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10CFR54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis.In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

PG&E Letter DCL-25-001 Page 10 of 29

Background:

As amended by letter dated October 14, 2024 (ML24289A118), the applicant included a proposed revision to aging management program (AMP) B.2.3.36, Insulation Material for Electric Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. The proposed revision resulted from an observation made during the NRC staffs onsite audit at DCPP. Specifically, during the onsite audit, the applicants staff identified the presence of and showed the NRC staff an adverse localized environment (ALE) that involved oil mist residue on in-scope cables located in the auxiliary building.

The proposed aging management revision is contrary to existing guidance noted in EPRI Report 3002010641, Low Voltage and Instrumentation and Control Cable Aging Management Guide. Revision 1 which provides guidance for instances when low voltage and instrumentation and controls cables that are unintentionally exposed to chemicals, including oil. Unlike the actual condition at DCPP, the EPRI report guidance assumes that the oil exposure was because of a one-time event/spill (i.e., assumes that once the cables are cleaned that they will no longer be exposed to chemicals/oil, thereby removing a potential degradation mechanism). The cables were not designed to be protected against constant exposure to oil.

The proposed aging management revision consisted of visual inspection of the accessible portions of the cable trays from the ground level and the wiping of the cables. The NRC staff is not aware of any additional inspections or tests that the applicant performed on the impacted cables to assess the current condition or the effects of the oil on the cables. The proposed aging management for in-scope cables subject to this ALE may lead to degradation going undetected. Therefore, consistent with EPRI Report 3002010641, more precise testing, such as indenter modulus, in combination with full visible and tactile inspections appears to be more appropriate to fully ascertain whether in-scope cables are showing signs of degradation (i.e., softening or swelling) during the period of extended operation.

The NRC staff needs additional information to reach a conclusion of reasonable assurance that the applicants proposed AMP B.2.3.36, Insulation Material for Electric Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements, as modified in Amendment 1, will adequately manage the degradation mechanisms caused by the aforementioned ALE to ensure that in-scope cables will continue to perform their design function(s) consistent with the CLB during the period of extended operation.

Request:

Provide additional information supporting the proposed aging management of in-scope cables subjected to the ALE (chemicals/oil mist) and/or additional aging management actions to provide reasonable assurance that the impacted cables will perform their PG&E Letter DCL-25-001 Page 11 of 29 design function(s) during the period of extended operation including corrective actions to prevent oil mist residue from contacting the impacted cables.

PG&E Response to RAI B.2.3.36:

A limited portion of in-scope cables in the auxiliary building are exposed to oil dripping from supply fan louvers that are above the cable trays. On November 20, 2024, PG&E engineering directly viewed the affected cables to document the oil residue extent of condition. The findings from this inspection show that in most cases, the oil condenses and drops in a vertical plane directly below the louver onto the cables. In other cases (1-2 instances), the oil coats the cables in a very thin layer across 1-2 feet. Overall, the amount of oil found was minimal and affected a small, localized area of cable. No damage or degradation to the cable or cable jackets was identified.

As discussed in DCL-24-092, Enclosure 1, Attachment JJJ, PG&E has implemented annual preventive maintenance plans to tactilely/visually inspect the cables as well as perform cleanings every 6 months offset from the inspection. Given the long-standing operating experience (OE) (greater than 10 years) with this condition and no recorded issues, PG&E concludes this approach provides reasonable assurance of cable health until covers are installed over the affected portion of the cables to eliminate the ALE prior to December 31, 2025.

In Enclosure 1, Attachment A, PG&E revises LRA Table A-3, item 38, and LRA Section B.2.3.36 to implement a solution to prevent or divert oil from the cables affected by oil residue prior to December 31, 2025. The affected portion of the cables will first be inspected and cleaned prior to then installing covers over the affected portion of the cables to eliminate the ALE. As described in LRA Section B.2.3.36 (as amended in DCL-24-092, Enclosure1, Attachment JJJ), annual inspections and cleanings will no longer be required to manage the cables affected by the oil residue ALE once PG&E verifies the ALE is eliminated.

RAI B.2.3.33-1 Regulatory Basis Title 10 of the Code of Federal Regulations Section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL-LR Report when evaluation of the matter in the GALL-LR Report applies to the plant.

PG&E Letter DCL-25-001 Page 12 of 29

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Background===

LRA Section B.2.3.33, as modified by LRA Amendment 1 (ML24289A118), provides an enhancement to the parameters monitored or inspected program element, which relates to monitoring/inspecting structural sealants (including weatherproofing boots) for parameters specified in ACI 349.3R and/or ANSI/ASCE 11, and it also provides an enhancement to the acceptance criteria program element, which relates to specifying that structural sealants (including weatherproofing boots) are acceptable if the observed loss of material, cracking, and hardening will not result in loss of sealing.

LRA Section A.2.2.33 states that the DCPP Structures Monitoring AMP utilizes acceptance criteria for structural components and structural features in accordance with ACI 349.3R-02 and ASCE 11-90.

GALL-LR XI.S6 AMP states in the parameters monitored or inspected program element that elastomeric vibration isolators and structural sealants are monitored for cracking, loss of material, and hardening.

Issue LRA does not specify the version of ACI 349.3R and ANSI/ASCE 11 in the enhancement. The staff reviewed ACI 349.3R-02 and ANSI/ASCE 11-90 and did not find parameters monitored or inspected for structural sealants (including weatherproofing boots).

Request

1. Clarify the parameters monitored or inspected for structural sealants (including weatherproofing boots).

2. Clarify the version of ACI 349.3R and ANSI/ASCE 11 in this enhancement and clarify which code provisions specify the parameters monitored or inspected for structural sealants (including weatherproofing boots).

3. Revise the enhancement accordingly based on the responses above.

PG&E Response to RAI B.2.3.33-1:

1. Consistent with the recommendations in NUREG-1801, Revision 2,Section XI.S6, and NUREG-2191,Section XI.S6, Element 3, the parameters monitored or inspected for structural sealants (including weatherproofing boots) are cracking, loss of material, and hardening.

2. As discussed in response to item 3, PG&E revises the subject enhancement to remove reference to ACI 349.3R and ANSI/ASCE 11.

3. In Enclosure 1, Attachment A, PG&E revises LRA Table A-3, item 35(f), and the associated enhancement in LRA Section B.2.3.33 to remove reference to ACI PG&E Letter DCL-25-001 Page 13 of 29 349.3R and ANSI/ASCE 11 and list the specific parameters monitored for structural sealants (including weatherproofing boots).

RAI B.2.3.33-2 Regulatory Basis Title 10 of the Code of Federal Regulations Section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL-LR Report when evaluation of the matter in the GALL-LR Report applies to the plant.

Background

EPRI 3002007358, 2016 technical report, provides guidance for aging management of leaking spent fuel pools (SFPs) for pressurized water reactors (PWRs) with a focus on boric acid attack of concrete (BAAC). The Appendix A of EPRI report provides a generic aging management program (AMP) template for managing effects of BAAC in a spent fuel pool (SFP) structure that has been exposed to leakage.

LRA Section B.2.3.33, as modified by LRA Amendment 1 (ML24289A118), provides enhancements to the Elements 1 to 7, which relate to including but not limited to the following: (1) Develop or revise procedures to manage the SFP and Transfer Canal (TC) surveillance and maintenance activities consistent with Elements 1 through 7 of EPRI 3002007348; and (2) Evaluate NUREG/CR-7111, EPRI 3002007348 enhancement recommendations, industry OE, and DCPP OE pertaining to reactor cavity and refueling canal liner leaks to determine appropriate inspection and maintenance activities for the reactor cavity and refueling canal. The staff noted that no enhancement to the preventative actions program element is needed for aging management of BAAC based on review of EPRI 3002007358 report.

During the audit (ML24311A123), the staff noted that the applicant made an evaluation of the DCPP Structures Monitoring program elements 1 through 7 for the SFP and TC to identify the level of consistency with the Appendix A AMP template for aging management of boric acid attack on reinforced concrete structures in EPRI 3002007348 report and provided the detailed enhancements to the Structures Monitoring program for each program element. The staff reviewed these enhancements to the Structures Monitoring program (file name: SFP & Transfer Canal Element 1-7 Evaluations.pdf) and identified the following issues:

(1) All Elements: Enhancements to the Structures Monitoring program do not make clear whether they are applicable to the TC, reactor cavity and refueling canal since only SFP is mentioned; PG&E Letter DCL-25-001 Page 14 of 29 (2) Element 3, Parameters monitored or inspected: Monitoring of leak chase system discharge: The enhancement lacks information for determining flow (drip) rate from the leak chase system discharge, it also miss some parameters (e.g. pH, Boron, Iron) from the chemical analyses; (3) Element 4, Detection of aging effects: Monitoring of leak chase system discharge: Sample collection and analyses lack other parameters such as pH, boron, and iron. Inspection of telltale: Subsequent periodic tell-tale drain internal inspection frequency is not specified; (4) Element 6, Acceptance criteria: Inspection of telltales: The enhancement is inconsistent with EPRI 3002007348 report recommendations on no indications of blockage development; (5) Element 7, Corrective actions: The applicant does not provide the justification why the enhancement to the corrective actions program element is not needed.

Issue The enhancements to the Structures Monitoring program for aging management of BAAC in LRA Section B.2.3.33, as modified by LRA Amendment 1 (ML24289A118) are too broad. They need to be specific with detailed information based on the plant-specific operating experiences to ensure when they are implemented, they will be consistent with the EPRI 3002007358 report recommendations. In addition, see issues identified by the staff in the background section above.

Request

1. Evaluate Elements 1, and 3 through 7 in the EPRI 3002007348 report AMP template to determine which elements need to be enhanced in the DCPP Structures Monitoring program for managing aging effects of BAAC in the SFP, TC, reactor cavity and refueling canal, and provide detailed enhancements to each program element if necessary to ensure the consistency with EPRI 3002007348 report recommendations.

2. Provide the justification for why certain enhancements described in EPRI 3002007348 report AMP template are not necessary.

3. Address the issues from 1 to 5 identified by the staff in the background section.

4. Revise the LRA accordingly based on the responses above.

PG&E Response to RAI B.2.3.33-2:

1. Element Evaluation:

The following is a summary of DCPP Structures Monitoring AMP (SMP) enhancement details that will provide added assurance that the intended function of reinforced concrete structures that have the potential to be exposed to leakage containing boric acid are maintained through the period of extended operation (PEO) consistent with Elements 1, and 3 through 7 in the EPRI Report 3002007348 AMP template.

PG&E Letter DCL-25-001 Page 15 of 29 SMP Aging Management of the Spent Fuel Pool (SFP) and Transfer Canal (TC):

Element 1 Scope of Program - For the SFP and TC:

Element 1 of the DCPP SMP management of the SFP and TC, is consistent without exception to the EPRI Report 3002007348 AMP template.

Element 3 Parameters Monitored or Inspected - For the SFP and TC:

Visual inspection of SFP and TC structure enhancement: LRA Table A-3, item 35(o) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included an enhancement to require that walkdowns monitor for evidence of new leak sites or changes in existing leak sites in accordance with EPRI Report 3002007348.

Monitoring of leak chase system discharge enhancement: LRA Table A-3, item 35(p) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included, as volume permits, periodic leak chase sample analysis for chlorides and sulfates in accordance with EPRI Report 3002007348.

Inspection of leak chase enhancement: Per LRA Table A-3, item 35(n), as added in DCL-24-092, Enclosure 1, Attachment HHH, video inspections of all Units 1 and 2 SFP and TC leak chases to check for development of blockages was completed prior to entrance into the PEO. LRA Table A-3, item 35(q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included an enhancement to require subsequent periodic leak chase internal inspections be performed, in the PEO, based on monitoring and trending leak chase data for indication of potential blockage.

Element 3 of the DCPP SMP management of the SFP and TC, with the enhancements included above, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 4 Detection of Aging Effects - For the SFP and TC:

Data review enhancement: LRA Table A-3, item 35(q), as added in DCL-24-092,, Attachment HHH, included an enhancement to require a periodic integrated evaluation of all data obtained from the various inspection and monitoring activities associated with this AMP to accurately characterize the SFP and TC leakage condition and the associated aging effects.

Visual inspection of SFP and TC structure enhancement: LRA Table A-3, item 35(o) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included an enhancement to require that walkdowns, of the accessible portions of the SFP and TC structure adjacent to and below the normal SFP and TC water level, PG&E Letter DCL-25-001 Page 16 of 29 include looking for any evidence of SFP and TC leakage, such as formation of deposits or wet areas on SFP and TC structure walls.

Monitoring of leak chase system discharge enhancement: LRA Table A-3, item 35(p) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included an enhancement to require periodic chlorides and sulfates analysis, as volume permits, that is obtained in accordance with EPRI 3002007348 recommendations.

Inspection of leak chase enhancement: Per LRA Table A-3, item 35(n), as added in DCL-24-092, Enclosure 1, Attachment HHH, video inspections of all Units 1 and 2 SFP and TC leak chases to check for development of blockages was completed prior to entrance into the PEO. LRA Table A-3, item 35(n) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, also included an enhancement to require subsequent periodic leak chase internal inspections to be performed based on monitoring and trending leak chase drain data to check for development of blockages. Plant and industry OE indicate that this frequency will be sufficient to detect formation of blockages before they are completely closed.

Element 4 of the DCPP SMP management of the SFP and TC, with the enhancements included above, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 5 Monitoring and Trending - For the SFP and TC:

Enhancement: LRA Table A-3, item 35(q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included an enhancement to require a periodic integrated review of data to identify any departures from the SFP and TC leakage conditions assumed in the DCPP structure evaluation of degradation due to exposure of borated SFP leakage.

Element 5 of the DCPP SMP management of the SFP and TC, with enhancements included above, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 6 Acceptance Criteria - For the SFP and TC:

LRA Table A-3, item 35(n), (o), (p), and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, included enhancement to establish the following acceptance criteria for each of the monitored parameters. Exceedance of any criterion will result in an entry into the corrective action program that requires further disposition.

PG&E Letter DCL-25-001 Page 17 of 29 Table A-1 Acceptance criteria for leak chase system discharge

[Parameter] Frequency Acceptance Criteria Commitment 35 Enhancement(s)

[Leak Rate] Monthly

[Upper limit: 700 milliliters (ml)/chase/day if any leakage has previously occurred; Lower limit: >

0 for known leakers]

p and q

[pH] Monthly

[8 to 11]

p and q

[Boron] Annually and if leak rate has increased by 3x previous value

[Information Only]

p and q

[Chloride] Conditional if leak rate has increased by 3x previous value and total volume collected

>300 ml

[<500 parts per million(ppm)]

p and q

[Sulfate] Conditional if leak rate has increased by 3x previous value and total volume collected

>300 ml

[<1,500 ppm]

p and q

[Iron] Monthly

[Information Only]

p and q

[Tritium] Monthly

[Information Only]

p and q

[Gamma Isotopic] Monthly

[Information Only]

p and q

[Integrated Review] Quarterly

[N/A]

p and q

[Pre-PEO Internal rodding, snaking or video Inspections of all leak chases] One-Time No indications of blockage development. Residue may remain from old blockages that were resolved. Such residue is not an indication of new blockage development. Reduction in flow area through the residue is evidence of blockage development and should be addressed via the corrective action program.

p and n

[Periodic Internal rodding, snaking or video Leak Chase Inspections] Based on monitoring and trending leak chase data for indication of blockage development.

n, p, and q

[Periodic Walkdowns] 5-Years Monitor for evidence of new leak sites or changes in existing leak sites in accordance with the EPRI Report 3002007348 AMP template. This includes no indications of new or increased leakage from the SFP and TC.

More specifically, this criterion includes inspection for formation of deposits that are potentially o, p, and q PG&E Letter DCL-25-001 Page 18 of 29 Table A-1 Acceptance criteria for leak chase system discharge

[Parameter] Frequency Acceptance Criteria Commitment 35 Enhancement(s) related to SFP and TC leakage (for example, white crystals) or weeping from cracks or construction joints.

Element 6 of the DCPP SMP management of the SFP and TC, with the enhancements included above, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 7 Corrective Actions - For the SFP and TC:

Corrective Actions enhancement: LRA Table A-3, item 35(q), as added in DCL-24-092,, Attachment HHH, included procedural enhancement to require that (1) the SFP and TC data that does not meet the acceptance criteria result in entries into the plants corrective action program for subsequent dispositioning; (2) corrective actions associated with SFP and TC leakage to determine whether the observed indications of changes in the leakage conditions cause structural margin to become inadequate; (3) if inspection of leak chase identifies development of a blockage, appropriate methods will be evaluated to restore leak chase flow.

Element 7 of the DCPP SMP management of the SFP and TC, with enhancements included above, will be consistent without exception to the EPRI Report 3002007348 AMP template.

SMP Aging Management of the Reactor (Rx) Cavity and Refueling Canal (RC)

See revised LRA Table A-3, item 35(o), (p), (q), (r), and (s) in part 4 of this response.

Element 1 Scope of Program - For the Reactor (Rx) Cavity and Refueling Canal (RC):

Scope of Program enhancement: LRA Table A-3, item 35(o), (p), (q), and (r) is revised, as described in part 4 of this response, to add enhancements for the management of aging effects due to interaction between Rx Cavity/RC leakage and the concrete adjacent to the Rx Cavity and RC liner in accordance with EPRI Report 3002007348 AMP template.

New LRA Table A-3, item 35(s), as described in part 4 of this response, requires a structural evaluation of the Rx Cavity and RC structure that includes identification of surfaces exposed to Rx Cavity and RC leakage and a conservative projection of the PG&E Letter DCL-25-001 Page 19 of 29 potential degradation of those surfaces in accordance with EPRI Report 3002007348 AMP template.

Element 1 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 3 Parameters Monitored or Inspected - For the Rx Cavity and RC:

Visual inspection of Rx Cavity and RC structure enhancement: LRA Table A-3, item 35(o) and (q) is revised, as described in part 4 of this response, to include an additional enhancement to require that walkdowns monitor for evidence of new leak sites or changes in existing leak sites in accordance with EPRI Report 3002007348.

Monitoring of leak chase system discharge enhancement: LRA Table A-3, item 35(p) and (q) is revised, as described in part 4 of this response, to include enhancement requiring sample analysis for flow rate, pH, Boron, Chloride, Sulfates, Iron, Tritium and Gamma Isotropic (as sample volumes permit) in accordance with EPRI Report 3002007348.

Inspection of leak chases enhancement: LRA Table A-3, item 35(r) is revised, as described in part 4 of this response, to require performance of rodding, snaking or video inspections of Rx Cavity and RC leak chases for indication of blockage development. LRA Table A-3, item 35(r) and (q) is revised, as described in part 4 of this response, to require subsequent periodic leak chase internal inspections be performed based on monitoring and trending leak chase drain data for indication of potential blockage.

Element 3 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 4 Detection of Aging Effects - For the Rx Cavity and RC:

Data review enhancement: LRA Table A-3, item 35(q) is revised, as described in part 4 of this response, to include an enhancement to require a periodic integrated evaluation of all data obtained from the various inspection and monitoring activities associated with this AMP to accurately characterize the Rx Cavity and RC leakage condition and the associated aging effects.

Visual inspection of Rx Cavity and RC structure enhancement: LRA Table A-3, item 35(o) and (q) is revised, as described in part 4 of this response, to include and enhancement for walkdowns of the accessible portions of the Rx Cavity and RC structure adjacent to and below the normal Rx Cavity and RC water level.

This enhancement includes a requirement to identify any evidence of Rx Cavity PG&E Letter DCL-25-001 Page 20 of 29 and RC leakage, such as formation of deposits or wet areas on Rx Cavity and RC structure walls.

Monitoring of leak chase system discharge enhancement: LRA Table A-3, item 35(p) and (q) is revised, as described in part 4 of this response, to include enhancement to require leak chase drain sample analysis for flow rate, pH, Boron, Chloride, Sulfates, Iron, Tritium and Gamma Isotropic.

Inspection of leak chases enhancement: LRA Table A-3, item 35(r) is revised, as described in part 4 of this response, to require performance of rodding, snaking or video inspections of Rx Cavity and RC leak chases to identify potential blockages. LRA Table A-3, item 35(r) and (q) is revised, as described in part 4 of this response, to also require subsequent periodic leak chase internal inspections be performed based on monitoring and trending leak chase data to check for development of blockage. Plant and industry OE indicate that this frequency will be sufficient to detect formation of blockages before they are completely closed.

Element 4 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 5 Monitoring and Trending - For Rx Cavity and RC:

Enhancement: New LRA Table A-3, item 35(s), as described in part 4 of this response, includes a structural evaluation of the Rx Cavity and RC structure. This structural evaluation includes a prediction of potential degradation due to exposure of borated Rx Cavity and RC leakage.

Enhancement: LRA Table A-3, item 35(q) is revised, as described in part 4 of this response, to implement a periodic integrated evaluation of data to identify any departures from the Rx Cavity and RC leakage conditions assumed in the structure evaluation.

Element 5 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 6 Acceptance Criteria - For the Rx Cavity and RC:

LRA Table A-3, item 35(p), (q), (r), and (o) is revised, as described in part 4 of this response, to establish the following acceptance criteria for each of the monitored parameters. Exceedance of any criterion will result in an entry into the corrective action program that requires further disposition.

PG&E Letter DCL-25-001 Page 21 of 29 Table A-1 Acceptance criteria for leak chase system discharge

[Parameter] Frequency Acceptance Criteria Commitment 35 Enhancement(s)

[Leak Rate] Refueling Outage (RFO) 0 drips per minute unless identified as a known leaker p and q

[pH] RFO

[>5]

p and q

[Boron] RFO

[Information Only]

p and q

[Chloride] Conditional, during RFO, if leak rate has increased by 3x previous value and total volume collected >300 ml

[<500 ppm]

p and q

[Sulfate] Conditional, during RFO, if leak rate has increased by 3x previous value and total volume collected >300 ml

[<1,500 ppm]

p and q

[Iron] RFO

[Information Only]

p and q

[Tritium] RFO

[Information Only]

p and q

[Gamma Isotopic] RFO

[Information Only]

p and q

[Integrated Review] After collection of RFO data

[N/A]

p and q Baseline Internal Inspections of all leak chases] One-Time No indications of blockage development.

Residue may remain from old blockages that were resolved. Such residue is not an indication of new blockage development. Reduction in flow area through the residue is evidence of blockage development and should be addressed via the corrective action program.

p and r

[Periodic Internal Inspections], During RFOs, based on monitoring and trending leak chase data for indication of blockage development.

p, q, and r

[Walkdowns] 5-year, during RFOs Monitor for evidence of new leak sites or changes in existing leak sites in accordance with the EPRI Report 3002007348 AMP template. This includes no indications of new or increased leakage from the Rx Cavity and RC. More specifically, this criterion includes inspection for formation of deposits that are potentially related to Rx Cavity and RC leakage (for example, white crystals) or weeping from cracks or construction joints.

p, q, and o PG&E Letter DCL-25-001 Page 22 of 29 Element 6 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

Element 7 Corrective Actions - For the Rx Cavity and RC:

Corrective Actions enhancement: LRA Table A-3, item 35(q) is revised, as described in part 4 of this response, to include procedural enhancement to require that (1) the Rx Cavity and RC data that does not meet the acceptance criteria result in entries into the plants corrective action program for subsequent dispositioning; (2) corrective actions associated with Rx Cavity and RC leakage to determine whether the observed indications of changes in the leakage conditions cause structural margin to become inadequate; (3) if inspection of leak chase identifies development of a blockage, appropriate methods will be evaluated to restore leak chase flow.

Element 7 of the DCPP SMP management of the Rx Cavity and RC, with enhancement, will be consistent without exception to the EPRI Report 3002007348 AMP template.

2. Enhancement Justification:

SFP and TC: As discussed in response to item 1, LRA Table A-3, item 35(n),

(o), (p), and (q) enhancements will ensure consistency with EPRI Report 3002007348, Elements 1 and 3 through 7.

Rx Cavity and Refueling Canal: As discussed in response to item 1, LRA Table A-3, item 35(o), (p), (q), (r), and (s) enhancements, as revised in part 4 of this response, will ensure consistency with EPRI Report 3002007348, Elements 1 and 3 through 7.

3. Address Issues 1 to 5 identified by the staff in the background section:

1) All elements:

i.

The DCPP SFP and TC are continuously filled with borated water. DCPP SFP and TC liner leakage monitoring began in 1988. The DCPP Unit 1 and 2 SFP and TC leak chases are located behind all liner weld joints for capturing water that potentially leaks through the liner seam welds. Any leakage through the liner is collected in the leak chases and is routed via gravity to a leakage monitoring station which has six separate collection points with isolation valves and capped lines. SFP and TC leakage monitoring station is located outside of containment.

ii.

The DCPP Rx Cavity and RC is filled with borated water during refueling fuel transfers (approximately 2 to 3 weeks every 18 months) to permit underwater transport of fuel elements between the SFP and the Rx Vessel. These Rx Cavity and RC leak chases are located behind all liner weld joints for capturing water that potentially leaks through the liner seam welds. Any leakage through the liner is collected in the leak chases and is routed via gravity to a leakage monitoring station which has nine leak detection collection points (for each unit). The Rx Cavity and RC leak PG&E Letter DCL-25-001 Page 23 of 29 chase monitoring station monitoring station is inside containment and the leak chase lines do not have isolation valves/caps allowing for leakage (if any) to freely drip into a scupper.

2) Element 3:

i.

SFP and TC: The example, provided in EPRI Report 3002007348, for flowrate determination via collection of drips from a leak chase for a specific time is not utilized because the DCPP SFP and TC leak chase lines have isolation valves and caps preventing drippage from the lines.

Leak chase flow rate is determined by measuring the volume collected from each leak detection sample tap that contained leakage and dividing the volume collected over the time that leakage was allowed to accumulate behind the isolation valve. Reference item 1 response, Table A-1, for identification of all parameters monitored.

ii.

Rx Cavity and RC: LRA Table A-3, item 35(q) and (p) is revised, as described in part 4 of this response, to implement the example provided in EPRI Report 3002007348, for flowrate determination via estimation of drips or ml per minute.

3) Element 4:

i.

SFP and TC: Reference item 1 response, Table A-1, for detection of pH, boron and iron. Per LRA Table A-3, item 35(n) and (q), as added in DCL-24-092, Enclosure 1, Attachment HHH, subsequent periodic leak chase internal inspections will be performed in the PEO based on monitoring and trending leak chase data for indication of potential blockage. Plant and industry OE indicates that this frequency will be sufficient to detect formation of blockages before they are completely closed. This is in accordance with the EPRI Report 3002007348 recommendation for periodic leak chase internal inspections.

ii.

Rx Cavity and RC: Reference item 1 response, Table A-1, for detection of pH, boron and Iron. LRA Table A-3, item 35(r) is revised, as described in part 4 of this response, to require subsequent periodic leak chase internal inspections be performed in the PEO based on monitoring and trending leak chase data for indication of potential blockage. Plant and industry OE indicates that this frequency will be sufficient to detect formation of blockages before they are completely closed. This is in accordance with the EPRI Report 3002007348 recommendation for periodic leak chase internal inspections.

4) Element 6:

i.

SFP and TC: Reference item 1 response, Table A-1, for detailed internal inspection of telltales acceptance criteria.

ii.

Rx Cavity and RC: Reference item 1 response, Table A-1, for detailed internal inspection of telltales acceptance criteria.

5) Element 7:

i.

SFP and TC: Reference item 1 response, Element 7, for LRA Table A-3, item 35(q) corrective action procedural enhancement clarification.

PG&E Letter DCL-25-001 Page 24 of 29 ii.

Rx Cavity and RC: Reference item 1 response, Element 7, for LRA Table A-3, item 35(q) corrective action procedural enhancement clarification.

4. LRA Revisions:

In Enclosure 1, Attachment A, PG&E revises LRA Table A-3, item 35, and Sections A.2.2.33 and B.2.3.33, as discussed in response to items 1 through 3 above.

RAI 3.5.2 Regulatory Basis Title 10 of the Code of Federal Regulations Section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL-LR Report when evaluation of the matter in the GALL-LR Report applies to the plant.

Background

LRA Table 3.5.2-14, as modified by LRA Amendment 1 (ML24289A118), lists PVC conduit and supports exposed to a buried environment, there is no aging effect, and no Aging Management Program (AMP) is proposed. The AMR item cites generic note G. The AMR item cites plant-specific note 2, which states that, due to DCPPs location in a negligible weathering region where concrete is rarely exposed to freezing in the presence of moisture, there are no significant seasonal changes on the soil, and no movement over time that would induce loss of material due to wear on the buried PVC conduit. While the staff noted that a freeze/thaw cycle is a potential contributor to movement of deleterious materials on the soil, it is not the only potential contributor to loss of material due to wear on the buried PVC conduit and supports. Seasonal heavy precipitation and/or variations of groundwater levels throughout the site could potentially cause significant changes to occur on the soil surrounding PVC conduit and supports.

Issue The LRA does not provide adequate technical basis for not managing the aging effect of loss of material due to wear for PVC conduit and supports exposed to a buried environment. In addition, the LRA does not make clear how the definition of a negligible weathering region defined for not impacting concrete due to freeze-thaw is applicable to PVC as these materials are subject to different aging mechanisms and aging effects due to their inherent differences in chemical/physical composition and their interactions with the surrounding soil or groundwater.

PG&E Letter DCL-25-001 Page 25 of 29 Request

1. Provide adequate justification for not managing the aging effect of loss of material due to wear for PVC conduit and supports exposed to a buried environment.

Otherwise, identify and assess an appropriate AMP to manage loss of material for PVC in a buried environment to be consistent with the GALL-LR Report.

2. Revise the application accordingly based on the responses above.

PG&E Response to RAI 3.5.2:

In evaluating the buried polyvinyl chloride (PVC) conduit for this response (LRA Table 3.5.2-14), PG&E identified that the conduit material is rigid galvanized steel that is coated with PVC. Because the galvanized steel performs the intended functions of shelter, protection and structural support, in Enclosure 1, Attachment A, PG&E revises LRA Table 3.5.2-14 to correct the material of the subject conduit and revise the applicable aging effects and aging management accordingly. This applies to all the conduit previously identified as PVC but now determined to be galvanized steel.

Corresponding changes are made to LRA Table 3.5-1 and Sections 3.5.2.1.14, A.2.2.22, and B.2.3.22.

RAI 3.6 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the U.S. Nuclear Regulatory Commission (NRC) staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. To complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background:

SRP-LR section 3.6.2.2.3, Loss of Material due to Wind-Induced Abrasion, Loss of Conductor Strength due to Corrosion, and Increased Resistance of Connection due to Oxidation or Loss of Pre-load, states that the loss of material due to wind-induced abrasion could occur in switchyard bus and connections.

LRA Table 3.6-1, Summary of Aging Management Evaluations for Electrical Commodities, item 3.6-1, 006 indicates that the aging effects for switchyard bus and PG&E Letter DCL-25-001 Page 26 of 29 connections are loss of material due to wind-induced abrasion and increased resistance of connection due to oxidation or loss of pre-load. LRA Table 3.6-1, Item Number 3.6-1, 006 states that the plant-specific AMP B.2.3.42 is used to manage the aging effects of loss of material - and increased resistance for switchyard bus and connections and further evaluation is provided in LRA section 3.6.2.2.3.

LRA Table 3.6-1, item 3.6-1, 007 indicates that the aging effect of loss of material due to wind-induced abrasion is applicable to transmission conductors, and the plant-specific AMP B.2.3.42 is used to manage this aging effect. LRA Table 3.6-1, item 3.6-1, 007 states that further evaluation is provided in LRA section 3.6.2.2.3.

LRA Table 3.6.2-1, Electrical and Instrument and Controls - Summary of Aging Management Evaluation - Electrical Components, Table 1 item 3.6-1, 006 and Table 1 item 3.6-1, 007 indicate that the aging effect requiring management of loss of material is applicable to the switchyard bus and the transmission conductors, respectively.

LRA section B.2.3.42, element 3, Parameters Monitored or Inspected, states that Aluminum buses are inspected for degradation of the bus due to aging that would be evidenced by corrosion buildup or cracks at joints and connections, and element 5 Monitoring and Trending, discusses monitoring of switchyard buses for corrosion and degraded connections.

SRP-LR Table 3.0-1, FSAR Supplement for Aging Management of Applicable Systems, states that the description of the AMP should contain information associated with the bases for determining that aging effects will be managed during the period of extended operation.

LRA section A.2.2.42, Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators, provides the following Final Safety Analysis Report (FSAR) Supplement for the aging management program (AMP) B.2.3.42, Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators:

The DCPP Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators AMP is an existing AMP that manages the aging effects of the 230 kV and 500 kV components required for SBO recovery which include transmission conductors and connections, insulators, and switchyard bus and connections to ensure that these components are capable of performing their intended functions throughout the PEO.

Infrared thermography inspection of transmission and bus connections for indications of loose or degraded connections, inspection of transmission conductors for corrosion and fatigue, and inspection of insulator supports for corrosion and wear will be conducted at a frequency based on plant-specific OE. In addition, inspection of the high-voltage insulators for contamination occurs at a frequency based on plant-specific OE.

PG&E Letter DCL-25-001 Page 27 of 29 The NRC staff notes that:

1. It appears that LRA section 3.6.2.2.3, Loss of Material due to Wind-Induced Abrasion, Loss of Conductor Strength due to Corrosion, and Increased Resistance of Connection due to Oxidation or Loss of Pre-load, and LRA section B.2.3.42 do not discuss the aging effect of loss of material due to wind-abrasion on switchyard bus and transmission conductors.

2. It appears that LRA section A.2.2.42 does not contain information associated with the bases for determining that aging effects on the switchyard bus will be managed during the period of extended operation.

Issue The NRC staff is unclear on whether the loss of material due to wind-abrasion or other cause is an applicable aging effect for DCPP switchyard bus and transmission conductors. The staff is also unclear on how the FSAR supplement in LRA section A.2.2.42 covers the information for determining that aging effects on the switchyard bus will be managed during the period of extended operation.

Request

1. Provide further evaluation for the aging effect of loss of material on switchyard bus in LRA section 3.6.2.2.3 and section B.2.3.42.

2. Provide further evaluation for the aging effect of loss of material on transmission conductors in LRA section 3.6.2.2.3 and section B.2.3.42.

3. Provide the bases for determining that applicable aging effects (corrosion, loss of material) on the switchyard bus will be adequately managed during the period of extended operation in LRA section A.2.2.4 PG&E Response to RAI 3.6:

Items 1 and 2: As discussed in LRA Section 3.6.2.2.3, loss of material (wear due to wind-induced abrasion) is managed by the DCPP Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators AMP (B.2.3.42). LRA Section B.2.3.42 addresses this using the term wear. In particular, LRA Section B.2.3.42, Elements 3, 4, and 5, address this aging effect/mechanism and types of inspections on switchyard bus and conductors by performing aerial, ground based or infrared thermography inspections to identify evidence of contamination, corrosion, and wear. Aluminum buses are inspected for degradation of the bus due to aging that would be evidenced by corrosion buildup or cracks at joints and connections.

These inspection methods are appropriate based on industry experience and DCPP OE.

For clarification, the DCPP Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators AMP uses the following activities to PG&E Letter DCL-25-001 Page 28 of 29 manage the remaining aging effects requiring management (reduced insulation resistance, increased resistance of connection, and loss of conductor strength):

Reduced insulation resistance is managed by visually inspecting high voltage insulators for evidence of contamination (see LRA Section B.2.3.42, Elements 3, 4, 5, and 6).

Increased resistance of connection is managed by infrared thermography inspection of connections for indication of temperature rise (see LRA Section B.2.3.42, Elements 4, 5, and 6).

Loss of conductor strength is managed by inspecting conductors for strand breakage, excessive corrosion, and swelling, and for broken strands and wear at connections and support points (see LRA Section B.2.3.42, Elements 3 and 4).

Item 3: In Enclosure 1, Attachment A, PG&E revises LRA Section A.2.2.42 to provide the basis for determining the applicable aging effects will be adequately managed during the period of extended operations.

RCI B.2.3.33-1 Regulatory Basis Title 10 of the Code of Federal Regulations Section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL-LR Report when evaluation of the matter in the GALL-LR Report applies to the plant.

Background

LRA Section B.2.3.33, as modified by LRA Amendment 1 (ML24289A118), provides new enhancement to the acceptance criteria program element which relates to clarifying that fiberglass roofing is acceptable if there is no evidence of blistering, cracking or loss of material that could cause a loss of function prior to the next scheduled inspection.

LRA Table 3.5.2-4, as modified by LRA Amendment 1 (ML24289A118), lists aging effects of blistering, cracking, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture for fiberglass roofing panel, that are managed by the Structures Monitoring program.

PG&E Letter DCL-25-001 Page 29 of 29 Request:

Confirm that the fiberglass roofing described in the enhancement above refers to the fiberglass roofing panel.

Confirm that blistering, cracking, loss of material due to exposure to ultraviolet light, ozone, radiation, temperature, or moisture are aging effects being considered for the fiberglass roofing panel, which will be included in an enhancement to the parameters monitored or inspected program element in LRA Section B.2.3.33.

PG&E Response to RCI B.2.3.33-1:

PG&E confirms the fiberglass roofing described in the cited enhancement refers to the fiberglass roofing panel. In Enclosure 1, Attachment A, PG&E revises LRA Table A-3, item 35, and LRA Section B.2.3.33 to add a new enhancement for Element 3, Parameters Monitored/Inspected, to monitor fiberglass roofing panels for blistering, cracking, and loss of material.

Attachment A PG&E Letter DCL-25-001 Page 1 of 29 DCPP LRA, Amendment 2 DCPP LRA Amendment 2 Index Affected LRA Section/Table Basis for Change Table 3.3.2-3 RAI B.2.3.26-1 Section 3.5.2.1.14 RAI 3.5.2 Table 3.5-1 RAI 3.5.2 Table 3.5.2-14 RAI 3.5.2 Table 4.1-2 RAI 4.3.2-1 Section 4.3.2.12 RAI 4.3.2-1 Section 4.9 RAI 4.3.2-1 Section A.2.2.22 RAI 3.5.2 Section A.2.2.26 RAI B.2.3.26-1 Section A.2.2.33 RAI B.2.3.33-2 Section A.2.2.42 RAI 3.6 Section A.3.2.1.9 RAI 4.3.2-1 Table A-3, item 35 RAI B.2.3.33-1, RAI B.2.3.33-2, RCI B.2.3.33-1 Table A-3, item 38 RAI B.2.3.36 Section B.2.3.22 RAI 3.5.2 Section B.2.3.24 RAI B.2.3.24 Section B.2.3.26 RAI B.2.3.26-1 Section B.2.3.33 RAI B.2.3.33-1, RAI B.2.3.33-2, RCI B.2.3.33-1 Section B.2.3.36 RAI B.2.3.36 Attachment A PG&E Letter DCL-25-001 Page 2 of 29 DCPP LRA, Amendment 2 LRA Table 3.3.2-3 on pages 3.3-113 and 3.3-131 (as modified by DCL-24-092, Encl. 1, Att. J) is revised as follows to address RAI B.2.3.26-1:

Table 3.3.2-3: Saltwater and Chlorination System - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Item Table 1 Item Notes Expansion Joint Leakage Boundary (spatial)

Stainless Steel Raw Water (Int)

Loss of Material; Fouling Open Cycle Cooling Water System (B.2.3.11)

VII.C1.A-54 3.3-1, 040 A

Expansion Joint Pressure Boundary Elastomer Buried (Ext)

Hardening and Loss of Strength Buried and Underground Piping and Tanks (B.2.3.26)

None None J

Expansion Joint Pressure Boundary Elastomer Buried (Ext)

Loss of Material Buried and Underground Piping and Tanks (B.2.3.26)

None None J

Expansion Joint Pressure Boundary Elastomer Plant Indoor Air (Ext)

Hardening and Loss of Strength External Surfaces Monitoring of Mechanical Components (B.2.3.22)

VII.F1.AP-102 3.3-1, 076 A

Generic Notes J.

Neither the component nor the material and environment combination are evaluated in NUREG-1801.

Attachment A PG&E Letter DCL-25-001 Page 3 of 29 DCPP LRA, Amendment 2 LRA Section 3.5.2.1.14 on pages 3.5-13 and 3.5-14 (as modified by DCL-24-092, Encl.

1, Att. JJ) is revised as follows to address RAI 3.5.2:

3.5.2.1.14 Supports and Structural Commodities Materials The materials of construction for the supports and commodities component types are:

Aluminum Calcium Silicate Carbon Steel Carbon Steel (Galvanized)

Concrete Elastomer Fire Barrier (Cementitious Coating)

Fire Barrier (Ceramic Fiber)

Fire Barrier (Subliming Compounds (Thermo-lag, Darmatt', 3M' Interam', and Other Similar Materials))

Foam Glass Grout Gypsum & Plaster Lubrite Polyvinyl Chloride (PVC)

Stainless Steel Environments The supports and structural commodities component types are exposed to the following environments:

Atmosphere/Weather (Structural)

Borated Water Leakage Buried (Structural)

Encased in Concrete Plant Indoor Air (Structural)

Submerged (Structural)

Aging Effects Requiring Management The following supports and structural commodities aging effects require management:

Change in material properties Cracking Delamination Increased hardness Attachment A PG&E Letter DCL-25-001 Page 4 of 29 DCPP LRA, Amendment 2 Loss of material Loss of mechanical function Loss of preload Loss of sealing Loss of strength Reduced thermal insulation resistance/moisture intrusion Reduction in concrete anchor capacity Reduction in impact strength Separation Shrinkage Attachment A PG&E Letter DCL-25-001 Page 5 of 29 DCPP LRA, Amendment 2 LRA Table 3.5-1 on pages 3.5-67, 3.5-73, and 3.5-74 (as modified by DCL-24-092, Encl. 1, Att. B and II) is revised as follows to address RAI 3.5.2:

Table 3.5-1: Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.5-1, 079 Steel components: piles Loss of material due to corrosion Chapter XI.S6, Structures Monitoring No Consistent with NUREG-1801.

The DCPP Structures Monitoring AMP (B.2.3.33) will be used to manage loss of material due to corrosion of the galvanized steel gabion mattress and conduit, and the structural steel exposed to a buried environment.

3.5-1, 093 Support members; welds; bolted connections; support anchorage to building structure Loss of material due to pitting and crevice corrosion Chapter XI.S6, Structures Monitoring No Consistent with NUREG-1801.

The DCPP Structures Monitoring AMP (B.2.3.33) will be used to manage loss of material due to corrosion of galvanized steel, stainless steel, and aluminum support members, doors, metal siding, and other structural components that are exposed to an atmosphere/weather environment.

3.5-1, 095 Aluminum, galvanized steel and stainless steel Support members; welds; bolted connections; support anchorage to building structure exposed to Air -

indoor, uncontrolled None None NA - No AEM or AMP Consistent with NUREG-1801 for support members, bird screens, cabinets, metal siding, conduit, cable trays and supports (including tube track), and other structural components that are located in a plant indoor air environment.

Attachment A PG&E Letter DCL-25-001 Page 6 of 29 DCPP LRA, Amendment 2 LRA Table 3.5.2-14 on pages 3.5-160 and 3.5-171 (as modified by DCL-24-092, Encl. 1, Att. B and JJ) is revised as follows to address RAI 3.5.2:

Table 3.5.2-14: Supports and Commodities - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Item Table 1 Item Notes Conduit and Supports

Shelter, Protection Structural Support Aluminum Plant Indoor Air (Structural) (Ext)

None None III.B2.TP-8 3.5-1, 095 A

Conduit and Supports

Shelter, Protection Structural Support Carbon Steel Atmosphere/We ather (Structural)

(Ext)

Loss of Material Structures Monitoring Program (B.2.3.33)

III.B2.TP-43 3.5-1, 092 A

Conduit and Supports

Shelter, Protection Structural Support Carbon Steel (Galvanized)

Polyvinyl Chloride (PVC)

Atmosphere/

Weather (Structural)

(Ext)

Loss of MaterialReduction in impact strength Structures Monitoring Program (B.2.3.33)External Surfaces Monitoring of Mechanical Components (B.2.3.22)

III.B2.TP-6 None 3.5-1, 093 None AG, 10 Conduit and Supports

Shelter, Protection Structural Support Carbon Steel (Galvanized)

Polyvinyl Chloride (PVC)

Buried (Structural) (Ext)

Loss of MaterialNone Structures Monitoring Program (B.2.3.33)None III.A3.TP-219 None 3.5-1, 079 None CG, 2 Conduit and Supports

Shelter, Protection Structural Support Carbon Steel (Galvanized)

Polyvinyl Chloride (PVC)

Plant Indoor Air (Structural)

(Ext)

None None III.B2.TP-8 None 3.5-1, 095 None AG, 10 Attachment A PG&E Letter DCL-25-001 Page 7 of 29 DCPP LRA, Amendment 2 Table 3.5.2-14: Supports and Commodities - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Item Table 1 Item Notes Conduit and Supports

Shelter, Protection Structural Support Stainless Steel Plant Indoor Air (Structural) (Ext)

None None III.B2.TP-8 3.5-1, 095 A

Conduit and Supports

Shelter, Protection Structural Support Carbon Steel (Galvanized)

Polyvinyl Chloride (PVC)

Encased in Concrete (Ext)

None None VII.J.AP-282 None 3.3.1, 112 None CG, 3 Plant-Specific Notes

2. Not used.For the external PVC buried environment, NUREG-2192, Table IX.F, includes the following with regards to defining wear:

Loss of material due to wear can also occur in polymeric components buried in soil containing deleterious materials that move over time due to seasonal change effects on soil. DCPP is located in a negligible weathering region, as defined in ASTM C33/C33M-23, Figure 1. A negligible weathering region is defined as a climate where concrete is rarely exposed to freezing in the presence of moisture. Due to DCPPs location in a negligible weathering region, there are no significant seasonal changes on the soil, and no movement over time that would induce loss of material due to wear on the buried PVC conduit.

3. Not used.Consistent with guidance in NUREG-2191, PVC encased in concrete has no applicable aging effect requiring management.

10. Consistent with guidance in NUREG-2191, PVC exposed to air - outdoor is susceptible to reduction in impact strength due to photolysis and PVC exposed to air - indoor uncontrolled has no aging effects requiring management. The DCPP External Surfaces Monitoring of Mechanical Components AMP (B.2.3.22) will be used to manage PVC conduit exposed to atmosphere/weather.

Attachment A PG&E Letter DCL-25-001 Page 8 of 29 DCPP LRA, Amendment 2 LRA Table 4.1-2 on page 4.1-6 is revised as follows to address RAI 4.3.2-1:

Table 4.1-2 Time-Limited Aging Analyses Applicable to DCPP Section Title Disposition Method(s)

LRA Section Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break Elimination of Dynamic Effects of Primary Loop Piping Failures 10 CFR 54.21(c)(1)(ii) and 10 CFR 54.21(c)(1)(iii) 4.3.2.12 Attachment A PG&E Letter DCL-25-001 Page 9 of 29 DCPP LRA, Amendment 2 LRA Section 4.3.2.12 on page 4.3-18 is revised as follows to address RAI 4.3.2-1:

4.3.2.12 Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break Elimination of Dynamic Effects of Primary Loop Piping Failures TLAA Description The leak-before-break (LBB) analysis eliminated the need to consider large breaks in the primary loop piping, which allowed removal of evaluations of their jet and pipe whip effects. This allowed removal of large jet barriers and whip restraints.

The DCPP LBB analysis was performed by Westinghouse and is presented in WCAP-13039 (Reference 4.9.16). The original revision of WCAP-13039 was reviewed and accepted by the NRC for use at DCPP with a safety evaluation issued in 1993.

The LBB analysis was performed for DCPP to evaluate postulated flaw growth in the primary loop piping of the RCS. This analysis considered the thermal aging of the cast austenitic stainless steel (CASS) piping for fracture mechanics and plant transients for fatigue crack growth over the operating life of the plant assuming a 60-year plant life. As discussed in Section 4.7.2, DCPP RCS piping includes unmitigated Alloy 82/182 dissimilar metal at the RPV inlet nozzle to safe-end welds and the RPV outlet nozzle to safe-end welds, which are known to be susceptible to PWSCC. The current LBB analysis conservatively evaluates for the potential effects of PWSCC in these Alloy 82/182 dissimilar metal welds.

TLAA Evaluation WCAP-13039: Fracture Mechanics Analysis The fracture mechanics analysis in WCAP-13039 was performed to determine crack stability.

The analysis is influenced by the crack initiation energy integral for CF8M CASS. CASS, used in the DCPP RCS, is subject to time-dependent thermal aging during service.Plant-specific geometry, operating parameters, loading, and material properties were used in the fracture mechanics analysis. The mechanical properties were determined at operating temperatures.

Since portions of the DCPP RCS primary loop piping are made of CASS that is susceptible to thermal aging at the reactor operating temperature, the analysis also considers the associated reductions in fracture toughness.

The governing or critical locations for the LBB analysis are established based on the fracture toughness properties of the metal base at the weld points and also on the basis of pipe geometry, welding process, operating temperature, operating pressure, and the highest faulted stresses at the welds for each loop legs (Reference 4.9.16, Section 5). A margin of 10 is demonstrated between the calculated leak rate and the leak detection capability and a margin of 2 between the leakage flaw size and the critical flaw size (Reference 4.9.16, Section 9).The effects of thermal aging in stainless steels depend logarithmically on time (i.e., after a prolonged exposure to high temperatures, the thermal aging effects achieve a saturation level, after which further exposure to high temperatures do not affect the material properties of stainless steel).

Since the analyses reported in WCAP-13039 relied on fully aged reference material (i.e., with Attachment A PG&E Letter DCL-25-001 Page 10 of 29 DCPP LRA, Amendment 2 the properties at the saturation levels), the analyses do not have a material property time-dependency that would require further evaluation for LR and therefore, the fracture mechanics analyses are not TLAAs in accordance with 10 CFR 54.3(a), Criterion 3 (Reference 4.9.16, Table 7-1).

WCAP-13039: Fatigue Crack Growth Analysis The fatigue crack growth analysis in WCAP-13039 was performed to determine the sensitivity of the RCS to small cracks. The analysis is influenced by the number of design basis transients assumed during the life of the plant. WCAP-13039 concludes that The effects of low and high cycle fatigue on the integrity of the primary piping are negligible (Reference 4.9.16, Section 10.0-ec).

The evaluation of LBB fatigue effects was for a typical Westinghouse plant, which is representative of the DCPP RCS design. Table 81 of WCAP-13039 summarizes the number of transients assumed, based on operation of the plant for 40 years. These transients are a subset of those listed in UFSAR Table 5.24, which contains similar information for a design life of 50 years. Therefore, the numbers in UFSAR Table 5.2-4 are typically 25 percent higher to account for the additional 10 years of operation.

The LBB analysis determined that fatigue crack growth effects will be negligible. The basis for evaluation of fatigue crack growth effects in the LBB analysis will remain unchanged so long as the design basis number of transients remains unchanged. Section 4.3.1 demonstrates that the specified set of design basis transient events used by WCAP-13039 should not be exceeded during the PEO.

TLAA Disposition Revision, 10 CFR 54.21(c)(1)(ii) - The LBB fracture mechanics analysis has been projected to the end of the PEO.

Aging Management, 10 CFR 54.21(c)(1)(iii) - The design basis number of transients used in the LBB analysis will be managed for the PEO by the DCPP Fatigue Monitoring AMP (B.2.2.1).

Action limits will permit completion of corrective actions before the design basis number of transients is exceeded. These effects will be managed for the PEO in accordance with 10 CFR 54.21(c)(1)(iii).

Attachment A PG&E Letter DCL-25-001 Page 11 of 29 DCPP LRA, Amendment 2 LRA Section 4.9 on page 4.9-2 (as modified by DCL-24-092, Encl. 1, Att. A, NN, and PP) is revised as follows to address RAI 4.3.2-1:

4.9 REFERENCES

4.9.16 Westinghouse Report WCAP-13039. Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants. Revision 21. September 2023April 2016.

Westinghouse Proprietary Class 2.

Attachment A PG&E Letter DCL-25-001 Page 12 of 29 DCPP LRA, Amendment 2 LRA Section A.2.2.22 on page A.2-12 (as modified by DCL-24-092, Encl. 1, Att. AAA) is revised as follows to address RAI 3.5.2:

A.2.2.22 External Surfaces Monitoring of Mechanical Components The DCPP External Surfaces Monitoring of Mechanical Components AMP is a new AMP. This AMP is a condition monitoring program that directs inspection of external surfaces of components that are performed during system inspections and walkdowns. The DCPP External Surfaces Monitoring of Mechanical Components AMP consists of periodic visual inspections of metallic and elastomeric components such as piping, piping components, ducting, heat exchangers (unit coolers) and other components within the scope of LR. The DCPP External Surfaces Monitoring of Mechanical Components AMP manages aging effects of metallic and elastomeric components through visual inspection of external surfaces for evidence of loss of material, cracking, reduction in impact strength, and change in material properties. Visual inspections are augmented by physical manipulation as necessary to detect hardening and loss of strength of elastomers or reduction in impact strength. The DCPP External Surfaces Monitoring of Mechanical Components AMP includes outdoor insulated components and indoor insulated components exposed to condensation, to monitor for degraded conditions under insulation.

Attachment A PG&E Letter DCL-25-001 Page 13 of 29 DCPP LRA, Amendment 2 LRA Section A.2.2.26 on page A.2-14 (as modified by DCL-24-092, Encl. 1, Att. DDD) is revised as follows to address RAI B.2.3.26-1:

A.2.2.26 Buried and Underground Piping and Tanks The DCPP Buried and Underground Piping and Tanks AMP is an existing program that manages cracking, loss of material, hardening and loss of strength (for elastomers only),

and change in material properties (for cementitious piping only) of buried and underground piping, piping components and tanks in the auxiliary saltwater system, diesel generator fuel transfer system, fire protection system, and the makeup water system. The AMP manages aging through preventive measures (i.e., coatings, backfill quality, and cathodic protection),

inspection, and, as appropriate, performance monitoring activities. The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. For steel components, where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, loss of material rates are measured. 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 period of extended operation, an increase in sample size is conducted. Visual inspections monitor the condition of protective coatings and wrappings and directly assess the surface condition of components with no protective coatings or wraps.

Evidence of wall loss beyond minor scale observed during visual inspections of buried piping will require a supplemental surface and/or volumetric non-destructive testing. The AMP includes opportunistic inspection of buried piping and tanks as they are excavated or on a planned basis if opportunistic inspections have not occurred.

Attachment A PG&E Letter DCL-25-001 Page 14 of 29 DCPP LRA, Amendment 2 LRA Section A.2.2.33 on page A.2-16 (as modified by DCL-24-092, Encl. 1, Att. HHH) is revised as follows to address RAI B.2.3.33-2:

A.2.2.33 Structures Monitoring The DCPP Structures Monitoring AMP is an existing AMP that manages the condition of structures and structural component supports that are within the scope of LR that are not covered by other structural LR programs. The DCPP Structures Monitoring AMP implements the requirements of 10-CFR-50.65, the Maintenance Rule, and is consistent with the guidance of NUMARC 93-01, "Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and RG 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," as described in UFSAR Section 13.5.2.19. The DCPP Structures Monitoring AMP will implement EPRI 3002007348 recommendations to ensure the program is effective in managing the effects of Reactor Cavity, Refueling Canal, SFP, and transfer canal leakage. This AMP will also evaluate EPRI 3002007348 and other NRC and industry guidance to determine the appropriate inspection and maintenance activities for the reactor cavity and refueling canal. The DCPP Structures Monitoring AMP consists of periodic inspections at a frequency not to exceed 5 years and monitoring of the condition of structures and structural component supports to ensure that aging degradation leading to a potential loss of intended functions will be detected and that the extent of degradation can be determined. The DCPP Structures Monitoring AMP provides inspection guidelines for concrete elements, structural steel, structural bolting, structural features (e.g., caulking, sealants, roofs, etc.), and miscellaneous components such as doors. Inspection methods, inspector qualifications, and acceptance criteria are in accordance with ACI 349.3R-02 and ASCE 11-90.

Attachment A PG&E Letter DCL-25-001 Page 15 of 29 DCPP LRA, Amendment 2 LRA Section A.2.2.42 on page A.2-22 is revised as follows to address RAI 3.6:

A.2.2.42 Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators The DCPP Transmission Conductor and Connections, Switchyard Bus and Connections, and High-Voltage Insulators AMP is an existing AMP that manages the aging effects of the 230 kV and 500 kV components required for SBO recovery which include transmission conductors and connections, insulators, and switchyard bus and connections to ensure that these components are capable of performing their intended functions throughout the PEO.

Transmission conductors, insulators, connections and supports, and switchyard bus and connections within the scope of this AMP are managed for reduced insulation resistance, loss of material, increased resistance of connection, and loss of conductor strength at a frequency based on plant-specific OE via aerial or ground-based visual and/or infrared thermography inspections of the components. These inspection methods are appropriate based on industry experience and DCPP OE. The inspections monitor for, but are not limited to, insulator, conductor, connector and electrical support degradation including corrosion, mechanical wear, loss of preload, and contamination. Conductors are also monitored for indications of degradation including strand breakage, excessive corrosion and swelling. Infrared thermography inspection of transmission and bus connections are monitored for indications of loose or degraded connections, inspection of transmission conductors for corrosion and fatigue, and inspection of insulator supports for corrosion and wear will be conducted at a frequency based on plant-specific OE. In addition, inspection of the high-voltage insulators for contamination occurs at a frequency based on plant-specific OE. The results of the inspections will be documented providing the ability to predict the extent of future degradation. The first inspection for license renewal will be completed prior to November 2, 2024 and August 26, 2025, for Units 1 and 2, respectively.

Attachment A PG&E Letter DCL-25-001 Page 16 of 29 DCPP LRA, Amendment 2 LRA Section A.3.2.1.9 on page A.3-6 (as modified by DCL-24-092, Encl. 1, Att. S) is revised as follows to address RAI 4.3.2-1:

A.3.2.1.9 Fatigue Crack Growth Assessments and Fracture Mechanics Stability Analyses for Leak-Before-Break Elimination of Dynamic Effects of Primary Loop Piping Failures The leak-before-break (LBB) analysis was performed for DCPP to evaluate postulated flaw growth in the primary loop piping of the RCS. This analysis considered the thermal aging of the cast austenitic stainless steel (CASS) piping for fracture mechanics and plant transients for fatigue crack growth over the operating life of the plant.

The LBB analysis was updated for LR to consider the effects of additional thermal aging on the fracture toughness of the CASS materials through the PEO. The fracture toughness properties used were based on the fully-aged condition, which is applicable for the PEO. Therefore, the fracture mechanics analysis has been projected to the end of the PEO in accordance with 10 CFR 54.21(c)(1)(ii).

The LBB analysis determined that fatigue crack growth effects will be negligible. The basis for evaluation of fatigue crack growth effects in the LBB analysis will remain unchanged so long as the design basis number of transients remains unchanged. The DCPP Fatigue Monitoring AMP (A.2.1.1) will monitor the transients used in the LBB analysis. Action limits will permit completion of corrective actions before the number of events used in the LBB analysis is exceeded. Therefore, the TLAA will be managed for the PEO, in accordance with 10 CFR 54.21(c)(1)(iii).

Attachment A PG&E Letter DCL-25-001 Page 17 of 29 DCPP LRA, Amendment 2 LRA Table A-3,item 35, on pages A.2-28 and A.2-29 (as modified by DCL-24-092, Encl. 1, Att. HHH) is revised as follows to address RAI B.2.3.33-1, RAI B.2.3.33-2, and RCI B.2.3.33-1:

No.

Aging Management Program or Activity (Section)

NUREG-1801 Section Commitment Implementation Schedule 35 Structures Monitoring (A.2.2.33)

XI.S6 Continue the existing DCPP Structures Monitoring AMP, including enhancements to:

(f) Monitor/inspect structural sealants (including weatherproofing boots) for cracking, loss of material, and hardening.parameters specified in ACI 349.3R and/or ANSI/ASCE 11 for elastomers.

(o) Periodic walkdowns of accessible interior walls and ceilings that are adjacent to the Reactor Cavity, Refueling Canal, SFPs, and TCs will be periodically performed to identify in-leakage into the structure in-accordance with EPRI 3002007348. Any newly identified leaks or changes in existing leak sites will be entered into CAP and evaluated to assure that Reactor Cavity, Refueling Canal, SFP, and TC leakage is being effectively managed.

(p) Reactor Cavity, Refueling Canal, SFP, and TC leak chase sampling parameters and acceptance criteria will be enhanced consistent with Table A-1 of EPRI TR-3002007348.

(q) Procedure(s) will be developed or revised to manage the Reactor Cavity, Refueling Canal, SFP, Enhancements (a),

(d), (e), (h), (i), (j), and (n) are implemented by:

Unit 1: 11/02/2024 Unit 2: 08/26/2025 Enhancements (b),

(c), (f), (g), (k), (l), and (m) are implemented by 01/30/2025.

Enhancement (o)walkdowns completed and enhancements (o),

(p), and (q) implemented prior to completion of first refueling outage after 11/02/24 and 8/26/25 for Units 1 and 2, respectively.

For eEnhancement Attachment A PG&E Letter DCL-25-001 Page 18 of 29 DCPP LRA, Amendment 2 No.

Aging Management Program or Activity (Section)

NUREG-1801 Section Commitment Implementation Schedule and TC surveillance and maintenance activities consistent with Elements 1 through 7 of EPRI 3002007348.

(r) During the first Unit 1 refueling outage in the PEO, PG&E will perform a Reactor Cavity and Refueling Canal leak chase internal inspection feasibility determination. Prior to completion of the second Unit 1 refueling outage in the PEO, PG&E will perform an internal inspection of all Unit 1 Reactor Cavity and Refueling Canal leak chases. During the first Unit 2 refueling outage in the PEO, PG&E will perform an internal inspection of all Unit 2 Reactor Cavity and Refueling Canal leak chases.

Subsequent periodic telltale drain internal inspections will be performed in the PEO based on monitoring and trending tell-tale drain data for indication of potential blockage.Evaluate NUREG/CR-7111, EPRI 3002007348 enhancement recommendations, industry OE and DCPP OE pertaining to reactor cavity and refueling canal liner leaks to determine appropriate inspection and maintenance activities for the reactor cavity and refueling canal. As part of this evaluation, during the first Unit 1 refueling outage in the PEO, PG&E will perform the following activities:

Perform a reactor cavity and refueling canal leak chase internal inspection feasibility (r), the evaluation and determination of the appropriate inspection and maintenance activities for the reactor cavity and refueling canal will be completed implemented and submitted to NRC six months followingprior to completion of the first Unit 2 refueling outage in the Unit 2 PEO. The evaluation-recommended enhancements will be implemented during the second Unit 1 refueling outage in the Unit 1 PEO.

Enhancement (s) will be completed six months following completion of the first Unit 2 refueling outage Attachment A PG&E Letter DCL-25-001 Page 19 of 29 DCPP LRA, Amendment 2 No.

Aging Management Program or Activity (Section)

NUREG-1801 Section Commitment Implementation Schedule determination.

Conduct monitoring of the reactor cavity and refueling canal leak chase system discharge. If any leakage is observed and as volume permits samples will be collected to determine flow rate and chemistry in-accordance with EPRI 3002007348 guidance.

Conduct a walkdown of accessible concrete adjacent to the reactor cavity and refueling canal liner to identify if there is any evidence of reactor cavity and refueling canal liner leak sites in-accordance with EPRI 3002007348 guidance.

Also, as part of the evaluation, during the first Unit 2 refueling outage in the PEO, PG&E will perform the following activities:

If feasible, perform an internal inspection of all Unit 2 reactor cavity and refueling canal leak chases.

Conduct monitoring of the Unit 2 reactor cavity and refueling canal leak chase system discharge. If any leakage is observed and as volume permits samples will be collected to determine flow rate and chemistry in-accordance with EPRI 3002007348 guidance.

Conduct a walkdown of accessible Unit 2 concrete adjacent to the reactor cavity and refueling canal liner to identify if there is any evidence of reactor cavity and refueling canal liner leak sites in-accordance with EPRI 3002007348 guidance.

(s) Perform a structural evaluation of any identified in the Unit 2 PEO.

Attachment A PG&E Letter DCL-25-001 Page 20 of 29 DCPP LRA, Amendment 2 No.

Aging Management Program or Activity (Section)

NUREG-1801 Section Commitment Implementation Schedule degradation of concrete and structural steel due to leakage of borated water from the Rx Cavity and RC and a conservative projection of the potential degradation of those surfaces for the PEO.

(t) Monitor fiberglass roofing panels for blistering, cracking, and loss of material.

Attachment A PG&E Letter DCL-25-001 Page 21 of 29 DCPP LRA, Amendment 2 LRA Table A-3, item 38, on pages A.2-28 and A.2-29 is revised as follows to address RAI B.2.3.36:

No.

Aging Management Program or Activity (Section)

NUREG-1801 Section Commitment Implementation Schedule 38 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (A.2.2.36)

XI.E1 Implement the new DCPP Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP.

(a) Implement a solution to prevent or divert oil from the cables affected by oil residue.

AMP is implemented by Unit 1: 11/02/2024 Unit 2: 08/26/2025 A solution to prevent or divert oil from the cables affected by oil residue will be implemented prior to 12/31/2025.

Attachment A PG&E Letter DCL-25-001 Page 22 of 29 DCPP LRA, Amendment 2 LRA Section B.2.3.22 on page B.2-108 (as modified by DCL-24-092, Encl. 1, Att. AAA) is revised as follows to address RAI 3.5.2:

B.2.3.22 External Surfaces Monitoring of Mechanical Components Program Description The DCPP External Surfaces Monitoring of Mechanical Components AMP is a new AMP that manages aging effects of components fabricated from metallic and elastomeric materials through periodic visual inspection of external surfaces for evidence of loss of material, cracking, reduction in impact strength, and change in material properties (i.e., hardening and loss of strength). When appropriate for the component and material, physical manipulation, such as pressing, flexing and bending, is used to augment visual inspections to confirm the absence of elastomer hardening and loss of strength or reduction in impact strength. The DCPP External Surfaces Monitoring of Mechanical Components AMP is also credited for situations where the material and environment combinations are the same for the internal and external surfaces such that the external surfaces are representative of the internal surfaces. When credited, the program will describe the component internal environment and the similar credited external environment, as well as provide justification for crediting the condition of the internal environment. Inspections are performed at least once every refueling cycle by personnel qualified through a plant-specific program. Deficiencies are documented and evaluated under the CAP. Surfaces that are not readily visible during plant operations and refueling outages are inspected when they are made accessible and at such intervals that would ensure the components intended functions are maintained.

Attachment A PG&E Letter DCL-25-001 Page 23 of 29 DCPP LRA, Amendment 2 LRA Section B.2.3.24 on pages B.2-115 and B.2.3-117 (as modified by DCL-24-092, Encl. 1, Att. CCC) is revised as follows to address RAI B.2.3.24:

B.2.3.24 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Description The DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP is a new AMP that will use the work control process to conduct and document inspections.

The AMP will consist of visual inspections to detect aging effects that could result in a loss of component intended function. Visual inspections of internal surfaces of plant components will be performed opportunistically by qualified inspectors during the conduct of periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. Additionally, visual inspections may be augmented by physical manipulation to detect hardening and loss of strength of both internal and external surfaces of elastomers or by sufficient pressurization of the elastomer material to expand the surface in such a way that cracks or crazing is evident.

The AMP also includes VT-1 or surface examination of the internal surfaces of stainless steel, aluminum, and copper alloy (>15% Zn or >8% Al) to detect cracking. Visual inspections for leakage or surface cracks are an acceptable alternative to conducting surface examination to detect cracking if it has been determined that cracks will be detected prior to challenging the structural integrity or intended function of the component.

Exceptions to NUREG-1801 Exception 2 to Element 3, Parameters Monitored or Inspected, and Element 4, Detection of Aging Effects The DCPP Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components AMP will perform visual inspections, VT-1, or surface examination of stainless steel, aluminum, and copper alloy (>15% Zn or >8% Al) components to detect cracking. Also, stainless steel and aluminum opportunistic inspections need not be conducted once the minimum sample inspections are completed.

Justification for Exception Justification 2 NUREG-2191, XI.M38 recommends that surface examinations are conducted if this program is being used to manage cracking in stainless steel and aluminum components. Visual inspections for leakage or surface cracks are an acceptable alternative to conducting surface examination to detect cracking if it has been determined that cracks will be detected prior to challenging the structural integrity or intended function of the component. In addition, the NRC previously found these methods acceptable for managing cracking of copper alloy (>15% Zn or

>8% Al) components (Reference ML22054A108). NUREG-2191, XI.M38 further recommends stainless steel and aluminum opportunistic inspections need not be conducted once the minimum sample inspections are completed because the material properties are more durable than others included in this AMP.

Attachment A PG&E Letter DCL-25-001 Page 24 of 29 DCPP LRA, Amendment 2 LRA Section B.2.3.26 on page B.2-123 (as modified by DCL-24-092, Encl. 1, Att. DDD) is revised as follows to address RAI B.2.3.26-1:

B.2.3.26 Buried and Underground Piping and Tanks Program Description The DCPP Buried and Underground Piping and Tanks AMP is an existing program that manages cracking, loss of material, hardening and loss of strength (for elastomers only),

and change in surface conditions of buried and underground components in the auxiliary saltwater (ASW) system, diesel generator fuel transfer system, fire protection system, and the makeup water system. The AMP manages aging through preventive measures (i.e., coatings, backfill quality, and cathodic protection), inspection, and, as appropriate, performance monitoring activities. Visual inspections monitor the condition of protective coatings and wrappings and directly assess the surface condition of components with no protective coatings or wraps. Individuals responsible for conducting coatings inspections or assessing the type and extent of coating degradation will be qualified in accordance with the recommendations provided in LR-ISG-2015-01, Appendix B, Section 6.a. Evidence of wall loss beyond minor scale observed during visual inspections of buried piping will require a supplemental surface and/or volumetric non-destructive testing. The AMP includes opportunistic inspection of buried piping and tanks as they are excavated or on a planned basis if opportunistic inspections have not occurred.

Attachment A PG&E Letter DCL-25-001 Page 25 of 29 DCPP LRA, Amendment 2 LRA Section B.2.3.33 on pages B.2-151, B.2-152, and B.2-155 (as modified by DCL 092, Encl. 1, Att. HHH) is revised as follows to address RAI B.2.3.33-1, RAI B.2.3.33-2, and RCI B.2.3.33-1:

B.2.3.33 Structures Monitoring Program Description The DCPP Structures Monitoring AMP is an existing AMP that manages the condition of structures and structural supports that are in the scope of LR that are not covered by other structural LR programs. The DCPP Structures Monitoring AMP implements the requirements of 10 CFR 50.65, the Maintenance Rule, which is consistent with the guidance of NUMARC 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, and Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, as described in UFSAR Section 13.5.2.19. The DCPP Structures Monitoring AMP will implement EPRI 3002007348 recommendations to ensure the program is effective in managing the effects of aging due to interaction between the Reactor Cavity, Refueling Canal, SFP, and transfer canal (TC) leakage and reinforced concrete adjacent to the Reactor Cavity, Refueling Canal, SFP, and TC (that is, structural concrete and its embedded reinforcement). To improve the sampling and analysis of the SFP, and TC leak chase tell-tale drain chemistry, the sampling will be based on DCPP operating experience and initially changes to a monthly frequency. The Reactor Cavity, Refueling Canal sampling and analysis frequency will be based on DCPP operating experience and initially implemented on a once per refueling outage frequency while the systems are filled with water. This frequency These frequencies may be adjusted based on the on-going review of the Reactor Cavity, Refueling Canal, SFP, and TC leak chase results. The DCPP Structures Monitoring AMP provides inspection guidelines and walkdown checklists for concrete elements, structural steel (e.g., including associated with masonry walls), structural bolting, structural features (e.g., caulking, sealants, siding, roofs, etc.), structural supports, and miscellaneous components such as doors. The DCPP Structures Monitoring AMP also inspects supports for equipment, piping, conduit, cable trays, HVAC, and instrument components. The scope of the DCPP Structures Monitoring AMP does not include the inspection of the supports specifically inspected per the requirements of the DCPP ASME Section XI, Subsection IWE AMP (B.2.3.28) and the DCPP ASME Section XI, Subsection IWF AMP (B.2.3.30). Though coatings may have been applied to the external surfaces of structural members, no credit is taken for these coatings in the determination of aging effects for the underlying materials. The DCPP Structures Monitoring AMP evaluates the condition of the coatings as an indication of the condition of the underlying materials.

Enhancements Element Enhancement 1 - Scope of Program Perform a structural evaluation of any identified degradation of concrete and structural steel due to leakage of borated water from the Rx Cavity and RC and a conservative projection of the potential degradation of those surfaces for the PEO.

Attachment A PG&E Letter DCL-25-001 Page 26 of 29 DCPP LRA, Amendment 2 1 - Scope of Program 2 - Preventive Actions 3 - Parameters Monitored/Inspected 4 - Detection of Aging Effects 5 - Monitoring and Trending 6 - Acceptance Criteria 7 - Corrective Actions Procedure(s) will be developed or revised to manage the Reactor Cavity, Refueling Canal, SFP, and TC surveillance and maintenance activities consistent with Elements 1 through 7 of EPRI 3002007348.

1 - Scope of Program 2 - Preventive Actions 3 - Parameters Monitored/Inspected 4 - Detection of Aging Effects 5 - Monitoring and Trending 6 - Acceptance Criteria 7 - Corrective Actions During the first Unit 1 refueling outage in the PEO, PG&E will perform a Reactor Cavity and Refueling Canal leak chase internal inspection feasibility determination. During the second Unit 1 refueling outage in the PEO, PG&E will perform an internal inspection of all Unit 1 Reactor Cavity and Refueling Canal leak chases. During the first Unit 2 refueling outage in the PEO, PG&E will perform an internal inspection of all Unit 2 Reactor Cavity and Refueling Canal leak chases. Subsequent periodic telltale drain internal inspections will be performed in the PEO based on monitoring and trending tell-tale drain data for indication of potential blockage.Evaluate NUREG/CR-7111, EPRI 3002007348 enhancement recommendations, industry OE, and DCPP OE pertaining to reactor cavity and refueling canal liner leaks to determine appropriate inspection and maintenance activities for the reactor cavity and refueling canal. As part of this evaluation, during the first Unit 1 refueling outage in the PEO, PG&E will perform the following activities:

Perform a reactor cavity and refueling canal leak chase internal inspection feasibility determination.

Conduct monitoring of the reactor cavity and refueling canal leak chase system discharge. If any leakage is observed and as volume permits samples will be collected to determine flow rate and chemistry in-accordance with EPRI 3002007348 guidance.

Conduct a walkdown of accessible concrete adjacent to the Reactor cavity and refueling canal liner to identify if there is any evidence of reactor cavity and refueling canal liner leak sites in-accordance with EPRI 3002007348 guidance.

Also, as part of the evaluation, during the first Unit 2 refueling outage in the PEO, PG&E will perform the following activities:

If feasible, perform an internal inspection of all Unit 2 reactor cavity and refueling canal leak chases.

Conduct monitoring of the Unit 2 reactor cavity and refueling canal leak chase system discharge. If any leakage is observed Attachment A PG&E Letter DCL-25-001 Page 27 of 29 DCPP LRA, Amendment 2 and as volume permits samples will be collected to determine flow rate and chemistry in-accordance with EPRI 3002007348 guidance.

Conduct a walkdown of accessible Unit 2 concrete adjacent to the reactor cavity and refueling canal liner to identify if there is any evidence of reactor cavity and refueling canal liner leak sites in-accordance with EPRI 3002007348 guidance.

3 - Parameters Monitored/Inspected 4 - Detection of Aging Effects 7 - Corrective Actions Periodic walkdowns of accessible interior walls and ceilings that are adjacent to the Reactor Cavity, Refueling Canal, SFP, and TC will be periodically performed to identify in-leakage into the structure in-accordance with EPRI 3002007348. Any newly identified leaks or changes in existing leak sites will be entered into CAP and evaluated to assure that Reactor Cavity, Refueling Canal, SFP, and TC leakage is being effectively managed.

3 - Parameters Monitored/Inspected 6 - Acceptance Criteria Reactor Cavity, Refueling Canal, SFP, and TC leak chase sampling parameters and acceptance criteria will be enhanced consistent with Table A-1 of EPRI 3002007348.

3 - Parameters Monitored/Inspected Monitor/inspect structural sealants (including weatherproofing boots) for cracking, loss of material, and hardening.parameters specified in ACI 349.3R and/or ANSI/ASCE 11 for elastomers.

3 - Parameters Monitored/Inspected Monitor fiberglass roofing panels for blistering, cracking, and loss of material.

Operating Experience Plant Specific Operating Experience In addition to the above examples, the following Units 1 and 2 SFP leakage information is updated based on a review of industry and plant-specific OE. The Units 1 and 2 SFP has had persistent minor leakage from the liner to the leak chase that appears to slightly increase during refueling outages. Prior investigations performed by engineering have concluded that long-term liner leakage is acceptable and will have negligible adverse effect on the concrete and reinforcing steel. Deterioration of concrete from boric acid would result in very slight surface scaling and no cracking of the concrete would occur. Boric acid can cause exposed reinforcing steel to corrode. However, the lack of oxygen in the concrete would prohibit rebar corrosion and the potential for concrete to crack behind the SFP liner is minimal. In addition, chemistry monitors the iron concentration of captured leakage to evaluate for rebar corrosion. Leak chase surveillances are performed and have shown no appreciable increase in leakage over the past 20 years. Video inspections of the Units 1 and 2 leak chases were conducted in January 2008 and a follow-up video inspection of the Unit 2 leak chases was performed in March 2010. In October 2024 (prior to entering the Unit 1 PEO), additional video inspections of all Units 1 and 2 SFP and TC leak chase tell-tale drains were conducted. These inspections determined the leak Attachment A PG&E Letter DCL-25-001 Page 28 of 29 DCPP LRA, Amendment 2 chases were not blocked. The DCPP Structures Monitoring AMP is being enhanced to conduct rodding, snaking, or video inspections of all Units 1 and 2 SFP and TC leak chase tell-tale drains to identify potential blockages prior to the PEO. Subsequent periodic tell-tale drain internal inspections will be performed based on monitoring and trending tell-tale drain data for indication of potential blockage. Monthly sampling for chlorides and sulfates was initiated in February 2024 and results through September 2024 indicate stable values significantly below the associated acceptance criteria (<500 ppm for chlorides and <1,500 ppm for sulfates).

Attachment A PG&E Letter DCL-25-001 Page 29 of 29 DCPP LRA, Amendment 2 LRA Section B.2.3.36 on page B.2-166 (as modified by DCL-24-092, Encl. 1, Att. JJJ) is revised as follows to address RAI B.2.3.36:

B.2.3.36 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description Program Description All accessible non-EQ insulated cables and connections within the scope of LR and installed in ALEs will be visually inspected at least once every 10 years for cable jacket and connection insulation surface anomalies such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination, that could indicate conductor insulation aging degradation from temperature, radiation, or moisture. If an unacceptable condition or situation is identified for a cable or connection, corrective actions may include, but are not limited to, testing, shielding, or otherwise changing the environment or relocation or replacement of the affected cables or connections. The corrective action program will also evaluate if the same condition or situation is applicable to inaccessible cables or connections. Extent of condition inspections will be initiated as appropriate.

For cables subject to the identified oil mist residue ALE (located in the auxiliary building, elev. 115), annual visual/tactile inspections will be conducted on a six-month offset with annual cable cleaning until a solution to prevent or divert oil from the affected cables is implemented prior to December 31, 2025. These activities will provide reasonable assurance there is no cable age-related degradation.

PG&E Letter DCL-25-001 Non-Proprietary WCAP-13039-NP, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants, Revision 2

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 WCAP-13039-NP September 2023 Revision 2 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants

@Westinghouse

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 Westinghouse Electric Company LLC 1000 Westinghouse Drive Cranberry Township, PA 16066, USA

© 2023 Westinghouse Electric Company LLC All Rights Reserved WCAP-13039-NP Revision 2 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants September 2023 Author:

Momo Wiratmo*

Operating Plants Piping & Supports Piping Engineering Verifier:

Nadia B. Petkova*

Operating Plants Piping & Supports Piping Engineering Reviewer:

Dulal C. Bhowmick*

Reactor Vessel and Containment Vessel Design and Analysis Approved: Lynn A. Patterson*, Manager Reactor Vessel and Containment Vessel Design and Analysis

• Electronically approved records are authenticated in the electronic document management system.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 iv WCAP-13039-NP September 2023 Revision 2 RECORD OF REVISIONS Revision Date Revision Description 2

September 2023 Revised to demonstrate compliance with LBB technology for the Diablo Canyon Units 1 and 2 reactor coolant systems piping due to the Nuclear Steam Supply System (NSSS) Structural and Licensing Review (NSLR) project.

Revised to update the LBB evaluations for the Diablo Canyon Units 1 and 2 RCL piping due to Initial License Renewal (ILR) project, and to include the latest considerations of Time-Limited Aging Analyses (TLAA) effects for the plant operation extension into 60-years.

Revised to update the normal and faulted loads by the inclusion of torsional moment loads for Deadweight, Normal Thermal, Seismic Safe Shutdown Earthquake (SSE), and Pressure loadings which were not included in the previous revisions.

Revised to update the tensile properties and chemistry composition for some of the material heats to be consistent with the CMTR data and recalculated the tensile typical values for TP316 and CF8M material at operating temperatures (544°F and 618°F) with the updated CMTR values and summarized the recalculation results in Table 4-6.

Calculated and included in Table 4-6, the Alloy 82/182 material tensile properties.

Removed the SA351-CF8M chemistry composition data in Appendix B from Revision 1 and relocated the chemistry composition data to Table 4-7 and Table 4-8.

The LBB evaluation also accounts for the past modifications to the RCL piping system, such as those associated with the following programs:

Replacement Steam Generator (RSG), Replacement Reactor Vessel Head and Head Assembly Upgrade Package (RRVH/HAUP) and Increase Operating Ranges Program (Tavg Window Program).

This is the Non-Proprietary Class 3 version of WCAP-13039-P, Revision 2 and is issued for the Initial License Renewal (ILR) program.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 v

WCAP-13039-NP September 2023 Revision 2 TABLE OF CONTENTS 1.0 Introduction....................................................................................................................................... 1-1 1.1 Purpose................................................................................................................................. 1-1 1.2 Scope and Objective............................................................................................................. 1-2 1.3 Background Information...................................................................................................... 1-2 1.4 References............................................................................................................................ 1-3 2.0 Operation and Stability of the Reactor Coolant System.................................................................... 2-1 2.1 Stress Corrosion Cracking.................................................................................................... 2-1 2.2 Water Hammer...................................................................................................................... 2-2 2.3 Low Cycle and High Cycle Fatigue..................................................................................... 2-3 2.4 Wall Thinning, Creep, and Cleavage.................................................................................... 2-3 2.5 References............................................................................................................................ 2-3 3.0 Pipe Geometry and Loading.............................................................................................................. 3-1 3.1 Introduction to Methodology................................................................................................ 3-1 3.2 Calculation of Loads and Stresses........................................................................................ 3-1 3.3 Loads for Leak Rate Evaluation........................................................................................... 3-2 3.4 Load Combination for Crack Stability Analyses.................................................................. 3-3 3.5 References............................................................................................................................ 3-3 4.0 Material Characterization.................................................................................................................. 4-1 4.1 Primary Loop Pipe and Fittings Materials............................................................................ 4-1 4.2 Tensile Properties................................................................................................................. 4-1 4.3 Fracture Toughness Properties.............................................................................................. 4-2 4.4 References............................................................................................................................ 4-7 5.0 Critical Location and Evaluation Criteria.......................................................................................... 5-1 5.1 Critical Locations................................................................................................................. 5-1 5.2 Fracture Criteria.................................................................................................................... 5-2 6.0 Leak Rate Predictions........................................................................................................................ 6-1 6.1 Introduction.......................................................................................................................... 6-1 6.2 General Considerations........................................................................................................ 6-1 6.3 Calculation Method.............................................................................................................. 6-1 6.4 Leak Rate Calculations......................................................................................................... 6-2 6.5 References............................................................................................................................ 6-2 7.0 Fracture Mechanics Evaluation......................................................................................................... 7-1 7.1 Local Failure Mechanism..................................................................................................... 7-1 7.2 Global Failure Mechanism................................................................................................... 7-1 7.3 Results of Crack Stability Evaluation................................................................................... 7-2 7.4 RPV Nozzle Alloy 82/182 Welds......................................................................................... 7-3 7.5 References............................................................................................................................ 7-5 8.0 Fatigue Crack Growth Analysis......................................................................................................... 8-1 8.1 References............................................................................................................................ 8-3 9.0 Assessment of Margins...................................................................................................................... 9-1 10.0 Conclusions..................................................................................................................................... 10-1 APPENDIX A: Limit Moment...................................................................................................................... A-1

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 vi WCAP-13039-NP September 2023 Revision 2 LIST OF TABLES Table 3-1: Dimensions, Normal Loads and Stresses for Diablo Canyon Units 1 and 2 from Most Limiting Temperature Case......................................................................................... 3-4 Table 3-2: Dimensions, Enveloped Faulted Loads and Stresses for Diablo Canyon Units 1 and 2.............. 3-5 Table 3-3: Faulted Loads and Stresses at Location 11 for Each Loop........................................................... 3-6 Table 4-1: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Piping........................................................................... 4-8 Table 4-1 (cont'd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Fittings (i.e. Elbows)................................................. 4-10 Table 4-2: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Piping......................................................................... 4-12 Table 4-2 (cont'd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Fittings (i.e. Elbows)................................................. 4-14 Table 4-3: Typical Tensile Properties of SA376 TP316, SA351 CF8A and Welds of Such Material for Primary Loop......................................................................................................... 4-16 Table 4-4: Mechanical Properties of SA351 CF8M Material at Room Temperature (from A Typical PWR Plant)...................................................................................................... 4-17 Table 4-5: Mechanical Properties of SA351 CF8M Material at 650°F Temperature (from A Typical PWR Plant)...................................................................................................... 4-19 Table 4-6: Mechanical Properties for Diablo Canyon Units 1 and 2 Materials at 544°F and 618°F.......... 4-21 Table 4-7: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 1................................................................................................................. 4-22 Table 4-8: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 2................................................................................................................. 4-26 Table 4-9: RCL SA351 CF8M Heats with Lowest Fracture Toughness Properties..................................... 4-30 Table 5-1: Diablo Canyon Units 1 and 2 RCL Critical Locations for LBB................................................... 5-3 Table 6-1: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for SA376 TP316 Piping Material................................................................................................ 6-3 Table 6-2: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for SA351 CF8M Elbow Material.............................................................................................. 6-3 Table 6-3: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for Alloy 82/182 Materials.......................................................................................................... 6-4 Table 7-1: Elastic-Plastic J-Integral Stability Results at the SA351 CF8M Elbow Locations...................... 7-6 Table 7-2: Critical Flaw Sizes and Leakage Flaw Sizes for SA376 TP316 Piping Material......................... 7-6 Table 7-3: Critical Flaw Sizes and Leakage Flaw Sizes for SA351 CF8M Elbow Material....................... 7-7 Table 7-4: Critical Flaw Sizes and Leakage Flaw Sizes for Alloy 82/182 Materials.................................. 7-7 Table 8-1: Summary of Reactor Vessel Transients........................................................................................ 8-4 Table 8-2: Summary of NSSS Design Transients for 60-Year Plant Life...................................................... 8-5 Table 8-3: Typical Fatigue Crack Growth at [ ]a,c,e................................................. 8-6 Table 9-1: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for SA376 TP316 Piping Material.......... 9-2 Table 9-2: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for SA351 CF8M Elbow Material.......... 9-2 Table 9-3: J-Integral Stability Results for SA351 CF8M Elbow Material.................................................... 9-3 Table 9-4: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for Alloy 82/182 Weld Material.................................................................................................... 9-3

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 vii WCAP-13039-NP September 2023 Revision 2 LIST OF FIGURES Figure 3-1: Hot Leg Pipe................................................................................................................................ 3-7 Figure 3-2: Schematic Diagram of Diablo Canyon Units 1 and 2 Primary Loop Weld Locations................ 3-8 Figure 4-1: J vs. a for SA351-CF8M Cast Stainless Steel at 600°F.......................................................... 4-31 Figure 5-1: Diablo Canyon Units 1 and 2 Primary Loop Critical Weld Locations....................................... 5-4 Figure 6-1: Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures................................... 6-5 Figure 6-2: [ ]a,c,e Pressure Ratio as a Function of L/D....................................................... 6-6 Figure 6-3: Idealized Pressure Drop Profile Through a Postulated Crack..................................................... 6-7 Figure 7-1: [ ]a,c,e Stress Distribution........................................................................................... 7-8 Figure 8-1: Reactor Vessel Inlet Nozzle with Stress Cut Locations............................................................... 8-7 Figure 8-2: Reference Fatigue Crack Growth Curves for [ ]a,c,e........... 8-8 Figure 8-3: Reference Fatigue Crack Growth Law for [ ]a,c,e in a Water Environment at 600°F................................................................................................................. 8-9 Figure A-1: Pipe with a Through-Wall Crack in Bending............................................................................. A-2

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 viii WCAP-13039-NP September 2023 Revision 2 EXECUTIVE

SUMMARY

Westinghouse performed analysis for the Leak-Before-Break (LBB) of Diablo Canyon Units 1 and 2 primary loop piping back in 1991. The results of the analysis were documented in WCAP-13039 [1-1] and approved by the United States Nuclear Regulatory Commission (U.S. NRC) in a letter dated March 2, 1993

[1-3]. Subsequently, in 2016 Westinghouse has also performed an evaluation to demonstrate that the primary loop piping remains in compliance with LBB technology due to the Nuclear Steam Supply System (NSSS) Structural and Licensing Review (NSLR) program as documented in WCAP-13039-P Revision 1[1-2].

WCAP-13039-P Revision 1 [1-2]:

Revision 1 was developed specifically for the NSLR program, but also considered past modifications to the Reactor Coolant Loop (RCL) piping system, such as those associated with the following programs:

Replacement Steam Generator (RSG), Replacement Reactor Vessel Head and Head Assembly Upgrade Package (RRVH/HAUP) and Increase Operating Ranges Program (Tavg Window Program).

It was demonstrated that due to the NSLR project the original LBB analysis and conclusions in [1-1]

remained valid, and the dynamic effects of reactor coolant system primary loop pipe breaks need not to be considered in the structural design basis.

WCAP-13039-P Revision 2:

The purpose of Revision 2 is to update the LBB evaluations for the Diablo Canyon Units 1 and 2 RCL piping due to Initial License Renewal (ILR) project, and to include the latest considerations of Time-Limited Aging Analyses (TLAA) effects for the plant operation extension into 60-years. The LBB evaluation also accounts for the past modifications to the RCL piping system, such as those associated with the following programs:

Replacement Steam Generator (RSG), Replacement Reactor Vessel Head and Head Assembly Upgrade Package (RRVH/HAUP) and Increase Operating Ranges Program (Tavg Window Program).

The LBB evaluations for Diablo Canyon Units 1 and 2 are updated using the LBB criteria and methodology in Standard Review Plan (SRP) 3.6.3 [1-5] and NUREG-0800 [1-11], including determination of fracture toughness properties for the cast austenitic stainless steel (CASS) components for 60-year operating life using the methodology in NUREG/CR-4513 Revision 1 [1-12] and Revision 2 including Errata [1-13], and an evaluation of the acceptability of the CASS material for LBB. In addition, the tensile properties and chemistry composition for some of the heats were updated to be in agreement with the CMTR data.

A reconciliation of the fatigue crack growth (FCG) is also performed based on the generic set of LBB analysis transients used in the existing analysis documented in Revision 1 of this report [1-2]. The analyzed set of design transients established for a 40-year design life for Diablo Canyon Units 1 and 2 used in the FCG assessment are reconciled for the 60-years period to confirm that the potential for flaws to initiate or significant growth is very low during the 60-year design life of the plant.

Diablo Canyon Units 1 and 2 RCS piping includes Alloy 82/182 dissimilar metal at the reactor pressure vessel inlet nozzle (RPVIN) to safe-end welds and the reactor pressure vessel outlet nozzle (RPVON) to safe-end welds. These Alloy 82/182 weld locations are known to be susceptible to Primary Water Stress Corrosion Cracking (PWSCC). Diablo Canyon Units 1 and 2 Alloy 82/182 weld locations are unmitigated.

The current LBB evaluation in Revision 2 accounts the potential effects of PWSCC in the leak rate and stability analyses.

The proprietary information from document WCAP-13039-P, Revision 2 in the brackets has been deleted in this non-proprietary report version.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 1-1 Introduction September 2023 WCAP-13039-NP Revision 2

1.0 INTRODUCTION

1.1 PURPOSE This report applies to the Diablo Canyon nuclear power plant, Units 1 and 2, Reactor Coolant System (RCS) primary loop piping. It is intended to demonstrate that for the specific parameters of Diablo Canyon plant, RCS primary loop pipe breaks need not be considered in the structural design basis.

The purpose of Revision 2 of this report is to update the LBB evaluations for the Diablo Canyon Units 1 and 2 RCL due to Initial License Renewal (ILR) project and to include the latest considerations of Time-Limited Aging Analyses (TLAA) effects for the plant operation extension into 60-years.

Historically, Westinghouse has performed analyses for the Leak-Before-Break (LBB) of Diablo Canyon Units 1 and 2 primary loop piping back in 1991. The results of these analyses were documented in WCAP-13039 [1-1] and approved by the NRC [1-3].

Subsequently, in 2016, the LBB was re-evaluated for the Nuclear Steam Supply System (NSSS) Structural and Licensing Review (NSLR) program and documented in WCAP-13039-P, Revision 1 [1-2]. Inputs in the LBB analysis for the NSLR program includes pipe stress analysis loads, normal operating parameters and transients and cycles information. The Revision 1 report was developed specifically for the NSLR program, but also considered the past modifications to the RCL piping system, such as those associated with the following programs: Replacement Steam Generator (RSG), Replacement Reactor Vessel Head and Head Assembly Upgrade Package (RRVH/HAUP) program and Increase Operating Ranges Program (Tavg Window Program).

For the ILR project, the LBB evaluations include the TLAA evaluations using the NUREG/CR-4513 Revision 1 [1-12] and Revision 2 including Errata [1-13].

The LBB evaluation for Diablo Canyon Units 1 and 2 is updated according to the LBB criteria and methodology in Standard Review Plan (SRP) 3.6.3 [1-5] and NUREG-0800 Revision 1 [1-11], including determination of the fracture toughness properties for the cast austenitic stainless steel (CASS) materials for 60-year operating life using the methodology in NUREG/CR-4513 Revision 1 [1-12] and NUREG/CR-4513 Revision 2 including Errata [1-13], and an evaluation of the acceptability of the CASS material for LBB is performed.

A reconciliation of the fatigue crack growth (FCG) is also performed based on the generic set of LBB analysis transients used in the existing analysis documented in WCAP-13039-P, Revision 1 [1-2]. The analyzed set of design transients established for a 40-year design life for Diablo Canyon Units 1 and 2 used in the FCG assessment is reconciled for the 60-years period to confirm that the potential for flaws to initiate or significant growth is very low during the 60-year design life of the plant.

Diablo Canyon Units 1 and 2 RCS piping includes Alloy 82/182 dissimilar metal (DM) welds at the reactor pressure vessel inlet nozzle (RPVIN) to safe-end and the reactor pressure vessel outlet nozzle (RPVON) to safe-end. These Alloy 82/182 weld locations are known to be susceptible to Primary Water Stress Corrosion Cracking (PWSCC). Unmitigated RPVIN and RPVON Alloy 82/182 weld locations are evaluated to account the effects of PWSCC.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 1-2 Introduction September 2023 WCAP-13039-NP Revision 2 1.2 SCOPE AND OBJECTIVE The purpose of this revision is to demonstrate Leak-Before-Break for the Diablo Canyon Units 1 and 2 primary loops piping for 60-years of plant service. The recommendations and criteria proposed in SRP 3.6.3 [1-5 and 1-11] are used in this evaluation. The criteria and resulting steps of the evaluation procedure can be briefly summarized as follows:

1.

Calculate the applied loads. Identify the locations at which the highest faulted stress occurs.

2.

Identify the materials and the associated material properties.

3.

Postulate a through-wall flaw at the governing locations. The size of the flaw should be large enough so that the leakage is assured of detection with margin using the installed leak detection equipment when the pipe is subjected to normal operating loads. A margin of 10 is demonstrated between the calculated leak rate and the leak detection capability.

4.

Using maximum faulted loads, demonstrate that there is a margin of at least 2 between the leakage flaw size and the critical flaw size.

5.

Review the operating history to ascertain that operating experience has indicated no particular susceptibility to failure from the effects of corrosion, water hammer, or low and high cycle fatigue.

6.

For the materials actually used in the plant, provide representative material properties including toughness and tensile test data. Evaluate long term effects such as thermal aging.

7.

Demonstrate margin on the calculated applied load value; margin of 1.4 using algebraic summation of faulted loads or margin of 1.0 using absolute summation of faulted loads.

8.

Perform an assessment of fatigue crack growth. Show that a through-wall crack will not result.

This report provides a fracture mechanics demonstration of primary loop integrity for the Diablo Canyon Units 1 and 2 consistent with the NRC position for exemption from consideration of dynamic effects.

It should be noted that the terms flaw and crack have the same meaning and are used interchangeably.

1.3 BACKGROUND

INFORMATION Westinghouse has performed considerable testing and analysis to demonstrate that RCS primary loop pipe breaks can be eliminated from the structural design basis of all Westinghouse plants. The concept of eliminating pipe breaks in the RCS primary loop was first presented to the NRC in 1978 in WCAP-9283

[1-6]. That topical report employed a deterministic fracture mechanics evaluation and a probabilistic analysis to support the elimination of RCS primary loop pipe breaks. That approach was then used as a means of addressing Generic Issue A-2 and Asymmetric Loss of Coolant Accident (LOCA) Loads.

Westinghouse performed additional testing and analysis to justify the elimination of RCS primary loop pipe breaks. This material was provided to the NRC along with Letter Report NS-EPR-2519 [1-7].

The NRC funded research through Lawrence Livermore National Laboratory (LLNL) to address this same issue using a probabilistic approach. As part of the LLNL research effort, Westinghouse performed extensive evaluations of specific plant loads, material properties, transients, and system geometries to

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 1-3 Introduction September 2023 WCAP-13039-NP Revision 2 demonstrate that the analysis and testing previously performed by Westinghouse and the research performed by LLNL applied to all Westinghouse plants [1-8 and 1-9]. The results from the LLNL study were released at a March 28, 1983, Advisory Committee on Reactor Safeguards (ACRS) Subcommittee meeting. These studies which are applicable to all Westinghouse plants east of the Rocky Mountains determined the mean probability of a direct LOCA (RCS primary loop pipe break) to be 4.4 x 10-12 per reactor year and the mean probability of an indirect LOCA to be 10-7 per reactor year. Thus, the results previously obtained by Westinghouse [1-6] were confirmed by an independent NRC research study.

Based on the studies by Westinghouse, LLNL, the ACRS, and the Atomic Industrial Forum (AIF), the NRC completed a safety review of the Westinghouse reports submitted to address asymmetric blowdown loads that result from a number of discrete break locations on the pressurized water reactor (PWR) primary systems. The NRC Staff evaluation [1-10] concludes that an acceptable technical basis has been provided so that asymmetric blowdown loads need not be considered for those plants that can demonstrate the applicability of the modeling and conclusions contained in the Westinghouse response or can provide an equivalent fracture mechanics demonstration of the primary coolant loop integrity. In a more formal recognition of LBB methodology applicability for PWRs, the NRC appropriately modified 10 CFR 50, General Design Criterion 4, Requirements for Protection Against Dynamic Effects of Postulated Pipe Rupture [1-4].

This report provides a fracture mechanics demonstration of primary loop integrity for the Diablo Canyon Units 1 and 2 consistent with the NRC position for exemption from consideration of dynamic effects. The re-evaluations were performed to ensure that the LBB evaluation conclusions remain valid for 60-year plant operating life in the ILR project.

Several computer codes are used in the evaluations. The LBB computer programs are under Configuration Control which has requirements conforming to Standard Review Plan 3.9.1. The computer codes used in this evaluation for leak rate and fracture mechanics calculations have been validated and used for all the LBB applications by Westinghouse.

1.4 REFERENCES

1-1 WCAP-13039, Technical Justification For Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis For the Diablo Canyon Units 1 and 2 Nuclear Power Plants, November 1991 (Westinghouse Proprietary Class 2).

1-2 WCAP-13039-P, Revision 1, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants, April 2016 (Westinghouse Proprietary Class 2).

1-3 USNRC Docket Nos. 50-275 and 50-323 dated March 2, 1993,

Subject:

Leak-Before-Break Evaluation of Reactor Coolant System Piping for Diablo Canyon Nuclear Power Plant, Unit No. 1 (TAC No. M83283) and Unit No. 2 (TAC No. M83284).

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 1-4 Introduction September 2023 WCAP-13039-NP Revision 2 1-4 Nuclear Regulatory Commission, 10 CFR 50, Modification of General Design Criteria 4 Requirements for Protection Against Dynamic Effects of Postulated Pipe Ruptures, Final Rule, Federal Register/Vol. 52, No. 207/Tuesday, October 27, 1987/Rules and Regulations, pp. 41288-41295.

1-5 Standard Review Plan; public comments solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal Register/Vol. 52, No. 167/Friday, February 28, 1987/Notices, pp. 32626-32633.

1-6 WCAP-9283, Integrity of the Primary Piping Systems of Westinghouse Nuclear Power Plants During Postulated Seismic Events, March 1978.

1-7 Letter Report NS-EPR-2519, Westinghouse (E. P. Rahe) to NRC (D. G. Eisenhut), Westinghouse Proprietary Class 2, November 10, 1981.

1-8 Letter from Westinghouse (E. P. Rahe) to NRC (W. V. Johnston), April 25, 1983.

1-9 Letter from Westinghouse (E. P. Rahe) to NRC (W. V. Johnston), July 25, 1983.

1-10 U.S. NRC Generic Letter 84-04, Subject Safety Evaluation of Westinghouse Topical Reports Dealing with Elimination of Postulated Pipe Breaks in PWR Primary Main Loops, February 1, 1984.

1-11 NUREG-0800, Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

1-12 NUREG/CR-4513, Revision 1, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, O. K. Chopra, U.S. Nuclear Regulatory Commission, Washington, DC, May 1994.

1-13 NUREG/CR-4513, Revision 2, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, O. K. Chopra, U.S. Nuclear Regulatory Commission, Washington, DC, May 2016, including Errata, March 15, 2021.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-1 Operation and Stability of the Reactor Coolant System September 2023 WCAP-13039-NP Revision 2 2.0 OPERATION AND STABILITY OF THE REACTOR COOLANT SYSTEM 2.1 STRESS CORROSION CRACKING The Westinghouse reactor coolant system (RCS) primary loops have an operating history that demonstrates the inherent operating stability characteristics of the design. This includes a low susceptibility to cracking failure from the effects of corrosion (e.g., intergranular stress corrosion cracking (IGSCC)). This operating history totals over 1400 reactor years, including 16 plants each having over 30 years of operation, 10 other plants each with over 25 years of operation, 11 plants each with over 20 years of operation and 12 plants each with over 15 years of operation.

In 1978, the United States Nuclear Regulatory Commission (USNRC) formed the second Pipe Crack Study Group. (The first Pipe Crack Study Group (PCSG) established in 1975 addressed cracking in boiling water reactors only.) One of the objectives of the second PCSG was to include a review of the potential for stress corrosion cracking in Pressurized Water Reactors (PWR's). The results of the study performed by the PCSG were presented in NUREG-0531 [2-1] entitled Investigation and Evaluation of Stress Corrosion Cracking in Piping of Light Water Reactor Plants. In that report the PCSG stated:

The PCSG has determined that the potential for stress corrosion cracking in PWR primary system piping is extremely low because the ingredients that produce IGSCC are not all present.

The use of hydrazine additives and a hydrogen overpressure limit the oxygen in the coolant to very low levels. Other impurities that might cause stress corrosion cracking, such as halides or caustic, are also rigidly controlled. Only for brief periods during reactor shutdown when the coolant is exposed to the air and during the subsequent startup are conditions even marginally capable of producing stress corrosion cracking in the primary systems of PWRs. Operating experience in PWRs supports this determination. To date, no stress corrosion cracking has been reported in the primary piping or safe ends of any PWR.

The discussion below further qualifies the PCSGs findings.

For stress corrosion cracking (SCC) to occur in piping, the following three conditions must exist simultaneously: high tensile stresses, susceptible material, and a corrosive environment. The potential for stress corrosion is minimized by properly selecting a material immune to SCC as well as preventing of a corrosive environment. The material specifications consider compatibility with the systems operating environment (both internal and external) as well as other material in the system, applicable American Society of Mechanical Engineers (ASME) Code rules, fracture toughness, welding, fabrication, and processing.

The elements of a water environment known to increase the susceptibility of austenitic stainless steel to stress corrosion are oxygen, fluorides, chlorides, hydroxides, hydrogen peroxide, and reduced forms of sulfur (e.g., sulfides, sulfites, and thionates). Strict pipe cleaning standards prior to operation and careful control of water chemistry during plant operation are used to prevent the occurrence of a corrosive environment. Prior to being put into service, the piping is cleaned internally and externally. During flushes and preoperational testing, water chemistry is controlled in accordance with written specifications.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-2 Operation and Stability of the Reactor Coolant System September 2023 WCAP-13039-NP Revision 2 Requirements on chlorides, fluorides, conductivity, and pH are included in the acceptance criteria for the piping.

During plant operation, the reactor coolant water chemistry is monitored and maintained within very specific limits. Contaminant concentrations are kept below the thresholds known to be conducive to stress corrosion cracking with the major water chemistry control standards being included in the plant operating procedures as a condition for plant operation. For example, during normal power operation, oxygen concentration in the RCS is expected to be in the ppb range by controlling charging flow chemistry and maintaining hydrogen in the reactor coolant at specified concentrations. Halogen concentrations are also stringently controlled by maintaining concentrations of chlorides and fluorides within the specified limits. Thus, during plant operation, the likelihood of stress corrosion cracking is minimized.

During 1979, several instances of cracking in PWR feedwater piping led to the establishment of the third PCSG. The investigations of the PCSG reported in NUREG-0691 [2-2] further confirmed that no occurrences of IGSCC have been reported for PWR primary coolant systems.

It should be noted that the Diablo Canyon Units 1 and 2 reactor coolant system (RCS) primary loop piping contains Alloy 82/182 DM welds which are susceptible to PWSCC, found at the Reactor Vessel Inlet and Outlet nozzle weld locations.

The LBB evaluation of the Alloy 82/182 DM welds is performed for unmitigated weld locations at the RPVIN and RPVON, including methodology to address the Alloy 82/182 PWSCC effects for 60- year plant life in the ILR project. A detailed evaluation of Alloy 82/182 welds is documented in Sections 6.4 and 7.4.

2.2 WATER HAMMER Overall, there is a low potential for water hammer in the RCS since it is designed and operated to preclude the voiding condition in normally filled lines. The reactor coolant system, including piping and primary components, is designed for normal, upset, emergency, and faulted condition transients. The design requirements are conservative relative to both the number of transients and their severity. Relief valve actuation and the associated hydraulic transients following valve opening are considered in the system design. Other valve and pump actuations are relatively slow transients with no significant effect on the system dynamic loads. To ensure dynamic system stability, reactor coolant parameters are stringently controlled. Temperature during normal operation is maintained within a narrow range by control rod position; pressure is controlled by pressurizer heaters and pressurizer spray also within a narrow range for steady state conditions. The flow characteristics of the system remain constant during a fuel cycle because the only governing parameters, namely system resistance and the reactor coolant pump characteristics, are controlled in the design process. Additionally, Westinghouse design has instrumented typical reactor coolant systems to verify the flow and vibration characteristics of the system. Preoperational testing and operating experience have verified the Westinghouse approach. The operating transients of the RCS primary piping are such that no significant water hammer can occur.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-3 Operation and Stability of the Reactor Coolant System September 2023 WCAP-13039-NP Revision 2 2.3 LOW CYCLE AND HIGH CYCLE FATIGUE An assessment of the low cycle fatigue loadings was carried out as part of this study in the form of a fatigue crack growth analysis, as discussed in Section 8.0.

High cycle fatigue loads in the system would result primarily from pump vibrations. These are minimized by restrictions placed on shaft vibrations during hot functional testing and operation.

During operation, an alarm signals the exceedance of the vibration limits. Field measurements have been made on a number of plants during hot functional testing. Stresses in the elbow below the reactor coolant pump resulting from system vibration have been found to be very small, between 2 and 3 ksi at the highest. These stresses are well below the fatigue endurance limit for the material and would also result in an applied stress intensity factor below the threshold for fatigue crack growth. Diablo Canyon RCS configurations are similar and the results are concluded to be similar.

2.4 WALL THINNING, CREEP, AND CLEAVAGE Wall thinning by erosion and erosion-corrosion effects should not occur in the primary loop piping stainless steel material, which is highly resistant to these degradation mechanisms at velocities greater than the mechanical design flow.

The maximum operating temperature of the primary loop piping, which is 610.1°F, is well below the temperature that would cause significant mechanical creep damage in stainless steel piping.

Cleavage type failures are not a concern for the operating temperatures and the stainless steel material used in the primary loop piping.

2.5 REFERENCES

2-1 Investigation and Evaluation of Stress-Corrosion Cracking in Piping of Light Water Reactor Plants, NUREG-0531, U.S. Nuclear Regulatory Commission, February 1979.

2-2 Investigation and Evaluation of Cracking Incidents in Piping in Pressurized Water Reactors, NUREG-0691, U.S. Nuclear Regulatory Commission, September 1980.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-1 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 3.0 PIPE GEOMETRY AND LOADING

3.1 INTRODUCTION

TO METHODOLOGY The general approach is discussed first. As an example a segment of the primary coolant hot leg pipe is shown in Figure 3-1. The as-built outside diameter and minimum wall thickness of the pipe are 33.99 in.

and 2.395 in., respectively, as seen in the figure. Normal stresses at the weld locations result from the load combination procedure discussed in Section 3.3 while faulted loads are developed as outlined in Section 3.4. The components for normal loads are pressure, dead weight and thermal expansion. An additional component, Safe Shutdown Earthquake of seismic double design earthquake (DDE) and HOSGRI earthquake (HE) is considered for faulted loads. Once the normal and faulted loads are calculated in this section, the load critical locations are determined in Section 5.0. These locations are called load critical locations and are locations at which, as enveloping locations, leak before break is to be established. Essentially a circumferential flaw is postulated to exist at these locations, thus the normal loads and faulted loads must be available to assess leakage and stability, respectively. Set of loads (developed below) at these locations are also given. As an example, location 1 is the highest stressed location at the Hot leg and the loads and geometry are shown in Figure 3-1. For the LBB evaluation, terminology such as flaw and crack are used interchangeably.

Since the elbows are cast stainless steel, thermal aging must be considered (see Section 4.0). Thermal aging results in lower fracture toughness criteria; thus, other locations than the load critical locations described above must be examined taking into consideration both fracture toughness and stress. The enveloping locations so determined are called toughness critical locations. Once loads (this section) and fracture toughnesses (Section 4.0) are available, the load critical and toughness critical locations are determined (see Section 5.0). At these locations, leak rate evaluations (see Section 6.0) and fracture mechanics evaluations (see Section 7.0) are performed per the guidance in [3-1 and 3-2]. Fatigue crack growth (see Section 8.0) and stability margins are also evaluated (see Section 9.0).

The welded locations are those shown in Figure 3-2.

3.2 CALCULATION OF LOADS AND STRESSES The stresses due to axial loads and total moments are calculated by the following equation:

(3-1)

Where:

=

stress, ksi F

=

axial load, kips M

=

total moment, in-kips A

=

pipe cross-sectional area, in2 Z

=

section modulus, in3 Z

M A

F

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-2 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 The total moments for the desired loading combinations are calculated by the following equation:

(3-2)

where, M

=

total moment for required loading MX =

X component of torsion moment MY =

Y component of bending moment MZ

=

Z component of bending moment The axial load and total moment for leak rate predictions and crack stability analyses are computed by the methods to be explained in Sections 3.3 and 3.4.

3.3 LOADS FOR LEAK RATE EVALUATION The normal operating loads for leak rate predictions are calculated by the following equations:

F

=

FDW + FTH + FP (3-3)

MX

=

(MX)DW + (MX)TH +(MX)P (3-4)

MY

=

(MY)DW + (MY)TH +(MY)P (3-5)

MZ

=

(MZ)DW + (MZ)TH +(MZ)P (3-6)

The subscripts of the above equations represent the following loading cases:

DW

=

deadweight TH

=

normal thermal expansion.

P

=

load due to internal pressure The axial force (FP) is calculated as follows: FP = x r2 x p, where r is the inside radius of the pipe and p is the normal operating pressure.

This method of combining loads is often referred to as the algebraic sum method [3-1 and 3-2].

The loads based on this method of combination are calculated, and the limiting normal loads for all loops are summarized in Table 3-1 at all the weld locations identified in Figure 3-2. The tables provide the as-built dimensions as well.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-3 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 3.4 LOAD COMBINATION FOR CRACK STABILITY ANALYSES In accordance with Standard Review Plan 3.6.3 [3-1 and 3-2], the margin in terms of applied loads needs to be demonstrated by crack stability analysis. Margin on loads of 1.4 (= 2) can be demonstrated if normal plus Safe Shutdown Earthquake (SSE) of seismic double design earthquake (DDE) and HOSGRI earthquake (HE) are applied algebraically and increased by 1.4. The 1.4 margin can be reduced to 1.0 if the deadweight, thermal expansion, internal pressure, Safe Shutdown Earthquake (SSE) inertia and seismic anchor motion (SAM) loads are combined based on individual absolute values as shown in the following equations:

F = FDW + FTH + FP + FSSEINERTIA + FSSEAM (3-7)

MX = (MX)DW + (MX)TH + (MX)P + (MX)SSEINERTIA + (MX)SSEAM (3-8)

MY = (MY)DW + (MY)TH + (MY)P + (MY)SSEINERTIA + (MY)SSEAM (3-9)

MZ = (MZ)DW + (MZ)TH + (MZ)P + (MZ)SSEINERTIA + (MZ)SSEAM (3-10)

Where subscript SSEINERTIA refers to safe shutdown earthquake inertia and SSEAM is safe shutdown earthquake anchor motion.

Note: for Diablo Canyon Units 1 and 2, the SSE SAM does not need to be added in the above equations, since the SAM loads are already inherently included in the SSE inertia piping loads.

The loads so determined are used in the fracture mechanics evaluations (Section 7.0) to demonstrate the LBB margins at the locations established to be the governing locations. The combined loads in this Section 3.4 at all the weld locations (as shown in Figure 3-2) are calculated, then the enveloped faulted loads and stresses used in the evaluation are summarized in Table 3-2. Additional detailed load calculation specifically for weld location 11 is provided in Table 3-3.

3.5 REFERENCES

3-1 Standard Review Plan: Public Comments Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal Register/Vol. 52, No. 167/Friday, August 28, 1987/Notices, pp. 32626-32633.

3-2 NUREG-0800 Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-4 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 Table 3-1: Dimensions, Normal Loads and Stresses for Diablo Canyon Units 1 and 2 from Most Limiting Temperature Case Location(a)

Outside Diameter (in)

Thickness (in)

Axial Load (kips)

Moment (in-kips)

Stress (ksi) 1 33.99 2.395 1485 21737 18.63 2

33.99 2.395 1485 7985 10.80 3

34.81 2.800 1486 5728 8.02 4

37.19 2.990 1564 14146 10.43 5

37.19 2.990 1671 2530 6.20 6

37.19 2.990 1662 1732 5.85 7

37.19 2.990 1655 1214 5.63 8

37.19 2.990 1707 3257 6.59 9

37.19 2.990 1707 6812 7.99 10 37.19 2.990 1794 10723 9.80 11 32.26 2.275 1360 4255 9.18 12 32.26 2.275 1361 3199 8.48 13 33.06 2.675 1361 4203 7.67 14 33.06 2.675 1359 4611 7.89 Note:

(a). See Figure 3-2.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-5 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 Table 3-2: Dimensions, Enveloped Faulted Loads and Stresses for Diablo Canyon Units 1 and 2(b)

Location(a)

Outside Diameter (in)

Thickness (in)

Axial Load (kips)

Moment (in-kips)

Stress (ksi) 1 33.99 2.395 2233 33929 28.72 2

33.99 2.395 2260 10691 15.60 3

34.81 2.800 2261 18706 16.99 4

37.19 2.990 2415 26852 18.07 5

37.19 2.990 2011 25483 16.27 6

37.19 2.990 1949 20278 14.03 7

37.19 2.990 1857 16423 12.23 8

37.19 2.990 1912 12826 10.99 9

37.19 2.990 1837 17111 12.44 10 37.19 2.990 1954 34113 19.49 11 32.26 2.275 1861 32779 30.51(c) 12 32.26 2.275 1861 16871 19.92 13 33.06 2.675 1863 15864 16.13 14 33.06 2.675 1821 20570 18.58 Notes:

(a). See Figure 3-2.

(b). Faulted Loadings consider both DDE and HOSGRI earthquakes.

(c). The highest faulted stress of 30.51 ksi occurs at location 11 of loop 3. As it is shown in Table 3-3, the second highest faulted stress occurs at location 11 of loop 2 with 29.78 ksi. The stress difference is only about 2.5%, and since location 11 of loop 2 has the lower bounding tensile properties which makes it more limiting as further discussed in Section 4.0, only the LBB evaluation and results at location 11 of loop 2 are provided in following sections of this report.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-6 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 Table 3-3: Faulted Loads and Stresses at Location 11 for Each Loop Loop Faulted Loads and Stresses(a,b)

Axial Moment Stress (kips)

(in-kips)

(ksi) 1 1681 20752 21.66 2

1844 31794 29.78 3

1861 32779 30.51 4

1857 28692 27.77 Notes:

(a) The enveloped faulted loads and stresses for location 11 from Units 1 and 2 are summarized in this table.

Faulted Loadings consider both DDE and HOSGRI earthquakes.

(b) Governing loop location, axial force, moment and stress are shown in bold.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-7 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 Location 1:

ODa = 33.99 in ta = 2.395 in Normal Loadsa Faulted Loadsb Forcec:

1485 kips Forcec:

2233 kips Moment:

21737 in-kips Moment:

33929 in-kips a See Table 3-1 b See Table 3-2 c Includes the force due to a pressure of 2250 psia Figure 3-1: Hot Leg Pipe Crack M

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-8 Pipe Geometry and Loading September 2023 WCAP-13039-NP Revision 2 HOT LEG Temperature: 610.1°F* Pressure: 2250 psia CROSS-OVER LEG Temperature: 544.8°F* Pressure: 2250 psia COLD LEG Temperature: 545.1°F* Pressure: 2250 psia

• Applicable Operating Temperatures for Diablo Canyon Unit 1and Unit 2 for the ILR project.

Figure 3-2:

Schematic Diagram of Diablo Canyon Units 1 and 2 Primary Loop Weld Locations 0

Reactor Pressure Vessel ~

COLD LEG

\__ Reacoor Coolant Pump

\__Steam Generator CROSSOVER EG

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-1 Material Characterization September 2023 WCAP-13039-NP Revision 2 4.0 MATERIAL CHARACTERIZATION 4.1 PRIMARY LOOP PIPE AND FITTINGS MATERIALS For Diablo Canyon Units 1 and 2, the primary loop pipe material is SA376 TP316, and the elbow fitting material is SA351 CF8M.

4.2 TENSILE PROPERTIES The Certified Materials Test Reports (CMTRs) for Diablo Canyon Units 1 and 2 were used to establish the tensile properties for the leak before break analyses. The CMTRs include tensile properties at room temperature for each of the heats of material. These properties are given for Diablo Canyon Units 1 and 2 in Tables 4-1 and 4-2, respectively. The average properties are given and the lower bound properties are identified. The 1989 Code [4-3] minimum properties are also given below these tables.

The properties at 544°F and 618°F (conservative from [4-1]) were established from the tensile properties at room temperature given in Tables 4-1 and 4-2 by utilization of Tables 4-3, 4-4, and 4-5. These last three tables provide typical tensile properties at room temperature and at 650°F for both materials of concern. The tensile properties for typical materials at 544°F and 618°F were obtained by interpolating between the room temperature and the 650°F tensile properties given in Tables 4-3, 4-4, and 4-5. Ratios of the strengths at 544°F and 618°F to the strengths at room temperature for the typical materials were then applied to the room temperature values given in Tables 4-1 and 4-2 to obtain the Diablo Canyon properties at 544°F and 618°F (conservative from [4-1]).

In Table 4-3, the SA376 TP316 material properties of 'plant A' were closer to the Diablo Canyon material properties than 'plant C', and therefore the 'plant A' values were used. In Tables 4-4 and 4-5 the tensile properties for all the listed components were averaged, to obtain the typical tensile properties for SA351 CF8M.

The average and lower bound yield strengths and ultimate strengths, for both Diablo Canyon Units 1 and 2, are given in Table 4-6. The ASME Code Modulus of Elasticity is also given, and Poisson's ratio was taken as 0.3.

For Alloy 82/182 DM welds, the CMTR data was not available, and the typical tensile properties from Westinghouse source for Alloy 82/182 weld material at the applicable operating temperatures as listed in Table 4-6 are used in the LBB evaluation.

Material Properties Impact for the Temperature Changes Hot leg (HL): existing analyzed temperature is 618°F [4-1] and ILR project PCWG temperature range is 598.1°F to 610.1°F [4-2].

Cross-over leg (XL): existing analyzed temperature is 544°F [4-1] and ILR project PCWG temperature range is 531.4 to 544.8°F [4-2].

Cold leg (CL): existing analyzed temperature 544°F [4-1] and ILR project PCWG temperature range is 531.7 to 545.1°F [4-2].

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-2 Material Characterization September 2023 WCAP-13039-NP Revision 2 Since, there are insignificant differences between the existing analysis temperature used in the original report [4-1] and for the ILR project in [4-2], a qualitative discussion is presented here to account for the applicability of the new operating temperature range.

The ILR operating temperature is lower than the analyzed temperature from [4-1] at the hot leg. Lower temperatures provide higher material (yield and ultimate) properties. Higher material properties are beneficial for the LBB stability analysis (higher material properties mean higher critical flaw sizes and therefore higher LBB flaw size margins). For the crossover and cold legs, the analyzed temperature is lower by 1°F than the upper bound temperature; this difference in temperature will have an insignificant impact on the material properties and the final LBB margins. Therefore, the analyzed material properties at normal operating temperatures of 618°F and 544°F are acceptable for the ILR project.

4.3 FRACTURE TOUGHNESS PROPERTIES The pre-service fracture toughness (J) of cast austenitic stainless steel (CASS) that are of interest are in terms of JIC (J at Crack Initiation) and have been found to be very high at 600F. [

]a,c,e However, cast stainless steel is susceptible to thermal aging at the reactor operating temperature, that is, about 550°F. Thermal aging of cast stainless steel results in embrittlement, which means a decrease in the ductility, impact strength, and fracture toughness of the material. Depending on the material composition, the Charpy impact energy of a cast stainless steel component could decrease to a small fraction of its original value after exposure to reactor temperatures during service.

The susceptibility of the material to thermal aging increases with increasing ferrite and molybdenum contents.

In 1994, the Argonne National Laboratory (ANL) completed an extensive research program in assessing the extent of thermal aging of cast stainless steel materials [4-4]. The ANL research program measured mechanical properties of cast stainless steel materials after they had been heated in controlled ovens for long periods of time. ANL compiled a database, both from data within ANL and from international sources, of about 85 compositions of cast stainless steel exposed to a temperature range of 290°-400°C (550°-750°F) for up to 58,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (6.5 years). In 2015, the work done by ANL was augmented, and the fracture toughness database for CASS materials was aged to 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> at 290°-350°C (554°-633°F).

The methodology for estimating fracture properties has been extended to cover CASS materials with a ferrite content of up to 40%. From this database (NUREG/CR-4513, Revision 2), ANL developed correlations for estimating the extent of thermal aging of cast stainless steel [4-6]. From this database (NUREG/CR-4513, Revision 2), ANL developed correlations for estimating the extent of thermal aging of cast stainless steel [4-6].

ANL developed the fracture toughness estimation procedures by correlating data in the database conservatively. After developing the correlations, ANL validated the estimation procedures by comparing the estimated fracture toughness with the measured value for several cast stainless steel plant components removed from actual plant service. The procedure developed by ANL in Revision 1 and Revision 2 of NUREG/CR-4513 [4-5 and 4-6] was used to calculate the end of life limiting fracture toughness values of the CASS elbows for the cold leg, crossover leg and hot leg locations. Note that LBB analyses have acceptable margins when performing the elastic-plastic J-integral evaluations with the use of lower bound

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-3 Material Characterization September 2023 WCAP-13039-NP Revision 2 fracture toughness properties from NUREG/CR-4513, Revision 1 and Revision 2. Furthermore, this report used saturated toughness approved by NRC in NUREG/CR-4513 Revision 1 and Revision 2 with Errata. Therefore, the LBB analysis is acceptable from a saturated toughness perspective.

The results from the ANL Research Program indicate that the lower-bound fracture toughness of thermally aged cast stainless steel is similar to that of submerged arc welds (SAWs). In addition, historic testing done on representative plants documented in [4-7 and 4-8], has shown that the wrought and cast stainless steel piping exhibits more limiting (unaged) fracture toughness properties than the weld metal.

Since the CASS materials aged lower bound fracture toughness values are similar to that of Submerged Arc Welds (SAWs), and since SAWs are considered to be the most limiting of welding processes (with respect to GTAW and SMAW), it is concluded that the aged fracture toughness of the wrought and cast base metal is more limiting than the aged fracture toughness of the stainless-steel weld metal. Therefore, the stainless-steel weld regions are less limiting than the cast material, and the applied value of the J-integral for a flaw in the weld regions will be lower than that in the base metal because the yield stress for the stainless steel weld materials is much higher at operating temperature(a).

Forged stainless steel piping such as SA376 TP316 does not degrade due to thermal aging. Thus, fracture toughness values well in excess of that established for the cast material exist for this material throughout service life and are not limiting.

Alloy 82/182 weld materials have high toughness values and do not degrade due to thermal aging. As discussed in [4-9], the fracture resistance of Ni Alloys (Alloys 82) and their welds have been investigated by conducting fracture toughness J-R curve tests at 24-338°C in deionized water. The results indicated that Alloy 690 welds exhibit excellent fracture toughness in air and high-temperature water (> 93 °C).

Nickel alloys are known to have high toughness properties and because CF8M CASS base metal and is susceptible to thermal aging degradation of the fracture toughness, it is determined that the CF8M CASS base metal presents the most limiting condition. Therefore, in the fracture mechanics analyses that follow, the thermally aged fracture toughness allowables of the CASS material given in Table 4-9 will be used as the criteria against which the calculated applied fracture toughness values will be compared.

Since SA351 CF8M cast material is susceptible to thermal aging and embrittlement (low fracture toughness), a crack stability evaluation is performed using elastic-plastic fracture mechanics methods.

The calculation is performed for 60-year service life considering that the material is fully aged.

The method described below was used to calculate the toughness properties for the cast material, SA351 CF8M, of the primary coolant loop elbows. RCS elbows are made of static-cast CF8M material.

a) In the report, all the applied J values were conservatively determined by using base metal strength properties.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-4 Material Characterization September 2023 WCAP-13039-NP Revision 2 The following methodology and equations are taken from NUREG/CR-4513, Revision 1 [4-5] and NUREG/CR-4513, Revision 2 including Errata [4-6], and applicable for CF8M type static-cast material.

The JIc, Jmax and Tmat values for each material heat for CASS elbows were calculated using both Revision 1 and Revision 2 of NUREG/CR-4513 [4-5 and 4-6], and the enveloped values from both revisions are used in the evaluation. The equations listed below are used to calculate delta ferrite based on Hulls equivalent factor methodology.

Creq = Cr + 1.21(Mo) + 0.48(Si) - 4.99 = (Chromium equivalent)

Nieq = (Ni) + 0.11(Mn) - 0.0086(Mn)2 + 18.4(N) + 24.5(C) + 2.77 = (Nickel equivalent) c = 100.3(Creq / Nieq)2 -170.72 (Creq / Nieq) + 74.22 = (Ferrite Content) where the elements are in percent weight and c is ferrite in percent volume.

Note: %N values of 0.04% are per [4-5 and 4-6], where N stands for Nitrogen.

The saturation room temperature (RT) at 77°F as suggested in [4-6] impact energies of the cast stainless steel materials are determined from the chemical composition.

NUREG/CR-4513 Revision 2 CF8M Material:

For CF8M steel with < 10% Ni, the saturation value of RT impact energy Cvsat (J/cm2) is the lower value determined from:

log10Cvsat = 0.27 + 2.81 exp (-0.022) where the material parameter is expressed as

= c (Ni + Si + Mn)2(C + 0.4N)/5.0 and from log10Cvsat = 7.28 - 0.011c - 0.185Cr - 0.369Mo - 0.451Si- 0.007Ni - 4.71(C + 0.4N)

For CF8M steel with 10% Ni, the saturation value of RT impact energy Cvsat (J/cm2) is the lower value determined from:

log10Cvsat = 0.84 + 2.54 exp (-0.047) where the material parameter is expressed as

= c (Ni + Si + Mn)2(C + 0.4N)/5.0 and from log10Cvsat = 7.28 - 0.011c - 0.185Cr - 0.369Mo - 0.451Si - 0.007Ni - 4.71(C + 0.4N)

The saturation J-R curve at RT, for static-cast CF8M steel is given by:

Jd = 1.44 (Cvsat)1.35(a)n for Cvsat < 35 J/cm2 Jd = 16 (Cvsat)0.67(a)n for Cvsat 35 J/cm2 n = 0.20 + 0.08 log10 (Cvsat) where Jd is the deformation J in kJ/m2 and a is the crack extension in mm.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-5 Material Characterization September 2023 WCAP-13039-NP Revision 2 The saturation J-R curve at 290-320C (554-608F), for static-cast CF8M steel is given by Jd = 5.5 (Cvsat)0.98(a)n for Cvsat < 46 J/cm2 Jd = 49 (Cvsat)0.41(a)n for Cvsat 46 J/cm2 n = 0.19 + 0.07 log10 (Cvsat) where Jd is the deformation J in kJ/m2 and a is the crack extension in mm.

NUREG/CR-4513 Revision 1 CF8M Material:

For CF8M steel with < 10% Ni, the saturation value of RT impact energy Cvsat (J/cm2) is the lower value determined from:

log10Cvsat = 1.10 + 2.12 exp (-0.041)

[different from NUREG/CR-4513 Rev. 2]

where the material parameter is expressed as

= c (Ni + Si +Mn)2(C + 0.4N)/5.0 and from log10Cvsat = 7.28 - 0.011c - 0.185Cr - 0.369Mo - 0.451Si- 0.007Ni - 4.71(C + 0.4N)

For CF8M steel with 10% Ni, the saturation value of RT impact energy Cvsat (J/cm2) is the lower value determined from:

log10Cvsat = 1.10 + 2.64 exp (-0.064)

[different from NUREG/CR-4513 Rev. 2]

where the material parameter is expressed as

= c (Ni + Si +Mn)2(C + 0.4N)/5.0 and from log10Cvsat = 7.28 - 0.011c - 0.185Cr - 0.369Mo - 0.451Si - 0.007Ni - 4.71(C + 0.4N)

The J-R curve at RT, for static-cast CF8M steel is given by:

Jd = 16 (Cvsat)0.67(a)n n = 0.23 + 0.08 log10 (Cvsat)

[different from NUREG/CR-4513 Rev. 2]

where Jd is the deformation J in kJ/m2 and a is the crack extension in mm.

The J-R curve at 290C (554F), for static-cast CF8M steel is given by:

Jd = 49 (Cvsat)0.41(a) n = 0.23 + 0.06 log10 (Cvsat) [different from NUREG/CR-4513 Rev. 2]

where Jd is the deformation J in kJ/m2 and a is the crack extension in mm.

4.3.1.1 JIc and Jmax Calculations:

[The crack extension for Jd at initiation was calculated using the ASTM E813-85 procedures. Jd at initiation (JIC) was defined on the 0.2 mm offset line. Jmax is calculated at 10 mm offset line].

NUREG/CR-4513, Revision 1, methodology calculates JIc at room temperature (77°F) and 554°F.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-6 Material Characterization September 2023 WCAP-13039-NP Revision 2 NUREG/CR-4513, Revision 2, methodology calculates JIc at room temperature (77°F), as well as the temperature range of 554 - 608°F.

Using the NUREG/CR-4513, Revision 2, including Errata [4-6] and NUREG/CR-4513 Revision 1 [4-5]

methodology, the fracture toughness properties for Unit 1 and Unit 2 are calculated and provided in Tables 4-7 and 4-8, respectively. The heats with the lowest fracture toughness properties at the HL, XL, and CL are summarized in Table 4-9.

4.3.1.2 Tmat Calculations:

Using the NUREG/CR-4513, Revision 2 including Errata [4-6] and NUREG/CR-4513 Revision 1 [4-5]

methodology, the tearing modulus values, Tmat, are calculated and provided in Table 4-7 for Unit 1, and Table 4-8 for Unit 2, and the heats with the lowest tearing modulus at the HL, XL and CL are summarized in Table 4-9.

The material tearing modulus, Tmat, at aged condition is calculated as follows:

Tmat = dJ/da x E/(fa)2 where:

dJ/da

= Ceff x10^[neff-1]x neff Ceff

= 10^[(log(JIc)-log(0.2)*log(Jmax))/(1-log(0.2))]

neff

= log(Jmax / Ceff)/log(10)

E

= Elastic Modulus at operating temperature, psi.

fa

= aged flow stress = (unaged flow stress) x Rf, psi fu

= (unaged flow stress) = unaged (y + u)/2, psi.

Tensile Strength At RT, the tensile-flow-strength ratio, Rf = (fa /fu ) for CF8M steel is given by Rf

= 0.77 + 0.10P (1.0 Rf 1.19)

At 290°C (554°F), the Rf for CF8M steel is given by:

Rf

= 0.69 + 0.14P (1.0 Rf 1.24)

The equations are valid for service temperatures between 280°C and 330°C (536°F and 626°F) and ferrite contents of >7% for CF8M steels.

The tearing modulus, Tmat values at aged condition for the elbow material as calculated are shown in Table 4-7 and Table 4-8.

Note: stress-strain data to calculate Ramberg-Osgood (n and ) parameters are derived from NUREG/CR-4513 [4-5 and 4-6] methods.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-7 Material Characterization September 2023 WCAP-13039-NP Revision 2

4.4 REFERENCES

4-1 WCAP-13039, Technical Justification For Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis For the Diablo Canyon Units 1 and 2 Nuclear Power Plants, November 1991 (Westinghouse Proprietary Class 2).

4-2

[

]a,c,e 4-3 ASME Boiler and Pressure Vessel Code,Section III, Division 1 - Appendices, Rules for Construction of Nuclear Power Plant Components, 1989 Edition.

4-4 O. K. Chopra and W. J. Shack, Assessment of Thermal Embrittlement of Cast Stainless Steels, NUREG/CR-6177, U.S. Nuclear Regulatory Commission, Washington, DC, May 1994.

4-5 O. K. Chopra, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, NUREG/CR-4513, Revision 1, U.S. Nuclear Regulatory Commission, Washington, DC, August 1994.

4-6 O. K. Chopra, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, NUREG/CR-4513, Revision 2, U.S. Nuclear Regulatory Commission, Washington, DC, May 2016 including Errata, March 15, 2021.

4-7 Westinghouse Report, WCAP-9787, Tensile and Toughness Properties of Primary Piping Weld Metal for Use in Mechanistic Fracture Evaluation, May 1981 (Westinghouse Proprietary Class 2).

4-8 Westinghouse Report, WCAP-9558, Revision 2, Mechanistic Fracture Evaluation of Reactor Coolant Pipe Containing a Postulated Circumferential Through-Wall Crack, May 1981 (Westinghouse Proprietary Class 2).

4-9 NUREG/CR-6721, Effects of Alloy Chemistry, Cold Work, and Water Chemistry on Corrosion Fatigue and Stress Corrosion Cracking of Nickel Alloys and Welds, April 2001.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-8 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-1: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Piping(2)

Component Loop No.

Heat No. (1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Cold Leg 1

V0630/3259 SA376 TP316 43.9 87.6 Cold Leg 1

V0630/3259 SA376 TP316 42.4 84.1 Cold Leg 2

V0629/3334 SA376 TP316 42.5 80.1 Cold Leg 2

V0629/3334 SA376 TP316 41.9 81.2 Cold Leg 3

K2011/3682 SA376 TP316 34.7 77.0 Cold Leg 3

K2011/3682 SA376 TP316 36.0 78.4 Cold Leg 4

V0630/3261 SA376 TP316 38.5 78.5 Cold Leg 4

V0630/3261 SA376 TP316 42.9 86.3 Cold Leg 1

E1478/3258 SA376 TP316 37.9 77.9 Cold Leg 1

E1478/3258 SA376 TP316 39.9 81.7 Cold Leg 2

K2010/3684 SA376 TP316 38.6 81.8 Cold Leg 2

K2010/3684 SA376 TP316 35.2 77.2 Cold Leg 3

E1478/3256 SA376 TP316 45.5 84.1 Cold Leg 3

E1478/3256 SA376 TP316 43.4 87.9 Cold Leg 4

K2011/3680 SA376 TP316 34.1 75.3 Cold Leg 4

K2011/3680 SA376 TP316 43.4 82.9 Hot Leg 1

E1490/3358 SA376 TP316 43.5 85.4 Hot Leg 1

E1490/3358 SA376 TP316 44.9 84.9 Hot Leg 2

E1485/3352Y SA376 TP316 42.3 85.4 Hot Leg 2

E1485/3352Y SA376 TP316 45.4 87.4 Hot Leg 3

V0688/3539 SA376 TP316 39.9 81.7

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-9 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-1: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Piping(2)

Component Loop No.

Heat No. (1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Hot Leg 3

V0688/3539 SA376 TP316 40.2 81.7 Hot Leg 4

E1484/3349X SA376 TP316 39.0 79.1 Hot Leg 4

E1484/3349X SA376 TP316 42.9 85.9 Hot Leg 1

E1484/3349Y SA376 TP316 39.0 79.1 Hot Leg 1

E1484/3349Y SA376 TP316 42.9 85.9 Hot Leg 2

E1483/3350X SA376 TP316 44.1 86.2 Hot Leg 2

E1483/3350X SA376 TP316 47.3 88.4 Hot Leg 3

E1483/3350Y SA376 TP316 44.1 86.2 Hot Leg 3

E1483/3350Y SA376 TP316 47.3 88.4 Hot Leg 4

V0684/3537X SA376 TP316 38.9 79.8 Hot Leg 4

V0684/3537X SA376 TP316 40.6 80.7 Crossover Leg 1

F-0222/2902X SA376 TP316 43.5 85.1 Crossover Leg 1

F-0222/2902X SA376 TP316 44.3 85.6 Crossover Leg 2

F0222/2902Y SA376 TP316 43.5 85.1 Crossover Leg 2

F0222/2902Y SA376 TP316 44.3 85.6 Crossover Leg 3

F0216/2863X SA376 TP316 43.7 86.7 Crossover Leg 3

F0216/2863X SA376 TP316 39.5 82.1 Crossover Leg 4

E1485/3361X SA376 TP316 38.3 83.9 Crossover Leg 4

E1485/3361X SA376 TP316 45.9 91.4 Crossover Leg 1

E1493/3381X SA376 TP316 41.0 84.9 Crossover Leg 1

E1493/3381X SA376 TP316 43.5 86.9 Crossover Leg 2

E1493/3381Y SA376 TP316 41.0 84.9

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-10 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-1: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Piping(2)

Component Loop No.

Heat No. (1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Crossover Leg 2

E1493/3381Y SA376 TP316 43.5 86.9 Crossover Leg 3

K2029/4438Y SA376 TP316 32.5 78.9 Crossover Leg 3

K2029/4438Y SA376 TP316 40.0 82.4 Crossover Leg 4

E1468/3365 SA376 TP316 42.0 84.4 Crossover Leg 4

E1468/3365 SA376 TP316 44.0 87.4 Min 32.5 75.3 Average 41.53 83.6 Notes:

1. Each heat has two tests for SA376 TP 316 material.

2. The text in bold font indicates changes to heat numbers done to match the numbers in the spool drawings or changes to the tensile properties to match the original CMTRs data.

3. Underlined number indicates the lower bound values.

Table 4-1 (contd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Fittings (i.e. Elbows)

Component Loop No.

Heat No.(1)

Material Yield Strength(2)

(ksi)

Ultimate Strength(2)

(ksi)

Cold Leg 1

30845-1 SA351 CF8M 36.5 76.9 Cold Leg 2

33047-4 SA351 CF8M 42.3 85.3 Cold Leg 3

32425-4 SA351 CF8M 42.5 85.8 Cold Leg 4

32469-2 SA351 CF8M 47.25 89.75 Hot Leg 1

10966-1 SA351 CF8M 45.0 87.5 Hot Leg 2

11937-2 SA351 CF8M 43.5 88.0 Hot Leg 3

12198-2 SA351 CF8M 42.0 85.0 Hot Leg 4

10563-2 SA351 CF8M 45.0 88.5 Crossover Leg 1

13174-2 SA351 CF8M 48.0 85.0 Crossover Leg 2

13704-1 SA351 CF8M 48.0 86.5

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-11 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-1 (contd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 1 Primary Loop Fittings (i.e. Elbows)

Component Loop No.

Heat No.(1)

Material Yield Strength(2)

(ksi)

Ultimate Strength(2)

(ksi)

Crossover Leg 4

16654-2 SA351 CF8M 36.0 74.0 Crossover Leg 3

16690-2 SA351 CF8M 39.0 75.0 Crossover Leg 1

13421-1 SA351 CF8M 46.5 85.0 Crossover Leg 1

14576-1 SA351 CF8M 40.5 78.75 Crossover Leg 2

14804-1 SA351 CF8M 51.0 93.0 Crossover Leg 2

15560-1 SA351 CF8M 43.5 86.0 Crossover Leg 3

15987-2 SA351 CF8M 45.0 87.0 Crossover Leg 3

15823-1 SA351 CF8M 42.0 83.25 Crossover Leg 4

14535-2 SA351 CF8M 41.5 80.50 Crossover Leg 4

16037-3 SA351 CF8M 37.5 75.25 Crossover Leg 1

16690-3 SA351 CF8M 40.5 81.75 Crossover Leg 1

17388-2 SA351 CF8M 37.5 75.0 Crossover Leg 2

13930-5 SA351 CF8M 48.0 89.0 Crossover Leg 2

14251-1 SA351 CF8M 39.0 82.5 Crossover Leg 3

11743-1 SA351 CF8M 45.0 86.0 Crossover Leg 3

11556-1 SA351 CF8M 43.5 83.5 Crossover Leg 4

12281-1 SA351 CF8M 42.0 84.75 Crossover Leg 4

11974-1 SA351 CF8M 43.0 83.0 Min 36.0 74.0 Average 42.89 86.63 Notes:

1. The text in bold font indicates changes to heat numbers done to match the numbers in the spool drawings.

2. Underlined number indicates the lower bound values.

1989 Code [4-3] Minimum Properties (ksi) at room temperature:

Yield Ultimate SA376 TP316 30 75 SA351 CF8M 30 70

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-12 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-2: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Piping(2)

Component Loop No.

Heat No.(1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Cold Leg 1

F0654/4153 SA376 TP316 38.9 81.6 Cold Leg 1

F0654/4153 SA376 TP316 42.4 86.1 Cold Leg 2

J1676/4555 SA376 TP316 38.2 81.6 Cold Leg 2

J1676/4555 SA376 TP316 41.2 83.6 Cold Leg 3

F0654/4152 SA376 TP316 38.7 83.1 Cold Leg 3

F0654/4152 SA376 TP316 43.3 86.0 Cold Leg 4

K2029/4557 SA376 TP316 38.7 80.6 Cold Leg 4

K2029/4557 SA376 TP316 36.4 88.1 Cold Leg 1

F0653/4151X SA376 TP316 40.7 83.1 Cold Leg 1

F0653/4151X SA376 TP316 41.2 83.6 Cold Leg 2

J1676/4556X SA376 TP316 37.5 82.7 Cold Leg 2

J1676/4556X SA376 TP316 41.9 84.1 Cold Leg 3

J1677/4554X SA376 TP316 38.7 81.6 Cold Leg 3

J1677/4554X SA376 TP316 40.4 82.6 Cold Leg 4

J1681/4677 SA376 TP316 43.7 87.4 Cold Leg 4

J1681/4677 SA376 TP316 41.2 83.6 Hot Leg 1

F0655/4132 SA376 TP316 42.4 86.9 Hot Leg 1

F0655/4132 SA376 TP316 48.3 91.6 Hot Leg 2

F0656/4131 SA376 TP316 38.7 83.0 Hot Leg 2

F0656/4131 SA376 TP316 39.1 81.5 Hot Leg 3

F0654/4136 SA376 TP316 38.9 82.1

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-13 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-2: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Piping(2)

Component Loop No.

Heat No.(1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Hot Leg 3

F0654/4136 SA376 TP316 47.4 86.6 Hot Leg 4

J1682/4627 SA376 TP316 44.9 87.6 Hot Leg 4

J1682/4627 SA376 TP316 51.0 93.1 Hot Leg 1

K2029/4480X SA376 TP316 37.4 79.9 Hot Leg 1

K2029/4480X SA376 TP316 36.4 80.9 Hot Leg 2

F0656/4137X SA376 TP316 49.9 88.6 Hot Leg 2

F0656/4137X SA376 TP316 50.9 92.1 Hot Leg 3

K2029/4479 SA376 TP316 37.2 80.6 Hot Leg 3

K2029/4479 SA376 TP316 44.2 87.1 Hot Leg 4

J1676/4631X SA376 TP316 38.2 81.9 Hot Leg 4

J1676/4631X SA376 TP316 47.8 87.3 Crossover Leg 1

J-1681/4560X SA376 TP316 45.0 84.9 Crossover Leg 1

J-1681/4560X SA376 TP316 40.7 81.1 Crossover Leg 2

J-1681/4561X SA376 TP316 37.7 81.9 Crossover Leg 2

J-1681/4561X SA376 TP316 41.2 84.8 Crossover Leg 3

J-1682/4669X SA376 TP316 43.7 85.9 Crossover Leg 3

J-1682/4669X SA376 TP316 45.5 87.5 Crossover Leg 4

J1681/4562Y SA376 TP316 43.0 83.9 Crossover Leg 4

J1681/4562Y SA376 TP316 40.9 83.6 Crossover Leg 1

J-1681/4562X SA376 TP316 43.0 83.9 Crossover Leg 1

J-1681/4562X SA376 TP316 40.9 83.6

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-14 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-2: Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Piping(2)

Component Loop No.

Heat No.(1)/

Serial No.

Material Yield Strength(3)

(ksi)

Ultimate Strength(3)

(ksi)

Crossover Leg 2

J-1682/4563Y SA376 TP316 46.7 84.3 Crossover Leg 3

J-1681/4561Y SA376 TP316 37.7 81.9 Crossover Leg 3

J-1681/4561Y SA376 TP316 41.2 84.9 Crossover Leg 4

J-1682/4563X SA376 TP316 39.4 82.0 Min 36.4 79.9 Average 41.8 84.44 Notes:

1. Each heat has two tests for SA376 TP 316 material, except for XL, Loop 2 and Loop 4.

2. The text in bold font indicates changes to heat numbers done to match the numbers in the spool drawings or changes to the tensile properties to match the original CMTR scanned microfiche data.

3. Underlined number indicates the lower bound values.

Table 4-2 (contd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Fittings (i.e. Elbows)

Component Loop No.

Heat No.(1,2)

Material Yield Strength(2,3)

(ksi)

Ultimate Strength(2,3)

(ksi)

Cold Leg 1

40874-4 SA351 CF8M 43.8 86.1 Cold Leg 2

40874-3 SA351 CF8M 43.8 86.1 Cold Leg 3

39716-4 SA351 CF8M 43.8 87.1 Cold Leg 4

39716-1 SA351 CF8M 47.75 87.3 Hot Leg 1

33756-2 SA351 CF8M 44.25 84.0 Hot Leg 2

41192-2 SA351 CF8M 34.3 73.3 Hot Leg 3

37168-1 SA351 CF8M 38.65 76.3 Hot Leg 4

39792-3 SA351 CF8M 42.3 84.3 Crossover Leg 1

38408-3 SA351 CF8M 43.6 83.1 Crossover Leg 2

39231-3 SA351 CF8M 46.8 89.6 Crossover Leg 3

39445-2 SA351 CF8M 42.3 83.5

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-15 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-2 (contd): Measured Room Temperature Tensile Properties for Diablo Canyon Unit 2 Primary Loop Fittings (i.e. Elbows)

Component Loop No.

Heat No.(1,2)

Material Yield Strength(2,3)

(ksi)

Ultimate Strength(2,3)

(ksi)

Crossover Leg 4

34900-2 SA351 CF8M 33.75 70.5 Crossover Leg 1

55485-1 SA351 CF8M 43.3 86.35 Crossover Leg 1

55485-2 SA351 CF8M 43.3 86.35 Crossover Leg 2

51922-3 SA351 CF8M 42.45 86.9 Crossover Leg 2

52665-1 SA351 CF8M 43.05 86.3 Crossover Leg 3

52282-2 SA351 CF8M 41.7 85.65 Crossover Leg 3

52369-2 SA351 CF8M 41.85 85.75 Crossover Leg 4

51712-2 SA351 CF8M 39.4 80.35 Crossover Leg 4

52665-2 SA351 CF8M 42.45 88.7 Crossover Leg 1

49686-1 SA351 CF8M 46.95 89.95 Crossover Leg 1

50362-2 SA351 CF8M 41.7 86.15 Crossover Leg 2

41423-1 SA351 CF8M 40.0 79.25 Crossover Leg 2

52449-1 SA351 CF8M 42.75 87.5 Crossover Leg 3

51712-1 SA351 CF8M 38.25 79.50 Crossover Leg 3

52369-1 SA351 CF8M 42.60 88.00 Crossover Leg 4

34900-1 SA351 CF8M 32.25 70.0 Crossover Leg 4

50115-1 SA351 CF8M 42.45 81.9 Min 32.25 70.0 Average 41.63 83.56 Notes:

1. Material heat No. 55485-2 was listed as unavailable in [4-1]. After performed review, it is confirmed that the tensile properties are the same as No. 55485-1.

2. The text in bold font indicates changes to heat numbers done to match the numbers in the spool drawings or changes to the tensile properties to match the original CMTR scanned microfiche data.

3. Underlined number indicates the lower bound values.

1989 Code [4-3] Minimum Properties (ksi) at room temperature:

Yield Ultimate SA376 TP316 30 75 SA351 CF8M 30 70

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-16 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-3: Typical Tensile Properties of SA376 TP316, SA351 CF8A and Welds of Such Material for Primary Loop Plant Material Test Temperature (oF)

Yield Strength (psi)

Ultimate Strength (psi) a,c,e U....-------------'--------------'------------JL.-----------'---------------"'-

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-17 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-4: Mechanical Properties of SA351 CF8M Material at Room Temperature (from A Typical PWR Plant)

PRODUCT FORM HEAT NO.

TEST PIECE NO.

MATERIAL 0.2%

OFFSET YIELD STRENGTH (PSI)

ULTIMATE STRENGTH (PSI)

ELONGATION REDUCTION AREA a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-18 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-4 (contd) Mechanical Properties of SA351 CF8M Material at Room Temperature (from A Typical PWR Plant)

PRODUCT FORM HEAT NO.

TEST PIECE NO.

MATERIAL 0.2%

OFFSET YIELD STRENGTH (PSI)

ULTIMATE STRENGTH (PSI)

ELONGATION REDUCTION AREA a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-19 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-5: Mechanical Properties of SA351 CF8M Material at 650OF Temperature (from A Typical PWR Plant)

PRODUCT FORM HEAT NO.

TEST PIECE NO.

MATERIAL 0.2% OFFSET YIELD STRENGTH (PSI)

ULTIMATE STRENGTH (PSI)

ELONGATION REDUCTION AREA a,c,e

---

~----~-----~---------~---------~-------~---------~------------

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-20 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-5 (contd): Mechanical Properties of SA351 CF8M Material at 650°F Temperature (from A Typical PWR Plant)

PRODUCT FORM HEAT NO.

TEST PIECE NO.

MATERIAL 0.2%

OFFSET YIELD STRENGTH (PSI)

ULTIMATE STRENGTH (PSI)

ELONGATION REDUCTION AREA a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-21 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-6: Mechanical Properties for Diablo Canyon Units 1 and 2 Materials at 544°F and 618°F a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-22 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-7: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 1 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-23 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-7: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 1 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-24 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-7: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 1 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-25 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-7: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 1 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-26 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-8: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 2 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-27 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-8: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 2 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-28 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-8: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 2 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-29 Material Characterization September 2023 WCAP-13039-NP Revision 2 Table 4-8: Fully Aged JIc, Jmax and Tmat for the SA351 CF8M Heats of Diablo Canyon Unit 2 a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-30 Material Characterization WCAP-13039-NP Table 4-9: RCL SA351 CF8M Heats with Lowest Fracture Toughness Properties(1) a,c,e

_l~I ----~

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-31 Material Characterization September 2023 WCAP-13039-NP Revision 2 Figure 4-1 J vs. a for SA351-CF8M Cast Stainless Steel at 600°F a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 5-1 Critical Location and Evaluation Criteria September 2023 WCAP-13039-NP Revision 2 5.0 CRITICAL LOCATION AND EVALUATION CRITERIA 5.1 CRITICAL LOCATIONS The leak-before-break (LBB) evaluation margins are to be demonstrated for the critical locations (governing locations). The governing or critical locations for the LBB evaluation are established based on the highest faulted stresses at the welds for each loop legs (HL, XL, and CL) and based on the fracture toughness properties of the base metal at the weld locations as established in Sections 3.0 and 4.0.

For LBB evaluation, the critical locations as identified for HL, XL, CL and material type (SA376 TP316 for piping, SA351 CF8M for elbows) are shown below:

Piping:

Location 1 - highest faulted stress for HL piping (SA376 TP316)

Location 11 - highest faulted stress for XL and CL piping (SA376 TP316)*

Elbows:

Location 4 - highest faulted stress for HL elbow (SA351 CF8M)

Location 10 - highest faulted stress for XL elbow (SA351 CF8M)

Location 14 - highest faulted stress for CL elbow (SA351 CF8M)

All five critical locations listed in order: 1, 4, 10, 11, 14 as shown above are evaluated in Section 6.0 using the limit load method. The three elbow locations, i.e.: 4, 10, and 14, are evaluated further using the J-integral method to obtain the applied thermal aged fracture toughness, Japp, and the applied tearing modulus, Tapp, for each leg: HL, XL, and CL in Section 7.0. In the J-integral evaluation for XL, the highest faulted stress at location 10 is evaluated against the XL lowest fracture toughness values (allowable values) from locations 7 and 8.

Table 5-1 summarizes the critical locations bounding both Diablo Canyon Units 1 and 2. The critical locations are shown in Figure 5-1.

Note:

• based on combined factors, i.e.: both the limiting tensile material properties and the corresponding faulted stress, location 11 of loop 2, Units 1 and 2, is determined to be the critical location, based on the lowest flaw size margin, as confirmed in Section 9.0.

The evaluation results are provided in Sections 6.0, 7.0 and 9.0.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 5-2 Critical Location and Evaluation Criteria September 2023 WCAP-13039-NP Revision 2 5.2 FRACTURE CRITERIA As will be discussed later, fracture mechanics analyses are made based on loads and postulated flaw sizes related to leakage. The stability criteria against which the calculated J (i.e., Japp) and tearing modulus (Tapp) are compared are:

(1)

If Japp < JIC, then an existing crack is stable (or a crack will not initiate);

(2)

If Japp > JIC; and Tapp < Tmat and Japp < Jmax, then the crack is stable.

Where:

Japp

=

Applied J JIC

=

J at Crack Initiation Tapp =

Applied Tearing Modulus Tmat =

Material Tearing Modulus Jmax =

Maximum J value of the material For critical locations, the limit load method discussed in Section 7.0 was also used.

For global failure mechanism, the stability analysis is performed using limit load method based on loads and postulated flaw sizes related to leakage, with the criteria as follows:

Margin of 10 on the Leak Rate Margin of 2.0 on Flaw Size Margin of 1.0 on Loads (using the absolute summation method for faulted load combination).

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 5-3 Critical Location and Evaluation Criteria September 2023 WCAP-13039-NP Revision 2 Table 5-1: Diablo Canyon Units 1 and 2 RCL Critical Locations for LBB Location Welding Process (a)

Material OD (in)

Thickness (in)

Operating Pressure (psia)

Operating Temperature

(°F)

Faulted Stress (ksi) 1 (HL)

SMAW SA376 TP316/

Alloy 82/182 33.99 2.395 2250 618 28.72 4 (HL)

SAW SA351 CF8M 37.19 2.990 2250 618 18.07 10 (XL)

SAW SA351 CF8M 37.19 2.990 2250 544 19.49 11 (CL)

SMAW SA376 TP316 32.26 2.275 2250 544 29.78(b) 14 (CL)

SMAW SA351 CF8M/

Alloy 82/182 33.06 2.675 2250 544 18.58 Notes:

a. Z-correction factors for SMAW and SAW weld process are used in the limit load calculation as discussed in Section 7.3. The weld process type (SAW) is conservatively used for locations 4 and 10.

b. For location 11, the faulted load and stress are obtained from loop 2, which was determined to be limiting location from the four loops as shown in Table 3-3.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 5-4 Critical Location and Evaluation Criteria September 2023 WCAP-13039-NP Revision 2 Figure 5-1:

Diablo Canyon Units 1 and 2 Primary Loop Critical Weld Locations HOT LEG Re.ac:tor Pres,s-vre Ves,s,el COLD UEG

~

F!teactor Coolant IPu!llp

\,,_ __ Steam Gen era or

,cROSS,OVER ILEG,

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-1 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 6.0 LEAK RATE PREDICTIONS

6.1 INTRODUCTION

The purpose of this section is to discuss the method which is used to predict the flow through postulated through-wall cracks and present the leak rate calculation results for through-wall circumferential cracks.

6.2 GENERAL CONSIDERATIONS The flow of hot pressurized water through an opening to a lower back pressure causes flashing which can result in choking. For long channels where the ratio of the channel length, L, to hydraulic diameter, DH, (L/DH) is greater than [

]a,c,e 6.3 CALCULATION METHOD The basic method used in the leak rate calculations is the method developed by [

]a,c,e The flow rate through a crack was calculated in the following manner. Figure 6-1 per [6-2] was used to estimate the critical pressure, Pc, for the primary loop enthalpy condition and an assumed flow. Once Pc was found for a given mass flow, the [ ]a,c,e was found from Figure 6-2 per [6-2]. For all cases considered, since [ ]a,c,e Therefore, this method will yield the two-phase pressure drop due to momentum effects as illustrated in Figure 6-3, where Po is the operating pressure. Now using the assumed flow rate, G, the frictional pressure drop can be calculated using:

Pf = [ ]a,c,e (6-1) where the friction factor f is determined using the [ ]a,c,e The crack relative roughness,,

was obtained from fatigue crack data on stainless steel samples. The relative roughness value used in these calculations was [ ]a,c,e The frictional pressure drop using Equation 6-1 is then calculated for the assumed flow rate and added to the [ ]a,c,e to obtain the total pressure drop from the primary system to the atmosphere.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-2 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 That is, for the primary loop:

Absolute Pressure of 14.7 = [ ]a,c,e (6-2) for a given assumed flow rate G. If the right-hand side of Equation 6-2 does not agree with the pressure difference between the primary loop and the atmosphere, then the procedure is repeated until Equation 6-2 is satisfied to within an acceptable tolerance which in turn leads to flow rate value for a given crack size.

6.4 LEAK RATE CALCULATIONS Leak rate calculations were made as a function of crack length at the governing locations previously identified in Section 5.1. The normal operating loads of Table 3-1 were applied in these calculations. The crack opening areas were estimated using the method of [6-3], and the leak rates were calculated using the two-phase flow formulation described above. The average material properties of Section 4.0 (see Table 4-

6) were used for these calculations.

The flaw sizes to yield a leak rate of 10 gpm for Diablo Canyon Units 1 and 2 were calculated at the governing locations with pipe material SA376 TP316, elbow material SA351 CF8M, and weld material Alloy 82/182 and are provided in Table 6-1, Table 6-2, and Table 6-3, respectively. The flaw sizes, so determined, are called leakage flaw sizes. Based on the PWSCC crack morphology, an increase factor of 1.69 between the PWSCC and fatigue crack morphologies [6-4] is applied to the leakage flaw sizes for the Alloy 82/182 DM welds as shown in Table 6-3.

The Diablo Canyon Units 1 and 2 RCS pressure boundary leak detection system meets the intent of Regulatory Guide 1.45 [6-5], and the plant leak detection capability is 1 gpm. Thus, to satisfy the margin of 10 on the leak rate, the flaw sizes (leakage flaw sizes) are determined which yield a leak rate of 10 gpm.

6.5 REFERENCES

6-1

[

]a,c,e 6-2 M. M, El-Wakil, Nuclear Heat Transport, International Textbook Company, New York, N.Y.,

1971.

6-3 Tada, H., The Effects of Shell Corrections on Stress Intensity Factors and the Crack Opening Area of Circumferential and a Longitudinal Through-Crack in a Pipe, Section II-1, NUREG/CR-3464, September 1983.

6-4 D. Rudland, R. Wolterman, G. Wilkowski, R. Tregoning, Impact of PWSCC and Current Leak Detection on Leak-Before-Break, proceedings of Conference on Vessel Head Penetration, Inspection, Cracking, and Repairs, Sponsored by USNRC, Marriot Washingtonian Center, Gaithersburg, MD, September 29 to October 2, 2003.

6-5 Regulator Guide 1.45, Revision 1, Guidance on Monitoring and Responding to Reactor Coolant System Leakage, May 2008.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-3 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 Table 6-1: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for SA376 TP316 Piping Material Table 6-2: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for SA351 CF8M Elbow Material a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-4 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 Table 6-3: Flaw Sizes Yielding a Leak Rate of 10 gpm at the Critical Locations for Alloy 82/182 Materials a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-5 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 Figure 6-1:

Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures a,c,e STAGNATION ENTHALPY (1o2 Btu/lb)

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-6 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 Figure 6-2:

[ ]a,c,e Pressure Ratio as a Function of L/D a,c,e LENGTH/DIAMETER RATIO (L/0)

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-7 Leak Rate Predictions September 2023 WCAP-13039-NP Revision 2 Figure 6-3:

Idealized Pressure Drop Profile Through a Postulated Crack a,c,e

[

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-1 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 7.0 FRACTURE MECHANICS EVALUATION 7.1 LOCAL FAILURE MECHANISM The local mechanism of failure is primarily dominated by the crack tip behavior in terms of crack-tip blunting, initiation, extension, and final crack instability. The local stability will be assumed if the crack does not initiate at all. It has been accepted that the initiation toughness measured in terms of JIC from a J-integral resistance curve is a material parameter defining the crack initiation. If, for a given load, the calculated J-integral value is shown to be less than the JIC of the material, then the crack will not initiate.

If the initiation criterion is not met, one can calculate the tearing modulus (see equation A-14a of [7-1]),

as defined by the following relation:

2 f

app E

x da dJ T

(7-1)

Where:

Tapp

=

applied tearing modulus E

=

modulus of elasticity f

=

0.5 (y + u) = flow stress a

=

crack length y, u

=

yield and ultimate strength of the material, respectively Stability is said to exist when ductile tearing does not occur if Tapp is less than Tmat, the experimentally determined tearing modulus. Since a constant Tmat is assumed, a further restriction is placed in Japp. Japp must be less than Jmax; where Jmax is the maximum value of J for which the experimental Tmat is greater than or equal to the Tapp used.

As discussed in Section 5.2 the local crack stability criteria is a two-step process:

(1)

If Japp < JIC, then an existing crack is stable (or a crack will not initiate);

(2)

If Japp > JIC; and Tapp < Tmat and Japp < Jmax, then the crack is stable.

7.2 GLOBAL FAILURE MECHANISM Determination of the conditions which lead to failure in stainless steel should be done with plastic fracture methodology because of the large amount of deformation accompanying fracture. One method for predicting the failure of ductile material is the plastic instability method, based on traditional plastic limit load concepts, but accounting for strain hardening and taking into account the presence of a flaw. The flawed pipe is predicted to fail when the remaining net section reaches a stress level at which a plastic hinge is formed. The stress level at which this occurs is termed as the flow stress. The flow stress is generally taken as the average of the yield and ultimate tensile strength of the material at the temperature of interest. This methodology has been shown to be applicable to ductile piping through a large number of experiments and will be used here to predict the critical flaw size in the primary coolant piping. The failure criterion has been obtained by requiring equilibrium of the section containing the flaw (Figure 7-1)

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-2 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 when loads are applied. The detailed development is provided in Appendix A for a through-wall circumferential flaw in a pipe with internal pressure, axial force, and imposed bending moments. The limit moment for such a pipe is given by:

Where:

[

The analytical model described above accurately accounts for the piping internal pressure as well as imposed axial force as they affect the limit moment. Good agreement was found between the analytical predictions and the experimental results [7-1]. For application of the limit load methodology, the material, including consideration of the configuration, must have a sufficient ductility and ductile tearing resistance to sustain the limit load.

7.3 RESULTS OF CRACK STABILITY EVALUATION As discussed in Sections 7.1 and 7.2, the LBB evaluation for Diablo Canyon Units 1 and 2 consists of evaluating two failure mechanisms. Stability analyses were performed at the critical locations established in Section 5.1. The elastic-plastic fracture mechanics (EPFM) J-integral analyses for through-wall circumferential cracks in a cylinder were performed using the procedure in the EPRI fracture mechanics handbook [7-2].

The more limiting lower-bound tensile properties for base metal for SA351-CF8M elbow material from Section 4.0 were applied (see Table 4-6). The fracture toughness properties established in Section 4.3, and at the selected critical locations in Section 5.0 with the highest faulted loads for SA351-CF8M material given in Table 3-2, were used for the EPFM calculations. Evaluations were performed at the load critical locations identified in Section 5.1. The three bounding J-integral evaluations were performed for the SA351 CF8M material at highest faulted stress HL, XL and CL, i.e. locations 4, 10, and 14, respectively, to obtain the applied J value, Japp, and the applied tearing modulus value, Tapp. For XL SA351 CF8M elbow material, the J-integral evaluation is conservatively performed using the XL highest faulted loads at location 10 and the XL lowest allowable fracture toughness values calculated at locations 7 and 8.

[

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-3 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 The results of the elastic-plastic fracture mechanics J-integral evaluations are given in Table 7-1. The associated leakage flaw sizes from Table 6-2 are also presented in Table 7-1.

A stability analysis based on limit load as described in Section 7.2 was performed for the critical locations as described in Section 5.1.

The limit load analyses consider material properties (yield and ultimate strength) of the base metal, and not the material properties of the weld metal. The base metal (piping and fittings) is considered to have more limiting material properties than the weld metal. Therefore, in the limit load evaluation the faulted loads (include both the axial loads and the moment loads) from Table 3-2 were increased by the Z-correction factors to account for reduction of the material toughness due to the welding process used during construction consistently with the methodology of SRP 3.6.3. It is confirmed that the limit load analysis in this report bounds both the weld metal and base metal since the more limiting material properties of the base metals were used in combination with additional penalty Z-correction factor for the stainless-steel weld.

The welding processes SAW and SMAW are conservatively used in the LBB analysis, as shown in Table 5-1. For LBB evaluations, SAW is more limiting for crack stability analysis compared to SMAW process.

Therefore, a conservative approach is taken assuming a SAW process for locations 4 and 10, and a SMAW process is used for locations 1, 11, and 14. The Z-correction factor for the SMAW and SAW welding processes per [7-3 and 7-5] is as follows:

Locations 1, 11 and 14:

Z = 1.15 [1.0 + 0.013 (OD-4)] for SMAW Locations 4 and 10:

Z = 1.30 [1.0 + 0.010 (OD-4)] for SAW Where OD is the outer diameter of the pipe in inches.

The limit load analysis for CASS materials in this report considered the reduced fracture toughness of the weld (Z-correction factor), and the J-applied analysis considered the reduced fracture toughness of the thermally aged CASS material per [7-6 and 7-7].

In the J-integral evaluation, Japp was calculated based on the faulted loads in Table 3-2 without any Z-correction factors that account for reduction in fracture toughness. This is because the J-integral evaluations already consider reduction in fracture toughness due to thermal aging of the CASS materials at normal operating temperature over extended operating periods. This reduction in fracture toughness is based on correlations in NUREG/CR-4513 Revisions 1 and 2 [7-6 and 7-7], which have determined lower bound fracture toughness as discussed in Section 4.3. Therefore, no additional Z-factors are necessary because the reduction in fracture toughness is already captured with the consideration of end-of-life (saturated) fracture toughness values from NUREG/CR-4513 Revisions 1 and 2 [7-6 and 7-7].

7.4 RPV NOZZLE ALLOY 82/182 WELDS Alloy 82/182 DM welds, which are susceptible to PWSCC are present at the RPVIN and RPVON for all loops of both Units 1 and 2. The LBB evaluation of the Alloy 82/182 DM welds was performed for the unmitigated RPVIN and RPVON weld locations. The methodology to evaluate these welds is based on

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-4 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 the limit load evaluation by considering global failure mechanism (Section 7-2), to address the Alloy 82/182 PWSCC concerns for 60- year plant life in the ILR project.

The typical material properties of the Alloy 82/182 DM weld material from Table 4-6 were considered in the limit load analysis at locations 1 (RPVON) and 14 (RPVIN) for all loops. The limit load analysis of the Alloy 82/182 welds considered a crack morphology factor (Z-multiplication factor).

[

]a,c,e Using the above formula, the Z-multiplication factor for the Alloy 82/182 material was calculated to be 1.21 at locations 1 and 14 for all loops. Note that in the limit load calculation for these locations, the applicable Z-correction factors for SMAW (Z = 1.60 for RPVON and Z = 1.58 for RPVIN) were conservatively used instead of the Z-multiplication factor of 1.21 for Alloy 82/182 material.

As discussed in Section 6.4, an increased factor of 1.69 to account for the PWSCC as applicable is applied to the leakage flaw size calculation.

Table 7-4 provides the summary results for Alloy 82/182 DM weld material including associated leakage flaw sizes from Table 6-3.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-5 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2

7.5 REFERENCES

7-1 Kanninen, M. F., et al., Mechanical Fracture Predictions for Sensitized Stainless Steel Piping with Circumferential Cracks, EPRI NP-192, September 1976.

7-2 Kumar, V., German, M. D. and Shih, C. P., An Engineering Approach for Elastic-Plastic Fracture Analysis, EPRI Report NP-1931, Program 1237-1, Electric Power Research Institute, July 1981.

7-3 Standard Review Plan; Public Comment Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal Register/Vol. 52, No. 167/Friday, August 28, 1987/Notices, pp. 32626-32633.

7-4 ASME Pressure Vessel and Piping Division Conference Paper PVP2008-61840, Technical Basis for Revision to Section XI Appendix C for Alloy 600/82/182/132 Flaw Evaluation in Both PWR and BWR Environments, July 28-31, Chicago IL, USA.

7-5 NUREG-0800, Revision 1, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures, March 2007.

7-6 O. K. Chopra, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, NUREG/CR-4513, Revision 1, U.S. Nuclear Regulatory Commission, Washington, DC, August 1994.

7-7 O. K. Chopra, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems, NUREG/CR-4513, Revision 2, U.S. Nuclear Regulatory Commission, Washington, DC, May 2016 including Errata, March 15, 2021.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-6 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 Table 7-1: Elastic-Plastic J-Integral Stability Results(a) at the SA351 CF8M Elbow Locations Bounding Location Leakage Flaw Size (in)

Calculated(b)

Allowable Fracture Toughness Value(c)

Japp (in-lb/in2)

Tapp JIc (in-lb/in2)

Jmax (in-lb/in2)

Tmat Table 7-2: Critical Flaw Sizes and Leakage Flaw Sizes for SA376 TP316 Piping Material a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-7 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 Table 7-3: Critical Flaw Sizes and Leakage Flaw Sizes for SA351 CF8M Elbow Material Table 7-4: Critical Flaw Sizes and Leakage Flaw Sizes for Alloy 82/182 Materials a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-8 Fracture Mechanics Evaluation September 2023 WCAP-13039-NP Revision 2 Figure 7-1

[ ]a,c,e Stress Distribution Neutral Axis

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-1 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 8.0 FATIGUE CRACK GROWTH ANALYSIS To determine the sensitivity of the primary coolant system to the presence of small cracks, a plant specific fatigue crack growth (FCG) analysis was carried out for the [ ]a,c,e region (see Location [ ]a,c,e of Figure 3-2). This region was selected because crack growth calculated here will be typical (i.e., the design transient thermal and pressure stresses will be representative) of that in the entire primary loop. The crack growth at the [ ]a,c,e will demonstrate that small surface flaws would not develop to through-wall flaws during the plant design life. Crack growths calculated at other locations can be expected to show less than 10% variation.

A [ ]a,c,e of a plant typical in geometry and operational characteristics to any Westinghouse PWR System. [

]a,c,e All normal, upset, and test conditions were considered. A summary of the applied transients is provided in Table 8-1. Circumferentially oriented surface flaws were postulated in the region, assuming the flaw was located in three different locations, as shown in Figure 8-1.

Specifically, these were:

Cross Section A: [ ]a,c,e Cross Section B: [ ]a,c,e Cross Section C: [ ]a,c,e Fatigue crack growth rate laws were used [

] a,c,e The law for stainless steel was derived from [8-1], with a very conservative correction for the R ratio, which is the ratio of minimum to maximum stress during a transient. For stainless steel, the fatigue crack growth formula is:

48

.4 eff 12 K

10 x

4.5 dn da

inches/cycle (8-1)

Where:

da/dn = crack growth rate Keff

= KImaxx(1.0 -R)0.5 R

= ratio of minimum KI and maximum KI

= KImin/KImax

[

]a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-2 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 (8-2)

Where:

[ ]a,c,e The calculated fatigue crack growth results for semi-elliptic surface flaws of circumferential orientation and various depths taken from [8-4] are summarized in Table 8-3. The results show that the crack growth is very small [ ].a,c,e To demonstrate that the small surface flaws will not result in a through-wall flaw over the design life of the plant. The aspect ratio for the postulated initial crack sizes are for a typical flaw shape of [ ]a,c,e (flaw length/flaw depth). Various initial flaw depths were considered in the FCG analysis to demonstrate that small, NDE-detectable flaw sizes on the order of [ ]a,c,e would be acceptable for the life of the plant (i.e., will not grow to the become complete through-wall). Even for the largest postulated flaw of 0.425, the results show that the flaw growth through the wall will not occur during the design life of the plant. Therefore, fatigue crack growth is not a concern for the Diablo Canyon Units 1 and 2 RCL piping.

Table 8-1 shows the transients and cycles used for the fatigue crack growth analysis in [8-4 and 8-8].

Table 8-2 shows the transients and cycles for the Diablo Canyon Units 1 and 2 for the 60 year plant life and applicable for the NSLR program [8-4], and also applicable for the ILR project.

A comparison was performed in [8-4] between the design transients considered in the FCG evaluation (Table 8-1) and the NSLR transients from [8-4] in Table 8-2 showed that there are some differences in cycles and additional three upset transients. The three additional upset transients (i.e., inadvertent auxiliary spray, design earthquake and RCS cold over-pressurization) and difference in cycles will not have a significant impact on the fatigue crack growth. The maximum final flaw based on the design transient and cycles from Table 8-1 was only 8.7% of an initial postulated flaw of 0.375 inch for the Inconel weld. This shows that significant margin is still available for flaw to grow. There will be no significant additional growth that will cause the flaw to grow completely through the wall thickness for the three additional upset transients and the increase cycles as shown in Table 8-2 for the 60 year plant life. Since the design transients and cycles used in [8-4] remain unchanged for the ILR project, the above justification and conclusion remain applicable for the ILR project.

The fatigue crack growth results documented in Table 8-3 show that there is a sufficient margin to ensure that small surface flaws will not become through-wall flaws. Additionally, the fatigue crack growth evaluation is considered a defense in depth review. FCG is no longer a requirement for the Leak-Before-Break (LBB) analysis [8-6 and 8-7], since the LBB analysis is based on the postulation of through-wall flaw, whereas the FCG analysis is performed based on the surface flaw. Furthermore, [8-5] has indicated that the Commission deleted the fatigue crack growth analysis in the proposed rule. This requirement was found to be unnecessary because it was bounded by the crack stability analysis. Nevertheless, the fatigue crack growth analysis is retained herein for information purposes and to demonstrate that small surface flaws do not result in through-wall flaws over the life of the plant.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-3 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2

8.1 REFERENCES

8-1 Bamford, W. H., Fatigue Crack Growth of Stainless Steel Piping in a Pressurized Water Reactor Environment, Trans. ASME Journal of Pressure Vessel Technology, Vol. 101, Feb. 1979.

8-2

[

]a,c,e 8-3

[

]a,c,e 8-4 WCAP-13039-P, Revision 1, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the Diablo Canyon Units 1 and 2 Nuclear Power Plants, April 2016 (Westinghouse Proprietary Class 2).

8-5 Nuclear Regulatory Commission, 10 CFR 50, Modification of General Design Criteria 4 Requirements for Protection Against Dynamic Effects of Postulated Pipe Ruptures, Final Rule, Federal Register/Vol. 52, No. 207/Tuesday, October 27, 1987/Rules and Regulations, pp. 41288-41295.

8-6 Standard Review Plan; Public Comment Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal Register/Vol. 52, No. 167/Friday, August 28, 1987/Notices, pp. 32626-32633.

8-7 NUREG-0800 Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

8-8 WCAP-13039, Technical Justification For Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis For the Diablo Canyon Units 1 and 2 Nuclear Power Plants, November 1991 (Westinghouse Proprietary Class 2).

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-4 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Table 8-1: Summary of Reactor Vessel Transients Typical Transient Identification Number of Cycles Normal Conditions Plant Heatup & Cooldown at 100F/hr (pressurizer cooldown 200F/hr) 200 Load Follow Cycles (Unit loading and unloading at 5% of full power/min) 18300 Step load increase and decrease 2000 Large step load decrease, with steam dump 200 Steady state fluctuations 106 Upset Conditions Loss of load, without immediate turbine or reactor trip 80 Loss of power (blackout with natural circulation in the Reactor Coolant System) 40 Loss of Flow (partial loss of flow, one pump only) 80 Reactor trip from full power 400 Test Conditions Turbine roll test 10 Hydrostatic test conditions Primary side 5

Primary side leak test 50 Cold Hydrostatic test 10

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-5 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Table 8-2: Summary of NSSS Design Transients for 60-Year Plant Life Transient Design Basis Frequency of Occurrences over 60 Year Plant Life Normal Condition Plant Heatup 250 Plant Cooldown 250 Unit Loading at 5%/Minute 18,300 Unit Unloading at 5%/Minute 18,300 Step Load Increase of 10% of Full Load 2500 Step Load Decrease of 10% of Full Load 2500 Large Step Load Decrease 250 Steady State Fluctuations Infinite Upset Condition Loss of Load w/o Immediate Turbine or Reactor Trip 100 Loss of Offsite Power 50 Partial Loss of Flow 100 Reactor Trip from Full Power 500 Inadvertent Auxiliary Spray 12 Design Earthquake 20 RCS Cold Overpressurization 10 Faulted Condition*

Main Reactor Coolant Pipe Break 1

Steam Pipe Break 1

Steam Generator Tube Rupture Not applicable Double Design Earthquake 1

Hosgri Earthquake 1

Test Condition Turbine Roll Test 10 Primary Side Hydrostatic Test 10 Secondary Side Hydrostatic Test Not applicable Primary Side Leak Test 60 Secondary Side Leak Test Not applicable Tube Leakage Tests Not applicable Note: *Faulted transients are not applicable for fatigue crack growth analysis.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-6 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Table 8-3:

Typical Fatigue Crack Growth at [ ]a,c,e Initial Flaw (in.)

Final Flaw (in.)

[ ]a,c,e

[ ]a,c,e

[ ]a,c,e 0.292 0.31097 0.30107 0.30698 0.300 0.31949 0.30953 0.31626 0.375 0.39940 0.38948 0.40763 0.425 0.45271 0.44350 0.47421 Note: Information in this table is reproduced from Reference 8-8 for 40-years.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-7 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Figure 8-1: Reactor Vessel Inlet Nozzle with Stress Cut Locations

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-8 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Figure 8-2:

Reference Fatigue Crack Growth Curves for [ ]a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-9 Fatigue Crack Growth Analysis September 2023 WCAP-13039-NP Revision 2 Figure 8-3:

Reference Fatigue Crack Growth Law for [ ]a,c,e in a Water Environment at 600°F a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 9-1 Assessment of Margins September 2023 WCAP-13039-NP Revision 2

9.0 ASSESSMENT

OF MARGINS The results of the leak rates of Section 6.4 and the corresponding stability and fracture toughness evaluations of Sections 7.1, 7.2, 7.3 and 7.4 are used in performing the assessment of margins. Margins for all reactor coolant loop weld critical locations are shown in Table 9-1 through Table 9-4. All of the LBB recommended margins are satisfied.

In summary, at all the critical locations relative to:

1. Flaw Size - Using faulted loads obtained by the absolute sum method, a margin of 2 or more exists between the critical flaw and the flaw having a leak rate of 10 gpm (the leakage flaw).

2. Leak Rate - A margin of 10 exists between the calculated leak rate from the leakage flaw and the plant leak detection capability of 1 gpm.

3. Loads - At the critical locations the leakage flaw was shown to be stable using the faulted loads obtained by the absolute sum method (i.e., a flaw twice the leakage flaw size is shown to be stable; hence the leakage flaw size is stable). A margin of 1 on loads using the absolute summation of faulted load combinations is satisfied.

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 9-2 Assessment of Margins September 2023 WCAP-13039-NP Revision 2 Table 9-1: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for SA376 TP316 Piping Material Table 9-2: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for SA351 CF8M Elbow Material a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 9-3 Assessment of Margins September 2023 WCAP-13039-NP Revision 2 Table 9-3: J-Integral Stability Results for SA351 CF8M Elbow Material Table 9-4: Leakage Flaw Sizes, Critical Flaw Sizes and Margins for Alloy 82/182 Weld Material Location Leakage Flaw Size (in)(a)

Critical Flaw Size (in)

Margin a,c,e a,c,e

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 10-1 Conclusions September 2023 WCAP-13039-NP Revision 2

10.0 CONCLUSION

S This report justifies the elimination of RCS primary loop pipe breaks from the structural design basis for the Diablo Canyon Units 1 and 2 for the 60-year Initial License Renewal (ILR) project as follows:

a. Stress corrosion cracking is precluded by use of fracture resistant materials in the piping system and controls on reactor coolant chemistry, temperature, pressure, and flow during normal operation. However, Alloy 82/182 welds are present at the RPVINs and RPVONs for all four loops of each unit. The Alloy 82/182 welds are susceptible to PWSCC (Primary Water Stress Corrosion Cracking).

b. The potential PWSCC effect has been conservatively evaluated at unmitigated locations by considering Alloy 82/182 material properties which includes appropriate PWSCC crack morphology parameter. The results demonstrate that the postulated crack will be stable and ample margin exists.

c. Evaluation of the RCS piping considering the thermal aging effects for the 60-year plant operating life period of the ILR project, and also the use of the most limiting fracture toughness properties ensures that each materials profile is appropriately bounded by the LBB results presented in this report. As stated in Section 7.0, for local and global failure mechanisms, all locations are evaluated using the cast austenitic stainless steel material properties (SA351-CF8M), which present a limiting condition due to the thermal aging effects.

d. Water hammer should not occur in the RCS piping because of system design, testing, and operational considerations.

e. The effects of low and high cycle fatigue on the integrity of the primary piping are negligible.

f. Adequate margin exists between the leak rate of small stable flaws and the capability of the Diablo Canyon Units 1 and 2 reactor coolant system pressure boundary Leakage Detection System.

g. Ample margin exists between the small stable flaw sizes of item (f) and larger stable flaws.

h. Ample margin exists in the material properties used to demonstrate end-of-service life (fully aged) stability of the critical flaws.

For the critical locations, postulated flaws will be stable because of the ample margins described in f, g, and h above.

Based on the discussion above, the Leak-Before-Break conditions and margins are satisfied for the Diablo Canyon Unit 1 and Unit 2 primary loop piping. All the recommended margins are satisfied. It is therefore concluded that dynamic effects of RCS primary loop pipe breaks need not be considered in the structural design basis for Diablo Canyon Units 1 and 2 for the 60-year plant operating life (ILR).

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 A-1 Limit Moment September 2023 WCAP-13039-NP Revision 2 APPENDIX A: LIMIT MOMENT JI a,c,o

• • • This record was final approved on 09/21/2023 13:23:31. (This statement was added by the PRIME system upon its validation)

WESTINGHOUSE NON-PROPRIETARY CLASS 3 A-2 Limit Moment September 2023 WCAP-13039-NP Revision 2 Figure A-1:

Pipe with a Through-Wall Crack in Bending a,c.e PG&E Letter DCL-25-001 Affidavit for Withholding Proprietary WCAP-13039-P, Revision 2

• • • This record was final approved on 09/25/2023 15:50:33. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-23-037 Page 1 of 3 Commonwealth of Pennsylvania:

County of Butler:

(1)

I, Zachary Harper, Senior Manager, Licensing Engineering, have been specifically delegated and authorized to apply for withholding and execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse).

(2)

I am requesting the proprietary portions of WCAP-13039-P Revision 2 be withheld from public disclosure under 10 CFR 2.390.

(3)

I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged, or as confidential commercial or financial information.

(4)

Pursuant to 10 CFR 2.390, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i)

The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse and is not customarily disclosed to the public.

(ii)

The information sought to be withheld is being transmitted to the Commission in confidence and, to Westinghouses knowledge, is not available in public sources.

(iii)

Westinghouse notes that a showing of substantial harm is no longer an applicable criterion for analyzing whether a document should be withheld from public disclosure. Nevertheless, public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar technical evaluation justifications and licensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

• • • This record was final approved on 09/25/2023 15:50:33. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-23-037 Page 2 of 3 (5)

Westinghouse has policies in place to identify proprietary information. Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

(b)

It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage (e.g., by optimization or improved marketability).

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d)

It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

(f)

It contains patentable ideas, for which patent protection may be desirable.

(6)

The attached documents are bracketed and marked to indicate the bases for withholding. The justification for withholding is indicated in both versions by means of lower-case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower-case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (5)(a) through (f) of this Affidavit.

• • • This record was final approved on 09/25/2023 15:50:33. (This statement was added by the PRIME system upon its validation)

Westinghouse Non-Proprietary Class 3 AFFIDAVIT CAW-23-037 Page 3 of 3 I declare that the averments of fact set forth in this Affidavit are true and correct to the best of my knowledge, information, and belief. I declare under penalty of perjury that the foregoing is true and correct.

Executed on: 9/25/2023 Signed electronically by Zachary Harper