Text

Issuance of Amendment No. 228 Re; Revise Technical Specifications to Address Generic Safety Isusue-191 and Respond to Generic Letter 2004-02 Using Risk-Informed Approach
	ML22220A132
Person / Time
Site:	Callaway
Issue date:	10/21/2022
From:	Mahesh Chawla; Plant Licensing Branch IV
To:	Diya F; Ameren Missouri
	Lingam S
References
	EPID L-2021-LLA-0059
	Download: ML22220A132 (104)
	v • d • e

October 21, 2022 Mr. Fadi Diya Senior Vice President and Chief Nuclear Officer Ameren Missouri Callaway Energy Center 8315 County Road 459 Steedman, MO 65077

SUBJECT:

CALLAWAY PLANT, UNIT NO. 1 - ISSUANCE OF AMENDMENT NO. 228 RE:

REVISE TECHNICAL SPECIFICATIONS TO ADDRESS GENERIC SAFETY ISSUE-191 AND RESPOND TO GENERIC LETTER 2004-02 USING A RISK-INFORMED APPROACH (EPID L-2021-LLA-0059)

Dear Mr. Diya:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 228 to Renewed Facility Operating License No. NPF-30 for Callaway Plant, Unit No. 1 (Callaway). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated March 31, 2021, as supplemented by letters dated May 27, 2021, July 22, 2021, August 23, 2021, October 7, 2021, January 27, 2022, March 8, 2022, May 26, 2022, and September 8, 2022.

The amendment revises the TSs to address the concerns of Generic Safety Issue (GSI)-191, Assessment of Debris Accumulation on PWR [Pressurized Water Reactor] Sump Performance, and respond to Generic Letter (GL) 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors, which is an approved change to the Standard TSs into the Callaway TSs. The proposed change requested to modify the Callaway licensing basis analyses to show compliance with Title 10 of the Code of Federal Regulations (10 CFR) Section 50.46, Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors, considering the effects of debris using both deterministic and risk-informed methodologies.

The amendment revises TS Table of Contents, TS 3.5.2, ECCS [Emergency Core Cooling System] - Operating, TS 3.5.3, ECCS - Shutdown, TS 5.5.15, Safety Function Determination Program (SFDP), adds a new TS 3.6.8, Containment Sump, and adds an Action to address the condition of the containment sump made inoperable due to containment accident generated and transported debris exceeding the analyzed limits. The Action provides time to correct or evaluate the condition in lieu of an immediate plant shutdown.

In addition to the license amendment, Union Electric Company, doing business as (dba)

Ameren Missouri (the licensee) requested exemptions pursuant to 10 CFR 50.12, Specific exemptions, from certain requirements of 10 CFR 50.46, Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors, and 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, General Design Criterion (GDC) 35,

Emergency core cooling; GDC 38, Containment heat removal; and GDC 41, Containment atmosphere cleanup, to allow use of a risk-informed methodology instead of the traditional deterministic methodology to resolve the concerns associated with GSI-191 and respond to GL 2004-02 for Callaway. The approval of the exemptions is documented separately.

A copy of the related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA Siva Lingam for/

Mahesh L. Chawla, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-483

Enclosures:

1. Amendment No. 228 to NPF-30

2. Safety Evaluation cc: Listserv

UNION ELECTRIC COMPANY CALLAWAY PLANT, UNIT NO. 1 DOCKET NO. 50-483 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 228 License No. NPF-30

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Union Electric Company (UE, the licensee),

dated March 31, 2021, as supplemented by letters dated May 27, 2021, July 22, 2021, August 23, 2021, October 7, 2021, January 27, 2022, March 8, 2022, May 26, 2022, and September 8, 2022, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commissions regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-30 is hereby amended to read as follows:

(2)

Technical Specifications and Environmental Protection Plan*

The Technical Specifications contained in Appendix A, as revised through Amendment No. 228 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This amendment is effective as of its date of issuance and shall be implemented within 120 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jennifer L. Dixon-Herrity, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License No. NPF-30 and the Technical Specifications Date of Issuance: October 21, 2022 Jennifer L.

Dixon-Herrity Digitally signed by Jennifer L. Dixon-Herrity Date: 2022.10.21 16:14:24 -04'00'

ATTACHMENT TO LICENSE AMENDMENT NO. 228 CALLAWAY PLANT, UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. NPF-30 DOCKET NO. 50-483 Replace the following pages of Renewed Facility Operating License No. NPF-30 and the Appendix A, Technical Specifications, with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Renewed Facility Operating License REMOVE INSERT Technical Specifications REMOVE INSERT 3

3 3.5-6 3.5-6 3.5-8 3.5-8 3.6-24 3.6-25 3.6-26 5.0-19 5.0-19

Renewed License No. NPF-30 Amendment No. 228 (3)

UE, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4)

UE, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source of special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5)

UE, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C.

This renewed license shall be deemed to contain and is subject to the conditions specified in the Commissions regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level UE is authorized to operate the facility at reactor core power levels not in excess of 3565 megawatts thermal (100% power) in accordance with the conditions specified herein.

(2)

Technical Specifications and Environmental Protection Plan*

The Technical Specifications contained in Appendix A, as revised through Amendment No. 228 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3)

Environmental Qualification (Section 3.11, SSER #3)**

Deleted per Amendment No. 169.

Amendments 133, 134, & 135 were effective as of April 30, 2000 however these amendments were implemented on April 1, 2000.

The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued)

CALLAWAY PLANT 3

Amendment 228 3.6.4 Containment Pressure.....................................................................3.6-16 3.6.5 Containment Air Temperature.........................................................3.6-17 3.6.6 Containment Spray and Cooling Systems......................................3.6-18 3.6.7 Recirculation Fluid pH Control (RFPC) System...............................3.6-22 3.6.8 Containment Sumps........................................................................3.6-24 3.7 PLANT SYSTEMS.................................................................................3.7-1 3.7.1 Main Steam Safety Valves (MSSVs)...............................................3.7-1 3.7.2 Main Steam Isolation Valves (MSIVs), Main Steam Isolation Valve Bypass Valves (MSIVBVs), and Main Steam Low Point Drain Isolation Valves (MSLPDIVs).................................3.7-5 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Regulating Valves (MFRVs), and Main Feedwater Regulating Valve Bypass Valves (MFRVBVs)..............................................3.7-9 3.7.4 Atmospheric Steam Dump Valves (ASDs)......................................3.7-12 3.7.5 Auxiliary Feedwater (AFW) System.................................................3.7-15 3.7.6 Condensate Storage Tank (CST)....................................................3.7-19 3.7.7 Component Cooling Water (CCW) System.....................................3.7-21 3.7.8 Essential Service Water System (ESW)..........................................3.7-23 3.7.9 Ultimate Heat Sink (UHS)................................................................3.7-26 3.7.10 Control Room Emergency Ventilation System (CREVS).................3.7-28 3.7.11 Control Room Air Conditioning System (CRACS)...........................3.7-32 3.7.12 Not Used..........................................................................................3.7-35 3.7.13 Emergency Exhaust System (EES).................................................3.7-36 3.7.14 Not Used..........................................................................................3.7-39 3.7.15 Fuel Storage Pool Water Level........................................................3.7-40 3.7.16 Fuel Storage Pool Boron Concentration..........................................3.7-41 3.7.17 Spent Fuel Assembly Storage.........................................................3.7-43 3.7.18 Secondary Specific Activity..............................................................3.7-45 3.7.19 Secondary System Isolation Valves (SSIVs)...................................3.7-46 3.7.20 Class 1E Electrical Equipment Air Conditioning (A/C) System........3.7-48 3.8 ELECTRICAL POWER SYSTEMS........................................................3.8-1 3.8.1 AC Sources - Operating...................................................................3.8-1 3.8.2 AC Sources - Shutdown..................................................................3.8-18 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air.......................................3.8-22 3.8.4 DC Sources - Operating..................................................................3.8-25 3.8.5 DC Sources - Shutdown..................................................................3.8-28 3.8.6 Battery Cell Parameters...................................................................3.8-30 3.8.7 Inverters - Operating........................................................................3.8-34 3.8.8 Inverters - Shutdown........................................................................3.8-36 3.8.9 Distribution Systems - Operating.....................................................3.8-38

ECCS - Operating 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

CALLAWAY PLANT 3.5-6 Amendment No. 228 SR 3.5.2.4 Verify each ECCS pump's developed head at the test flow point is greater than or equal to the required developed head.

In accordance with the INSERVICE TESTING PROGRAM SR 3.5.2.5 Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.6 Verify each ECCS pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.7 Verify, for each ECCS throttle valve listed below, each mechanical position stop is in the correct position.

In accordance with the Surveillance Valve Number EMV0095 EMV0107 EMV0089 EMV0096 EMV0108 EMV0090 EMV0097 EMV0109 EMV0091 EMV0098 EMV0110 EMV0092 Frequency Control Program SR 3.5.2.8 Not used.

SURVEILLANCE FREQUENCY

ECCS - Shutdown 3.5.3 CALLAWAY PLANT 3.5-8 Amendment No. 228 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 The following SRs are applicable for all equipment required to be OPERABLE:

SR 3.5.2.1 SR 3.5.2.7 SR 3.5.2.3 SR 3.5.2.4 In accordance with applicable SRs

CALLAWAY PLANT 3.6-24 Amendment No. 228 Containment Sumps 3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 Containment Sumps LCO 3.6.8 Two containment sumps shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more containment sumps inoperable due to containment accident generated and transported debris exceeding the analyzed limits.

A.1 Initiate actions to reduce containment accident generated and transported debris.

AND A.2 Perform SR 3.4.13.1.

AND A.3 Restore the containment sump(s) to OPERABLE status.

Immediately Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 90 days (continued)

Containment Sumps 3.6.8 ACTIONS (continued)

CALLAWAY PLANT 3.6-25 Amendment No. 228 B.

One or more containment sumps inoperable for reasons other than Condition A.

B.1

NOTES ---------

1.

Enter applicable Conditions and Required Actions of LCO 3.5.2, "ECCS -

Operating," and LCO 3.5.3, "ECCS -

Shutdown," for emergency core cooling trains made inoperable by the containment sump(s).

2.

Enter applicable Conditions and Required Actions of LCO 3.6.6, "Containment Spray and Cooling Systems," for containment spray trains made inoperable by the containment sump(s).

Restore the containment sump(s) to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months C.

Required Action and associated Completion Time not met.

C.1 Be in MODE 3.

AND C.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours CONDITION REQUIRED ACTION COMPLETION TIME

Containment Sumps 3.6.8 CALLAWAY PLANT 3.6-26 Amendment No. 228 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.8.1 Verify, by visual inspection, the containment sumps do not show structural damage, abnormal corrosion, or debris blockage.

In accordance with the Surveillance Frequency Control Program

Programs and Manuals 5.5 5.5 Programs and Manuals CALLAWAY PLANT 5.0-19 Amendment No. 228 5.5.15 Safety Function Determination Program (SFDP) (continued) c.

Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and d.

Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a.

A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or b.

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

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

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.16 Containment Leakage Rate Testing Program a.

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

1.

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

(continued)

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 228 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-30 UNION ELECTRIC COMPANY CALLAWAY PLANT, UNIT NO. 1 DOCKET NO. 50-483

1.0 INTRODUCTION

By letter dated March 31, 2021 (Reference 1), as supplemented by letters dated May 27, 2021 (Reference 2), July 22, 2021 (Reference 3), August 23, 2021 (Reference 4), October 7, 2021 (Reference 5), January 27, 2022 (Reference 6), March 8, 2022 (Reference 7), May 26, 2022 (Reference 8), and September 8, 2022 (Reference 9), Union Electric Company, doing business as (dba) Ameren Missouri (the licensee), submitted a license amendment request (LAR),

exemption requests, and an updated response to Generic Letter (GL) 2004-02 Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized Water Reactors (Reference 10) for Callaway Plant, Unit No. 1 (Callaway). The amendment would modify the Callaway Technical Specifications (TSs). Specifically, the amendment would allow the use of a risk-informed approach to address safety issues discussed in U.S. Nuclear Regulatory Commission (NRC or the Commission) Generic Safety Issue (GSI)-191, Assessment of Debris Accumulation on PWR [Pressurized Water Reactor] Sump Performance. The letter dated March 31, 2021, and supplements and revisions constitute the licensees final response to GL 2004-02. This safety evaluation (SE) reviews the requested amendment and the licensees response to GL 2004-02.

The licensee also requests approval of conforming changes to the Callaway Final Safety Analysis Report (FSAR) (Reference 11), The licensee requests NRC approval of the change in methodology as described in section 6.3A.2 of appendix 6.3A of FSAR update as required by Title 10 of the Code of Federal Regulations (10 CFR) Section 50.59(c)(2)(viii).

In addition to the license amendment, the licensee requested exemptions pursuant to 10 CFR 50.12, Specific exemptions, from certain requirements of 10 CFR 50.46, Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors, and 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, General Design Criterion (GDC) 35, Emergency core cooling; GDC 38, Containment heat removal; and GDC 41, Containment atmosphere cleanup, to allow use of a risk-informed methodology instead of the traditional deterministic methodology to resolve the concerns associated with GSI-191 and respond to GL 2004-02 for Callaway. The approval of the exemptions is documented separately (Reference 12).

The supplemental letters dated January 27, 2022, March 8, 2022, May 26, 2022, and September 8, 2022, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on December 28, 2021 (86 FR 73820).

1.1 Background

1.1.1 Challenges to Function of Safety Systems from Debris in Containment The function of the emergency core cooling system (ECCS) is to cool the reactor core and provide shutdown capability following a loss-of-coolant accident (LOCA). The primary functions of the containment spray system (CSS) are to reduce containment pressure and reduce the concentration and quantity of fission products in the containment building after a LOCA.

Nuclear plants are designed and licensed with the expectation that they are able to remove reactor decay heat following a LOCA to prevent core damage. Long-term core cooling (LTCC) following a LOCA is also a basic safety function for nuclear reactors. The recirculation sump located in the lower areas of the reactor containment structure provides a water source to the ECCS for extended cooling of the core in a PWR once the initial water source has been depleted and the systems are switched over to recirculation mode.

If a LOCA occurs, piping thermal insulation and other materials located in containment may be dislodged by the two-phase (steam and liquid) coolant jet emanating from the broken reactor coolant system (RCS) pipe. This debris may transport by the flow of water and steam from the break or from the CSS to the pool of water that collects in the containment recirculation sump.

Once transported to the sump pool, the debris could be drawn toward the ECCS sump strainers, which are designed to prevent debris from entering the CSS and the ECCS. If this debris clogs the strainers, the ECCS could fail, resulting in core damage, or the CSS pumps could fail, resulting in containment pressure or radiation dose increasing beyond deterministic limits. It is also possible that some debris could bypass the sump strainers and get lodged in the reactor core. This could result in reduced core cooling and potential core damage.

1.1.2 Generic Safety Issue-191 In 1996, the NRC identified an issue associated with the effects of debris accumulation on PWR sump performance during design-basis accidents (DBAs).

Findings from research and industry operating experience raised questions concerning the adequacy of PWR sump designs. Research findings demonstrated that the amount of debris generated and transported by a high-energy LOCA could be greater than originally anticipated.

The debris from a LOCA could also be finer, and thus, more easily transportable, and could be comprised of debris consisting of fibrous material combined with particulate material that could result in a substantially greater flow restriction than an equivalent amount of either type of debris alone. These research findings prompted the NRC to open GSI-191.

The two distinct but related safety concerns are: (1) potential clogging of the sump strainers that results in ECCS or CSS pump failure, and (2) potential clogging of flow channels within the reactor vessel because of debris bypassing the sump strainers, often referred to as in-vessel

effects. Clogging at either the strainers or in-vessel channels can result in loss of the LTCC safety function.

1.1.3 GL 2004-02 As part of the actions to resolve GSI-191, in September 2004, the NRC issued GL 2004-02 to holders of operating licenses for PWRs. In GL 2004-02, the NRC staff requested that licensees perform an evaluation of their ECCS and CSS recirculation functions, considering the potential for debris-laden coolant to be circulated by the ECCS and the CSS after a LOCA or high-energy line break (HELB) inside containment, and, if appropriate, take additional actions to ensure system function. GL 2004-02 required, per Title 10 of the Code of Federal Regulations (10 CFR) Section 50.54(f), that licensees provide the NRC a written response describing the results of their evaluation and any modifications made, or planned, to ensure ECCS and CSS system function during recirculation following a design-basis event, or any alternate action proposed, and the basis for its acceptability.

The staff requirements memorandum (SRM) associated with SECY-10-113, Closure Options for Generic Safety Issue 191, Assessment of Debris Accumulation on Pressurized Water Reactor Sump Performance, dated December 23, 2010 (Reference 13), directed the NRC staff to consider a risk-informed approach for resolution of GSI-191. In 2012, the NRC staff developed three options to resolve GSI-191. These options were documented and proposed to the Commission in SECY-12-0093, Closure Options for Generic Safety Issue-191, Assessment of Debris Accumulation on Pressurized Water Reactor Sump Performance, dated June 9, 2012 (Reference 14). The options are summarized as follows:

Option 1 allows licensees to demonstrate compliance with 10 CFR 50.46, Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors, through approved models and test methods.

Option 2 requires implementation of additional mitigating measures and allows additional time for licensees to resolve issues through further industry testing or use of a risk-informed approach.

Option 3 involves separating the regulatory treatment of the sump strainer and in-vessel effects so that strainer issues can be treated deterministically and in-vessel issues can be risk-informed.

These options allowed industry alternative approaches for resolving GSI-191. The Commission issued SRM-SECY-12-0093 on December 14, 2012 (Reference 15), approving all three options for closure of GSI-191.

By letter dated September 24, 2019 (Reference 16), the licensee stated it would pursue a full risk-informed resolution path (i.e., Option 2 of SECY-12-0093), to resolve GL 2004-02 and GSI-191 for Callaway utilizing the methodology developed by the South Texas Project (STP) pilot assessment (Reference 17).

1.2 Licensees Approach The licensees risk informed approach to evaluate the effects of debris on the sump strainer and pumps of the ECCS is documented in enclosure 3 to the supplemental letter dated October 7, 2021. Effects referred to as downstream effects (including in vessel effects) were addressed

using methods in topical report (TR) WCAP-17788-NP, Comprehensive Analysis and Test Program for GSI-191 Closure (PA-SEE-1090), Volume 1, Revision 0 (Reference 18) and summarized in enclosure 3 to the supplemental letter dated October 7, 2021. This SE documents the NRC staffs evaluation of the licensees risk informed approach to resolve GL 2004-02 at Callaway.

The licensees LAR enclosed with the letter dated March 31, 2021, was organized according to draft Regulatory Guide (RG) 1.229, Risk Informed Approach for Addressing the Effects of Debris on Post Accident Long Term Cooling (Reference 19), addressing key principles of risk informed integrated decision-making such as defense in depth (DID) and safety margins. The licensees overall evaluation of risk attributable to debris for Callaway is based on physical models that have been used in the past in similar GSI-191 risk informed assessments and generally accepted by the NRC for GSI-191 resolution. The licensee provided a summary of the plant specific conditions and models related to GSI-191, as well as a description of the risk quantification using a method similar to the one used in the STP pilot GSI-191 evaluation, relying on the Containment Accident Stochastic Analysis GSI Resolution and Evaluation (CASA Grande) software to compute debris amounts as a function of postulated break sizes and break orientations at multiple potential break locations, and loss of coolant break frequencies from NUREG 1829, Estimating Loss of Coolant Accident (LOCA) Frequencies Through the Elicitation Process, Volumes 1 and 2, dated April 2008 (Reference 20). The licensee considered limited outputs of the probabilistic risk assessment (PRA) model, such as the core damage frequency (CDF) and large early release frequency (LERF) in its evaluation.

The licensee determined that most break scenarios were mitigated successfully when evaluated using deterministic methods. Any scenario that was not predicted to be mitigated was assumed to result in a core damage event. These failures, accounting for their frequency, were assumed to contribute to the change in plant risk and were compared against RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant Specific Changes to the Licensing Basis, acceptance guidelines (Reference 21). The approach of deterministically evaluating some breaks and considering other breaks to contribute to the plant risk was referred by the licensee as RoverD (for risk over deterministic), as in the STP pilot evaluation. The licensee concluded the change in risk is very small.

1.3 Method of NRC Staff Review The purpose of the NRC staffs review is to evaluate the licensees assessment of the impact of debris on ECCS and CSS functions following postulated LOCAs at Callaway. The NRC staff evaluated the licensees LAR and the supplemental letters (References 2 through 8). The NRC staff also conducted a regulatory audit and performed confirmatory calculations in areas deemed appropriate by the NRC staff (Reference 22). The licensee revised and updated its request in the supplemental letters dated October 7, 2021, January 27, 2022, and March 8, 2022, partially to address questions raised at the audit and partially to address other issues identified by the licensee.

In areas where the licensee used NRC approved or widely accepted methods in performing analyses related to the proposed methodology, the NRC staff reviewed relevant material to ensure that the licensee used the methods consistent with the limitations and conditions placed on the methods. Details of the NRC staff review, audit, and confirmatory calculations are provided in section 3.0 of this SE.

2.0 REGULATORY EVALUATION

2.1 Applicable Regulatory Requirements The NRC staff assesses proposed remedial actions in accordance with the general standards for license amendments. Under 10 CFR 50.92(a), determinations on whether to grant an applied-for license amendment are to be guided by the considerations that govern the issuance of initial licenses or construction permits to the extent applicable and appropriate. Both the common standards for licenses and construction permits in 10 CFR 50.40(a), and those specifically for issuance of operating licenses in 10 CFR 50.57(a)(3), provide that there must be reasonable assurance that the activities at issue will not endanger the health and safety of the public.

The NRC staffs acceptance criteria for ECCS performance following a LOCA are based on 10 CFR 50.46. LOCAs are postulated accidents that would result in the loss of reactor coolant from piping breaks in the reactor coolant pressure boundary at a rate exceeding the capability of the normal reactor coolant makeup system to replenish it. Loss of significant quantities of reactor coolant would prevent heat removal from the reactor core unless the water is replenished. The reactor protection and ECCS systems are provided to mitigate these accidents. The NRC staffs review covered the acceptance criteria based on 10 CFR 50.46, insofar as it establishes standards for the calculation of ECCS performance and acceptance criteria, considering the effects of debris as specified in GL 2004-02.

The NRC requirements for TSs are in 10 CFR 50.36, which state that TSs are to include items in, among other things, the following five specific categories related to station operation:

(1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls.

2.2 Applicable Regulatory Guides, Review Plans, and Guidance Documents Volume 1 of Nuclear Energy Institute (NEI) 04-07, Pressurized Water Reactor Sump Performance Evaluation Methodology, dated December 2004, and Volume 2, Safety Evaluation by the Office of Nuclear Reactor Regulation Related to NRC Generic Letter 2004-02, dated December 6, 2004 describe a method acceptable to the NRC staff, with limitations and conditions for performing the evaluations requested by GL 2004-02. Taken together NEI 04-07 and the associated NRC staff SE are often referred to as the guidance report/safety evaluation (GR/SE).

The industry developed the following additional TRs to aid licensees in responding to GL 2004-02.

TR WCAP-16530-NP-A, Evaluation of Post-Accident Chemical Effects in Containment Sump Fluids to Support GSI-191, dated March 2008 (Reference 25) and the associated NRC SE (Reference 26).

TR WCAP-16406-P-A, Evaluation of Downstream Sump Debris Effects in Support of GSI-191, Revision 1, dated March 2008 (Reference 27) and the associated NRC SE (Reference 28).

TR WCAP-17788-P Volume 1 (Reference 18) and Volume 5, Comprehensive Analysis and Test Program for GSI-191 Closure (PA-SEE-1090) - Autoclave Chemical Effects Testing for GSI-191 Long-Term Cooling (Reference 29).

The reports listed above, subject to the limitations and conditions contained in the NRC SEs for those TRs, describe methods acceptable to the NRC staff for performing the evaluations and analyses within the scope stated in those documents (References 26 and 28).

To more clearly communicate the NRC staffs expectations for the level of technical detail in the licensees submittals, the NRC staff issued documents entitled Revised Content Guide for Generic Letter 2004-02 Supplemental Responses, dated November 21, 2007 (Reference 23),

and Revised Guidance for Review of Final Licensee Responses to Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design-Basis Accidents at Pressurized Water Reactors, dated March 28, 2008 (Reference 24). The content guide describes the information necessary to be submitted to the NRC for review.

RG 1.82, Revision 4, Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident, dated March 2012 (Reference 30), provides guidance for an evaluation of the effects of debris on ECCS strainers and, more generally, guidance for the evaluation of water sources for long-term recirculation following a LOCA. Although the licensee used Revision 4, the NRC staff note that Revision 5 was published in August 2022 (Reference 31). However, Revision 4 continues to be one way to meet the NRCs regulations.

Accordingly, the NRC staff used Revision 4 during its review.

RG 1.174, Revision 3 provides guidance on the use of PRA findings and risk insights in support of licensee requests for changes to a plants licensing basis. This RG provides risk acceptance guidelines for evaluating the results of such evaluations. RG 1.174 also provides the five key principles of risk-informed integrated decision-making.

RG 1.200 An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities, Revision 2 (Reference 32), endorses, with clarifications, the American Society of Mechanical Engineers (ASME) and the American Nuclear Society (ANS) PRA Standard ASME/ANS RA-Sa-2009, Addenda to ASME/ANS RA-S 2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications (Reference 33). Revision 3 of RG 1200 was issued in December 2020. Revision 3 did not supersede Revision 2. The licensee chose to use Revision 2 of the RG as guidance for its submittal. The NRC staff notes that Revision 2 contains less flexibility than Revision 3 so that its use does not adversely affect the staffs conclusions in this SE. The ASME/ANS RA-Sa-2009 PRA Standard addresses PRAs for internal events and other hazards. RG 1.200 describes one acceptable approach for determining whether the PRA, in total, or the parts that are used to support an application, is acceptable for use in regulatory decision-making for light-water reactors (LWRs).

General guidance for evaluating the technical basis for proposed risk informed changes is provided in NUREG-0800, Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition, Section 19.2, Review of Risk Information Used to Support Permanent Plant Specific Changes to the Licensing Basis: General Guidance, dated June 2007 (Reference 34).

2.3 Proposed Changes In the LAR dated March 31, 2021, as supplemented, the licensee proposed changes to the Callaway TSs. The changes incorporate Technical Specifications Task Force (TSTF) Traveler TSTF-567, Revision 1, Add Containment Sump TS to Address GSI-191 Issues, dated August 2, 2017 (Reference 35). The NRC issued a final SE approving TSTF-567, Revision 1, on July 3, 2018 (Reference 36). The amendment would revise TS 3.5.2, ECCS - Operating, and TS 3.5.3, ECCS - Shutdown. The proposed changes would also add a new TS 3.6.8, Containment Sumps, to section 3.6, Containment Systems. Although the proposed changes are based on TSTF 567, the NRC staff identified minor variations from the TS changes described in TSTF 567. These variations are described in section 2.3.5 of this SE and evaluated in section 3.6.5.

2.3.1 Proposed Changes to TS 3.5.2 TS 3.5.2 currently contains SR 3.5.2.8, which states the following at a Frequency in accordance with the Surveillance Frequency Control Program (SFCP):

Verify, by visual inspection, each ECCS train containment sump suction inlet is not restricted by debris and suction inlet strainers show no evidence of structural distress or abnormal corrosion.

The licensee proposed to modify and move SR 3.5.2.8 from TS 3.5.2 and include it in the new containment sump TS.

2.3.2 Proposed Changes to TS 3.5.3 TS 3.5.3 currently contains SR 3.5.3.1, which refers to applicable SRs under TS 3.5.2. One of those referenced SRs is SR 3.5.2.8, as described in section 2.3.1 of this SE.

Because the licensee proposed to modify and move SR 3.5.2.8 from TS 3.5.2 and include it in the new containment sump TS, the licensee also proposed to delete the reference to SR 3.5.2.8 in SR 3.5.3.1.

2.3.3 Proposed Changes to TS 5.5.15 The licensee proposed to add the following sentence at the end of TS 5.5.15:

When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

2.3.4 Proposed Addition of a New Containment Sumps TS The licensee proposed to add new TS 3.6.8 requiring two containment sumps to be operable during Modes 1, 2, 3, and 4. Condition A specifies that if the containment sump is inoperable due to containment accident generated and transported debris exceeding the analyzed limits, then the licensee is required to: (1) initiate action to mitigate the containment accident generated and transported debris immediately, (2) perform SR 3.4.13.1 once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and (3) restore the containment sump to OPERABLE status within 90 days (Required Actions A.1,

A.2, and A.3, respectively). SR 3.4.13.1 requires verification that the RCS operational leakage is within limits by performance of an RCS water inventory balance.

Condition B specifies that if the containment sumps are inoperable for reasons other than Condition A, then the licensee is required to restore the containment sumps to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Action B.1). Required Action B.1 is modified by two notes, which direct entering the applicable conditions and required actions of LCOs 3.5.2 and 3.5.3 for ECCS trains made inoperable by the containment sump(s) and entering the applicable conditions and required actions of LCO 3.6.6, Containment Spray and Cooling Systems, for CSS and cooling system trains made inoperable by the containment sump(s).

Condition C specifies that if required actions and associated completion times under Condition A and B are not met, then the licensee is required to be in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Mode 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Actions C.1 and C.2, respectively).

The licensee proposed to modify and move SR 3.5.2.8 currently located in TS 3.5.2. The new SR 3.6.8.1 requires the licensee to [v]erify, by visual inspection, the containment sumps do not show structural damage, abnormal corrosion, or debris blockage [i]n accordance with the Surveillance Frequency Control Program.

The containment sump design for Callaway includes two containment sumps. The system includes two strainers: one for each train of ECCS and CSS. For Condition A, the sumps are considered part of a single support system because containment accident generated and transported debris issues that would render one sump inoperable would render all of the sumps inoperable.

The licensee also proposed a conforming change to the TS Table of Contents to reflect the addition of the new containment sump TS.

2.3.5 Proposed Variations from TSTF-567, Revision 1 The NRC staff identified the following variations from the traveler. The Callaway TSs utilize different numbering than the Standard TSs (STS) on which TSTF-567 was based. Specifically, TS 3.6.19 in TSTF-567 is TS 3.6.8 in the Callaway TSs. These differences are editorial and do not affect the applicability of TSTF 567 to the proposed LAR. This SE uses the Callaway specific TS numbers throughout. The Callaway TSs contain an SFCP. Therefore, the frequency for SR 3.6.8.1 is In accordance with the Surveillance Frequency Control Program.

2.3.6 Proposed FSAR Changes In enclosure 2 of the supplemental letter dated October 7, 2021, the licensee provided changes to the Callaway FSAR. In the supplement dated January 27, 2022, the licensee made revisions to address NRC comments made during a regulatory audit. The changes are described in the response to Questions 3, 4, 5, 6, 7, 42, 43, and 44 of enclosure 5 to the supplement dated January 27, 2022. These changes describe the treatment of debris with respect to operation of the ECCS and CSS during sump recirculation. The licensee requested that the NRC approve the changes to methodology described in the markup for FSAR section 6.3A.2 of appendix 6.3A.

3.0 TECHNICAL EVALUATION

The licensee already replaced the sump screens with substantially larger and physically more robust strainers; therefore, there are no physical modifications needed or planned in support of this application.

Callaway operating procedures have actions that prevent and mitigate strainer blockage based on indications available to operators such as instrumentation to monitor core water levels, sump water levels, and containment temperatures.

At Callaway, initial training on sump blockage issues was completed, and licensed operator classroom and simulator training on indications of, and responses to, degraded pump flow indications, which may be caused by containment emergency sump clogging is provided during initial and requalification training. Further, Callaway conducted the training for Emergency Response Organization decision makers and evaluators in the Technical Support Center (TSC) on indications of sump blockage and compensatory actions.

The NRC staff performed an integrated review of the proposed risk-informed approach, considering the five key principles of risk-informed decision-making set forth in RG 1.174, Revision 3.

3.1 Key Principle 1: The Proposed Change Meets Current Regulations Unless it is Explicitly Related to a Requested Exemption or Rule Change The proposed change requested to modify the Callaway licensing basis analyses to show compliance with 10 CFR 50.46 considering the effects of debris using both deterministic and risk-informed methodologies.

NEI 04-07; RG 1.82, Revision 4; TR WCAP-17788-P; NRC Staff Review Guidance for In-Vessel Effects (Reference 37); and the SRP are the primary guidance documents used to show regulatory compliance with 10 CFR 50.46, considering the effects of debris using deterministic criteria. As described above, the RoverD method uses both deterministic and risk-informed criteria. Most of the break scenarios are shown to meet deterministic acceptance criteria. For scenarios where deterministic acceptance criteria are not satisfied, the licensee proposed an exemption to 10 CFR 50.46. The requested exemptions from 10 CFR 50.46(a)(1), and General Design Criteria 35, 38, and 41 of Appendix A to 10 CFR Part 50 were evaluated by the NRC staff against the criteria of 10 CFR 50.12, Specific exemptions, and found to be acceptable in the related exemption issuance. A successful demonstration that all break scenarios are bounded by the deterministic criteria or fall within the bounds of the exemption demonstrates that regulations have been met.

The criteria to evaluate compliance with 10 CFR 50.46 using a risk-informed methodology are provided in the SRP Section 19.2; RG 1.200, Revision 2; and RG 1.174, Revision 3. However, the NRCs position has historically interpreted and applied the current regulations in 10 CFR 50.46 as requiring a deterministic approach and bounding calculations to show compliance. Thus, the NRCs longstanding practice may be regarded as a legally binding requirement from which an exemption is the appropriate means of granting dispensation from compliance. The licensee stated that, as allowed by SRM-SECY-12-0093, it chose to use a risk-informed method to resolve GSI-191 and to respond to GL 2004-02. Thus, in accordance with 10 CFR 50.12, the licensee requested exemptions to 10 CFR 50.46(a)(1) and exemptions to GDC 35, 38, and 41 of Appendix A to 10 CFR Part 50 in enclosure 1 to the letter dated

March 31, 2021. The licensee concludes that for Callaway the risk for the effects of debris is less than the threshold for Region III (Very Small Changes) of RG 1.174, and no additional physical changes to the facility or changes to the operation of the facility were proposed.

The NRC staff determined that special circumstances exist to grant the proposed exemption and that granting the exemption would not result in a violation of the Atomic Energy Act of 1954, as amended. Therefore, since the NRC staff has granted the exemptions (Reference 12) and the change explicitly relates to these requested exemptions, the proposed change to use the risk-informed methodology meets the first key principle of RG 1.174.

3.2 Key Principle 2: The Proposed Change is Consistent with the DID Philosophy Regulatory Position C.2.1.1, Defense in Depth, of RG 1.174, Revision 3, states that the DID philosophy consists of a number of considerations and consistency with the DID philosophy is maintained if seven considerations addressed in sections 3.2.1 through 3.2.7 below are met.

In attachment 3-4 of enclosure 3 to the supplemental letter dated October 7, 2021, the licensee explicitly addressed DID and the seven considerations above for Callaway. Items associated with DID that were included in attachment 3-4 of the licensees analysis are evaluated in sections 3.2.1 to 3.2.7 of this SE. Section 3.2.8 of this SE evaluates additional DID considerations specific to the debris issue, which were also provided in attachment 3-4 of enclosure 3, section 2.3, NEI Guidance for Defense-in-Depth Measures in Support of Response to GL 2004-02, to the licensees supplemental letter dated October 7, 2021, following NEI Guidance, Defense-In-Depth Measures in Support of GSI-191 Resolution Options, dated March 5, 2012 (March 5, 2012 NEI Guidance) (Reference 38).

3.2.1 A Reasonable Balance is Preserved Among Prevention of Core Damage, Prevention of Containment Failure, and Consequence Mitigation The licensee highlighted the independent components of the LOCA response systems, including two independent trains of ECCS equipment and two independent trains of containment heat removal equipment made up of CSS and containment air cooler (CAC) equipment.

The NRC staff reviewed the licensees rationale and concluded that a reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation because of the following:

1. There is a robust plant design to survive hazards and minimize challenges that could result in the occurrence of an event, and the change to adopt a risk-informed approach for assessing the effects of debris does not increase the likelihood of initiating events or create new significant initiating events;

2. Prevention measures are in place with adequate availability and reliability of structures, systems, and components (SSCs), providing the safety functions that prevent plant challenges from progressing to core damage;

3. Existing measures are in place to contain a source term if a severe accident occurs, since the change does not impact the containment function or SSCs supporting that function such as containment sprays (CSs); and

4. The change does not reduce the effectiveness of the emergency preparedness program, including the ability to detect and measure releases of radioactivity, notify offsite agencies and the public, and shelter or evacuate the public as necessary.

3.2.2 Over-Reliance on Programmatic Activities as Compensatory Measures Associated with the Change in the Licensing Basis is Avoided This DID consideration evaluates if design features are substituted for programmatic activities to an extent that significantly reduces the reliability and availability of design features to perform their safety functions. The licensee identified that the change would not adversely affect any of the programmatic activities already in place at Callaway, such as the inservice inspection (ISI) program, plant personnel training, RCS leakage detection program, containment cleanliness inspection activities, which follow deterministic guidance in NEI 04-07 and the inservice testing program requiring testing of active components such as pumps and valves. The proposed change does not rely heavily on programmatic activities as compensatory measures nor propose any new programmatic activities that could be heavily relied upon (References 5 and 6).

The NRC staff reviewed the licensees description of programmatic activities and concluded that this DID consideration is met because the proposed change does not affect how safety functions are performed, nor does it reduce the reliability or availability of the SSCs that perform those functions. Existing programmatic activities are maintained, and therefore, there is not an excessive reliance on programmatic activities as compensatory measures related to the risk-informed approach.

3.2.3 System Redundancy, Independence, and Diversity are Preserved, Commensurate with the Expected Frequency, Consequences of Challenges to the System, and Uncertainties (for Example, No Risk Outliers)

The licensee highlighted the redundancy, independence, and diversity of the ECCS and containment heat removal equipment and asserted that the proposed change does not require any design change to these systems. Therefore, system redundancy, independence, and diversity are preserved. In addition, the licensee stated that the proposed licensing basis change does not call for any changes to the system operating procedures. These systems were analyzed relative to their contribution to nuclear safety through the Callaway plant-specific PRA (which meets industry PRA standards for risk-informed applications), accounting for a full range of LOCA events and uncertainties, and no risk outliers were identified (References 5 and 6).

The NRC staff reviewed the licensees evaluation of this DID consideration and concludes that it is met because the risk-informed analysis is consistent with the assumptions in the safety analysis for Callaway and does not significantly increase the expected frequency of challenges to the systems, or consequences of failure of the system functions as a result of a decrease in redundancy, independence, or diversity. The licensee performed a comprehensive risk assessment and demonstrated reductions in redundancy, independence, or diversity of systems resulting from postulated LOCAs do not cause a significant increase in risk, as evidenced by a margin to RG 1.174 risk acceptance guidelines. The licensee included sensitivity cases to assess uncertainty. Although some sensitivity cases yielded higher risk increases, those alternatives were considered as part of the uncertainty of the risk estimates and controlled by different sets of assumptions. See section 3.4.2.9 of this SE.

3.2.4 Defenses Against Potential Common-Cause Failures are Preserved, and the Potential for the Introduction of New Common-Cause Failure Mechanisms is Assessed The licensee examined common-cause failure mechanisms in the context of GL 2004-02; specifically, the primary failure mechanism of concern is recirculation strainer clogging limiting adequate flow to any of the ECCS and CSS pumps. The defenses against potential strainer clogging are not changed by the risk-informed methodology; there are no design changes to the equipment or changes to emergency operating procedures (EOPs) (enclosure 3 of Reference 5).

The NRC staff reviewed the evaluation of this DID consideration and concludes that it is met because the risk-informed evaluation does not introduce a new potential common-cause failure or event for which a defense is not in place; does not increase the probability or frequency of a cause or event that could cause simultaneous multiple component failures; does not introduce a new coupling factor for which a defense is not in place; and does not weaken or defeat an existing defense against a cause, event, or coupling factor. Even though the strainer blockage failure mechanism is not deterministically eliminated, the risk analysis shows that the risk is very small and that additional mitigative and DID measures exist.

3.2.5 Independence of Barriers is Not Degraded The three barriers to a radioactive release are the fuel cladding, RCS piping and components, and reactor containment building. The licensee stated that in its evaluation of a LOCA, the RCS barrier is postulated to be breached, and the proposed change does not affect the design and analysis requirements for the fuel. The licensee noted that during recirculation, the post-LOCA fluid collecting in the containment sump pits is mobilized by pumps in the auxiliary building and recirculated back to the containment. The auxiliary building relies on the ECCS and CSS piping and components in the recirculation flow path as release barriers, and on filters in heating, ventilation, and air-conditioning (HVAC) system to control gaseous leakage from any potential recirculating sump water leakage in the auxiliary building. The proposed licensing basis change does not involve any change to the physical design and operating requirements for this equipment, and the licensee concluded there is no change to the containment cooling water recirculation flow path (enclosure 3 of Reference 5).

The licensee stated that containment is fully analyzed for both design basis considerations, and from a Level 2 PRA perspective. The licensee asserted that containment was evaluated in detailed analyses for severe accident phenomena, including LOCAs, and found to be robust.

The licensee highlighted the independence of CACs, which have enough cooling capability to remove decay heat during the recirculation phase, thereby further reducing containment integrity challenges and contributing to DID capability (enclosure 3 of Reference 5).

The NRC staff reviewed the licensees evaluation of this DID consideration and concludes that it is met because implementation of the methodology does not result in a significant increase in the frequency of existing challenges to the integrity of the barriers or in the failure probability of any individual barrier. Moreover, implementation of the methodology does not introduce new or additional failure dependencies among barriers that significantly increase the likelihood of failure.

3.2.6 Defenses Against Human Errors are Preserved This consideration evaluates if implementation of the proposed methodology significantly increases the potential for or creates new human errors that might adversely impact one or more layers of defense. The licensee stated that the proposed change does not involve any design change to the current equipment or change to operating procedures. Operator actions during the initial accident mitigation stage are focused on monitoring automatic mitigation actions and performing manual pump switchover actions. Prior to refueling water storage tank (RWST) depletion, residual heat removal (RHR) pump switchover from injection to recirculation is automatic. Operators are engaged in the switchover of safety injection (SI), centrifugal charging pumps, and CS pumps to recirculation. The switchover from cold leg injection to core flush (combined cold leg and hot leg injection) is a manual action performed by the operator.

These operator actions are controlled by EOPs. The risk-informed approach does not change any of the EOPs or impose any additional operator actions or complexity. The licensee concluded that the defenses that are already in place with respect to human errors are not impacted by the proposed licensing basis change (enclosure 3 of Reference 5).

The NRC staff reviewed the evaluation of this DID consideration and concludes that it is met because the implementation of the proposed methodology does not reduce the ability of plant staff to perform actions. Specifically, the methodology does not create new human actions that are important to preserving any of the layers of defense, or significantly increase the probability of existing human errors by affecting performance shaping factors, including mental and physical demands and level of training.

3.2.7 The Intent of the Plants Design Criteria is Maintained The licensee stated that the proposed license change does not involve any change to the physical design of the current plant equipment associated with GL 2004-02. The proposed license change revises the licensing basis for acceptable containment emergency sump strainer design and performance in support of ECCS and CSS operation in recirculation mode following postulated LOCAs. The licensee concluded that the intent of the plants design criteria is maintained.

The licensee stated that the design and licensing basis descriptions of accidents requiring ECCS and CSS operation (including analysis methods, assumptions, and results provided in the FSAR Chapters 6, Engineered Safety Features; and 15, Accident Analysis) remain unchanged. The proposed change to the licensing basis continues to meet the intent of the design criteria that apply to functions addressed by GL 2004-02. As discussed in enclosure 3 of the supplemental letter dated October 7, 2021, the licensee based its conclusion on the results of the risk-informed approach showing that the calculated risk associated with GL 2004-02 concerns for Callaway is very small and in accordance with the Region III acceptance guidelines defined by RG 1.174 (enclosure 3 of Reference 5).

The performance evaluations for accidents requiring ECCS and CSS operation described in the Callaway FSAR Chapters 6 and 15 are based on the Callaway 10 CFR Part 50 Appendix K, ECCS Evaluation Models, large break LOCA (LBLOCA) analysis, where the licensee demonstrated that for breaks up to and including the double-ended guillotine break (DEGB) of a reactor coolant pipe, the ECCS will limit the clad temperature to below the limit specified in 10 CFR 50.46, thus, assuring that the core will remain in place and substantially intact with its essential heat transfer geometry preserved. Section 50.46 of 10 CFR also requires abundant long-term cooling. That is, following successful initial operation of the ECCS, the core

temperature must be maintained at an acceptable value and decay heat removed. The licensee demonstrated that the risk of the loss of long-term cooling is very small and demonstrated that additional DID and mitigative measures are available. Since the proposed change does not involve a change to the ECCS acceptance criteria specified in 10 CFR 50.46, the licensee concluded that the intent of the plants design criteria is maintained as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

The NRC staff reviewed the licensees evaluation of this DID consideration and concludes that the proposed change maintains the intent of the plants design criteria, because an alternate risk-informed evaluation method provides an acceptable approach that demonstrates that LTCC will be maintained following a LOCA, and thus, does not result in a reduction in the effectiveness of one or more layers of defense.

3.2.8 Additional DID Considerations Based on NEI Guidance The licensee provided additional information on DID measures in support of the response to GL 2004-02 following the March 5, 2012, NEI guidance. In enclosure 3 of the LAR and supplement dated October 7, 2021, the licensee stated that a method for ensuring adequate DID is to maintain the capability for operators to detect and mitigate inadequate flow through recirculation strainers and inadequate flow through the reactor core due to the potential impacts of debris blockage (enclosure 3 of Reference 5).

3.2.8.1 Prevention of Inadequate Recirculation Strainer Flow The licensee identified the existence of specific steps for monitoring indications of sump strainer blockage and actions to take if this condition occurs as specified in Callaways EOPs. These actions are described in the Callaway response to NRC Bulletin (BL) 2003-01, and the subsequent responses to the NRC requests for additional information (RAIs). These actions are still in effect at Callaway. Specific actions include (1) reducing flow through the strainer by stopping pumps, (2) monitoring for proper pump operation, core exit thermocouple temperatures, and reactor water level indication, (3) refilling the RWST for injection flow, (4) using injection flow from alternate sources, and (5) transferring to combined hot leg/cold leg injection flow paths. The licensee identified multiple EOPs that specify these actions in attachment 3-4 of enclosure 3 to the supplemental letter dated October 7, 2021 (page 9 of 19).

3.2.8.2 Detection of Inadequate Strainer Flow The licensee stated that Callaway has operational procedures to monitor operating parameters related to the ECCS and CSS pump flow, discharge pressure, and amperage. These procedures allow control room personnel to properly diagnose the occurrence of cavitation as an indication of sump clogging or deaeration. Control room personnel have been trained to evaluate sump clogging or deaeration indicators and take appropriate action such as reducing strainer flow rate by securing CS pumps as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

3.2.8.3 Mitigation of Inadequate Recirculation Strainer Flow The licensee highlighted that the Callaway Emergency Response Plan Implementing Procedures provide guidance for refilling the RWST and realigning the ECCS for injection flow, which increase the containment water level and reduce the potential for fluid deaeration and cavitation. In addition, during the pump realignment, temporarily terminating recirculation flow

may allow buoyancy forces to eject the non-condensable gases stored inside the strainer effectively back-flushing and disrupting the debris bed. The disrupted debris bed may potentially fall to the bottom of the sump pit; agglomerated large clumps of debris would not be expected to re-suspend in the flow and transport back to the strainer pockets as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

The licensee also noted the diverse and flexible coping strategies (FLEX) to maintain RCS inventory control, RCS cooling, and containment integrity developed in response to the NRC Order EA-12-049, Issuance of Order to Modify Licenses with Regard to requirements for Mitigation Strategies for Beyond-Design-Basis External Events (BDBEE) (Reference 39) The licensee asserted that various modifications have been implemented such that non-emergency equipment can be credited during an event.

3.2.8.4 Prevention of Inadequate Reactor Core Flow The licensee referred to its in-vessel analysis performed following the TR WCAP-17788 methodology for hot and cold leg breaks, which did not result in additional contributions to core damage. In addition, the licensee noted the following DID measures (see SE sections 3.2.8.5 to 3.2.8.8) to prevent inadequate reactor core flow as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

3.2.8.5 Detection of Inadequate Reactor Core Flow The licensee identified that inadequate core cooling due to debris blocking the core or boric acid precipitation would be indicated by an increase in core exit thermocouple temperature. The licensee noted additional monitored indicators of inadequate reactor core flow such as the reactor vessel water level and containment radiation levels as discussed in enclosure 3 to the supplemental letter dated October 7, 2021. Further, the operators are trained to monitor for these indicators to take further action.

3.2.8.6 Mitigation of Inadequate Reactor Core Flow The licensee referred to Procedures FR-C.1 and FR-C.2 for operator guidance for commencing core flush to restore and maintain RCS subcooling and noted that the FLEX RCS makeup pump is also available to inject coolant into the RCS in case of failure of the emergency recirculation strainer as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

3.2.8.7 Implementation of Severe Accident Management Guidelines and the Plant Engineering Staff Evaluation Manual The licensee noted that Severe Accident Management Guidelines (SAMGs) provide additional guidance and actions for addressing inadequate core flow conditions. For Callaway, SAMGs are invoked when directed by the EOPs and used without TSC engineer involvement. The SAMGs provide guidance for flooding containment above the reactor vessel hot and cold leg nozzles and covering the break location to provide for convective circulation cooling of the reactor vessel. The licensee asserted that EOPs may direct operators to the engineering department for guidance, where TSC engineers consult the Plant Engineering Staff Evaluation Manual to provide Operations with additional guidance during the mitigation of an accident as discussed in enclosure 3 to the supplemental letter dated October 7, 2021.

3.2.8.8 NRC Staff Review of Additional DID The NRC staff reviewed the licensees additional DID actions and programs and concludes that the licensees measures to prevent, detect, and mitigate adverse conditions (such as inadequate strainer flow or inadequate core flow), barriers for release of radioactivity, emergency plan actions, and SAMGs provide additional DID measures beyond the seven factors defined in RG 1.174, Revision 3.

3.

2.9 NRC Staff Conclusion

Regarding Key Principle 2: Defense-in-Depth The NRC staff finds that the philosophy of DID is maintained under the analysis described in attachment 3-4 of enclosure 3 to the supplemental letter dated October 7, 2021, because the licensee has appropriately addressed each of the seven factors in section 2.1.1 of RG 1.174, Revision 3, and provided the additional information following NEI DID guidance (Reference 38).

3.3 Key Principle 3: The Proposed Change Maintains Sufficient Safety Margins RG 1.174 states that safety margins are maintained when codes and standards or their alternatives approved for use by the NRC are met, and when the safety analysis acceptance criteria in the licensing basis (e.g., FSAR, supporting analyses) are met, or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

The licensee examined the safety margins and stated that there are numerous conservatisms included in the risk-informed GL 2004-02 evaluation. The licensee described barriers for release of radioactivity in attachment 3-4 section 2.5, Barriers for Release of Radioactivity, of enclosure 3 to the supplemental letter dated October 7, 2021, namely the fuel cladding, RCS boundary, containment, and emergency plan actions, referred to in the following sections. The licensee summarized a list of conservatisms in attachment 3-4 of enclosure 3 to the supplemental letter dated October 7, 2021, related to debris generation, debris transport, chemical effects predictions, strainer head loss tests, strainer performance, and the RoverD and risk analysis to show that the proposed risk-informed approach maintains sufficient safety margins.

3.3.1 Barriers for Release of Radioactivity The licensee concluded that the proposed change maintains sufficient margin for current barriers (cladding, RCS boundary, containment, and emergency plan actions) against the release of radioactivity. The licensee stated that the proposed licensing basis change:

Does not affect or remove any of these barriers.

Does not result in a significant increase in the existing challenges to the integrity of the barriers.

Does not significantly change the failure probability of any individual barrier.

Does not introduce new or additional failure dependencies among barriers that significantly increase the likelihood of failure when compared to the existing conditions.

Does not change the overall redundancy and diversity features among the barriers that are sufficient to ensure compatibility with the risk acceptance guidelines.

The licensee evaluated aspects contributing to safety margin such as the fuel cladding, emergency core cooling and long-term cooling, RCS pressure boundary, ISI program, RCS weld mitigation, RCS leakage detection, containment integrity, containment testing, and emergency plan actions. The licensee highlighted the following aspects in attachment 3-4, section 2.5 of enclosure 3 to the supplemental letter dated October 7, 2021, contributing to safety margin:

Callaway has a system to provide abundant emergency core cooling, including during scenarios of loss of offsite or onsite power.

Although the RCS pressure boundary is postulated to be failed for the GL 2004-02 sump risk-informed evaluation, the proposed change does not make any change to the previous analyses and testing programs that demonstrate the integrity of the RCS.

The Callaway ISI program plan provides verification that structural integrity of ASME Class 1, 2, and 3 piping components are within the limits specified in the ISI program, and verification that the structural integrity of the main feedwater piping is within the limits specified in the augmented ISI program.

Water jet peening was used in 2017 to mitigate all large bore reactor vessel welds susceptible to primary water stress corrosion cracking (PWSCC).

The leak detection program at Callaway is capable of early identification of RCS leakage to provide time for appropriate operator action prior to a large break.

The containment remains a low leakage barrier against the release of fission products for the duration of the postulated LOCAs. The CACs and CSS operate independently and are each effective at reducing the containment pressure and temperature after a DBA including a loss of offsite power.

The licensee stated that industry studies indicate that containment systems can withstand challenges of up to approximately 3 times the design pressure.

The proposed change to the licensing basis does not involve any changes to the emergency plan; the use of the risk-informed approach does not impose any additional operator actions or complexity.

In August 2021, the NRC staff performed an audit of the licensees documents supporting the LAR. By letter dated January 27, 2022, the licensee provided supplements to the LAR and to address the NRCs questions as part of the audit activities. Enclosure 5 to the supplemental letter dated January 27, 2022, contains the licensees response to NRC staffs Questions 39 and 40 regarding DID measures for the RCS pressure boundary. Although these measures were evaluated as part of the RCS pressure boundary contribution to DID, they contribute safety margin to failure of the RCS pressure boundary, and are therefore, discussed in this section of the SE.

The NRC staff noted that in attachment 3-4 of enclosure 3 to the supplemental letter dated October 7, 2021, the licensee discusses DID measures as part of the risk informed methodology to address GSI-191 and respond to GL 2004-02. The NRC staff reviewed the LAR to determine whether DID measures are maintained for the RCS pressure boundary to address the potential material degradation as part of the review of GSI-191 and found them to be acceptable based on the licensees established procedures to implement industry guidance NEI 03-08, Guideline for the Management of Materials Issues (Reference 40).

The NRC staff noted that nickel-based Alloy 600/82/182 components and welds in the RCS system are susceptible to PWSCC. Besides large bore pipe welds, some PWR plants have Alloy 600/82/182 material in various RCS components, such as reactor vessel closure head penetration nozzles and associated attachment welds, and welds joining the pipe/safe end to the nozzles at the reactor vessel, pressurizer, and steam generator. In audit Question 39, as shown in enclosure 5 (page 72 of 86) of the supplemental letter dated January 27, 2022, the NRC staff noted that the licensee stated in attachment 3-4 of enclosure 3, section 2.5.2.2, Reactor Coolant System Weld Mitigation, that all large bore RCS pipe welds susceptible to PWSCC were mitigated by water jet peening in 2017. The NRC staff notes that water jet peening on the welds reduces tensile stresses on the surface of the welds, decreasing the susceptibility of those welds to PWSCC. The NRC staff asked the licensee to (1) identify Alloy 600/82/182 dissimilar metal butt welds and components in the RCS pressure boundary that have not been mitigated to minimize PWSCC, and (2) discuss whether the non-mitigated Alloy 600/82/182 weld and component locations were analyzed for the debris generation with a higher probability than for the mitigated welds and components.

In response to NRC audit Question 39, in enclosure 5 to the supplemental letter dated January 27, 2022, the licensee stated that it considered break frequencies in NUREG-1829 that did not include special treatment of dissimilar metal welds. The licensee further stated that Callaway has a program to inspect, evaluate, and mitigate the dissimilar metal welds. The licensee explained that special treatment of the dissimilar metal welds in the CASA Grande analyses would require a type of bottom-up approach to assign frequencies, as examined in the pilot risk-informed exploratory analyses by STP. The licensee indicated that NUREG-1829 has some recommendations for treatment of dissimilar metal welds.

However, the licensee did not use any uneven frequency assignment to weld breaks in the analysis. Based on discussions during the audit, the licensee provided a description of its dissimilar metal weld inspection and evaluation program as discussed further below. The licensee stated that ASME Code Case N-770-5, Alternative Examination Requirements and Acceptance Standards for Class 1 PWR Piping and Vessel Nozzle Butt Welds Fabricated with UNS N06082 or UNS W86182 Weld Filler Material With or Without Application of Listed Mitigation Activities,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, Division 1, as conditioned by 10 CFR 50.55a(g)(6)(ii)(F), Augmented ISI requirements: Examination requirements for Class 1 piping and nozzle dissimilar-metal butt welds, must be used for the inspection of dissimilar metal welds.

The licensee stated that the Callaway risk-informed analysis of pipe-break LOCA assigns a uniform break probability to all welds (weld differences based on reactor system operating conditions, weld type, or credit for recent mitigation actions were not considered). Recognizing that PWSCC is a concern for Alloy-600 welds, the licensee stated that it has implemented an inspection and maintenance program for Callaway. The licensee asserted that when all past and planned mitigation steps are complete, Alloy-600 welds will not introduce a higher break frequency relative to other weld types, which helps in justifying the uniform break probability

assumption. The NRC staff finds the treatment of the mitigated Alloy 600 welds as equivalent to other welds in the risk-informed analysis (i.e., assuming breaks of Alloy 600 welds to be of the same probability as breaks in any other weld in the system for debris generation calculations) acceptable based on the licensees implementation of an inspection and maintenance program for Callaway.

With regard to the Alloy 82/182 dissimilar metal welds, the licensee stated that the dissimilar metal weld inspection, evaluation, and mitigation program for Callaway is implemented in its plant procedures, Alloy 600 Management Plan. The licensee developed this program to meet the following regulatory requirements and industry guidance: 10 CFR Part 50, Appendix A, GDC 14, Reactor coolant pressure boundary, GDC 15, Reactor coolant design, GDC 30, Quality of reactor coolant pressure boundary, GDC 31, Fracture prevention of reactor coolant pressure boundary, and GDC 32, Inspection of reactor coolant pressure boundary; NRC BL 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles, BL 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity, and BL 2002-02, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs; NRC Regulatory Issue Summary (RIS) 2008-25; Regulatory Approach for Primary Water Stress Corrosion Cracking of Dissimilar Metal Butt Welds in Pressurized Water Reactor Primary Coolant System Piping;Section XI of the ASME Code, as supplemented by NRC, NEI and Materials Reliability Program (MRP) criteria including: ASME Code Cases N-722-1, Additional Examination for PWR Pressure Retaining Welds in Class 1 Components Fabricated with Alloy 600/82/182 Materials,Section XI, Division 1, N-729-6, Alternative Examination Requirements for PWR Reactor Vessel Upper Heads With Nozzles Having Pressure-Retaining Partial-Penetration Welds Section XI, Division 1, and N-770-5, as incorporated by reference in 10 CFR 50.55a; NEI 03-08; Electric Power Research Institute (EPRI) MRP Letter 2004-053; EPRI MRP-126, Materials Reliability Program: Generic Guidance for ALLOY 600 Management (MRP-126NP); and EPRI MRP-206, Inspection and Evaluation guidelines for Reactor Vessel Bottom-Mounted Nozzles in US PWR Plants.

In its response to NRC audit Question 39, the licensee further stated that regarding the 60 critical welds that are listed in table 6.3A-1, Weld Locations in the Risk-Informed Category, as provided in attachment 2-5 of enclosure 2 to the supplemental letter dated October 7, 2021, and in tables 7-3, Baseline critical weld list for continuum model, and 9-3, Critical weld list for valve insulation sensitivity scenario, as provided in attachment 3-3 of enclosure 3 to the supplemental letter dated October 7, 2021, only Weld 2-RV-302-121-A (Safe-end to Loop No. 1 reactor pressure vessel (RPV) Inlet Nozzle) is composed of material that could be susceptible to PWSCC. The licensee stated that this weld has been mitigated with water jet peening. The licensee replaced the reactor vessel closure head with one made of material not susceptible to PWSCC and mitigated the pressurizer nozzles with a full structural weld overlay. The licensee stated that the only remaining pressure boundary welds susceptible to PWSCC and not yet mitigated are the hot and cold leg thermowells, which are planned to be replaced in Refueling Outage 27. The NRC staff determined that the licensee has mitigated or has plans to mitigate all Alloy 600/82/182 dissimilar metal welds and components. Therefore, the NRC staff finds that the licensee has performed corrective actions to reduce probability of failure and maintain safety margin of RCS piping.

In NRCs Audit Question 40, the NRC staff noted that to monitor structural integrity, in addition to use of the ISI program, PWR plant owners periodically inspect RCS piping and associated components through processes not required by NRC regulations such as operator walkdowns, opportunistic inspections, the boric acid corrosion program, and the fatigue monitoring program

per EPRI MRP-146, Revision 1, Management of Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines, and questioned whether the licensee has implemented inspection programs of this type. The licensee discussed the following inspection programs that monitor the structural integrity of RCS pressure boundary as DID measures in enclosure 5 of its supplemental letter dated January 27, 2022. This answered the intent of the question to provide information on how this monitoring is accomplished under plant procedures.

ISI program In enclosure 5 (page 77 of 86), to the supplement dated January 27, 2022, the licensee stated that FSAR section 19.1.1, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD explains that the ISI program consists of periodic volumetric, surface, and/or visual examinations and leakage testing of ASME Code Class 1, 2, and 3 pressure-retaining components, including welds, pump casings, valve bodies, integral attachments, and pressure-retaining bolting for assessment, signs of degradation, and corrective actions. The licensee further stated that [i]n accordance with the definition of INSERVICE TESTING PROGRAM in Technical Specification 1.1, this program fulfills the requirements of 10 CFR 50.55a(f).

The licensee further stated in enclosure 5 that [n]on-destructive examinations that are used to evaluate the structural integrity of RCS piping and components are conducted in accordance with applicable codes and standards by personnel who are qualified in accordance with the Operating Quality Assurance Manual (OQAM).

In attachment 3-4 of enclosure 3, section 2.5.2.1 to the supplemental letter dated October 7, 2021, the licensee discusses the ISI program at Callaway. The licensee stated that the integrity of the welds in ASME Code Class 1 piping and components are maintained at a high level of reliability through the ASME Code,Section XI inspection program. The licensee further stated that Callaway ISI program procedure ensures that the following requirements of 10 CFR 50.55a and ASME Code,Section XI, 2007 Edition through 2008 Addenda are satisfied: (1) verification of the structural integrity of ASME Class 1, 2, and 3 components are within the limits specified in the ISI program, and (2) verification of the structural integrity of the main steam and main feedwater piping is within the limits specified in the augmented ISI program. The NRC staff notes that although the 2007 Edition through 2008 Addenda of the ASME Code,Section XI is the code of record for the current fourth ISI interval, the licensee is required to update the code of record every 10 years in accordance with 10 CFR 50.55a(g)(4), Inservice inspection standards requirement for operating plants, when Callaway enters the subsequent 10-year ISI interval.

The licensee periodically examines vessel and piping of the RCS pressure boundary to ensure their structural integrity. This way, if degradation is detected early, the licensee could repair or replace in time to minimize catastrophic failure of the degraded RCS component(s).

Based on the above, the NRC staff determined that the licensees ISI program is in accordance with the ASME Code,Section XI, which is incorporated by reference in accordance with 10 CFR 50.55a to monitor structural integrity of the RCS pressure boundary, and therefore, contributes to the safety margin.

Alloy 600 Management Program As discussed above in detail, the NRC staff determined that Callaways Alloy 600 management program specifies inspections for the reactor vessel, pressurizer, and RCS piping that contain PWSCC susceptible materials. Therefore, the NRC finds the program contributes to the safety margin.

Steam Generator Management Program The licensees steam generator management program manages cracking, loss of material, reduction of heat transfer, and wall thinning of the steam generator tubes, plugs, sleeves and secondary side steam generator internal components. The program detects degradation through non-destructive examinations (NDE), visual inspection, and in situ pressure testing.

Assessments are used to verify that the steam generator performance criteria defined in Callaway TS 5.5.9, Steam Generator (SG) Program, have been met over the last operating interval and ensure that the criteria will be met over the next operating interval. NDE inspection and primary to secondary leak rate monitoring are conducted consistent with the requirements of Callaway TSs and NEI 97-06, Steam Generator Program Guidelines. The program ensures that performance criteria are maintained for operational leakage, accident induced leakage, and structural integrity as prescribed in the Callaway TSs.

The NRC staff has reviewed the licensees steam generator program and determined that the program manages various potential degradation mechanisms in the steam generators. The licensee has satisfied the steam generator performance criteria in the TS 5.5.9. Therefore, the NRC staff finds the steam generator management program contributes to the safety margin.

Boric Acid Corrosion Control Program In enclosure 5 (page 75 of 86), to the to the supplemental letter dated January 27, 2022, the licensee discusses the Boric Acid Corrosion Control Program in FSAR section 19.1.4, Boric Acid Corrosion. The licensee stated that this program manages loss of material and increased resistance of connection due to borated water or reactor coolant leakage and includes provisions to identify leakage through inspection and examination. The program follows guidance in TR WCAP-15988-NP, Generic Guidance for an Effective Boric Acid Inspection Program for Pressurized Water Reactors, dated March 2003 (Reference 41). The program relies in part on implementation of recommendations of NRC GL 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, dated March 17, 1988 (Reference 42). The licensee stated that the program also includes visual examinations conducted as part of the required pressure tests performed in accordance with ASME Code,Section XI. The NRC staff reviewed the licensees boric acid corrosion control program and determined that the program follows GL 88-05 and visual examinations are conducted as part of system leakage tests per IWA-5000 of the ASME Code,Section XI. Therefore, the NRC staff finds the boric acid corrosion program at Callaway contributes to the safety margin.

Integrated Fatigue Management Program Under this program, the licensee tracks cumulative fatigue usage at monitored locations by one of the following methods: (1) cycle counting monitoring, which tracks transient event cycles affecting the location to ensure that the number of transient events analyzed by the fatigue analyses are not exceeded; (2) cycle-based fatigue monitoring, which uses the cycle counting results and stress intensity ranges generated with the ASME Code,Section III methods that use

three-dimensional six component stress-tensor methods to calculate cumulative usage factors for a given location, and tracking of fatigue accumulation to ensure that cumulative usage factors are within the ASME allowable fatigue limit of 1.0; and, (3) stress-based fatigue monitoring, which computes a real time stress history for a given component from data collected from plant instruments to calculate transient pressure and temperature, and the corresponding stress history at the critical location in the component, which is analyzed to identify stress cycles, and then a cumulative usage factor is calculated either by using a three-dimensional six component stress tensor method meeting the ASME Code,Section III, NB-3200 requirements, or a method that will be benchmarked consistent with NRC RIS 2008-30, Fatigue Analysis of Nuclear Power Plants Components, dated December 16, 2008 (Reference 43). The program also considers the effects of the reactor water environment for a set that includes the sample locations for a newer-vintage Westinghouse Plant as shown in NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, dated February 1995 (Reference 44), plant-specific bounding environmentally assisted fatigue locations in the reactor coolant pressure boundary, and reactor vessel internals locations with fatigue usage calculations. The associated Fatigue Program Notebook also incorporates guidance from EPRI MRP Technical Reports, including MRP-146, MRP-146 Revision 2, and supplement MRP-146S. The NRC staff determined that Callaway has a fatigue management program to minimize the potential for pipe break caused by fatigue and that the program is consistent with NRC RIS 2008-30. Therefore, the NRC staff finds the fatigue management program contributes to the safety margin.

Bolting Integrity Program In enclosure 5 (page 77 of 86) to the supplemental letter dated January 27, 2022, the licensee stated that FSAR section 19.1.8, Bolting Integrity, manages cracking, loss of material and loss of preload for pressure retaining bolting. The program includes periodic inspection of closure bolting for pressure-retaining components consistent with recommendations as delineated in NUREG-1339, and EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2 (Reference 45), with the exceptions noted in NUREG-1339. The Bolting Integrity Program also includes activities for preload control, material selection and control, and use of lubricants/sealants as delineated in EPRI TR-104213, Bolted Joint Maintenance and Application Guide (Reference 46). The ASME Code,Section XI, ISI, subsections IWB, IWC and IWD program (FSAR section 19.1.1) supplements the Bolting Integrity Program by providing the requirements for ISI of ASME Class 1, 2, and 3 safety-related pressure-retaining bolting. Also, RPV head closure studs are managed by the Reactor Head Closure Stud Bolting Program (FSAR section 19.1.3). The NRC staff finds that Callaway has implemented two bolting integrity programs, Reactor Head Closure Stud Bolting and Bolting Integrity Programs. These two programs follow NRC and industry guidance such as RG 1.65, NUREG-1339 related to the required ASME Code,Section XI. Therefore, the NRC staff finds that the bolting management program contributes to the safety margin.

RCS Leakage Detection Program In enclosure 5 (page 77 of 86) to the supplemental letter dated January 27, 2022, the licensee stated that it performs RCS leakage rate tracking and monitoring of RCS leakage to satisfy TS SR 3.4.13.1, Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance, and 3.4.13.2, Verify primary to secondary LEAKAGE is 150 gallons per day through any one steam generator. The licensee has established tiered action levels and responses for abnormally high RCS identified leakage or unidentified leakage that does not exceed the TS 3.4.13 LCO limit(s) in accordance with the guidance of TR WCAP-16465-NP,

Revision 0, Pressurized Water Reactor Owners Group Standard RCS Leakage Action Levels and Response Guidelines for Pressurized Water Reactors, dated September 2006 (Reference 47). In addition, the licensee has established tiered action levels and responses for abnormally high primary-to-secondary leakage that does not exceed the TS 3.4.13 LCO limit in accordance with the guidance of the EPRI guidelines in PWR Primary to Secondary Leak Guidelines, Revision 4. The NRC staff determined that Callaways RCS leakage detection systems meet RG 1.45 and the plant TS impose limits on the leak rate. In addition, the licensee has administrative control limits on the leak rate so as not to exceed the TS leak rate limits.

Therefore, the NRC staff finds that Callaways RCS leakage detection systems are acceptable to minimize the potential for pipe failure thereby contributing to the safety margin.

Reactor Vessel Internals Monitoring Program In enclosure 5 (page 76 of 86) to the supplemental letter dated January 27, 2022, the licensee discusses the Reactor Vessel Internals Monitoring in FSAR section 19.1.6, PWR Vessel Internals. This program is used to manage the aging effects of reactor vessel internal components, including (a) various forms of cracking, including stress corrosion cracking, PWSCC, irradiation assisted stress corrosion cracking, or cracking due to fatigue/cyclical loading; (b) loss of material induced by wear; (c) loss of fracture toughness due to either thermal aging or neutron irradiation embrittlement; (d) changes in dimensions due to void swelling or distortion; and, (e) loss of preload due to thermal and irradiation-enhanced stress relaxation or creep. The program relies on implementation of the guidance included in EPRI 3002017168 (MRP-227 Revision, 1-A), Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (Reference 48), and inspection standard MRP-228, Revision 4, Materials Reliability Program: Inspection Standard for Pressurized Water Reactor Internals - 2002 Update (Reference 49). The NRC staff reviewed Callaways reactor vessel internal component program and determined that the program follows the NRC approved MRP-227, Revision 1-A, which provides inspection requirements to monitor integrity of the reactor vessel internal components. Therefore, the NRC staff finds the reactor vessel internal program contributes to the safety margin.

3.3.2 Debris Generation The licensee referred to approved guidance used in support of the debris generation analysis such as NEI 04-07 and the associated NRC SE. In attachment 3-4 of enclosure 3, section 3.2 to the supplemental letter dated October 7, 2021, the licensee highlighted aspects related to multiple levels of conservatism such as:

Gradual growth of pipe flaws allows for early detection by the leakage monitoring systems before cracks grow to unstable sizes, with the associated operator action to mitigate consequences. The detection process referred to as leak-before-break which is an accepted part of regulatory compliance with GDC 4 Environmental and Dynamic Effects Design Basis, but is not credited in LOCA debris generation evaluations.

The zone of influence (ZOI) is assumed to be spherical or hemispherical geometry overlapping a conservative volume of insulation and coatings, based on conservative extrapolation of limited test data performed under non-prototypic conditions with limiting configurations. Debris amounts under accident conditions are expected to be less than predicted based on the ZOI method due to factors such as greater robustness of qualified coating materials and test results based on conservative insulation system seam orientations.

The debris generation analysis does not take credit for shielding within the ZOI by equipment (e.g. steam generators, reactor coolant pumps) and large piping.

Instantaneous failure of 100 percent of the unqualified and degraded coatings inside containment as particulates is a very conservative assumption, especially of the Carboline 193LF primer with 191HB topcoat (question 20 in enclosure 5 to January 27, 2022 supplement).

Latent debris evaluations were completed in accordance with the NRC-approved guidance in NEI 04-07, conservatively concluding that latent debris loading is less than 100 pound-mass (lbm) in each containment building.

3.3.3 Debris Transport The licensee stated that debris transport analysis was performed in accordance with NRC-approved methods in NEI 04-07 and cited the following levels of conservatism of the risk-informed analysis and as discussed in attachment 3-4 of enclosure 3, section 3.3 to the supplemental letter dated October 7, 2021:

All fine debris is assumed to wash down to the sump pool elevation with no holdup on structures; however, some fine debris would be expected to be retained on walls and structures above the containment pool due to incomplete spray coverage and hold up on structures.

Most fine debris is assumed to transport to the strainer surface. It is expected that debris will be trapped by numerous obstacles in the path towards the strainer such as supports, equipment, and curbs.

For each debris type and size, debris transport fractions were determined at four locations and the largest transport fractions were assumed in the risk-informed analysis.

The Callaway system includes debris barriers installed in all the openings through the secondary shield wall nearest to the emergency recirculation sumps. These barriers were not credited in the risk-informed analysis.

3.3.4 Chemical Effects The licensee stated that the chemical effects analysis was performed in accordance with NRC-approved guidance in TR WCAP-16530-NP-A, which includes the following levels of conservatism and as discussed in attachment 3-4 of enclosure 3, section 3.4 to the supplemental letter dated October 7, 2021:

TR WCAP-16530-NP-A relies largely upon short-term release rates (hours) to determine long-term releases (30 days) of chemicals. However, long-term release rates of constituent materials are expected to be significantly lower than that predicted by design basis models, due to saturation, surface passivation and formation of surface films.

One hundred percent of chemical species of interest are assumed to precipitate.

However, formation of precipitates is constrained by solubility limits. Precipitates are

expected to form at later times, when the net positive suction head (NPSH) margins are greater.

It is assumed that 100 percent of the precipitates are readily transported to the sump screen. However, a significant portion of those precipitates may be trapped by structures and obstacles in the path towards the strainer.

The STP pilot plant and Callaway have similar conditions such as pH, temperature, material inventories, and trends from the chemical effect tests conducted by the pilot plant are also applicable to Callaway:

o Integrated corrosion tests with bounding conditions for large breaks show relatively little precipitate formation.

o Vertical loop headloss tests with dissolved aluminum indicate lack of precipitate formation prior to significant pool cooling, which could take days after the event.

3.3.5 Strainer Headloss Testing Strainer testing guidance has been developed to ensure that headlosses predicted from testing are reasonably assured to represent the most limiting values for the plant conditions being tested. The guidance also directs that the application of the test results be performed conservatively. The licensees test program used the maximum debris loads for all debris types, except fiber, that could be generated by any break.

The licensee stated that strainer headloss testing was performed in 2016 at Alden Research Laboratories (Alden) in accordance with the NRC guidance, NRC Staff Review Guidance Regarding Generic Letter 2004 02 Closure in the Area of Strainer Head Loss and Vortexing, dated March 2008 (Reference 50), which included the following several levels of conservatism and as discussed in, attachment 3-4 of enclosure 3, section 3.5 to the supplemental letter dated October 7, 2021:

Only fiber fines were used; larger pieces of fiber would have reduced the measured headloss.

Fiber and particulate debris were collected on the strainer prior to the addition of chemical precipitates, which optimizes the headloss and the uniformity of debris beds.

Debris beds would be expected to be less uniform resulting in lower debris bed headloss.

The headloss test did not credit near-field settling, which was accomplished by inducing turbulence in the test. The Callaway system includes a 6-inch curb surrounding the strainers which would promote settlement.

Metallic insulation was not included. Metallic insulation would disturb the formation of a uniform debris bed and lower the debris bed headloss. Paint chips would have a similar effect of disturbing the debris bed; however, particulates were conservatively employed as surrogate for paint chips in the testing.

Strainer headloss tests were conducted at an approach velocity approximately 15 percent larger than the expected approach velocity, conservatively causing larger strainer headloss.

3.3.6 Strainer Performance The licensee stated that the risk-informed analysis includes multiple levels of conservatism in strainer performance, namely (attachment 3-4 of enclosure 3 section 3.6 of Reference 5):

The maximum strainer headloss is applied at the beginning of the event, implicitly assuming instantaneous transport of conventional debris, eroded debris, and chemical precipitates. In reality, debris buildup is gradual and margins are expected to increase with time.

The minimum pool height was estimated based on extreme conditions never experienced in the operational history of Callaway.

Strainer headloss tests were executed at a temperature of 120 °F. The strainer headloss decreases with increasing temperature; however, this decrease was ignored in the analyses.

The strainer headloss tests included approach velocities approximately 15 percent above expected approach velocities, causing overestimates in the headloss. This headloss was not adjusted for actual approach velocities.

For the structural analysis, forces from debris load and safe shutdown earthquake forces were simultaneously applied, overestimating stresses.

3.3.7 RoverD and Risk The licensee highlighted the aspects differing from the STP risk-informed pilot analysis as discussed in attachment 3-4 of enclosure 3, section 3.7 to the supplemental letter dated October 7, 2021:

The Callaway analysis identified a risk metric equal to the total low-density fiberglass (LDFG) transported to the strainer (300 lbm), in contrast to the STP analysis that focused on fiber fines.

o All other debris types other than fiber are bounded by strainer tests.

The Callaway analysis assumed a single operable train, maximizing the amount of debris load on the single operating strainer.

A margin of 50 lbm of fiber was applied to all postulated breaks in addition to fiber generated by the LOCA break and latent fiber.

Breaks generating fiber in excess of 300 lbm of transported fiber are assumed to cause strainer failure and core damage. The frequency of these breaks is used as the basis to compute the change in CDF (CDF) and change in LERF (LERF). Breaks generating less than 300 lbm of

transported fiber would not challenge the strainer. Other potential failure modes were also concluded not to contribute to the plant risk.

3.

3.8 NRC Staff Conclusion

Regarding Key Principle 3: Safety Margins The NRC concludes that the applicant considered all relevant ASME Class-I piping welds in its risk-informed analysis, and that safety margin is not affected by this aspect of the risk-informed analysis. The NRC staff also notes that the ASME Class-I RCS piping considered in the debris generation analysis is fabricated with material that is resistant to cracking or mitigated such that catastrophic pipe breaks would not likely occur. If cracking does occur, the RCS leakage detection systems will be able to detect leakage, and the operator will take corrective actions (see section 3.3.1 of this SE). Therefore, the NRC staff concludes that the piping considered in the debris generation analysis maintains sufficient safety margin to minimize the potential for a large break that would significantly affect the containment sump performance.

The licensee considered approved guidance such as TR WCAP-16530-NP-A, the March 2008 NRC guidance on strainer headloss and vortexing, and NEI 04-07 to develop tests and analyses concerning debris generation, debris transport, chemical effects, and headloss testing. The NRC concludes that the proposed approach maintains safety margins and that the licensees evaluation included independent margins that help assure that the analysis results in a conservative prediction of risk associated with the impact of debris on LTCC.

3.4 Key Principle 4: When Proposed Changes Result in an Increase in Risk, the Increases Should be Small and Consistent with the Intent of the Commissions Safety Goal Policy Statement This section discusses the licensees base PRA model for Callaway, including the calculated total risk values (CDF and LERF) for each unit, and the licensees risk-informed assessment of debris. A review of this information was necessary to determine whether the risk attributable to debris is small and consistent with the Commissions Safety Goal Policy Statement.

3.4.1 Acceptability of the Base PRA Model Regulatory Position C.2.3 of RG 1.174, Revision 3, states, in part, that the scope, level of detail, and technical adequacy (technical elements) of the PRA are to be commensurate with the application for which it is intended, and the role the PRA results play in the integrated decision process.

The acceptability of the PRA is commensurate with the safety implications of the change being requested and the role that the PRA plays in justifying that change. That is, the more the potential change in risk or the greater the uncertainty in that risk from the requested change, or both, the more rigor is placed into ensuring the acceptability of the PRA.

The objective of the NRC staffs review of the Callaway base PRA model was to determine whether the PRA used in evaluating the risk attributable to debris was of sufficient scope, level of detail, technical elements, and plant representation for this application. The licensee asserted that the Callaways PRA is compliant with RG 1.200, Revision 2 for internal events and therefore acceptable to support the assessment of the risk of internal events associated with GL 2004-02 (enclosure 2 of Reference 5, page 24).

The Callaway PRA model was used in a limited extent to support the risk-informed GSI-191 analysis. The use of the PRA was limited to:

Determining the overall internal (including flooding and fire) and external (seismic and high winds) events CDF and LERF.

Establishing a valve failure probability to support the screening of breaks downstream of normally closed valves.

Justify a CDF-to-LERF multiplier less than 0.1 to estimate a change in LERF (LERF) value for the GL 2004-02 analysis, based on the calculated change in CDF (CDF) value.

The NRC staffs review focused on the above uses of the licensees PRA model to evaluate the risk of debris in containment.

3.4.1.1 Scope of the Base PRA (Modes/Hazards)

Regulatory Position C.2.3.1 Scope of a Probabilistic Risk Assessment to Support an Application, in RG 1.174 states that:

The scope of a PRA is defined in terms of the causes of initiating events and the plant operating modes it addresses. The causes of initiating events are classified into hazard groups, which are defined as groups of similar hazards that are assessed in a PRA using common approaches, methods, and likelihood data for characterizing the effect on the plant.

Although all plant operating modes and hazard groups should be addressed, a qualitative treatment of some modes and hazard groups may be sufficient when the licensee can demonstrate that their risk contributions would not affect the decision. However, when the risk associated with a particular hazard group or operating mode would affect the decision being made, it is the Commissions policy, SRM to SECY 04-0118, Plan for the Implementation of the Commissions Phased Approach to Probabilistic Risk Assessment Quality, dated October 6,,

2004, that, if a staff-endorsed PRA standard exists for that hazard group or operating mode, the risk will be assessed using a PRA that meets that standard (Reference 51).

The licensee stated that the PRA is compliant with RG 1.200, Revision 2. Therefore, it was peer reviewed and concluded appropriate to use for risk-informed applications. The Callaway PRA model was not modified to support the risk-informed GL 2004-02 evaluation. The dominant hazards of relevance to the risk-informed evaluation are LBLOCAs (which are internal events).

The Callaway system includes two independent RCS and CSS trains recirculating water from separate strainer sumps. For the risk-informed analyses, single train operation was postulated to overestimate the debris buildup on a single strainer. On the other hand, for the in-vessel debris buildup analyses, two train operation was assumed because the two-train configuration would circulate more debris through the reactor vessel. The risk-informed analysis did not require consideration of the probability of single train operation. The licensee concluded that only very large weld breaks in the main reactor coolant piping could generate sufficient debris to threaten strainer performance. For in-vessel effects, the licensee concluded that for all break scenarios that were not already counted as contributing to plant risk, accumulation of fiber in the core would not block the flow or challenge the core cooling system and the rate of heat removal from the core. The licensee examined secondary risk contributors including a LOCA event

beyond the first isolation valve (i.e., isolable weld breaks with simultaneous failure of the isolation valve) and concluded those secondary processes do not contribute or negligibly contribute to the CDF. The licensee considered a probability equal to 1.11x103 for the isolation valve to fail its function, consistent with information in the internal events PRA as discussed in attachment 3-3 of enclosure 3 to the supplemental letter dated October 7, 2021.

The hazards and initiating events the licensee considered in the risk assessment are random weld failures in piping systems at Class-I welds before and after the first isolation valve, secondary line breaks, spurious and stuck-open valves, pump seal LOCA, ex-vessel downstream wear, strainer structural damage, in-vessel effects, and seismic-induced LOCA events as discussed in attachment 3-3 of enclosure 3, section 8 to the supplemental letter dated October 7, 2021.

The licensee excluded analysis of secondary line breaks (large main steam line (MSL) and feedwater line (FWL) breaks) on the basis that recirculation is not required to mitigate effects of those breaks. However, a sensitivity analysis on PRA outputs accounting for a sump failure probability conditional on a HELB (e.g., large MSL or FWL breaks) yielded a CDF at least two orders of magnitude less than in the baseline scenario of the licensees risk-informed analysis.

Spurious and stuck-open pilot-operated relief valves and pump seal LOCAs were excluded on the basis of their similitude to small break LOCAs (SBLOCAs), which would not cause sufficient debris to challenge the strainers (the minimum breaks that would challenge the strainers are 9.145 inches).

The initiating events addressed in the Callaway risk-informed approach were limited to internal event LOCAs in the primary RCS. The licensee addressed both Class-I welds before and after the first isolation valve. The contribution of LOCAs outside isolable Class-I welds to the CDF is negligible, given the dependence on failure of the first isolation valve to perform its function (failure probability estimated to be 1.11x103).

The Callaway seismic PRA identifies seismic-induced large LOCA breaks that lead to core damage. All seismic-induced large LOCA events are assumed to cause core damage in the seismic PRA (and thus do not contribute to the CDF), except for one scenario related to a break on the pressurizer surge line after a seismic event. The licensee concluded this specific break would not produce sufficient debris to challenge the strainer and recirculation cooling.

Therefore, seismic-induced large LOCA events do not contribute to the CDF associated with GL 2004-02 processes.

The licensee addressed in-vessel effects following TR WCAP-17788-P. The Callaway Accident Analysis Basis Document (AABD) concludes that cold leg, hot leg, and simultaneous injection to the cold leg and hot leg prevent buildup of boric acid in the core and dilute potentially high boric acid concentrations in the core prior to reaching the solubility limit. The licensee concluded that the 13-hour hot-leg switchover implemented by procedures is sufficient to address issues associated with boric acid precipitation.

The NRC staff reviewed the licensees information regarding the scope of its base PRA and concludes that the risks associated with hazards and operating modes that would affect this application were evaluated using a PRA that meets the applicable PRA standard. Specifically, the NRC staff reviewed the licensees assessment regarding the scope of the PRA used to support this application and concludes that (1) the at-power risk bounds the shutdown risk of debris because debris ZOI is either approximately the same, or significantly higher, at full power RCS pressure and temperature, the flow rate required to cool the core is significantly reduced

for low power or shutdown modes, and the pressure of LOCA water jets at full power would generate more debris; and (2) the use of internal events is adequate because the risk contribution from other external hazards does not affect the evaluation of the risk attributable to debris.

3.4.1.2 Level of Detail of the Base PRA Regulatory Position C.2.3.2 in RG 1.174 states that the level of detail required of the PRA is that which is sufficient to model the impact of the proposed change. The characterization of the problem should include establishing a cause-effect relationship to identify portions of the PRA affected by the issue being evaluated.

The NRC staff reviewed the licensees description of its base PRA and concludes that the level of detail of the licensees base PRA is sufficient to evaluate the risk attributable to debris from sump strainer and core blockage failures, along with the associated LOCA initiating events. The licensee-implemented peer reviews following ASME/ANS standards and NEI guidance and these reviews did not identify issues that would affect the risk-informed GL 2004-02 evaluation.

3.4.1.3 Base PRA Technical Elements RG 1.200, Revision 2, describes one approach for determining whether the PRA, in total or the parts that are used to support an application, is acceptable such that the PRA can be used in regulatory decision-making for LWRs. RG 1.200 endorses, with comments and qualifications, the use of the ASME/ANS RA-Sa-2009 PRA Standard; NEI 00-02, Revision 1, Probabilistic Risk Assessment Peer-Review Process Guidance, dated May 2006 (Reference 52); and NEI 05-04, Revision 2, Process for Performing Internal Events PRA Peer Review Using the ASME/ANS PRA Standard (Reference 53).

Therefore, the NRC staff relied on the peer-review findings and reviewed the key assumptions in the licensees PRA in its determination of the acceptability of the technical elements of the base PRA model. The ASME/ANS RA-Sa-2009 PRA Standard provides technical supporting requirements in terms of three capability categories (CCs). The intent of the delineation of the CCs within the supporting requirements is generally that the degree of scope and level of detail, the degree of plant specificity, and the degree of realism increase from CC-I to CC-III. In general, the NRC staff anticipates that current good practice (i.e., CC-II of the ASME/ANS Standard) is adequate for most applications. Consistent with the guidance in RG 1.200 and RG 1.174 for this application of the Callaway PRA to assess the risk associated with GL 2004-02-related phenomena, the NRC staff considered CC-II to be adequate. The licensee concluded its base PRA to be CC-II or higher.

3.4.1.3.1 Callaway Internal Events PRA The licensee stated that the Callaway PRA models are at-power models consisting of four hazard models: internal flooding, fire, seismic, and high wind. Each hazard model has the internal events model as the base with hazard specific initiators added and fault tree modifications and additions made, as necessary. The models provide both CDF and LERF. All five of these PRA models were developed using processes that continue to comply with RG 1.200, Revision 3 (Reference 54).

PRA models have been peer reviewed and assessed against RG 1.200, Revision 2, endorsed guidance consistent with NRC RIS 2007-06, Regulatory Guide 1.200 Implementation, dated

March 22, 2007 (Reference 55) except that the seismic PRA was assessed against ASME/ANS RA-S CASE 1, Case for ASME/ANS RA-Sb-2013 (Reference 56), as amended by the NRC on March 12, 2018 and approved in RG 1.200, Revision 3.

The review and closure of finding-level facts and observations (F&Os) were performed by an independent assessment team using the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, Close-out of Facts and Observations (F&Os) as accepted by the NRC in letter dated May 3, 2017 (Reference 57). The reviews also met the requirements of NEI 17-07, Revision 2, Performance of PRA Peer Reviews Using the ASME/ANS PRA Standard, dated August 2019 (Reference 58).

The licensee stated that the PRA scope and technical adequacy is met for this application as the ASME/ANS RA-Sa-2009 PRA Standard requirements for all models are met at CC-II or higher. There are no open F&Os against any of the models discussed in this application, and all F&Os have been independently assessed and closed using the accepted processes. The resolved findings and the basis for resolution are documented in the Callaway PRA documentation and the F&O closure review reports.

Based on the licensee-implemented peer reviews following ASME/ANS standards, NEI guidance, and the CC-II classification of the internal events PRA, the NRC concludes that the Callaway internal events PRA is adequate to support the risk-informed GSI-191 assessment.

3.4.1.3.2 Callaway Seismic PRA The licensee employed in limited extent a seismic PRA to support the risk-informed GL 2004-02 assessment. The licensee asserted that the PRA identifies seismic-induced large LOCA breaks that lead to core damage. All seismic-induced large LOCAs are assumed to cause core damage in the seismic PRA except for one scenario related to a break on the pressurizer surge line after a seismic event. The licensee concluded this specific break would not produce sufficient debris to challenge the strainer and recirculation cooling. Therefore, seismic-induced large LOCAs do not contribute to the CDF associated with GL 2004-02 processes. The NRC concluded that it was adequate to exclude seismic-induced LOCAs from the risk-informed assessment.

3.4.1.4 Plant Representation RG 1.174, Revision 3, states, in part, The PRA results used to support an application are derived from a base PRA model that represents the as-built and as-operated plant to the extent needed to support the application.

That is, at the time of the application, the PRA should realistically reflect the risk associated with the plant.

The NRC staff concludes that the licensees PRA model adequately represents the as-built and as-operated plant to the extent needed to support the GL 2004-02 risk assessment because the licensees PRA maintenance procedures include an ongoing review of design and procedure changes for their impact on the PRA model, and PRA data or inputs are reviewed and updated, as necessary, on a periodic basis.

3.4.

1.5 NRC Staff Conclusion

Regarding the Base PRA Model The NRC staff concludes that the Callaway base PRA model used in support of the licensees GL 2004-02 risk assessment is acceptable (e.g., has the appropriate scope, level of detail, technical elements, and plant representation) to evaluate the risk attributable to debris because the licensee applied approaches consistent with the guidance in RG 1.174, Revision 3, and RG 1.200 Revision 2.

3.4.2 Risk-Informed Approach for Addressing the Effects of Debris on LTCC The licensee implemented simplified computations, using limited information from the internal events PRA, and combined those computations with traditional engineering analyses to estimate the risk attributable to debris. This integrated analysis is referred to as the systematic risk assessment.

3.4.2.1 Scope of the Systematic Risk Assessment This section describes the specific approach used by the licensee to determine all relevant initiating events for which debris could adversely affect the CDF or LERF. This includes how relevant scenarios (i.e., an initiating event followed by a plant response leading to a specified end state, such as event prevention, core damage, or large early release) that could be mitigated by the activation of sump recirculation were identified and considered in the systematic risk assessment.

In enclosure 3 to the supplemental letter dated October 7, 2021, the licensee provided information regarding the scope of its systematic risk assessment that employed a screening process to eliminate scenarios that were deemed not relevant, not affected by debris, not requiring sump recirculation, or having an insignificant contribution based on the identified failure modes. Screening is a common practice in quantitative risk assessments, and one acceptable approach is discussed in NUREG-1855, Volume 1, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk Informed Decision Making, dated March 2009 (Reference 59). Specifically, NUREG-1855, Volume 1, describes assessment of model and completeness uncertainty, including the identification of sources of uncertainty that are not related to either the parts of the PRA used to generate the results or the significant contributors to the results, and the use of screening and conservative analyses to address non-significant contributors. RG 1.174 recognizes that a screening approach allows the detailed analysis to focus on the more significant contributions. Information pertaining to the licensees initial plantwide and location-specific screening approach is described in the following subsections.

3.4.2.1.1 Initial Plant-Wide Screening The initiating events considered in the licensee risk-informed analysis included those with the potential to (1) generate debris inside containment, (2) require sump recirculation for mitigation of the event, and (3) result in debris transport to the containment sump (Reference 6, enclosure 3, attachment 3-3, section 8; enclosure 5, Question 34)

The licensee considered only scenarios that required recirculation through the ECCS or CSS strainers, since without recirculation, there is no potential for debris-related failures of the strainers, pumps, downstream components, or core. The licensee considered the following initiating events relevant to GSI-191 risk assessment:

RCS pipe breaks, resulting in small, medium, and large break LOCAs RCS pipe breaks downstream normally closed valves Secondary line breaks Spurious and failed-open relief and safety valves Mechanical LOCA (pump seal LOCA)

Seismically-induced LOCAs Internal fire LOCAs Internal flood LOCAs Non-piping LOCAs (e.g., manway covers, valves, control element drive assemblies, and instrument lines)

Water hammer-induced LOCAs High winds The licensee concluded that the only initiating events of relevance to the GSI-191 risk-informed assessment were RCS pipe breaks causing LOCAs, and that only LBLOCAs may generate enough debris to challenge the emergency recirculation sump system. The licensee excluded most initiating events based on (1) small equivalent break sizes, (2) reduced flows required to compensate the water inventory compared to equivalent flows in strainer tests, and (3) location of breaks away from significant insulation sources. The Callaway seismic PRA includes LOCA scenarios, and all but one are assumed to lead to core damage. A seismically induced break on the pressurizer surge line could cause a LOCA that does not directly proceed to core damage; however, breaks on the pressurizer surge line welds were explicitly examined in the Baseline CASA Grande analysis and concluded to not generate fibrous debris exceeding 300 lbm.

Therefore, the licensee concluded that breaks on such pressurizer surge line would not produce enough debris to challenge strainer functions.

The piping attached to the RCS at Callaway includes welds in ASME Class-I piping downstream of normally closed valves. The risk of these breaks is dependent on failure of the upstream valve function, which the licensee estimated to be 1.11x103 per demand, based on similar valves modeled in the internal events PRA model. The licensee estimated the contribution to the CDF, treating the set of isolable welds as an independent set and conservatively distributing the NUREG-1829 LOCA frequency among those welds alone (i.e., ignoring the pipes upstream of the isolation valve), and concluded that the corresponding CDF contribution was negligible (References 5 and 6; enclosure 3, table 8-1).

The licensee implemented a special analysis to exclude MSL breaks and FWL breaks as secondary system breaks in response to NRC staff questions during the regulatory audit (enclosure 5, Question 35 of Reference 6). The licensee used CASA Grande to compute fibrous debris amounts from breaks on welds in MSL and FWL, of size equal to the DEGB limit (16 inches). The licensee considered two ZOI radii, 10.4D and 17D, and computed that a fraction of the welds could generate fibrous debris exceeding 300 lbm of transported fiber. The NRC staff concluded that the use of the 10.4D ZOI was reasonable based on the lower pressures and temperatures in the secondary lines (compared to RCS breaks). This results in a smaller number of breaks exceeding the 300 lbm threshold in the MSL case and overall smaller amounts of fibrous debris generation as discussed in the licensees response. The licensee

highlighted that water flows in response to the break would be much less than large break injection with containment spray flows (approximately 8750 gallons per minute (gpm))

considered in strainer tests. Bounding flows for breaks in the MSL or FWL range between 878 gpm and 1021 gpm without spray, and 4186 gpm after the spray is activated 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the event. The licensee developed a simplified scaling argument to estimate an equivalent strainer fiber load for the low flow condition that would cause the same headloss produced by a 300-lbm fiber load under high flow rate. The licensee argued that the fiber load ratio (equivalent load/300 lbm) is inversely proportional to the square of the flow rate ratio (low flow/8750 gpm).

The licensee concluded that, given the low flow rates in response to the break, the strainer will withstand loads well in excess of 300 lbm caused by MSL or FWL breaks. Although the allowable increase in debris due to a reduction in flow cannot be accurately estimated without condition-specific testing, the NRC staff agrees with the physical processes discussed in the submittal. The licensee also stated that transport of fibrous debris to the strainer will be reduced due to the lower velocities in the pool. The NRC staff considers it reasonable to conclude that breaks on the MSL or the FWL do not contribute to the overall risk based on the observation that (1) smaller ZOIs apply to breaks with reduced flows, (2) strainers with reduced flows are expected to withstand higher fiber loads, (3) the amount of fiber calculated to reach the strainers for the secondary break cases is conservative, and (4) the selected fiber limit of 300 lbm is a practical limit corresponding to a success state (i.e., strainers were not observed to fail when subjected to a fiber load of 300 lbm).

The NRC staff reviewed the licensees screening approach and concluded that the approach is technically sound and consistent with state-of-practice approaches. Furthermore, the NRC staff concludes that the results of the plantwide screening adequately reflect initiating events relevant to the licensees systematic risk assessment of GL 2004-02 phenomena.

3.4.2.1.2 Location-Specific Screening For LOCA events, the effects of debris may be dependent on the location of the initiating event.

Therefore, the licensee completed a location-specific analysis to identify accident sequences that could be adversely impacted by debris. The licensee performed a break location-specific evaluation for all ASME Class-I piping welds in the RCS between the RPV and the first isolation valve (References 5 and 6; enclosure 3, attachment 3-3, section 2.1). The licensee considered LOCA break frequencies from NUREG-1829, which includes contributions of breaks in piping and non-piping locations.

The licensee proposed that any LOCA break that generates and transports more LDFG to the strainer than fiber loads shown to be acceptable by strainer tests could be assumed to result in strainer failure and core damage. Breaks that produce less than the amount of tested fiber reaching the strainer were considered to result in successful operation of the ECCS and CSS strainers. The licensee also examined the headloss from the calculated debris load to exclude failure from some other causes (for example deaeration, flashing, or mechanical collapse).

The acceptable debris loading was determined by testing (see section 3.4.2.8.3 of this SE). In order to determine the amount of debris generated from each potential break location, the licensee developed a computer-aided design (CAD) model of containment and incorporated the CAD model in the CASA Grande model. The CAD model included the locations of each potential break location (welds in the RCS) and locations of debris sources that could be damaged by a LOCA jet. The licensee calculated the amount of each type of debris that would transport to the strainer, considering the amount of debris generated by each break size and orientation. Each break location was evaluated by the combination of the debris generation and

transport to determine the largest amount of debris, especially fibrous debris, that could arrive at the strainer due to a break at a specific location.

Based on initial screening results, the licensee performed a quantitative analysis of LOCA RCS pipe breaks ranging from half-inch partial breaks to DEGBs on every Class-I ISI weld inside the first isolation valve. The licensee explicitly considered 411 ISI welds within the first isolation valve in its risk-informed analysis. Welds downstream of normally closed isolation valves were also examined, as discussed in section 3.4.2.1.1 of this SE, and concluded to be of low risk consequence.

The location-specific screening process refined the quantitative analysis to breaks in ISI welds in the unisolable portion of the Class-I pressure boundary (i.e., inside the first isolation valve).

The NRC staff reviewed the licensees location-specific screening evaluation and concludes that the licensee identified all locations that could result in a failure of the ECCS LTCC functions, because the full spectrum of possible break locations was considered and systematically assessed for potential effects on the calculation of debris amounts generated and transported to the sump.

NRC Staff Conclusion Regarding the Scope of the Systematic Risk Assessment The NRC staff reviewed the scope of the systematic risk assessment and finds it adequate, because the licensee employed a systematic screening process using initial plantwide and location-specific screening approaches to identify relevant scenarios and also eliminate scenarios that do not affect the GL 2004-02 risk assessment, in a manner consistent with state-of-practice approaches described in NUREG-1855, Revision 1. The licensee included all scenarios and initiating events relevant to the GL 2004-02 evaluation.

3.4.2.2 Initiating Event Frequencies The licensee implemented a simplified computation of the CDF, considering the geometric mean aggregation exceedance LOCA frequencies in NUREG-1829, Volume 1, table 7.19, Total PWR LOCA Frequencies without SGTR [Steam Generator Tube Rupture] Contributions (LOCA Categories 3-6 Reproduced from Table 7.17), and not relying on the internal events PRA model for the CDF computation. NUREG-1829 provides exceedance frequencies at discrete break sizes, which is the annual probability of having a specified break of a given size or larger. The licensee considered end-of-plant-license estimates corresponding to 25 and 40 years of operation, with 25-year operation data selected in the baseline analysis and 40-year data considered in a sensitivity analysis. Information in NUREG-1829, table 7.19, includes contributions from piping and non-piping LOCAs, but it excludes contributions from the SGTR.

The licensee concluded that breaks in the MSL would not contribute to the total risk (see section 3.4.2.1.1 of this SE).

For the calculation of small, medium, and large LOCA conditional failure probability, the LOCA frequencies were uniformly allocated to individual pipe welds using a top-down distribution methodology. The top-down LOCA frequency allocation methodology treats all breaks of a similar size as having an equivalent LOCA frequency, regardless of the weld location, operation conditions, and specific degradation mechanism (i.e., every break of the same size is assumed to occur with equal frequency).

The licensee used a linear interpolation scheme (i.e., linear interpolation between break sizes and between frequencies) to determine frequencies for medium and large break sizes not

explicitly listed in NUREG-1829. The guidance in NUREG-1829 states that interpolation may be used but does not specify use of any one interpolation scheme. The NRC staff concludes the licensees use of linear interpolation of NUREG-1829 data is acceptable because it overestimates the CDF compared to alternative and acceptable interpolation approaches such as log-linear interpolation (log-scale in LOCA frequencies and linear-scale in break sizes.

The guidance in NUREG-1829 contains 25-year or current LOCA frequencies and 40-year or end of license period LOCA frequencies. For most LOCA types, the 40-year values are slightly higher due to anticipated aging effects and the possibility of new degradation mechanisms. In some cases, however, the 40-year values are lower, reflecting an expectation that improved mitigation techniques will lower LOCA frequencies. Callaway was initially licensed in 1984, with a license renewed in 2015. Callaway has been operating for more than 30 years.

For the baseline analyses, the licensee selected LOCA frequencies in NUREG-1829 corresponding to 25 years of operation and considered 40-year frequencies in the sensitivity analyses.

The guidance in NUREG-1829 provides LOCA frequencies that are based on a formal expert elicitation process. Several aggregation schemes are presented in NUREG-1829 that combine, or aggregate, the inputs of the individual experts into a single set of frequencies that can be used for decision-making. The two primary aggregation schemes are the geometric mean, and simple average or arithmetic mean. Because alternate aggregation methods can lead to significantly different results, NUREG-1829 states that different methods may be appropriate for different applications and recommends that multiple methods and sensitivity studies be considered when selecting an aggregation method. The licensee provided a rationale for using geometric mean aggregation NUREG-1829 LOCA frequencies in the Baseline quantification of the CDF (Question 36 in enclosure 5 to Reference 6), based on consistency with recommendations and observations in NUREG-1829, consistency with inputs in the PRA model of record to compute the total CDF, and numerous approaches and assumptions adopted to ensure safety margin. Arithmetic mean aggregation was considered in sensitivity analyses to address uncertainty in LOCA frequencies. The arithmetic mean aggregation source frequencies from NUREG-1829, table 7.13, Total BWR and PWR LOCA Frequencies (Using Arithmetic-Mean Aggregation with Error-Factor Overconfidence Adjustment), used in the sensitivity analyses conservatively included contributions from SGTR LOCAs, which the licensee concluded do not contribute to the total risk (see section 3.4.2.1.1 of this SE).

The licensee summarized CDF results in table 9-1 of attachment 3-3 of enclosure 3 to the supplemental letters dated October 7, 2021, and January 27, 2022 (References 5 and 6). The licensee also examined the effect of assuming every break to be a DEGB (as opposed to the baseline approach of considering breaks of variable size less or equal than the pipe diameter) and concluded that the corresponding CDF is only slightly greater than the baseline CDF considering continuum break sizes. The licensees approach for evaluating the impact of the aggregation method and the continuum break and DEGB alternatives is consistent with the recommendation in NUREG-1829. The NRC staff reviewed the licensees sensitivity analysis and concluded that the licensee identified and dispositioned key assumptions and sources of uncertainty in its systematic risk assessment consistent with the guidance in RG 1.174. The NRC staffs review of this topic is discussed in section 3.4.2.9, of this SE.

NRC Staff Conclusion Regarding Initiating Event Frequencies The NRC staff reviewed the licensees information on initiating events and concludes that the initiating event frequencies selected by the licensee for this evaluation are acceptable because:

LOCA break frequencies were obtained from NUREG-1829, which is considered to be the most current source of information available.

The licensee interpreted the NUREG-1829 data in a manner consistent with the guidance in NUREG-1829.

The licensee performed sensitivity analyses to address the selection of LOCA frequencies from NUREG-1829 using the arithmetic mean and the geometric mean aggregated frequencies, continuum break and DEGB models, and 25-year and 40-year plant life frequencies.

The licensee identified several approaches and assumptions contributing to safety margin to justify the selection of geometric mean NUREG-1829 frequencies for baseline computations (enclosure 5 of Reference 6; Question 36).

3.4.2.3 Scenario Development For the purposes of this SE, the term scenario means an initiating event followed by a plant response such as a combination of equipment successes, failures, and human actions leading to a specified end state, such as successful event mitigation, core damage, or large early release.

The licensee considered system response to a LOCA break in the presence of debris based on a 30-day mission time. In the CASA Grande model, fiber debris amounts were selected as the limiting debris that may challenge the strainer function. Other debris types (i.e., particulates and chemical precipitates) were addressed by including bounding amounts in strainer testing. As described in section 2.1 of this SE, the Callaway system includes two independent ECCS and CSS trains connected to two independent sumps with strainers. The risk-informed analysis by the licensee assumed only one train would operate, to maximize debris amounts loaded on a single strainer. The CASA Grande model is aimed at the computation of debris quantities for postulated breaks and transported debris under simplified assumptions, independently of pump configurations. The licensee conservatively assumed that debris accumulates on a single strainer (debris penetrating strainers and accumulating in the core was ignored in the CASA Grande computations).

The licensee implemented independent computations to examine in-vessel debris buildup. The licensee assumed two operational trains of ECCS and one CSS train. This pump and flow state tends to maximize fiber build-up in the vessel (more fiber would penetrate two operational strainers, than the single strainer considered in the CASA Grande model). The in-vessel mass balance computations were complementary to the CASA Grande computations, focusing only on cases with 300 lbm of fiber initially in the pool which would not cause strainer failure. Breaks causing more fiber in the pool were declared as breaks causing strainer failure in the CASA Grande model computations and did not require additional examination as part of the in-vessel buildup computations.

The licensee excluded other initiating events causing different scenarios (see section 3.4.2.1.1 of this SE).

NRC Staff Conclusion Regarding Scenario Development The NRC staff evaluated the licensees scenario development process and results and concludes that the licensee adequately evaluated the relevant scenarios potentially causing strainer failure and in-vessel fiber buildup. The licensee considered models greatly simplifying the description of the system response. The licensee used a systematic process to identify germane operating components and states, and properly considered the period of performance in the risk-informed analysis. The NRC concluded that the licensee consideration of only one functional ECCS-CSS train for strainer debris bed analysis and two functional strainers for in-vessel buildup analysis is adequate because it maximizes the probability of system failure.

3.4.2.4 Failure Mode Identification The following are potential debris-related failure modes for the ECCS LTCC function. Each of these failure modes should be considered and specifically evaluated, or shown to be irrelevant, to the risk-informed evaluation. Other potential failure modes should be evaluated, as necessary, for plant-specific conditions. The licensee evaluated each of the phenomena below and did not identify additional failure modes. These failure modes are only those related to debris.

a. Excessive headloss at the strainer leads to loss of NPSH for adequate operation of the pumps

b. Excessive headloss at the strainer causes mechanical collapse of the strainer.

c. Excessive headloss at the strainer lowers the fluid pressure, causing release of dissolved gases (i.e., degassing) and void fractions in excess of pump limits. Vortexing and flashing may also cause pump failure due to excessive void fraction in the fluid.

d. Debris prevents adequate flow to the strainer or prevents the strainer from attaining adequate submergence.

e. Debris in the system downstream of the strainer exceeds ex-vessel limits (e.g., blocks small passages in downstream components or causes excessive wear).

f.

Debris results in core blockage, and decay heat is not adequately removed from the fuel.

g. Debris buildup on cladding results in inadequate decay heat removal.

h. Debris buildup in the vessel leads to excessive boron concentrations within the core.

The licensee evaluated relevant failure modes in its risk-informed analysis in enclosure 3, attachment 3-2 of the supplemental letter dated October 7, 2021. The licensee evaluated the failure modes a and c, headloss and vortexing, based on testing of limiting debris amounts (except for fiber), and concluded that vortexing (part of failure mode c) will not occur for both large and small breaks, and for full debris load (FDL) and thin bed (TB) conditions as discussed in attachment 3-2 of enclosure 3, section 3.f.3 to the supplemental letter dated October 7, 2021.

For the deaeration (voiding) part of failure mode c, the licensee provided a supplemental

analysis to demonstrate voiding will not adversely affect pump performance in enclosure 5 to the supplemental letter dated January 27, 2022 (Question 15). For the failure mode a (NPSH),

the licensee concluded that sufficient suction head would be available for adequate function of pumps, accounting temperature and friction factors as discussed in attachment 3-2 of enclosure 3 sections 3.g.2, 3.g.4 to the supplemental letter dated October 7, 2021. For failure mode d (submergence), the licensee concluded enough submergence for adequate strainer operation and to ensure adequate NPSH in attachment 3-2 of enclosure 3, sections 3.f.3, 3.g.9 to 3.g.12, and 3.I to the supplemental letter dated October 7, 2021). For failure mode b (mechanical collapse), the licensee concluded sufficient strength of the strainer but crediting Carboline 193LF primer and 191HB topcoat as qualified coatings in attachment 3-2 of enclosure 3, section 3.k.2 to the supplemental letter dated October 7, 2021. The licensee addressed failure modes f to h (fuel and vessel effects) considering the methodology in TR WCAP-17788-P, with modifications to account for strainer filtration efficiency as a function of debris loads as well as shedding rates from debris beds in attachment 3-2 of enclosure 3, section 3.n to the supplemental letter dated October 7, 2021.

NRC Staff Conclusion Regarding Failure Mode Identification The NRC staff evaluated the licensees analysis and compared the licensees failure modes to those established by the staff and determined that the failure modes evaluated by the licensee include all those that could reasonably lead to debris-induced failure of LTCC. Therefore, the NRC staff concludes that the licensee included the appropriate failure modes in its evaluation.

3.4.2.5 Changes to the Base PRA Model The licensee used the Callaway PRA model of record as the source of the base CDF and LERF values and to define the probability of valve failure to examine breaks downstream of normally closed valves. The Callaway PRA model was not modified to incorporate initiating events for the GL 2004-02 risk-informed analysis. The licensee performed the risk quantification outside the PRA model, and conservatively assuming specific equipment configurations.

NRC Staff Conclusion Regarding Changes to the Base PRA Model The NRC staff reviewed the information provided by the licensee and concluded that the use of the Callaway PRA model of record, without changes, is acceptable to provide supplementary information required by the risk-informed assessment implemented by the licensee.

3.4.2.6 Debris Source Term Submodel This section describes the debris that may be generated during an initiating event or may be present in the containment prior to the event. It includes a description of the debris sizes and characteristics that may transport to the strainers and affect the ability of the ECCS and CSS to perform their functions. Additionally, this section evaluates the parts of the deterministic analyses that deal with debris source term to determine whether the licensee used appropriate inputs to the risk-informed analysis.

The licensee conducted strainer headloss tests with bounding amounts of debris generated by LOCA initiating events, except for fibrous debris. The fibrous debris amount in the testing was used to define fail/pass criterion for strainer performance. The strainer testing considered bounding amounts of particulates (coating and latent particle surrogates), chemical precipitate surrogates (calcium phosphate and sodium aluminum silicate), and 300 lbm (plant equivalent) of

LDFG (enclosure 3, attachment 3-2, section 3.f.4 of the supplemental letter dated October 7, 2021). The 300 lbm fiber amount figure was used to define a fail/pass criterion.

The licensee conducted a risk-informed debris generation evaluation that considered the sources of debris that may affect system performance. The risk-informed debris generation evaluation included thousands of debris generation cases based on postulated breaks at all welds that could result in a LOCA. The evaluation considered hundreds of welds with breaks of varying size and orientation at each weld. Any break that was computed to generate and transport more fibrous debris than was included in the strainer tests is assumed to cause strainer failure and core damage.

3.4.2.6.1 Break Selection This section describes the licensees process to identify the break sizes and locations that present the greatest challenge to post-accident sump performance. The licensee provided a summary of the break selection process in enclosure 3, attachment 3-2 s well as the method to address debris generation and ZOI, in sections 3.a and 3.b. The licensee also considered other potential initiating events (debris generation locations). Some of these initiating events were excluded from the systematic risk assessment or were not explicitly considered in the break selection process.

The licensee evaluated LOCA breaks at all weld locations in ASME Class-I piping. The licensee also considered secondary line breaks (large main steam and feedwater line breaks) but concluded those only marginally contribute to the CDF based on information from the PRA model and conditional sump failure probabilities computed with the CASA Grande model.

The licensee implemented a simplified risk-informed analysis relying on the CASA Grande software, considering a range of potential break sizes and orientations on welds in Class-I piping. The CASA Grande model uses a Callaway CAD as input to define welds locations and insulation and qualified coating distributions. Debris amounts are computed in the CASA Grande software based on a ZOI concept. Debris sources that are not break-dependent, such as latent debris and unqualified coatings debris, were also evaluated by the licensee.

The licensee assembled a three-dimensional CAD model of the Callaway containment building, tracking the as-built insulation configuration and qualified coating distribution. The CAD model was used as input to the CASA Grande software to calculate debris quantities for each different break. CASA Grande implemented a ZOI concept to compute the amount of debris generated.

The ZOI represents the zone or volume in space where a two-phase jet from a HELB can generate debris that may be transported to the sump. The size of the ZOI is defined in terms of pipe diameters and is determined based on the system pressure and the destruction pressure of the insulation material impacted by the jet. Higher system pressures result in increased ZOIs.

Robust insulation materials have smaller ZOIs than fragile materials. The licensee considered each circumferential butt weld as a postulated break location, with partial breaks1 of different size up to DEGBs.2 For each partial break size, the licensee considered different orientations of the hemispherical ZOI, in 1-degree angular increments, to evaluate a range of debris sources 1 The licensee defined a partial break as a break of diameter less than the pipe diameter. The ZOI was assumed to be of hemispherical shape for partial breaks and centered at the pipe axis.

2 A DEGB is a break of size equal to the pipe diameter, with a full pipe offset. The ZOI was assumed to be spherical and centered at the axis of the pipe at the break location.

located around a break. The amounts of different types of debris were computed and compiled in a database generated by CASA Grande.

The licensee stated that the Callaway debris generation analysis was performed in accordance with the NRC-approved methodology of NEI 04-07. The licensee highlighted the following levels of conservatism in the analysis:

A large RCS pipe is more likely to leak and be detected by the plants leakage monitoring systems long before cracks grow to unstable sizes (referred to as leak-before-break detection).

The ZOI concept is based on bounding results. For example, debris destruction tests considered of worse case insulation seam orientation. Also, some insulation is expected to be of greater structural integrity than tested materials.

The analysis did not take credit for shielding within the ZOI by equipment (e.g., steam generators, reactor coolant pumps) and large piping.

Unqualified coatings were conservatively assumed to fail instantaneously as particulates.

The latent debris evaluation followed the NEI 04-07 guidance, which greatly overestimates latent debris amounts.

Strainer testing included bounding amounts of all debris types except for fibrous debris. The licensee listed all breaks (i.e., a specific break location, size, and orientation) that produced at least 300 lbm of fibrous debris buildup on the strainer in attachment 3-3 of enclosure 3, table 9-3 to the supplemental letter dated October 7, 2021. A total of 60 welds out of 411 were computed to produce break cases with fibrous debris exceeding 300 lbm at the strainer. The strainer fibrous debris amounts include ZOI-dependent (debris from insulation and qualified coatings) and ZOI-independent (latent debris and unqualified coatings) amounts. The ZOI-independent debris amounts are assumed to be the same for all breaks In response to Questions 8, 9. and 34 in enclosure 5 to the supplemental letter dated January 27, 2022, the licensee provided information regarding the potential for breaks at locations other than welds. The licensee stated that potential break locations other than those at Class-I welds do not contribute to the total risk. The licensee stated that the guidance in NUREG-1829 recognizes welds as the likely failure locations. The licensee also stated that the weld locations considered in the analysis are adequate to cover other potential break locations due to their proximity to the debris sources. Other scenarios were found to generate relatively small amounts of fibrous debris or result in plant conditions less challenging than LBLOCAs.

NRC Staff Conclusion Regarding Break Selection The NRC staff concludes that the break selection evaluation is acceptable because the licensee evaluated all welds on ASME Code Class-I pipes that can result in a LOCA. Although the NEI 04-07 guidance approved by the NRC states that the licensee should evaluate all pipe locations for potential rupture, the staff concludes that the licensees evaluation of piping only at welds is acceptable because the weld locations adequately represent the potential debris

generation of all breaks and are more likely break locations, consistent with recommendations in NUREG-1829.

The NRC staff concludes that the break selection process and criteria are acceptable because it identifies a number of postulated LOCAs of different sizes, locations, and other properties sufficient to provide assurance that the most severe postulated LOCAs are calculated as part of an acceptable evaluation model as required, in part, by 10 CFR 50.46.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning the break selection criteria. In its submittal the licensee:

Described and provided the basis for the break selection criteria used in the evaluation.

Examined the potential contribution of secondary line breaks (e.g., MSLs and FWLs).

Discussed the basis for reaching the conclusion that the break size(s) and locations chosen to present the greatest challenge to post-accident sump performance.

The licensee provided a basis for the use of the break selection process in the overall evaluation of change in risk due to LOCAs. The licensee evaluated all Class-I welds as potential break locations, determined the smallest break size at each location that could exceed the acceptance criteria (fiber test limit). The licensee computed the CDF accounting for the break frequency and assuming core damage for breaks exceeding the acceptance limit. The NRC staff concludes that the break selection methodology is acceptable to support estimates of risk.

3.4.2.6.2 Debris Generation and ZOI Submodels The licensee defined the ZOIs for Transco reflective metal insulation (RMI) and RMI-Mirror using NRC-approved guidance in NEI 04-07. ALION Science and Technology (ALION)

Proprietary report ALION-REP-ALION-2806-01 Insulation Debris Size Distribution for Use I GSI-191 Resolutions, Revision 4 (Reference 60), was used to define the ZOIs for NUKON and Thermal-Wrap. This report was reviewed by the NRC during and Indian Point Energy Center (Indian Point) audit (Reference 61) and found to be acceptable. The licensee concluded that Min-K and AlphaMat would not be destroyed based on site-specific testing. The licensee adopted debris size distributions for NUKON and Thermal-Wrap based on testing. The licensee calculated the amounts of debris and debris size distributions that could be generated from each postulated break. To compute the probability of sump strainer failure, the licensee compared the computed fibrous debris amounts for each postulated break that accumulate on the strainer to debris limits based on testing.

The ZOIs for each material are summarized in table 3.b-1, Destruction Pressure and ZOI Radii for Potential Debris Sources, in attachment 3-2 of enclosure 3 to the supplemental letter dated October 7, 2021. In the following discussion, the symbol D is used to represent the break size.

The ZOI is assumed of hemispherical shape for partial breaks on circumferential welds or breaks on longitudinal welds, and of spherical shape for DEGBs on circumferential welds. The size of the ZOI is defined by the radius of the sphere or hemisphere, and expressed as multiples of the break size D and symbolized with L. More robust materials have higher damage pressures and smaller values of radius/D.

NUKON and Thermal-Wrap Insulation For its risk-informed analysis, the licensee used a 17D ZOI for Thermal-Wrap and NUKON, which is consistent with the guidance in NEI 04-07. The licensee considered debris size distribution within the 17D ZOI using ALION proprietary subzones, which define different percentages of debris sizes for each subzone. The debris sizes consisted of fines, small pieces, large pieces, and intact blankets. The licensee used a similar approach to the Indian Point, which was found acceptable by the NRC staff in a letter dated July 29, 2008 (Reference 61).

The debris size distributions for each subzone are based on air jet impact tests (tests implemented in consistency with the methodology of Appendix II of the NEI 04-07 guidance document). Closer to the break, the debris produced is mainly fiber fines and small fiber pieces.

Further from the break, the debris is mostly large pieces of fiber.

Min-K and Alphamat D The licensee concluded Min-K blankets cannot be impacted by HELB jets. The NRC staff found this to be acceptable due to limited lateral offset and no separation of the piping at postulated breaks in the reactor cavity, which results in no jet impingement on these materials. The pipe restraints in the reactor, prevent pipe separation. The evaluation of the potential for debris generation also cited the geometry of equipment in the cavity that would preclude a jet from striking the insulation should one occur (Reference 62) and (Reference 63) ( (Issue 7). Similarly, the licensee concluded that Alphamat D cannot be destroyed by HELBs because Alphamat D is in a similar location to the Min-K blankets.

FOAMGLAS In 2019, the licensee discovered FOAMGLAS installed in the containment. Prior to this discovery, the insulation was thought to be NUKON so the FOAMGLASS material had not been evaluated as debris. Because the risk-informed analysis assumed that the insulation was LDFG instead of FOAMGLASS, the amount of fibrous material was overpredicted and particulates underpredicted for some breaks. During the audit, the NRC staff questioned whether the FOAMGLAS should be considered as a particulate debris source to ensure that particulate debris amounts used during testing were not exceeded. The licensee responded in its supplemental letter dated January 27, 2022 (enclosure 5, Question 10). The licensee stated that the modeling of FOAMGLAS as LDFG increased the calculated risk metrics because it caused some breaks to exceed the fiber limit when they would not have if the insulation was modeled as FOAMGLAS. The licensee also stated that if the FOAMGLAS was assumed to be 100 percent particulate and fully transported to the strainer, it would add 1167 lbm of particulate to the debris load. The minimum particulate margin for relevant breaks is 1081 lbm. The licensee stated that, due to its physical properties and the stainless steel jacketing covering the insulation, the FOAMGLAS would not be destroyed into 100 percent particulate fines and that the particulates would be larger, thus having a smaller effect on headloss than the particulates used in the testing. Those particulates tend to float in water and are likely to be trapped in structures. The licensee also stated that it is unlikely that all the FOAMGLAS would be damaged by a jet from a single break due to the geometry of the piping and the spread distribution of FOAMGLAS on the piping. The licensee evaluated the potential chemical impacts of FOAMGLAS and stated that the potential increases calculated by assuming that the FOAMGLAS was E-Glass were bounded by the amounts of chemical precipitates included in the testing.

The NRC determined that the licensees evaluation of FOAMGLAS performed in response to NRC staff questions was acceptable. The NRC found the response acceptable because the licensee assumed the FOAMGLAS was fiberglass, which is the limiting debris type. The licensee also evaluated the FOAMGLAS as particulate and examined its potential effects on chemical precipitates. The amount of particulates in strainer tests bounded the amount that could be generated, with few exceptions. For the few exceptions that the total amount of generated particulate debris, using bounding assumptions, did not significantly exceed the strainer test amount. Assuming a small fraction of the FOAMGLAS particulates would not transport to the strainer was sufficient to ensure the total particulate amount in strainer tests was still bounding. The NRC staff also noted other conservatisms associated with the particulate debris amounts used in the testing, including to consider Carboline 193LF primer with 191HB topcoat as unqualified coating. For the chemical effects evaluation, the NRC staff found that the tested amounts of chemicals remained bounding of the alternate FOAMGLAS case.

Transco RMI The licensee considered the NRC-approved methodology in NEI 04-07 and adopted a default value L/D equal to 2.0 to define the ZOI radius.

Risk-Informed Analysis The licensee followed the debris generation calculation methodology specified in NEI 04-07 and justified adopted deviations from the guidance. The licensee evaluated a full range of breaks instead of assessing only the limiting breaks, as recommended in NEI 04-07. All unisolable welds within the Class-I ISI pressure boundary (i.e., welds inside the first isolation valve) were evaluated, including DEGBs and partial breaks. In order to calculate thousands of break scenarios, the licensee considered a CAD model describing the insulation configuration and location of robust barriers within the containment, in conjunction with the CASA Grande software to automate computation of insulation and qualified coating amounts within the ZOI of each postulated break. The licensee calculated debris amounts for breaks in each circumferential weld, ranging from 1/2 inch to full DEGB, and considered a range of orientations for each break size. For DEGBs, a spherical ZOI was assumed centered at the axis of the pipe in the plane of the weld. For the partial breaks on circumferential welds, the ZOI was a hemisphere oriented normal to the pipe axis and also centered at the pipe axis (enclosure 5 to the supplemental letter dated January 27, 2022, Question 7). The smallest break size computed by the licensee to potentially cause strainer failure was 9.145 inches in the baseline analysis in attachment 3-3 of enclosure 3, table 9-1 of the supplemental letters dated October 7, 2021 and January 27, 2022.

CASA Grande code algorithms have been evaluated previously by the NRC staff as part of the STP pilot license amendment application related to GL 2004-02, supported by audits and independent calculations sponsored by the NRC to explore the adequacy of the CASA Grande software to identify insulation and coating sources and debris amounts. The NRC staff concluded that use of CASA Grande in conjunction with a detailed CAD model is a reliable approach to quantify potential debris amounts within the ZOI of a postulated break.

The licensee identified a total of 411 welds in the baseline scenario in attachment 3-3 of enclosure 3, table 10-1 to the supplemental letter dated October 7, 2021, and 704 welds in general including welds downstream of the isolation valve in attachment 3-2 of enclosure 3, section 3.b.4 to the supplemental letter dated October 7, 2021, as potential LOCA break locations distributed throughout the containment.

The licensee assumed that fixed amounts of unqualified and qualified but degraded coatings would detach immediately after the LOCA event and form particulate debris that could be transported to the strainer for any break. The licensee considered the presence of 200 pounds of latent debris, of which 15 percent was assumed in the form of fibrous debris (30 pounds) and 85 percent in the form of particulate (170 pounds). The estimated total amount of particulate from unqualified and qualified but degraded coatings and from latent debris was 4,614 pounds (attachment 3-2 of enclosure 3, table 3.b-2 to the supplemental letters dated October 7, 2021, and January 27, 2022), which was considered to be the same for all of the postulated breaks, independent of the radius of the ZOI.

The licensee also considered ZOI-dependent sources of particulates such as qualified inorganic zinc and qualified epoxy. From information in table 3.b-2 of attachment 3-2 of enclosure 3 to the supplemental letter dated October 7, 2021, the dominant proportion of particulates from any break is from ZOI-independent sources (unqualified or degraded coatings).

Strainer tests were conducted with bounding amounts of particulate, with an equivalent of 5,800 lbm of plant amount, and 300 lbm of fiber. The licensee evaluated each postulated break size, location, and orientation for the evaluated welds to determine if the fibrous debris generated and transported from that break exceeded the 300 lbm testing amount. Strainer failures were assumed to occur if fibrous debris transported to the strainer exceeded the tested amount equivalent to 300 lbm of fiber.

The licensee programmed algorithms in the CASA Grande software to automate computation of debris amounts generated by each postulated break location at each size and orientation. The licensee provided a list of 60 welds for which strainer failure was computed to occur in the baseline analysis (for specific postulated breaks on those welds) in table 7-3 of attachment 3-3 of enclosure 3 to the supplemental letters dated October 7, 2021, and January 27, 2022.

The NRC staff concludes that the licensee properly quantified amounts of debris that could be generated within the Callaway containment by the postulated LOCA breaks. The analysis included ZOI-dependent (e.g., fibrous debris from different insulation types, and qualified coatings) and ZOI-independent (e.g., dust and latent debris, unqualified and degraded coatings). For the ZOI-dependent debris, the licensee computed debris amounts using CASA Grande, which relied on a CAD model capturing the location and distribution of insulation and debris sources within the containments. For each break (of specific location, size, orientation, and ZOI), CASA Grande used CAD model information to determine debris amounts for each material type. For each break, the CAD model clipped the ZOI to account for robust barriers.

The NRC staff previously concluded that algorithms in the CASA Grande code for the computation of debris were properly implemented. The licensee adequately considered random factors such as the break size and jet orientation and identified debris amounts to compare to strainer test results. The NRC staff concludes that the licensees methodology to calculate debris loads for each postulated break is acceptable.

NRC Staff Conclusion Regarding Debris Generation and ZOI Submodels The NRC staff notes that the licensee considered guidelines in the NEI 04-07 report to (1) define ZOIs; (2) account for robust barriers; (3) compute debris amounts of LDFG and fibrous insulation, and particulate sources such as qualified coatings; (4) compute debris size distributions; and (5) estimate debris amounts associated with latent fiber, latent particulate, and unqualified and damaged or degraded qualified coatings.

The NRC staff verified that the licensees debris generation calculations were performed accurately and used acceptable assumptions. The NRC staff used a combination of confirmatory calculations, engineering judgement, and review of the licensees software outputs to perform the verifications. The Callaway method to compute debris amounts relies on the CASA Grande software, which was examined in detail as part of the pilot GL 2004-02 risk-informed evaluation for STP. This approach allows the NRC staff to conclude, with a high level of confidence, that the calculations for debris generation were conducted and applied properly.

The NRC staff reviewed the licensees evaluation against the NRC staff-accepted guidance and concludes that the licensee adequately determined for each postulated break location, size, and orientation, the zone within which debris would be generated by a two-phase jet. The NRC staff also concludes that the amount and characteristics of debris predicted to be generated are acceptable. The licensee calculated amounts for all types of debris and compared these values to the amounts of debris included in strainer headloss tests. Any break that results in any type of debris reaching the strainer exceeding the amounts in the test is assumed to lead to strainer failure and contribute to the plant risk. The licensees methods are consistent with NRC guidance. Therefore, the NRC staff concludes that the licensees evaluation of the ZOI and debris generation is acceptable. The amounts of debris from each postulated break scenario were determined appropriately.

The NRC staff concludes that debris generation and ZOI analysis and methodology are acceptable because it identifies a number of postulated LOCAs of differing properties sufficient to provide assurance that the most severe postulated LOCAs are calculated. Also, the NRC staff concludes that the debris generation and ZOI submodel described in the LAR is acceptable for use in an assessment or evaluation model of the effects of debris on long-term cooling of ECCS, as required, in part, by 10 CFR 50.46.

The NRC staff concludes that the licensee provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning the debris generation and ZOI, because the licensee:

Described the methodology used to determine the ZOIs for generating debris.

o Identified which debris analyses used approved methodology default values.

o For materials with ZOIs not defined in the guidance report discussed methods used to determine ZOI and the basis for each.

Provided destruction ZOIs and the basis for the ZOIs for each applicable debris constituent.

Identified destruction testing conducted to determine ZOIs.

Quantified the quantity of each debris type generated for each break location, size, and orientation evaluated.

3.4.2.6.3 Debris Characteristics The licensee generally used the NRC staff SE on NEI 04-07 to evaluate the debris characteristics.

NUKON and Thermal-Wrap Insulation For fibrous debris, the licensee used the four-size distribution described above in section 3.4.2.6.2 of this SE (Reference 60). This methodology is based on the NEI 04-07 guidance. This approach is similar to that used by Indian Point, which was reviewed and found acceptable by the NRC staff in a letter dated July 29, 2008 (Reference 61).

RMI For RMI, the licensee used the GR/SE guidance to determine the size distributions. The licensee concluded that RMI would not result in increased headloss if it transported to the strainer. Therefore, it was not included in headloss testing. During the audit, the NRC staff questioned whether the RMI could fill the sump pits and create a filtering bed that would have a smaller area than the strainer, thus potentially resulting in higher headlosses. In response, the licensee demonstrated that significant amounts of RMI would not transport to the sump pit (enclosure 5 to the supplemental letter dated January 27, 2022, Question 12).

FOAMGLAS Because FOAMGLAS is not discussed in NRC approved guidance for debris characteristics, the licensee did not have guidance to refer to for its debris characteristics. The licensee used the guidance discussed above for NUKON to estimate the FOAMGLASS characteristics.

The licensee provided the as fabricated and material densities of the fibrous materials and the RMI. Because headloss testing (not theoretical calculations) was used to establish the headlosses caused by the debris, the specific surface areas of the materials were not provided.

NRC Staff Conclusion Regarding Debris Characteristics The NRC staff concludes that the debris characteristics were defined per the applicable guidance with the exception of FOAMGLAS. For FOAMGLAS, the licensee assumed that the FOAMGLAS was equivalent to NUKON, which is the limiting material in the analysis. In its post-audit supplement, the licensee examined the outcome of assuming FOAMGLAS to form debris particulates. As discussed in section 3.4.2.6.2 of this SE, the NRC staff found the treatment of FOAMGLAS acceptable.

The NRC staff concludes that the licensee provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning the debris characteristics, because the licensee:

Identified debris characteristics using an approved methodology and default values where available.

For the FOAMGLAS material that is not defined in the guidance, examined scenarios that conservatively bounded the effects of the debris considering the potential characteristics of the material.

3.4.2.6.4 Latent Debris The licensee followed the guidance in the GR/SE to evaluate latent debris. A bounding value of 200 lbm of latent debris was assumed in the analysis, with the recommended 15 percent being latent fiber. The remaining 85 percent of the latent debris was assumed to be particulate.

The licensee sampled containment to determine the actual amount of latent debris present, following accepted guidance. The licensee performed one round of sampling that determined that approximately 60 lbm of latent debris was in containment. The sampling was repeated after the replacement of steam generators yielding approximately 44 lbm of latent debris.

The licensee provided the assumed characteristics for the fibrous and particulate latent debris and stated that the characteristics are consistent with the GR/SE.

The licensee stated that 200 square feet (ft2) of miscellaneous debris (tags and labels) were assumed to transport to the strainer with 25 percent overlap, per NRC guidance. The NRC staff questioned how the value for 200 ft2 of miscellaneous debris was developed during the audit.

The licensee responded in its post audit supplemental letter dated January 27, 2022 (enclosure 5, Question 11) that large tags, labels, and signs were removed from containment.

The remaining potential sources of miscellaneous debris were identified via walkdowns and design reviews. The licensee determined that 84.1 ft2 of potential miscellaneous debris that could transport to the strainer still remains in containment.

The NRC staff concludes that the licensee provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning latent debris, because the licensee:

Identified the amounts of latent debris and miscellaneous debris in containment using an approved methodology.

Used conservative values in the headloss analysis compared to the actual values in containment.

Identified debris characteristics using an approved methodology and default values.

3.4.2.6.5 Coatings The licensee stated that the coatings evaluation was performed in accordance with the guidance in the GR/SE. The licensee defined its DBA qualified coatings systems used in the containment and provided the coating systems and manufactures of those systems considered to be qualified. The licensee stated that all other coatings were assumed to be unqualified. The licensee listed the generic types of unqualified coatings and the major unqualified coating systems.

The licensee discussed the assumptions used for coatings transport. The licensee assumed that the unqualified coatings fail as 10-micron particulate and transport 100 percent to the strainer. The licensee also assumed the qualified coatings in the ZOI fail as 10-micron particulate and transport 99 percent to the strainer. The licensee provided chip sizes and transport fractions for degraded qualified coatings that could fail as chips. The licensee also designated the degraded qualified coatings as particulate in the headloss testing because this

typically results in higher debris headloss for conditions, like Callaway, where a contiguous debris bed can form on the strainer. The NRC staff asked a question during the audit regarding the statement that recirculation transport is the only credited transport phenomenon for the degraded qualified coatings. In its post-audit supplemental letter dated January 27, 2022 (enclosure 5, Question 14), the licensee provided a clarification and revision to attachment 3-2 of enclosure 3 to this supplemental letter dated January 27, 2022, to clarify the transport assumption.

The licensee stated that headloss testing adjusted the amount of particulate debris to ensure that the volume of coatings was conservative.

The licensee asserted that the coating surrogates used in testing were chosen to reflect an appropriate size distribution and provided a plot of the size distribution.

The licensee based the ZOI sizes for qualified coatings on NRC accepted jet impingement testing and staff guidance for reviewing the coatings evaluation. The licensee assumed the ZOI for epoxy topcoat to be 4D and exposed inorganic zinc coatings to have a 10D ZOI. The licensee determined the qualified coating debris amounts by using a three-dimensional model of containment that modeled the orientation of coated surfaces to postulated break jets. The licensee assumed the coated areas within the appropriate ZOIs fail and calculated the debris amounts using the dry film thicknesses and densities for the coating system on the impacted surface.

The licensee also included rust as a contributor to the coatings source term. Rust was identified on HVAC piping that is also insulated with an LDFG system. For areas of the pipe within 17D (the LDFG ZOI) the licensee assumed that the rust on the pipe failed as 10-micron particulate.

The licensee calculated the amount of particulate resulting from the corroded areas based on a 0.10-inch thickness (based on ultrasonic thickness measurements) and the area of the piping exposed. For areas of the piping that were not within the ZOI, the rust was assumed to remain in place and not contribute to the particulate source term.

The licensee assumed all unqualified coatings in containment fail regardless of location. The quantities of unqualified coatings were calculated similarly to the qualified coatings. The licensee provided a table of unqualified coating amounts since they are the same for all break scenarios.

The licensee discussed degraded qualified coatings, which are coatings that are initially installed as a qualified system but have physically degraded over time. The submittal cited testing performed on coating systems, which is applicable to the systems at Callaway. The testing showed that the inorganic zinc systems failed as particulate and the epoxy systems failed as chips. The licensee assumed that degraded qualified coatings in the containment fail for every postulated break. The licensee used the results of the testing to characterize the degraded qualified coatings for further evaluation during the transport and headloss evaluations.

The licensee stated that the plant conducts coating condition assessments at least each refueling outage. The inspections are visual and are performed on all accessible coated surfaces in containment. If the visual examination identifies degradation, additional testing is performed to determine whether the coating system remains qualified and if any corrective actions are required.

NRC Staff Conclusion Regarding Coatings The licensee performed its evaluation in accordance with NRC approved guidance. The guidance includes the GR/SE and subsequent guidance based on TR WCAP-16568-P, Jet Impingement Testing to Determine the Zone of Influence (ZOI) for DBA Qualified/Acceptable Coatings, dated July 12, 2006 (Reference 65), and subsequent NRC review guidance, Revised Guidance Regarding Coatings Zone of Influence for Review of Final Licensee Responses to Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized Water Reactors (Reference 66) for coatings evaluations. The debris generation amounts were determined using appropriate ZOIs and the debris volume was properly preserved for testing by correcting for density differences between the coatings and the test surrogates. The transport metrics used for the coatings debris were also based on the approved guidance.

The licensee further accounted for potential particulate debris generation from corroded materials within containment. The NRC staff reviewed the methodology used by the licensee for this inclusion in the debris source term and concluded that it was reasonable and likely conservative because it is unlikely that all of the corroded material would be liberated from the piping at a 17D ZOI jet pressure.

The licensee maintains a coatings condition assessment program that appropriately monitors, tests, and repairs coatings as required.

The NRC staff concludes that the licensee provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning coatings, because the licensee:

Identified the amounts of coatings materials in containment that can become debris using approved methodologies.

Used appropriate characteristics for the coatings as applied in the transport and headloss analyses.

Identified an appropriate coatings surrogate for testing and used conversions to assure that the volume of debris is preserved for the headloss tests.

Accounted for corrosion as a particulate debris source.

Identified a coatings assessment program to provide ongoing inspection and repair of qualified coatings systems.

3.4.2.6.6 Containment Material Control The licensee stated that housekeeping and foreign material control programs had been implemented to enhance containment cleanliness in Modes 1 through 4. These programs track all materials taken into containment during these modes and account for all items when exiting containment. In addition, work areas are cleaned and inspected to ensure that foreign materials have not been left in containment.

The licensee described programmatic controls used to ensure that design changes inside containment do not result in unanalyzed debris sources. All new components with coatings must use qualified coating systems. Materials added to containment are assessed for potential debris generation.

The licensee stated that procedures are in place to control maintenance activities and temporary modifications that may affect the debris source term. Guidance for design changes is also applied to temporary modifications.

During the steam generator replacement, the licensee replaced the insulation on the steam generators with RMI. The original insulation was jacketed NUKON. No additional insulation changes were described in the licensees submittal, nor were any planned for the future. The licensee stated that there are no actions planned to reduce the debris source term at the sumps.

NRC Staff Conclusion Regarding Containment Material Control The NRC staff concludes that the licensee provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning containment material control, because the licensee:

Identified the programs in place to reduce the introduction of debris during maintenance and modification activities, including temporary modifications.

Described significant actions taken to reduce the debris source term that may occur at the sumps.

NRC Staff Conclusion Regarding Debris Source Term Submodel Each of the aspects of the debris source term was evaluated. The NRC staff concluded that the debris source term submodel, including break selection, debris generation and ZOI, debris characteristics, latent debris, coatings, and containment material control were adequately addressed. Based on the evaluations for each of these subsections, the NRC staff concludes that the debris source term evaluation is acceptable.

The NRC staff concludes that the debris source term submodel (including break selection, debris generation and ZOI, debris characteristics, latent debris, coatings, and containment material control) is acceptable because it identifies a number of postulated LOCAs of sufficiently differing properties to provide assurance that the most severe postulated LOCAs are calculated.

Also, the NRC staff concludes that the debris source term submodel described in the licensees submittal is acceptable for use in an assessment or evaluation model of the effects of debris on long-term cooling of ECCS, as required, in part, by 10 CFR 50.46.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning the debris source term.

3.4.2.7 Debris Transport Submodel 3.4.2.7.1 Strainer Transport The licensee stated that the transport evaluation was primarily based on the methods in the GR/SE. The blowdown, washdown, pool fill, and recirculation phases were modeled in the evaluation. The licensee credited some holdups justified by the guidance in NUREG-CR-6369, Drywell Debris Transport Study, Volume 1, dated September 1999 (Reference 67). The licensee did not credit any inactive volume holdups until the pool height reached 6 inches (ECCS sump curb height) and no small or large pieces were assumed to transport to inactive cavities.

For the recirculation phase, the licensee used Flow-3D, Version 9.3 (computational fluid dynamics (CFD) software) to perform transport simulations. Although the licensee states that Stokes Law was used for determining the settling velocity of fine particulates, settling of fines was not credited. RMI debris was not considered in the recirculation transport analysis because the licensee claimed that any RMI in the debris bed would result in a decrease in headloss. The recirculation transport analysis compared transport metrics for the different debris types and sizes, determined via testing, to the local pool hydraulic conditions. If the velocity or turbulent kinetic energy in any specific area of the pool exceeded the metric, the debris in that region was considered to transport. The licensee stated that for the recirculation phase of the transport analysis all particulate fines and fiber fines transport 100 percent and do not settle.

The licensee assigned an erosion fraction of 10 percent to larger pieces of fiber in the pool and 1 percent for fiber held up on gratings. The pool erosion fraction based on 30-day erosion testing and the erosion for fiber held on gratings is justified by the Drywell Debris Transport Study. The 10 percent erosion fraction for fiber fines deviates from the recommended guidance in NEI 04-07 (which recommends a 90 percent erosion fraction for fiberglass debris). The licensee described that 10 percent erosion fraction was based on 30-day erosion testing by ALION completed in 2010 (Reference 64). In LDFG erosion testing conducted by ALION, it was determined that small and large pieces of fiber in the sump pool eroded at a rate below 10 percent. The NRC staff reviewed and developed conclusions regarding this report that are documented in a letter dated June 30, 2010 (Reference 68). The NRC staff concluded that plants that could demonstrate the testing was conducted under conditions that represented or bounded their plant could assume a 30-day erosion value of 10 percent for fiber settled in the sump pool.

The licensee stated that debris interceptors are installed at all openings in the secondary shield wall. These barriers were not credited for the capture of debris in the transport analysis. The licensee ran sensitivity studies for the recirculation portion of the transport analysis. These studies considered cases with the door barriers modeled as fully porous and as solid barriers.

The study that assumed the interceptors were fully blocked (solid barriers) resulted in greater transport fractions, so the interceptors were treated as solid barriers in the final CFD simulations.

The licensee stated that the overall transport fractions are determined by incorporating all phases of transport for each break location, which were summarized in table 3.e.1 in attachment 3-2 of enclosure 3 to the supplemental letter dated January 27, 2022.

The licensee used the maximum transport fractions for all break locations evaluated in the analysis. During the regulatory audit, the NRC reviewed the transport calculations and logic trees and confirmed that the calculations were performed correctly.

The licensee did not consider any amount of fiber penetration through the strainer for downstream and in-vessel effects when evaluating strainer failure scenarios. Ignoring fiber penetration is a conservative approach with respect to strainer effects.

3.4.2.7.2 In-Vessel Transport The licensee calculated the amount of debris that could reach the reactor core by penetrating the strainer and transporting through the ECCS. The strainer penetration behavior was determined by the licensee by performing plant-specific testing for Callaway in 2016. The testing used a scaled strainer and included scaled amounts of debris based on the ratio of plant to the test strainer areas. The results of the fiber penetration testing were used in the calculation of in-vessel debris amounts for various scenarios using empirical equations for fiber penetration and shedding.

The licensee performed the in-vessel debris loading calculation for different scenarios to assure that the maximum amount of debris reaching the core over time was determined. The fiber accumulation calculation assumed that 300 lbm was initially suspended in the pool and then transported to, and accumulated on, the strainer and inside the vessel. Break scenarios that generate and transport greater than 300 lbm of fiber are already assumed to result in strainer failure. The analysis found that the safeguards condition with one spray pump unavailable and all ECCS pumps operating resulted in the largest amount of debris reaching the vessel, of the potential plant-specific scenarios within the licensing basis. The NRC staff discussed the methodology with the licensee during the regulatory audit (enclosure 5 of Reference 6; Question 22 to ensure that the scenarios considered would result in limiting in-vessel fiber loads and determined that the plant conditions assumed in the evaluation were limiting. The licensee also stated that the pump would not be secured prior to the transport of all debris to the core, validating the assumption of CSS operation in the limiting case. The licensee calculated that approximately 89 grams of fiber per fuel assembly (g/FA) could reach the core.

During the regulatory audit, the NRC staff evaluated the empirical equations to compute fiber penetration through the strainer and found that the methodology potentially underestimated the amount of fiber reaching the reactor core compared to plant-specific test results for Callaway.

The licensee responded to this finding in its post-audit supplemental letter dated March 8, 2022 (Reference 7; Question 23). The licensee determined that plant-specific test results were more closely reproduced by doubling the shedding rate and recalculated the in-vessel fiber buildup.

The updated values are discussed in section 3.4.2.8.8 of this SE. The correction of the shedding rate resulted in the total in-vessel fiber amount increasing from 89 g/FA to 92 g/FA.

The results of the transport evaluation are important inputs for the strainer and in-vessel evaluations that are further evaluated in this SE.

NRC Staff Conclusions Regarding the Debris Transport Submodel The licensees approach to evaluating debris transport was consistent with the NEI 04-07 guidance and its associated NRC staff SE, and the licensee provided information requested in the content guide for GL 2004-02. For the in-vessel evaluation, the licensees approach followed the NRC staff accepted guidance from TR WCAP-17788-P.

The NRC staff reviewed the licensees transport evaluation against the NRC staff-accepted guidance in NEI 04-07 and verified the consistency of the computed debris amounts. The NRC staff concludes that the licensee appropriately estimated the fraction of debris that would transport from debris sources within containment to the ECCS strainers. For the in-vessel analysis, the NRC staff verified the licensees analyses with simplified independent calculations.

Therefore, the NRC staff concludes that the licensees evaluation of debris transport is acceptable.

The NRC staff concludes that the debris transport submodel described in the LAR is acceptable for use in an assessment or evaluation model of the effects of debris on long-term cooling of ECCS, as required, in part, by 10 CFR 50.46.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning debris transport, because the licensee:

Used approved and accepted guidance to perform the majority of the calculations.

Provided the technical basis for assumptions and methods used in the analysis that deviate from the approved guidance.

Provided a summary of, and supporting basis for, credit taken for reduction of debris amounts.

Provided the calculated debris transport fractions and the total quantities of each type of debris transported to the strainers.

Provided the limiting amount of fibrous debris that could accumulate in the reactor core.

3.4.2.8 Impact of Debris Submodel This section evaluates the potential effects that the debris, as described in section 3.4.2.6, of this SE, may have on operation of equipment important to LTCC. This section examines the operation of the ECCS strainer, the ECCS and CSS pumps, and other equipment downstream of the strainer, including the fuel and vessel. This section also evaluates the potential for the holdup of water in containment such that it may not reach the sump pool.

For this section, all descriptions attributed to the licensees submittal are taken from the licensees letters dated March 31, 2021, October 7, 2021, January 27, 2022, and March 8, 2022. The majority of the information is from sections 3f, 3g, 3j, 3k, 3l, 3m, 3n, and 3o of attachment 3-2 of enclosure 3 of the supplemental letter dated October 7, 2021, and its revision dated January 27, 2022.

3.4.2.8.1 Upstream Effects The licensee stated that the upstream effects evaluation conforms to the guidance in the GR/SE.

The licensee evaluated the containment for the potential for blockage or impedance of the transport of water to the sump using design drawings and photographs. The licensee evaluated

the layout of the structures and equipment and determined that significant blockage would not occur. The licensee identified a potential for blockage of a drain on the operating floor level at the reactor head storage and decontamination area. This floor drain was not credited for delivery of water to the sump.

The licensee evaluated all levels of the containment for curbs and other potential structures that could prevent or delay the flow of water to the sumps. Areas that could retain water were identified. The licensee noted that the passages through the shield wall at the ground floor level of containment are large and will not become blocked. Debris barriers were installed at the shield wall in two of the four large openings nearest the sumps to reduce the transport of debris.

The licensee also identified a system of drainage trenches for the normal sump as flowpaths to transport water into the annulus area. Debris barriers were also installed in the drain trenches and smaller openings in the shield wall near the sumps. The barriers are made of perforated plate so that water can flow through them. If they become blocked with debris, other flowpaths are available to allow water to flow to the sumps. The licensee stated that even large amounts of debris will not cause blockage of the open flowpaths.

Some areas of containment, like the reactor cavity basement and incore instrument tunnel were identified as water holdup volumes, but other than the holdup of inventory, other areas of the containment will not prevent water from reaching the sump. The holdups are accounted for in the sump level calculations.

The licensee stated that the refueling pool has two 10-inch diameter drains in the floor that are open during power operation. There are trash racks installed over the drains to prevent large pieces of debris from blocking them. Smaller pieces of debris that can pass through the trash racks will also flow freely through the drains which go straight through the floor and discharge into an open volume below. The licensee stated that administrative controls are in place to ensure that drains from the refueling cavity to lower containment are not obstructed during power operation.

NRC Staff Conclusion Regarding Upstream Effects The NRC staff reviewed the licensees evaluation against the NRC staff-accepted guidance in the GR/SE and concludes that the licensee has appropriately evaluated the flow paths upstream of the containment sump for holdup of inventory that could reduce flow to the sump and possibly starve the pumps that take suction from the sump. Therefore, the NRC staff concludes that the licensees evaluation of upstream effects is acceptable.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning upstream effects, because the licensee:

Summarized the evaluation of the flow paths from the postulated break locations and containment spray washdown to identify potential choke points in the flow fields upstream of the sump.

Summarized measures taken to mitigate potential choke points.

Summarized the evaluation of water holdup at installed curbs and/or debris interceptors.

Described how potential blockage of reactor cavity and refueling cavity drains has been evaluated, including likelihood of blockage and amount of expected holdup.

3.4.2.8.2 Screen Modification Package The licensee described the strainers in use at Callaway. The strainers are a vertical stacked disk, uniform flow design supplied by Performance Contracting, Inc. There are two redundant strainer arrays, each installed in a separate sump. The majority of the strainer surface is below the containment floor. Each sump is surrounded by a 6-inch curb and feeds one train of ECCS/CSS. The filtration surface for each array is about 3,300 ft2. The strainers are constructed of support structures covered by perforated plate. The filtration surface holes are 0.045 inches in diameter. There are 16 stacks of strainer modules in each sump. Half of the stacks extend about 7 feet below the floor and the other half about 5 feet below the floor. Each stack of strainers is designed to promote even flow through, and pressure drop across, the perforated plates. The strainers are constructed of stainless steel. The strainer stacks discharge to the sump pit below the stacks to supply filtered water to the ECCS and CSS suction piping.

The licensee stated that debris barriers were installed at openings in the secondary shield wall to force debris to take a longer route to the sumps and have a lower probability of transport. The barriers are also constructed of perforated plate with 1/8-inch holes. This allows debris to be trapped and water to pass through the barriers.

As part of the strainer installation modifications, the licensee relocated the trisodium phosphate dodecahydrate baskets and the sump level instrumentation.

NRC Staff Conclusion Regarding Screen Modification Package The NRC staff reviewed the design changes made by the licensee in response to GL 2004-02.

The information from the design was appropriately included in the licensees submittals. Based on its review, the NRC staff finds the licensee has provided sufficient information, as requested by GL 2004-02, and used appropriate inputs for its evaluation of LTCC, considering the effects of debris because the licensee:

Provided a description of the major features of the sump screen design modification.

Described modifications necessitated by the sump strainer installation.

3.4.2.8.3 Headloss and Vortexing The licensee stated that the headloss and vortexing evaluations were revised based on updated testing completed in 2016. The RoverD analysis does not include headloss calculations, but instead uses a headloss pass/fail criteria based on headlosses that occurred at various fiber loads during the testing.

The licensee stated that for the LBLOCA condition, the strainers are submerged with greater than 8 inches of water above the top of the strainers at the time of swapover to recirculation. For the SBLOCA, the strainers are submerged by about 2 inches of water at swapover to recirculation. The minimum submergence occurs at swapover, and submergence increases due to continued injection from the RWST.

To observe for vortex formation during testing, the level over the test strainer was reduced to 8 inches during both the full load and thin-bed tests. No indications of vortices were noted during the full load test and only surface dimples were noted during the thin-bed test. No air was observed entering the strainer. The licensee stated that to evaluate the SBLOCA case, it performed a comparative evaluation of the Froude Numbers and determined that the LBLOCA case was bounding, and vortex formation is not expected for the SBLOCA case.

During the audit, the NRC staff questioned how the potential for vortex formation was evaluated for the SBLOCA case. The licensee responded in its post audit supplemental letter dated January 27, 2022 (enclosure 5; Question 15), that the SBLOCA does not require recirculation to achieve core cooling. The response to Question 15 stated that even though recirculation is not required, flashing and degasification evaluations were done for the lower submergence that occurs during a SBLOCA. The licensee stated that the assumed submergence of 2 inches accounts for instrument error that would likely result in an additional submergence of 3 inches.

The NRC staff noted that including instrument error in the deterministic sump level calculation is an appropriate conservatism. The licensee provided additional information regarding the SBLOCA condition, the conditions that would be present if recirculation was required, and the conditions during testing for the TB cases. The licensee stated that the debris loading for the SBLOCA cases is bounded by the TB testing. The NRC staff reviewed the information regarding the postulated SBLOCA conditions but based its conclusions on the licensing basis premise that SBLOCAs do not require recirculation. The licensee also stated that the medium break LOCA (MBLOCA) case would result in submergence similar to the LBLOCA and concluded that the MBLOCA headloss was bounded by the TB test results, which are lower than the full load test results due to lower debris generation. Therefore, the licensee concluded that the MBLOCA cases are bounded. The NRC staff agrees that the MBLOCA cases are bounded by the LBLOCA cases. The licensee also discussed key assumptions in the sump performance evaluation that result in conservatism in the analysis. The NRC staff reviewed the key assumptions and concluded that they would result in conservatism that was not quantified by the licensee.

In its response to Question 15, the licensee also discussed the credit of containment pressure to suppress flashing. The licensee stated that 1.7 per square inch (psi) was credited for sump temperatures above 212 °F and this amount was less than 10 percent of the available containment pressure. During the audit, the NRC staff requested information on the basis for the magnitude of containment pressure credit. The licensee responded in audit Question 17 in the supplemental letter dated January 27, 2022, and stated that the magnitude of pressure credited was based on plant calculations for containment pressure. The NRC staff was unable to conclude that the response to Question 17 adequately characterized the amount of containment pressure available and requested additional information by email dated April 5, 2022 (Reference 69), regarding the details of the analysis including specificity to the LBLOCA case and whether the timing with respect to sump temperatures and containment pressures had been considered. The licensee responded by letter dated May 26, 2022 (Reference 8), with the requested information. The licensee stated that the available containment pressure is based on the LBLOCA case and also considers the timing of the event. The licensee provided information for the minimum and maximum safeguards cases. The licensee stated that for the minimum safeguards case the overpressure credit is about 15 percent of the calculated pressure, but that for a short time the overpressure credit is above 15 percent and reaches a peak of about 22 percent. However, the licensee also stated that the values are based on conservative timing assumptions for containment conditions and pump flows. Using realistic timing assumptions, the credit for containment pressure was shown to be about 10 percent for the minimum safeguards case. The licensee stated that the minimum safeguards case was more limiting than the

maximum safeguards case and provided graphical depictions of the credited containment pressure. Based on the response to RAI 2, the NRC staff concluded that it was demonstrated that the amount of containment pressure credited to suppress flashing meets staff guidance because the licensee demonstrated a large margin to flashing.

The licensee stated that strainer testing was conducted at Alden. Both a FDL test and a TB test were performed. The test description provides an overview of the important aspects of the testing and indicates that NRC staff review guidance in RG 1.82, Revision 4, was followed. The test used prototypical plant strainer modules and the test scaling accounted for area reduction due to miscellaneous debris. The licensee stated that fine fibrous debris predicted to reach the strainer was represented as fine debris in the testing. The NRC staff notes that this is a conservative practice. The tests included bounding amounts of all types of debris except fibrous.

Thus, the amount of fibrous debris calculated to transport to the strainer becomes an important parameter in the risk-informed evaluation.

The licensee provided a description of the TB and FDL tests including the debris surrogates and amounts used in the testing. The FDL test headloss was stated to be 1.45 pounds per square inch differential (psid) at 120 °F and a test flow rate of 1102 gpm. The TB test headloss was stated to be 0.9 psid at 100 °F and a test flow rate of 1102 gpm. The FDL test showed the high fiber case to result in the limiting condition.

The licensee provided conservatisms associated with the testing as stated in section 3.3.5 of this SE.

The NRC staff recognizes that these assumptions and test practices provide margins that help to ensure that the test results are bounding of the conditions in the plant. In some cases, the added margins add significant conservatism. For example, it is expected that in most scenarios both trains of ECCS will operate. However, the licensee assumed that only a single train would operate in the headloss analysis. This assumption results in a significantly greater debris load on the single operating strainer.

In addition to the test conservatisms listed above, for LBLOCA scenarios, the licensee did not scale the tested debris headloss to plant temperatures. At higher temperatures, the headloss is decreased due to viscosity and density changes in the fluid. Additionally, the headloss was not scaled to lower plant flow velocities. These assumptions provide another source of conservatism to the headloss analysis.

NRC Staff Conclusion Regarding Headloss and Vortexing The NRC staff reviewed the licensees evaluation against the staff-accepted guidance and concludes that the licensee has appropriately determined the headloss across the sump strainer for the debris load tested. The licensee has shown that the potential for formation of a vortex at the strainer does not exist under the plant-specific conditions at Callaway. The licensee has demonstrated that the strainer will perform acceptably under postulated LOCA conditions, limited by the amount of debris represented in the 2016 testing. Therefore, the NRC staff concludes that the licensees evaluation of headloss and vortexing is acceptable.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning headloss and vortexing, because the licensee:

Provided the minimum submergence of the strainer under SBLOCA and LBLOCA conditions and noted that recirculation is not within the design basis for a SBLOCA.

Provided a summary of the methodology, assumptions, and results of the vortexing evaluation and bases for key assumptions.

Provided a summary of the methodology, assumptions, and results of prototypical headloss testing for the strainer, including chemical effects and provided bases for key assumptions.

Addressed the ability of the design to accommodate the maximum volume of debris that is predicted to arrive at the strainer.

Addressed the ability of the screen to resist the formation of a thin bed.

Provided the basis for the strainer design maximum headloss.

Described significant margins and conservatisms used in the headloss and vortexing calculations.

Provided a summary of the methodology, assumptions, bases for the assumptions, and results for the clean strainer headloss calculation.

Provided a summary of the methodology, assumptions, bases for the assumptions, and results for the debris headloss analysis.

Showed that the sump is fully submerged for all accident scenarios.

Stated that near-field settling was not credited for the headloss testing.

Stated that temperature/viscosity was not used to scale the results of the headloss tests to actual plant conditions.

Stated that a small amount of the available containment accident pressure was credited in evaluating whether flashing can occur across the strainer surface and summarized the methodology used to determine the available containment pressure.

3.4.2.8.4 Sump Structural Analysis The licensee stated that trash racks are not installed at Callaway and that the strainers meet the acceptance criteria for all applicable loadings. Also, the structural loads were verified to bound the plant-specific strainer conditions.

The licensee stated that the Callaway code of record for structural qualification of the strainers is the American Institute of Steel Construction (AISC), 7th edition. The licensee also noted that when the AISC code does not provide adequate guidance for the particular component, other

codes or standards are used. The Callaway structural evaluations were performed using manual calculations and finite element analysis by employing GTSTRUDL and ANSYS software.

The licensee provided the load combinations that the strainers are designed for. These are seismic loads, live loads (weight of debris and differential pressure across strainer), thermal loads, and hydrodynamic loads.

The licensee provided the design margins for the sump structural components which show, that at all locations, the computed stress is less than the allowable stress.

The licensee compared the differential pressure conditions assumed in the structural analysis to those predicted by the headloss analysis. The comparison shows that there is margin at both the hot and cold conditions with the margins at cold conditions significantly greater.

The debris loading assumed in the structural analysis was compared to that assumed in the headloss analysis. The licensee noted that for single train operation, the mass of debris that could transport to the strainer was greater than the amount assumed in the structural analysis.

The structural analysis assumed 4330.8 lbm of debris and the maximum transportable debris was stated to be 5408.3 lbm. The licensee provided a table that identified the amount of each debris type that the transport analysis predicts to transport for the bounding single strainer case that passes all other strainer acceptance criteria. All scenarios with larger debris amounts are assumed to result in core damage. The majority of the transported mass comes from unqualified coatings. The licensee recognized that the potential transported mass exceeds the mass assumed in the structural analysis by 1077.5 lbm. The licensee stated that for the most likely plant response with two trains operating the debris would be split between the trains and the structural loading debris mass assumption would not be exceeded. To address the single train case, the licensee identified that the coating system consisting of Carboline 193LF primer and 191HB topcoat had been evaluated to ensure it would remain in place following a LOCA even though it is considered an unqualified coating system. The coating system was originally installed as qualified, but subsequent testing by an independent lab showed that the system had poor adhesion. Therefore, Callaway downgraded the system to unqualified. The licensee performed visual examinations and destructive testing on the containment coatings and determined that the criteria for a qualified system were met for the Callaway installation. The licensee also referred to testing conducted at Oak Ridge National Laboratory that showed the system would remain attached to the substrate under DBA conditions. Therefore, the licensee concluded that the Carboline 193 LF/191HB system would remain in place following a LOCA.

This assumption applies only to the structural analysis. The headloss analysis assumes that the system fails. The mass of the coatings from this system is 1105.3 lbm, which is greater than the deficit of 1077.5 lbm, in the structural analysis. Therefore, the licensee concluded that the structural analysis assumption for debris mass was valid.

During the regulatory audit, the NRC staff requested additional information regarding the testing used to determine that the Carboline 193LF/191HB system would remain adhered to the substrate in LOCA conditions. In its post-audit response dated January 27, 2022 (Question 20),

the licensee provided additional information regarding the adhesion testing used to determine that the coatings would remain in place. The NRC staff reviewed the information and concluded that the coatings will remain in place under post-LOCA conditions if they are not within the 4D ZOI associated with the system. Therefore, the NRC staff concluded that the debris mass assumption used in the structural analysis is acceptable.

The licensee stated that the locations of the strainers provide significant protection from dynamic effects like pipe whip, jet impingement, and missile impacts caused by HELBs. The geometry of the containment and structures in the area of the strainers as well as the lack of high energy lines in their vicinity prevent damage from these dynamic effects. The licensee provided photographs and diagrams to demonstrate how the strainers are protected.

The licensee stated that a backflushing strategy is not used for mitigating excessive strainer headloss conditions.

NRC Staff Conclusion Regarding Sump Structural Analysis The NRC staff concludes that the sump strainer is structurally acceptable for the assumed design-basis loads for which it is deterministically qualified. The NRC staff finds that the licensee has provided the information requested in item k (Sump Structural Analysis) of the NRCs revised content guide for GL 2004-02 Supplemental Responses because the licensee:

Summarized the design inputs, design codes, loads, and load combinations utilized for the sump strainer structural analysis.

Summarized the structural qualification results and design margins for the various components of the sump strainer structural assembly and demonstrated that code allowable stresses are not exceeded.

Demonstrated that dynamic effects such as pipe whip, jet impingement, and missile impacts associated with HELBs would not result in damage to the strainers.

Stated that a backflushing strategy is not used at Callaway.

3.4.2.8.5 Net Positive Suction Head The licensee stated that the NPSH evaluation had been updated from a previous submittal based on the updated headloss testing completed in 2016. The licensee performed the NPSH margin evaluation in accordance with the guidance in the GR/SE.

The licensee provided the strainer, ECCS, and CS pump flow rates, sump temperatures, and the containment water levels used in its NPSH analysis. The flow rates used in the analysis are maximums based on pump pre-operational testing. The NPSH analysis was performed at 212 °F because that temperature results in the limiting margin. At temperatures greater than 212 °F the containment pressure is set equal to the vapor pressure at the analyzed temperature. The NPSH analysis assumed a constant static head (sump level) based on the level calculated for a LBLOCA. The licensee used the minimum LBLOCA pool level which occurs at sump switchover to recirculation. This level is the minimum because CS, SI, and charging pumps continue to inject from the RWST until they are manually realigned to take suction from the sump. This results in increased level. The licensee stated that the clean strainer headloss used in the analysis was 0.7 ft. calculated at a temperature of 140 °F and the debris headloss was assumed to be 3.5 ft. from a test at a temperature of 120 °F. These values are both stated to be conservative because scaling the viscosity and density of the fluid to higher temperatures would result in lower values.

During the audit, the NRC staff requested that the licensee provide additional information regarding the sump level assumed for the SBLOCA case. The licensee responded that recirculation is not required in the design basis for the SBLOCA. The licensee provided additional details regarding this issue in its post-audit supplemental letter dated January 27, 2022 (Questions 15 and 18). This issue is discussed in more detail in section 3.4.2.8.3 of this SE.

The licensee stated that the required NPSH values for the pumps were determined by the pump vendor and that these values were not corrected for temperature. The NPSH required values were corrected for void fractions predicted to be present at the pump suctions under some plant-specific conditions. The licensee stated that flow losses were calculated using industry standard methods.

The licensee described the response of the ECCS to LBLOCAs and SBLOCAs. The response includes an injection mode and a recirculation mode. For a LBLOCA, the RCS depressurizes and the reactor trips on low pressurizer pressure. When RCS pressure is reduced to about 600 psi, the accumulator tanks inject into the RCS. A safety injection signal and a containment spray actuation signal are generated. These signals activate the ECCS and CSS and injection mode is initiated. All of the pumps take suction from the RWST during injection. The ECCS pumps (charging, SI, and RHR) inject to the RCS and the CSS pumps inject via spray headers to the containment. When the RWST level reaches a low setpoint, the RHR pumps automatically switch to recirculation mode, taking suction from the sump instead of the RWST.

The CS, SI, and charging pumps are then switched to take suction from the ECCS sump instead of the RWST. After about 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months , the SI pumps are realigned to inject to the RCS hot legs to mitigate the potential for boric acid precipitation. The RHR and charging pumps continue to inject to the cold legs.

For the SBLOCA, the licensee stated that for breaks smaller than approximately 3 inches, the RCS will depressurize to a pressure between 1000 and 1200 per square inch gauge (psig). For these small breaks, the accumulators would not discharge. For larger breaks, the accumulators are assumed to discharge. The NRC staff noted, for the SBLOCA, the lack of accumulator inventory results in a lower sump level.

The licensee stated that a SBLOCA would result in a safety injection signal that will start the charging, SI, and RHR pumps in the injection mode, injecting to the RCS cold legs. The charging pumps will inject to the RCS. The SI pumps will not inject until the RCS pressure decreases to about 1550 psig. The operators may secure the RHR pumps based on RCS pressure since they cannot inject at high pressures (greater than about 325 psig). If the charging and SI pump flows do not equal the break flow, RCS pressure will continue to decrease and the RHR pumps will be allowed to inject. The licensee stated that it is not expected for CSS to start or inject for a SBLOCA. The operators objective is to cool down and depressurize the RCS so that the RHR system can be aligned directly to the RCS for cooling.

However, if enough RWST inventory is injected so that the sump level indication is high enough, the RHR pumps will be aligned to take suction from the ECCS sump strainers. In this case the SI and charging pumps would be aligned to take suction from the RHR pump discharge similar to the LBLOCA case. Since the switchover to recirculation for the SBLOCA is based on sump level, there is assurance that there is adequate level in the sump for recirculation. See Question 18 of the post-audit supplemental letter dated January 27, 2022.

The licensee stated that the worst single failure for Callaway is the loss of a strainer because that diverts all debris to the strainer that remains in service. This causes the break size that

results in a calculated failure for the scenario to be smaller, and therefore more likely. In its RoverD analysis, the licensee assumed that only one strainer was in service for all scenarios.

The licensee provided an overview of the methods used to calculate the sump level. The sources of inventory along with the mass of water credited from each source were provided.

The phenomena that hold up or remove inventory in such a way that the pool level would be decreased were provided along with the assumed reductions in volume. The licensee also provided a summary of the assumptions including those intended to provide margin in the pool level calculation. The licensee provided a list of structures and components that will displace water resulting in a higher pool level. The list included the volumes of the structures and equipment that was credited in pool level increase.

The licensee provided the NPSH margin results for the limiting case at 212 °F. The RHR pump margin at the maximum debris quantity tested is 2.8 ft. for the RHR pumps and 2.1 ft. for the CS pumps.

NRC Staff Conclusion Regarding Net Positive Suction Head The NRC staff reviewed the licensees NPSH evaluation against the NRC staff-accepted guidance and concludes that the licensee has appropriately validated that the plant design provides adequate margin between the NPSH available and the NPSH required for each pump, taking suction from the recirculation sump for all cases that are not considered to result in an increase in plant risk. Therefore, the NRC staff concludes that the licensees evaluation of NPSH is acceptable.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning NPSH, because the licensee:

Provided applicable pump flow rates, the total recirculation sump flow rate, sump temperature(s), and minimum containment water level.

Described the assumptions used in the calculations for the above parameters and the sources/bases of the assumptions.

Provided the basis for the required NPSH values for the pumps.

Described how friction and other flow losses are calculated.

Described the system response scenarios for LBLOCA and SBLOCAs.

Described the operational status for each ECCS and CSS pump before and after the initiation of recirculation.

Described the limiting single failure assumptions relevant to pump operation and sump performance.

Described how the containment sump water level is determined.

Provided assumptions that are included in the analysis to ensure a minimum (conservative) water level is used in determining NPSH margin.

Described how the volumes associated with empty spray pipe, water droplets, condensation and holdup on horizontal and vertical surfaces were accounted for in pool level calculations.

Provided assumptions (and their bases) for equipment credited to displace water resulting in higher pool level.

Provided assumptions (and their bases) as to the water sources that are credited to provide pool volume, and the volume from each source.

Provided description of the calculation of containment accident pressure used in determining the available NPSH.

Provided assumptions made which minimize the containment accident pressure and maximize the sump water temperature.

Specified that the containment accident pressure is set at the vapor pressure corresponding to the sump liquid temperature.

Provided the NPSH margin results for pumps taking suction from the sump in recirculation mode.

3.4.2.8.6 Chemical Effects The objective of this chemical effects section is to evaluate chemical precipitate effect on strainer headloss. The evaluation of chemical effects on the reactor vessel is contained in section 3.4.2.8.8 of this SE.

Callaway evaluated chemical effects in a deterministic manner. The amount of plant-specific chemical precipitate was predicted using the TR WCAP-16530-NP spreadsheet with no refinements for aluminum passivation by phosphate or silicates. The NRC staff has previously reviewed and approved TR WCAP-16530-NP-A as one method to calculate the amount of chemical precipitate and to prepare precipitates for strainer testing. The licensee used the LOCA DBA temperature pressure profile that maximized the sump pool temperature throughout 30 days to provide a conservative calculated amount of post-LOCA precipitates. The licensee assumed CS would operate for 30 days following the LOCA, which results in more chemical precipitates. The full 30-day precipitate load is conservatively assumed to arrive at the strainer at the earliest possible time with no credit for settling or nucleation on containment surfaces.

A more realistic delayed precipitation assumption would be more easily accommodated since ECCS pump headloss margins increase with containment pool cooling.

The licensee performed plant-specific ECCS sump strainer headloss testing in 2016 at Alden.

Two prototypical vertical strainer stacks representing approximately 11 percent of the plant strainer area were situated in a pit arrangement similar to the plant but without a 6-inch curb.

The test flume was constructed to promote debris transport to the strainers. Both TB and FDL headloss tests were performed by adding particulate and fibrous debris to build a conventional materials debris bed and then adding chemical precipitates to the test flume after the particulate

and fibers headloss stabilized. enclosure 3 of the licensees supplemental letter dated January 27, 2022, confirmed that no credit was taken for near field settling of chemical precipitates as was initially indicated by enclosure 3, figure 3.o-1 in the supplemental letter dated October 7, 2021.

Chemical precipitates were prepared using the instructions outlined in TR WCAP-16530-NP-A.

After preparation, precipitate settling testing was performed to verify the precipitate settlement met the TR WCAP-16530-NP-A acceptance criterion. The precipitates were added to the test flume in batches; the calcium phosphate precipitate was added in one batch followed by multiple batches of aluminum oxyhydroxide precipitate. The licensees supplemental letter dated January 27, 2022 (enclosure 3, figures 3.f-5 and 3.f-6) show the debris beds for the FDL and TB test strainers covered with chemical precipitates. These tests demonstrated adequate NPSH margin for the fiber limit assumed in the Callaway deterministic evaluation.

NRC Staff Conclusion Regarding Chemical Effects The NRC staff finds the Callaway chemical effects strainer evaluation acceptable since it used the base model TR WCAP-16530-NP-A approach to determine the amount of precipitate and prepare it for strainer testing. In addition, the licensee made conservative assumptions that maximized the amount of predicted precipitate. TR WCAP-16530-NP-A was previously reviewed and approved by the NRC staff. For future tracking, the licensees FSAR (table 6.3-13) will contain Containment Recirculation Sump Debris Limits, including the analyzed source limits for aluminum oxyhydroxide and calcium phosphate precipitates.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning chemical effects. The licensee accomplished this by providing a summary of evaluation results that showed that chemical precipitates formed in the post-LOCA containment environment, either by themselves or combined with debris, do not deposit at the sump screen to the extent that an unacceptable headloss results, or deposit downstream of the sump screen to the extent that LTCC is unacceptably impeded.

3.4.2.8.7 Downstream Effects - Components and Systems The licensee stated that debris effects on components downstream of the sump screen were addressed using NRC staff-approved methods. The licensee used TR WCAP-16406-P-A, Revision 1, for the analysis, and no exceptions were taken to this methodology. The evaluation determined that no modifications were necessary for components or instrumentation.

The licensee stated that two trains of screens are installed with an area of 6623 ft2 and that this area was assumed in the evaluation to maximize the area available for penetration. The licensee summarized the methodology used to identify the components that required evaluation.

The licensee considered the systems and components that perform or support a safety function for ECCS and containment heat removal. The particulate debris dimensions used in the analysis for deformable particles were limited to the strainer opening size plus 10 percent for the width and 50 percent of the opening size for the thickness. The length of deformable particles was also limited to 2 times the opening size. For non-deformable particulates, the size was limited to the size of the flow passage in the sump screen. Based on these criteria the maximum debris size used in the evaluation was 0.094 inch for deformable debris and 0.047 inch for non-deformable debris.

The licensee provided assumptions for the particulate debris sizes available at the sump strainers and the depletion of various debris types and sizes over time. Instead of assuming 10-micron particulate as is assumed for headloss testing, a more realistic size distribution was selected based on coatings testing. The licensee stated that the larger particulate is less likely to penetrate the strainer, but assuming fewer particulates with larger sizes is more challenging to downstream component damage than a larger quantity of very fine particles. The unqualified coatings were assumed to fail as 10-micron particulate. The licensee described its assumptions for particulate penetration. The licensee determined, during a TB test, a penetration fraction of 24 percent. The NRC staff concluded that this is a reasonable method because the unqualified coatings and degraded qualified coatings outside of the ZOI are unlikely to fail before a fibrous bed forms on the strainer. The licensee assumed constant fluid velocities for the evaluation of the components, equal to that at the initiation of recirculation.

The licensee stated that it evaluated erosive wear, abrasion, and potential blockage that could affect the recirculation mode of ECCS and CSS for a mission time of 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months . The evaluations include the concentration and size of the debris. The licensee provided in table 5-1, Overall debris transport fractions in enclosure 3 of the supplemental letter dated January 27, 2022 (Reference 6) the assumptions of the debris sizes and concentrations. The components evaluated included valves, spray nozzles, orifices, heat exchanger tubes, instrument tubing, and the ECCS and CSS pumps. All of the components passed the acceptance criteria in TR WCAP-16406-P-A, Revision 1.

The licensee stated that no design or operational changes are being implemented to manage downstream effects.

NRC Staff Conclusion Regarding Downstream Effects Components and Systems The NRC staff reviewed the evaluation methods and results, and finds that the licensee followed the NRC staff-accepted guidance contained in TR WCAP-16406-P-A, Revision 1, including its associated NRC SE. The NRC staff concludes that the licensee performed an adequate downstream effects evaluation of components and systems and that the components are capable of performing their safety-related design functions for the required mission time after a LOCA.

The NRC staff concludes that the licensee has provided sufficient information as requested by GL 2004-02 and further described in the revised content guide for GL 2004-02 concerning downstream effects components and systems, because the licensee:

Summarized the application of NRC-approved methods and stated that the NRC-approved methods were used for the evaluation without exception.

Provided a summary and the conclusions of the downstream effects evaluations.

Stated that no design or operational changes are required as a result of the downstream evaluations.

3.4.2.8.8 Downstream Effects - In-vessel The licensee stated that it assessed the in-vessel effects using the methodology from TR WCAP-17788-P. The amount of fiber assumed to transport to the core was based on strainer penetration test results. The transport of fiber to the core is discussed in section 3.4.2.7

of this SE. The in-vessel evaluation assumed a fibrous debris source term (total on both strainers) of 300 lbm. Any scenario that generates and transports at least 300 lbm of fiber to the sump strainers is already assumed to lead to core damage due to failure of strainer acceptance limits.

The licensee stated that the reactor core contains 193 fuel assemblies that are of Westinghouse design, and that the core may contain a limited number of lead test assemblies. Hot leg injection is initiated at about 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months following the LOCA. The licensees supplemental letter dated January 27, 2022, stated that the results show that the plant-specific conditions result in in-vessel debris amounts that are within the limits developed in TR WCAP-17788-P and recognized in the NRC staff review guidance for in-vessel effects (Reference 37). The NRC staff did not endorse TR WCAP-17788-P, but instead recognized that the TR contains a significant amount of information that increased understanding regarding the effects of debris in the reactor vessel and at the fuel inlet. The NRC staff concluded that the debris limits developed by TR WCAP-1788-P could be used by licensees for the evaluation of in-vessel fibrous debris.

Because the licensee could not demonstrate that sump switchover (SSO) occurs in greater than 20 minutes as was assumed in the TR WCAP-17788-P, a plant-specific evaluation was performed for Callaway. The licensee did not provide direct comparisons between the TR WCAP-17788-P acceptance criteria and plant specific parameter values because the guidance does not suggest this format for a plant-specific evaluation. The NRC staff was able to evaluate LTCC for Callaway with respect to in-vessel debris by reviewing the licensees information and TR WCAP-17788-P.

The licensee stated that testing determined that chemical precipitates will not occur prior to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and that precipitation would not occur prior to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . During the regulatory audit, the NRC asked for clarification on chemical effects timing. In addition, the NRC staff noted that the TR WCAP-17788-P autoclave test representing Callaway used a bounding pH for the trisodium phosphate (TSP) buffer that was significantly higher than the projected post-LOCA plant equilibrium pH following a LOCA. Therefore, the NRC staff asked the licensee to provide additional technical justification for its conclusion that chemical precipitates would not form before 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following a LOCA. In enclosure 5, item 27, post-audit supplemental letter dated January 27, 2022, the licensee stated that the TR WCAP-17788-P, Test Group 36, is applicable to Callaway plant-specific conditions and demonstrated that chemical effects will not occur before 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . In addition, the licensee referred to results from two other TR WCAP-17788-P test groups with TSP buffer that had pH values representative of Callaways projected post-LOCA pH and much higher aluminum amounts in the test compared to Callaway. The NRC staff reviewed the licensees response to audit item 27, along with the applicable data in Volume 5 of TR WCAP-17788-P (Reference 29). The NRC staff verified that the two additional TR WCAP-17788-P autoclave test groups referenced by Callaway had the same TSP buffer, lower pH more representative of the projected Callaway post-LOCA conditions, and much higher aluminum. Aluminum is the most important contributor to post-LOCA chemical effects. All three test groups (including the Callaway plant-specific Test Group 36) had no chemical effects during the 24-hour test period. Therefore, the NRC staff confirmed that testing supports the Callaway conclusion that no chemical effects will occur before 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following a LOCA.

Following a LOCA, hot-leg switchover (HLSO) is a change in injection flowpath that most PWRs employ to prevent boric acid precipitation in the core. This change in the injection flowpath also bypasses any debris that may be accumulated at the core inlet. If HLSO is performed prior to the formation of chemical precipitates, LTCC is assured by this action that bypasses the core

inlet. At Callaway HLSO is performed at about 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months , which is significantly before the earliest time that chemical precipitates are predicted to form.

The licensee stated that core cooling can be maintained via alternate flowpaths (AFPs) as long as the maximum allowable amount of fibrous debris for the plant-specific fuel type is not exceeded prior to tblock. TR WCAP-17788-P defines tblock as the earliest time at which the core inlet can be fully blocked for a specific reactor design and still allow adequate flow through the AFP to ensure LTCC. The licensee evaluated several cases and found that the fuel inlet fiber limit for Callaway would not be exceeded if AFPs are credited. In the absence of early chemical effects, some coolant flow is likely to be maintained through the fiber bed at the core inlet along with flow through the AFP. As decay heat decreases, less flow is required to maintain LTCC.

Plants with lower resistance AFPs have lower tblock times. If chemicals do not precipitate prior to tblock, the tblock value is valid for the plant. Chemical effects testing demonstrated that chemical precipitation will not occur for at least 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months under Callaway plant-specific conditions. This is greater than the proprietary tblock time calculated by TR WCAP-17788-P for the Callaway reactor design.

As discussed in section 3.4.2.7 of this SE, the licensee calculated that the maximum amount of fiber that will transport to the core is 92 g/FA. This is greater than the fuel/RCS design specific acceptance criteria for the fuel inlet specified in TR WCAP-17788-P, but less than the total core fiber acceptance limit. The NRC staffs review guidance for in-vessel effects states that plants that exceed the fuel inlet limit but are within the total core limit will maintain adequate LTCC.

Since the maximum core fiber amount is less than the acceptance limit, LTCC will be maintained.

The licensee stated that the time to SSO assumed in the TR WCAP-17788-P analyses is 20 minutes and that the plant-specific switchover is 12 minutes. This is non-conservative from an in-vessel debris loading perspective because the debris is delivered to the core earlier and blockage may occur earlier resulting in the core having a higher decay heat value than was assumed in the TR analysis. If blockage occurs when the core is at a higher decay heat value, the temperature used as an acceptance criterion in the thermal hydraulic analysis could be exceeded.

The licensee stated that the analysis decay heat value is based on 10 CFR Part 50, Appendix K, which uses the 1971 ANS proposed decay heat standard with a 1.2 multiplier for conservatism. The licensee provided the TR analyzed decay heat (at 20 minutes) and stated that the Callaway decay heat calculated using the conservative methodology from the TR is 97.6 (Megawatt-thermal) MWth at 11.87 minutes. This value is greater than the value assumed in the TR. The licensee provided a comparison of the TR decay heat value, and a plant-specific value calculated using the plants decay heat model for several design basis event from ANSI/ANS-5.1-1979. The licensee stated that this model results in a plant-specific decay heat value of 83.2 MWth at 11.87 minutes. This value is lower than the TR decay heat value at 20 minutes. During the regulatory audit, the NRC staff requested that the licensee state whether there was any uncertainty included in the plant-specific value based on the newer model. In its post-audit supplemental letter dated January 27, 2022 (enclosure 5, Item 26), the licensee stated that the value for decay heat calculation applies a 1 sigma uncertainty, which equates to 2 percent at the calculated value. The licensees comparative evaluation indicates that, although SSO is sooner at Callaway than in the generic analysis, the core power at the time of swapover, when modeled using a more realistic model that still includes some conservatism to account for uncertainties, remains reasonably consistent with the generic analysis at SSO. In consideration of both the licensees decay evaluation and the fact that the rated thermal power level for

Callaway is slightly lower than that assumed in the generic analysis, the NRC staff determined that the licensee acceptably demonstrated that the thermal power at the 12-minute SSO time for Callaway will be reasonably consistent with that used in the generic analysis at 20 minutes.

The licensee provided several additional arguments to demonstrate that the 12-minute SSO time is acceptable from an in-vessel debris perspective. The licensee stated that the debris loading was calculated with maximum safeguards with one CS pump out of service. This condition results in acceptable in-vessel debris amounts. For this condition SSO does not occur until 15 minutes. At 15 minutes the decay heat value would be lower than at 12 minutes.

The NRC staff reviewed the information provided by the licensee and determined that the licensee had provided adequate information to demonstrate that cooling of the fuel will be maintained even with the early SSO time that may occur at Callaway.

NRC Staff Conclusion Regarding Downstream Effects - In-vessel The NRC staff reviewed the licensees in-vessel evaluation against the NRC staff-accepted guidance for the topic. The NRC staff concludes that the licensee has appropriately evaluated the ability of the ECCS to ensure LTCC considering the potential for buildup of debris at the core inlet and inside the reactor vessel. Therefore, the NRC staff concludes that the licensees evaluation of upstream effects is acceptable.

The NRC staff concludes that the licensee has provided sufficient information as requested by NRC staff review guidance for in-vessel effects and further described in the TR WCAP-17788-P concerning in-vessel effects, because the licensee demonstrated that:

HSLO is implemented before chemical precipitates are predicted to occur.

Chemical effects will not occur until after tblock.

The total amount of fiber reaching the core inlet would not exceed the core inlet fiber limit if AFPs are credited for flow.

The total amount of fiber reaching the core would not exceed the total in-vessel fiber limit. The AFP resistance is within the range analyzed for a Westinghouse, 4-loop upflow plant.

The plant thermal power is less than the thermal power used in the generic analysis.

Despite that the plant specific SSO time is less than the generic analysis assumption of 20 minutes, the decay heat at the plant SSO time remains within the ability of the ECCS to maintain LTCC.

NRC Staff Conclusion Regarding Impact of Debris Submodel Each of the aspects of the impact of debris area has been evaluated above. The NRC staff concludes that the sub-areas of upstream effects, screen modification package, headloss and vortexing, sump structural analysis, NPSH, chemical effects, downstream effects - components and systems, and downstream effects - in-vessel were adequately addressed. Based on the

evaluations for each of these subsections, the NRC staff finds that the licensees impact of debris evaluation is acceptable.

3.4.2.8.9 Submodel Integration This section provides an overview of how the submodels are combined to obtain the final results of the risk analysis.

The licensee used CASA Grande to compute debris amounts for postulated breaks on welds.

The licensee considered a total of 411 non-isolable welds, distributed over the piping system.

CASA Grande was integrated with a CAD three-dimensional model of the piping system, and insulation and coatings. For each postulated break, CASA Grande draws a three-dimensional ZOI (hemispherical for partial breaks and spherical for DEGBs) as a function of the break size, adjusted for the presence of robust barriers (which cannot be penetrated by water jets). Based on the ZOI and its orientation, CASA Grande computes the amount of debris generated and transported, with transport computed using simple and conservative transport fractions. The amount of debris generated also includes fixed amounts of degraded and unqualified coatings, 200 lbm latent debris, and 50 lbm of fiber margin, independently of the break size (attachment 3-2 of enclosure 3 table 3.b-2 of the supplemental letter dated January 27, 2022).

CASA Grande is executed to sweep breaks in small increments, varying the partial break orientation along a 360° circle. For each weld, engineers use CASA Grande to search for the minimal break size (referred to as critical break size) generating an amount of transported fiber exceeding 300 lbm (the amount of fiber in strainer tests by the licensee). Welds with breaks that could generate more than 300 lbm were referred to by the licensee as critical welds. The licensee identified a total of 60 critical welds that could generate more than 300 lbm of transported fiber (enclosure 3, table 9-3 of the supplemental letter dated January 27, 2022). The licensee assumed only one operational ECCS train, of the two ECCS trains available, so that generated and transported fiber would conservatively accumulate on a single strainer. To estimate the CDF, the licensee:

1 Assumed that strainers with a load exceeding 300 lbm would fail and cause core damage.

2 Assumed that a postulated break on any critical weld exceeding the critical break size would generate at least 300 lbm of transported fiber independently of the break orientation, and cause strainer failure and core damage. (In the actual CASA Grande computations, for a given location and break size, only certain break orientations on critical welds may generate fiber exceeding the 300 lbm limit.)

3 Assumed that weld breaks of the same size in different pipes are equally likely.

4 Strictly preserved the NUREG-1829, tables 7.13 and 7.19 LOCA break frequencies for the nuclear power plant.

The licensee also used the CASA Grande outputs to verify that strainer tests bounded debris types other than fiber (i.e. particulates and chemical precipitates), thus justifying the selection of the 300 lbm fiber limit as failure criterion. For example, the licensee examined the non-critical welds (a total of 411 60 = 351 welds) and concluded that chemical precipitates in strainer tests bounded chemical precipitates that would be produced by any break size in any of the non-critical welds.

The only possible exception to the test bounding all debris types except fibers was for FOAMGLAS insulation, which was incorrectly modeled as fiberglass in CASA Grande. The licensee examined whether considering FOAMGLAS as particulate could exceed particulate amounts in strainer tests in the 351 non-critical welds (enclosure 5, Question 10 of the supplemental letter dated January 27, 2022). The licensee developed CAD diagrams showing that the FOAMGLAS is well distributed in the piping system (enclosure 5, figure Q10.1 of the supplemental letter dated January 27, 2022). Therefore, it is unlikely that all FOAMGLAS would be damaged by any single break on a weld. Nonetheless, the licensee assumed all FOAMGLAS mass (1167 lbm) was added to debris from individual breaks in the 351 non-critical welds. The licensee identified 25 non-critical welds on which breaks could generate particulate exceeding strainer test amounts after the addition of 1167 lbm of FOAMGLAS.

However, the licensee noted that FOAMGLAS is not degraded to fine particulates by wetting or immersion, and that small pieces tend to remain floating in hot water. If 8 percent of the detached FOAMGLAS did not transport to the strainers, then none of the 25 non-critical welds would generate particulate exceeding strainer test limits. Crediting 8 percent reduction in the FOAMGLAS mass was considered reasonable by the NRC staff, because this insulation is well distributed in the piping system and unlikely to all be damaged by any single break in the non-critical welds, and FOAMGLAS is likely to break into large pieces which could be trapped and not transport to the strainer.

Also, the NRC staff noted that the licensee considered the Carboline 193LH/191HB coating system as unqualified; however, 36 pull-adhesion tests indicated acceptable adhesion strength to justify crediting the coating system as qualified (enclosure 5, Question 20 and enclosure 3 section 3.k.2 of the supplemental letter dated January 27, 2022). The coating mass is significant, 1105.3 lbm (enclosure 3, table 3.h-3; and section 3.K.2, of the supplemental letter dated January 27, 2022), and always added to the mass of particulate in every postulated break in CASA Grande. The licensee verified that strainer tests bounded particulate generated by non-critical breaks, including Carboline 193LH/191HB coating system sources. Therefore, the NRC staff concluded that crediting 8 percent reduction in the FOAMGLASS mass as debris to be also reasonable given the significant margin provided by the Carboline 193LH/191HB coating system. See section 3.4.2.8.4 of this SE for information regarding this coating system.

The licensee also examined the potential contribution of FOAMGLAS to chemical precipitates.

In this case, the licensee concluded that strainer tests well bounded the chemical precipitates even after accounting for potential contributions from FOAMGLAS, treated as E-Glass. The licensee concluded that the incorrect treatment of FOAMGLAS as fiber in the CASA Grande model would not change risk estimates (enclosure 5, Question 10, of the supplemental letter dated January 27, 2022).

Other failure modes including vortexing, degasification, upstream water holdups, structural failure, in-vessel blockage and effects, and effects on ECCS and CSS equipment were evaluated or screened out as described in the subsections of section 3.4.2.8 of this SE.

To examine if fiber buildup in the core could challenge head dissipation, the licensee examined scenarios of fiber buildup in the core, adopting the following assumptions:

i.

Two functional ECCS trains with maximal flow rate ii.

One functional CS pump with maximal flow rate iii.

300 lbm of fiber in the pool

Assumptions i and ii were intended to overestimate the amount of fiber in the core. Scenarios with greater than 300 lbm of fiber were already considered to cause strainer failure and core damage and did not require additional consideration. The licensee developed mass balance computations accounting for (a) fiber retention in the strainer and fiber shedding towards the core as a function of the fiber load on strainers, (b) fiber mass initially in the pool, and (c) redistribution of fiber to the strainer and core with the circulated flow. The licensee credited AFPs in the core and computed the split of fiber in the core between AFP and the core inlet. The licensee concluded that inlet accumulation would not exceed the proprietary TR WCAP-17788-P limit of fiber that is established on a per fuel assembly basis (enclosure 3, figure 3.n-2 to figure 3.n-5 of the supplemental letter dated January 27, 2022).

The licensee supplemented the analysis to address a question by NRC staff on uncertainty in the empirical equations for fiber retention by the strainer and fiber shedding rate in a letter dated March 8, 2022. The licensee doubled the shedding rate in the mass balance computations and computed accumulation at the core inlet remained less than the fuel assembly inlet limit. Also, the total in-vessel buildup (inlet + AFP) remained less than the proprietary total in-vessel limit after the empirical correlations were corrected. Therefore, the licensee concluded that in-vessel fiber accumulation would not challenge heat dissipation in the core and concluded that this potential mechanism would not contribute to the risk of core damage.

The NRC staff verified that the licensees debris generation and transport calculations were performed accurately and used acceptable assumptions (Reference 26). The NRC staff used a combination of confirmatory calculations, engineering review, and review of the licensees software outputs to perform the verifications. The verifications included comparing debris amounts of non-critical breaks to strainer tests amounts, alternative approaches to estimate critical break sizes, independent estimates of the CDF including alternative assumptions such as crediting break orientation and assuming only DEGBs, and independent mass balance computations to compute the distribution of fiber on strainers, AFP, and the core inlet. The approach allows the NRC staff to conclude, with a high level of confidence, that the calculations for debris generation for each potential weld break location were conducted and applied properly and are therefore acceptable. Mass-balance computations were properly implemented, adequately supporting the conclusion that in-vessel fiber buildup would not contribute to the risk of core damage. The resulting debris amounts were compared against the test criteria for the strainer to determine scenarios that could lead to core damage. Deterministic analyses were also performed using staff accepted guidance.

NRC Staff Conclusion Regarding Submodel Integration The NRC staff concluded that the licensees submodel integration was acceptable based on its review of the methodology, the CASA Grande results (debris amounts for postulated breaks, critical welds, and critical break sizes), computation of CDF using weld counts, critical break sizes, NUREG-1829 as inputs, and in-vessel fiber buildup computations. The NRC staff concludes that the approach for integrating submodels described in the licensees submittal is acceptable for use in an assessment or evaluation model of the effects of debris on long-term cooling of ECCS, as required, in part, by 10 CFR 50.46.

3.4.2.9 Systematic Risk Assessment RG 1.174 states that the licensee may use its decisionmaking principle that proposed increases in risk are small and are consistent with the intent of the NRCs Safety Goal Policy Statement. In attachment 3-3 of enclosure 3 to the supplemental letter dated January 27, 2022, the licensee

describes the risk-informed basis, including the systematic risk assessment. The licensee deterministically excluded potential failure modes addressed in section 3.4.2.8 of this SE. The only failure mode not excluded is failure of the strainer due to fiber buildup exceeding 300 lbm of fiber. The licensee assumed that a load exceeding 300 lbm of fiber would cause strainer failure and core damage. The frequency of breaks exceeding 300 lbm of transported fiber was used as the basis to compute the CDF and LERF. Breaks generating transported fiber less than 300 lbm of fiber were concluded not to contribute to the plant risk. The licensee referred to the evaluation methodology as RoverD (enclosure 3, attachment 3-3, figure 1-1 of the supplemental letter dated January 27, 2022).

The licensee screened break locations and GL 2004-02 relevant scenarios, which are evaluated in section 3.4.2.1 of this SE. The licensee concluded that the only breaks contributing to the CDF are breaks in Class-I welds. Debris generating models are evaluated in section 3.4.2.6 of this SE. The licensee considered LOCA break frequencies from NUREG-1829 to estimate CDF and LERF; the frequency selection approach is evaluated in section 3.4.2.2 of this SE.

LOCA break frequencies from an approach considering geometric mean aggregation of expert elicited frequencies, and 25-year plant life frequencies, were used by the licensee in the Baseline computations.

The licensee reported Baseline CDF values in table 7-1 of attachment 3-3 of enclosure 3 to the supplemental letter dated January 27, 2022, with a mean CDF equal to 5.37x107 1/yr, in RG 1.174 risk Region III. To estimate the LERF, the licensee conservatively assumed that a large early release would occur in 1 of 10 instances of core damage. The NRC staff considered this assumption to be reasonable and conservative, because the probability of a large-early release event conditional on a core damage event is commonly estimated to be much lower, based on detailed PRA analyses. Accordingly, the licensee estimated the mean LERF equal to 5.37x108 1/yr, also in the RG 1.174 risk Region III.

The licensee evaluated the impact of key assumptions and sources of uncertainty in the systematic risk assessment. The licensee considered NUREG-1829 LOCA break frequencies with 40-year plant life to compute the CDF and LERF. The licensee also examined alternative break models, such as assuming only full breaks equivalent to the DEGB limit.

Changing from a continuum break model to DEBG model modestly increased the CDF.

Changing to a 40-year plant life frequency, increased the CDF to a mean value of 1.22x106 1/yr, slightly inside risk Region II of RG 1.174. Changing from geometric mean aggregation to arithmetic mean aggregation, significantly increased the CDF, almost by one order of magnitude, from 5.37x107 1/yr to 4.07x106 1/yr, well into RG 1.174 risk Region II.

The licensee also addressed a case considering additional fiber insulation around valves. This case doubled the insulation amount at valves. The sensitivity was performed to address non-uniform fiber distribution on oddly shaped valve bodies caused by adding strips of insulation material to cover odd shapes or installing manufacturer-designed housings and cassettes containing additional fiberglass (enclosure 5, Question 32 of the supplemental letter dated January 27, 2022). For this case the CDF only marginally increased, from a baseline value of 5.37x107 1/yr to 5.4x107 1/yr.

As previously stated, the licensee examined changes in the CDF magnitude when considering arithmetic mean aggregation NUREG-1829 LOCA break frequencies. The sensitivity analysis revealed that the CDF estimate increased by almost one order of magnitude with respect to the baseline CDF using the geometric mean aggregation NUREG-1829 LOCA break frequencies. The licensee provided a justification for the selection of the geometric mean

aggregation of elicited frequencies for the Baseline computations of the CDF and LERF (enclosure 5, Question 36 of the supplemental letter dated January 27, 2022). In the same response, the licensee identified several areas of conservatism in its assessment. These include factors such as assuming immediate core damage with no opportunity for recovery if any single strainer or in-vessel performance criterion was violated; not crediting LBLOCA reduced or terminated spray flow rates as directed by EOP; and assuming single-train operation for all strainer performance evaluations resulting in maximum strainer debris load. The NRC staff also notes that the licensee identified performance monitoring strategies to ensure that inputs and assumptions of the LAR remain valid. The NRC staff concluded that the sensitivity to NUREG-1829 LOCA break frequencies based on the arithmetic mean aggregation does not change the licenses conclusion of very low risk (in RG 1.174 Region III) because conservatisms exist in the licensees assessment that can offset the impact of the use of arithmetic mean aggregation. The NRC staff continues to view the aggregation method of the NUREG-1829 LOCA break frequencies as a key assumption and source of uncertainty for the systematic risk assessment. The staff is not endorsing any specific aggregation method of NUREG-1829 LOCA expert-elicited frequencies for general use.

The NRC staff concluded that the licensee addressed dominant uncertainties in sensitivity analyses. The licensees approach to compute the CDF only includes a few factors. Other factors, such as uncertainty in fiber generated and transported, were addressed for example by using guidance with safety margin in the ZOI and consideration of bounding transport fractions.

Other failure modes and secondary break sources were properly screened and excluded. For example, the licensee concluded that fiber buildup in the vessel would not compromise heat dissipation of the core, considering reasonable sources of uncertainty in the analysis per supplemental letter dated March 8, 2022 (Reference 7 Question 23).

The NRC staff performed verification calculations, considering data provided during an audit.

Staff verified, for example, the selection of 60 critical welds (welds that could generate more than 300 lbm of transported fiber) and the critical break sizes using simplified interpolation instead of the exhaustive CASA Grande search deployed by the licensee. The NRC staff also reproduced the computation of the CDF, using the 60 critical welds, critical break sizes, and the NUREG-1829 frequencies as inputs. The NRC staff also examined implications of considering variations in the 300 lbm fiber limit as failure criterion, as well as alternative approaches to compute the CDF crediting the break orientation (the licensee does not credit break orientation to compute the CDF, as a conservative approach). The NRC staff performed independent in-vessel mass balance computations and derived results comparable to the licensee results. The NRC staff developed sufficient confidence that the licensee properly computed the CDF and LERF.

NRC Staff Conclusion Regarding the Systematic Risk Assessment The NRC staff evaluated the systematic risk assessment methodology and concluded it acceptable because inputs and assumptions (e.g., initiating event frequencies for critical welds) were derived using state of practice data and approaches, scenarios that affect the GSI-191 risk assessment were adequately identified and included in the risk evaluation, elements of the risk evaluation were developed in a systematic and acceptable manner, and key assumptions were appropriately considered and described. The NRC staff verified selected computations in support of the CDF. Therefore, the licensee used a verifiable and robust methodology to calculate the risk attributable to debris.

The licensee properly considered sources of uncertainty in the computation of the CDF and LERF and concluded that a dominant source of uncertainty is the input LOCA frequencies.

The licensee provided arguments to justify selection of the geometric mean aggregation NUREG-1829 LOCA frequencies to compute the Baseline CDF. The NRC staff found the conclusion that CDF and LERF belong in RG 1.174 risk Region III acceptable, based on the licensees baseline computations, as well as the licensees factors contributing to safety margins, evaluated in section 3.3 of this SE, and factors contributing to DID.

3.

4.3 NRC Staff Conclusion

Regarding Key Principle 4: Risk Assessment The licensee used a PRA of the appropriate scope, level of detail, and technical elements and plant representation. The risk-informed approach used by the licensee to address the effects of debris on LTCC is acceptable. Alternative assumptions were considered as sensitives for each key assumption employing non-consensus approaches. The increase in risk is very small and in accordance with the Region III acceptance guidelines defined by RG 1.174. Therefore, Principle 4 of integrated risk-informed decision-making is acceptable.

3.5 Key Principle 5: The Impact of the Proposed Change Should Be Monitored Using Performance Strategies RG 1.174, Regulatory Position C.3, Element 3: Define Implementation and Monitoring Program, states, in part, that:

The primary goal of Element 3 is to ensure that no unexpected adverse safety degradation occurs because of the change(s) to the licensing basis. The [NRC]

staffs principal concern is the possibility that the aggregate impact of changes that affect a large class of SSCs could lead to an unacceptable increase in the number of failures from unanticipated degradation, including possible increases in common-cause mechanisms. Therefore, an implementation and monitoring plan should be developed to ensure that the engineering evaluation conducted to examine the impact of the proposed changes continues to reflect the actual reliability and availability of the SSCs evaluated. This ensures that the conclusions drawn from the evaluation remain valid.

In the supplemental letter dated October 7, 2021, the licensee stated that it has implemented programs and procedures to evaluate and control potential sources of debris in containment, including TS SRs that require visual inspections of all accessible areas of the containment to check for loose debris, and each containment sump to check for debris. The licensee stated that its design change control procedure includes provisions for managing potential debris sources such as insulation, qualified coatings, addition of aluminum or zinc, and potential effects of post-LOCA debris on recirculation flow paths and downstream components. The licensee augmented the procedure to explicitly require changes that involve any work or activity inside the containment be evaluated for the potential to affect the following:

Reactor coolant pressure boundary integrity Accident or post-accident equipment inside containment Quantity of metal inside containment Quantity or type of coatings inside containment Change or addition of thermal insulation Addition or deletion of cable

The licensee stated that a 10 CFR 50.59 screening or evaluation is required to be completed for all design changes, which ensures that new insulation material that may differ from the initial design is evaluated for GSl-191 concerns. It also stated that it has implemented procedures to ensure that Service Level 1 protective coatings used inside containment are procured, applied, and maintained in compliance with applicable regulatory requirements. The licensee noted that the 10 CFR 50.65 also known as the Maintenance Rule program, includes performance monitoring of functions associated with ECCS and CSS. The inclusion of ECCS and CSS into the Maintenance Rule program, and the assessment of acceptable system performance, provide continued assurance of the availability for performance of the required functions.

The licensee also stated that for the purpose of monitoring future facility changes or other conditions that may impact the PRA results, appropriate changes to the as-built, as-operated plant are reflected in updates to the Callaway PRA reference model. Additionally, licensed operators are trained on indications of and actions in response to sump blockage issues related to GL 2004-02. The Callaway OQAP is implemented and controlled in accordance with policies, manuals, procedures and the Operating Quality Assurance Manual. This program is applicable to safety related SSCs to an extent consistent with their importance to safety. The OQAP complies with the requirements of 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, and other program commitments.

The NRC staff reviewed the licensees information and concludes that the licensees monitoring program is acceptable because it is consistent with the guidance in RG 1.174, Regulatory Position C.3.

3.

5.1 NRC Staff Conclusion

Regarding Key Principle 5: Performance Monitoring The Callaway Maintenance Rule program includes performance monitoring of functions associated with ECCS and CSS, including sump recirculation. Technical Requirements implemented by Callaway procedures require visual inspections of all accessible areas of the containment to check for loose debris, and each containment sump to check for debris.

Licensed Operators are trained on indications of and actions in response to sump blockage issues related to GL 2004-02, and performance is evaluated during training scenarios designed to simulate plant responses. The effect of changes incorporated into the at-power PRA model of record are periodically assessed to ensure the results of the analysis used to close GL 2004-02 remain within the aggregate baseline acceptance criteria in RG 1.174. Therefore, Principle 5 of performance monitoring is acceptable.

3.6 TS Changes for Implementation of TSTF-567 3.6.1 Proposed Changes to TS 3.5.2, ECCS - Operating The licensee proposed to modify and move SR 3.5.2.8 from TS 3.5.2 to the new containment sump TS. Therefore, the licensee proposed deletion of SR 3.5.2.8.

The new SR 3.6.8.1 does not limit the visual inspection to the suction inlet, trash racks and screens as currently required by the TSs, but instead requires inspection of the entire containment sump system. The containment sump system consists of the containment drainage flow paths, any design features upstream of the containment sump that are credited in the containment debris analysis, the containment sump strainers (or screens), the pump suction trash racks, and the inlet to the ECCS and CSS piping.

The NRC staff concludes the proposed change is acceptable since the existing requirements are either unchanged or expanded and continue to ensure the containment sump is unrestricted (i.e., unobstructed) and stays in proper operating condition. The proposed change meets the requirements of 10 CFR 50.36(c)(3) because it provides an SR to assure the necessary quality of systems and components are maintained, that facility operation will be within safety limits, and that the LCOs will be met. The NRC staff finds the change to TS 3.5.2 acceptable.

3.6.2 Proposed Changes to TS 3.5.3, ECCS - Shutdown The licensee proposed to delete the reference to SR 3.5.2.8 in SR 3.5.3.1.

The NRC staff concludes the proposed change is acceptable since SR 3.5.2.8 was modified and moved to the new containment sump TS. The existing SR on the containment sump is augmented (by requiring inspection of additional sump components) and moved to the new specification, and a duplicative requirement to perform the SR in TS 3.5.3 is removed. The new specification retains or expands the existing requirements on the containment sump and the actions to be taken when the containment sump is inoperable with the exception of adding new actions to be taken when the containment sump is inoperable due to containment accident generated and transported debris exceeding the analyzed limits. The new action provides time to evaluate and correct the condition instead of requiring an immediate plant shutdown. The proposed change meets the requirements of 10 CFR 50.36(c)(3) because it provides SRs to assure the necessary quality of systems and components are maintained, that facility operation will be within safety limits, and that the LCOs will be met. The NRC staff finds the change to TS 3.5.3 acceptable.

3.6.3 Proposed Changes to TS 5.5.15 Limiting Condition for Operation 3.0.6 states:

When a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. Only the support system LCO ACTIONS are required to be entered. This is an exception to LCO 3.0.2 for the supported system. In this event, an evaluation shall be performed in accordance with Specification 5.5.15, Safety Function Determination Program (SFDP). If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

When a support systems Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

When a loss of safety function is determined to exist, the SFDP requires entry into the appropriate conditions and required actions of the LCO in which the loss of safety function exists. When a loss of function is solely due to a single TS support system the appropriate LCO is the LCO for that support system. When the loss of function is the result of multiple support systems, the appropriate LCO is the LCO for the supported systems.

The licensee proposed to add the following sentence to TS 5.5.15:

When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

The NRC staff finds that the proposed addition to TS 5.5.15 clarifies the intent of the allowance (not to enter the Conditions and Required Actions) provided by LCO 3.0.6 and the SFDP for single-train support systems. The NRC staff concludes the proposed change is acceptable since the actions for the support system LCO adequately address the inoperability of that system.

Therefore, as required by 10 CFR 50.36(c)(5), the proposed change continues to provide adequate administrative controls to assure safe operation.

3.6.4 Proposed Addition of Containment Sumps TS LCO 3.6.8 3.6.4.1 Evaluation of New LCO 3.6.8 The licensee proposed to add a new LCO to address operability requirements of the containment sump. The numbering for this proposed TS is TS 3.6.8.

The containment sump supports the post-accident operation of the ECCS and CSS. However, only the current ECCS TS contains SRs related to the containment sump and the TS does not specify required actions that specifically address an inoperable containment sump. If the containment sump was found to be inoperable, as an ECCS and CSS support system, those respective LCOs would not be met. In order to address concerns related to containment sump operability due to debris accumulation described in GSI-191, the licensee proposed to add a new specification to address containment sump inoperability and create a condition for when the sump is inoperable due to analyzed containment accident generated and transported debris.

Based on the below evaluation, the NRC staff determined that the proposed TS satisfies the requirements of 10 CFR 50.36(c)(2)(i) because the LCO specifies the lowest functional capability or performance levels of equipment required for safe operation of the facility. There is reasonable assurance that the required actions to be taken when the LCO is not met are adequate to protect the health and safety of the public.

3.6.4.2 Evaluation of the Applicability The new TS requires the containment sump to be operable during Modes 1, 2, 3, and 4. The current ECCS and CSS TSs are applicable during Modes 1, 2, 3, and 4.

The NRC staff finds the proposed applicability is acceptable because the applicability is consistent with the applicability of the ECCS and CSS TSs, the containment sump supported systems.

3.6.4.3 Evaluation of Condition A The licensee has analyzed the susceptibility of the ECCS and CSS to the adverse effects of post-accident debris blockage and operation with debris-laden fluids. The licensee has established limits on the allowable quantities of containment accident generated debris that could be transported to the containment sump based on its current plant configuration. In the current TSs, if unanalyzed debris sources are discovered inside containment, if errors are

discovered in debris-related analyses, or if a previously unevaluated phenomenon that can affect containment sump performance is discovered, the containment sump, and the supported ECCS and CSS, may be inoperable and the TSs would require a plant shutdown with no time provided to evaluate the condition.

In order to address this situation and to provide sufficient time to evaluate the condition, the licensee proposed Condition A, which is applicable when the containment sump is inoperable due to containment accident generated and transported debris exceeding the analyzed limits.

Under Condition A, the operability of the containment sump with respect to debris is based on a quantity of debris evaluated and determined to be acceptable by the licensee. Conditions not evaluated under Condition A (containment accident generated and transported debris) and that affect the quantity of analyzed debris will be evaluated using a deterministic process.

Under Condition A, Required Action A.1 mandates immediate action to be initiated to mitigate the condition. The licensees proposed TS Bases for Required Action A.1 provided the following examples of mitigating actions:

Removing the debris source from containment or preventing the debris from being transported to the containment sump; Evaluating the debris source against the assumptions in the analysis; Deferring maintenance that would affect availability of the affected systems and other LOCA-mitigating equipment; Deferring maintenance that would affect availability of primary defense-in-depth systems, such as containment coolers; Briefing operators on LOCA debris management actions; or Applying an alternative method to establish new limits.

The NRC staff finds the proposed Required Action A.1 and its CT are acceptable because they place urgency on the initiation of the appropriate actions that could mitigate or reduce the impact of the identified conditions.

Concurrently, Required Action A.2 mandates SR 3.4.13.1, the RCS water inventory balance, to be performed at an increased frequency of once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . An unexpected increase in RCS leakage could be indicative of an increased potential for an RCS pipe break, which could result in debris being generated and transported to the containment sump.

The NRC staff finds the proposed Required Action A.2 and its CT are acceptable because the more frequent monitoring allows operators to act in a timely fashion to minimize the potential for an RCS pipe break while the containment sump is inoperable.

In addition, Required Action A.3 requires the inoperable containment sump to be restored to operable status in 90 days.

The NRC staff finds the proposed Required Action A.3 and its CT are acceptable because they provide a reasonable amount of time to diagnose, plan and possibly reduce the severity of, or

mitigate the unanalyzed debris condition and prevent a loss of ECCS and CSS safety function.

In addition, 90 days is adequate given the conservatisms in the containment debris analysis and the proposed compensatory actions required to be implemented immediately by Required Action A.1. Also, as discussed later in this SE section, the new SR will require visual inspection of the containment sump system (including the containment drainage flow paths, any design features upstream of the containment sump that are credited in the containment debris analysis, the containment sump strainers, the pump suction trash racks, and the inlet to the ECCS and CSS piping for evidence of structural degradation, potential for debris bypass, and presence of corrosion or debris blockage) to ensure no loose debris is present and there is no evidence of structural distress or abnormal corrosion.

For Condition A, a plant with multiple sumps is treated equivalently to a plant with a single sump, because multiple sumps are considered to be part of a single support system.

3.6.4.4 Evaluation of Condition B Condition B specifies the required actions for when the containment sump is inoperable for reasons other than containment accident generated and transported debris exceeding the analyzed limits.

Required Action B.1 requires restoring the containment sump to operable status and is modified by two notes. These two notes direct entry into the conditions and required actions for the supported systems (ECCS and CSS) upon entering Required Action B.1. Since Required Action B.1 directs entry to the corresponding ECCS and CSS TSs, these notes retain the existing TS actions for ECCS or CSS trains made inoperable by an inoperable containment sump for reasons other than containment accident generated and transported debris exceeding the analyzed limits.

The proposed CT for Required Action B.1 is 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This CT is consistent with the CT for a single inoperable ECCS train or CSS train so that the ECCS and CSS TS Actions control the licensees response.

The NRC staff finds the proposed change is acceptable since it continues to provide remedial actions for when the containment sump is inoperable for reasons other than Condition A and ensures safe operation of the plant. In addition, the proposed CT is acceptable since it provides a reasonable time for repairs, and there is a low probability of an accident occurring during this period that would require the use of the containment sump.

3.6.4.5 Evaluation of Condition C If operators are unable to restore the affected containment sump to operable status under Conditions A or B, Required Action C.1 requires the unit to be in Mode 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months followed by Mode 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months , as required by Required Action C.2.

The NRC staff finds this proposed condition and its required actions are acceptable because the condition is consistent with the STS and the required action requires the operators to place the unit in a condition in which the LCO no longer applies. In addition, the proposed CTs allow a reasonable amount of time to decrease from full power conditions to the required plant conditions in an orderly manner and without challenging plant systems.

3.6.4.6 Evaluation of the New SR The licensee proposed a new SR in the new containment sump TS. This SR is currently located in TS 3.5.2 and referred to in TS 3.5.3. The licensee proposes that the numbering for this new SR be SR 3.6.8.1. The frequency of the proposed SR is in accordance with the SFCP.

The proposed SR requires verification, by visual inspection, that the containment sump does not show structural damage, abnormal corrosion, or debris blockage.

The new SR is stated in generic terms and expands the scope of the required visual inspection to include the entire containment sump system. The entire containment sump system consists of the containment drainage flow paths, the containment sump strainers (or screens), the pump suction trash racks, and the inlet to the ECCS and CSS piping.

The NRC staff finds the proposed new SR is acceptable since it expands the scope of inspection of the original SR. In addition, the proposed frequency is acceptable since it is the same as that currently required by the TSs. Therefore, the NRC staff finds that, as required by 10 CFR 50.36(c)(3), the necessary quality of systems will be maintained in accordance with the associated LCOs.

3.6.4.7 Evaluation of Changes to Table of Contents The licensee also proposed a conforming change to the Table of Contents to include the new containment sump TS. This conforming change is acceptable since it is an editorial change to support the inclusion of the new containment sump TS. The NRC staff finds the changes to the Table of Contents acceptable.

3.6.4.8 Conclusion Regarding Proposed Containment Sump TS The new containment sump TS retains and expands the existing TS requirements with the exception of the addition of Condition A. Condition A provides a condition for an inoperable containment sump due to containment accident generated and transported debris exceeding the analyzed limits.

The NRC staff reviewed the proposed changes against the regulations and concludes that the changes continue to meet the relevant requirements of 10 CFR 50.36 for the reasons discussed above, and thus provide reasonable assurance that adoption of these TSs will have the requisite requirements and controls to operate safely. Therefore, the NRC staff concludes that the proposed TS changes are acceptable.

3.6.5 Variations The Callaway TSs utilize different numbering than the STSs on which TSTF-567 was based.

Specifically, TS 3.6.19 in TSTF-567 is proposed TS 3.6.8 in the Callaway TSs. These numbering differences are editorial, and do not affect the applicability of TSTF-567 to the proposed LAR.

As the Callaway TSs contain a SFCP, the frequency for SR 3.6.8.1 is [i]n accordance with the Surveillance Frequency Control Program. The SFCP was previously incorporated into the TSs and applied to SR 3.5.2.8 that is proposed to be replaced by SR 3.6.8.1. Although the requirements are somewhat expanded, SR 3.6.8.1 will perform the same function as SR 3.5.2.8,

and the intent of the proposed SR is the same. Therefore, the NRC staff finds it acceptable to apply the SFCP to the proposed SR 3.6.8.1.

3.7 Technical Evaluation Conclusion

The NRC staff determined that the proposed TS changes meet the standards for TSs in 10 CFR 50.36 and are acceptable and that the necessary quality of systems and components is maintained, facility operation will be within safety limits, and the LCOs will be met and satisfy the relevant portions of 10 CFR 50.36.

The proposed changes described in section 2.3 of this SE, describe how the effects of debris are evaluated and how these effects are incorporated into other calculations like NPSH margin for the pumps taking suction from the ECCS sumps. The NRC staff concluded that the description of the key methods used in the risk informed evaluation were acceptable. Any change in these methods is to be evaluated by the licensee to determine whether a departure from an approved methodology as described in the FSAR would result. Table 6.3A 2 of enclosure 2 (enclosure 2, attachment 2-5, Page 37 of 41) to the supplemental letter dated October 7, 2021 (Reference 5) contains information regarding the amounts of various debris types included in the design basis headloss testing for Callaway. The NRC staff reviewed this table and found that it accurately describes the debris loads used in the testing and therefore constitutes the design basis maximum debris source term for each debris type. FSAR section 6.3A.2.3 contains information regarding reporting required under various nonconforming conditions. The final proposed FSAR changes in the supplement dated January 27, 2022, includes updated information in the key methods and reporting areas, and in table 6.3A 2. The NRC staff concluded that the proposed FSAR changes are acceptable.

As discussed in this SE, the NRC staff reviewed the licensees LAR, as supplemented. The NRC staff finds that the information provided by the licensee demonstrates that there is reasonable assurance that debris will not adversely affect LTCC at Callaway. The NRC staffs conclusions are described in detail in the previous sections of this SE. The NRC staff finds that the licensee adequately addressed each technical area of GL 2004-02 using deterministic methods. For a limited set of scenarios that do not meet the acceptance criteria using the accepted deterministic methods, the licensee demonstrated that the risk of these scenarios is very small. To complete its evaluation of these low-risk scenarios, the licensee demonstrated that the five key principles of RG 1.174, Revision 3, were met. Therefore, the NRC staff concludes that the licensees risk-informed methodology for assessing the effects of debris on LTCC at Callaway (including submodels and integration of the submodels) demonstrates that the requirements of 10 CFR 50.46 for LTCC will not be adversely affected by debris.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Missouri State official was notified of the proposed issuance of the amendment including environmental assessment on August 29, 2022.

The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and changes surveillance requirements. The Commission has previously issued a proposed finding that the

amendment involves no significant hazards consideration published in Federal Register on December 28, 2021 (86 FR 73820), and there has been no public comment on such finding.

Pursuant to 10 CFR 51.21, Criteria for and identification of licensing and regulatory actions requiring environmental assessments, the NRC has prepared an Environmental Assessment (EA) and finding of no significant impact summarizing the findings of its review of the environmental impacts of the proposed action under the National Environmental Policy Act (NEPA). The NRC staff determined that special circumstances under 10 CFR 51.21 exist to warrant preparation of an EA because Callaway is proposing a risk-informed approach to resolve GSI-191 as recognized in SRM-SECY 12-0093, Closure Options for Generic Safety Issue-191, Assessment of Debris Accumulation on Pressurized-Water Reactor Sump Performance, dated December 14, 2012. Because this action uses risk information to justify exemptions from deterministic regulations, the NRC staff considered preparations of an EA to be a prudent course of action that would further the purposes of NEPA. Based on its review, the NRC concluded that an environmental impact statement is not required and that the proposed action will have no significant impact on the environment.

Pursuant to 10 CFR 51.21, 51.32, Finding of no significant impact, and 51.35, Requirement to publish finding of no significant impact; limitation on Commission action, an environmental assessment and finding of no significant impact was published in the Federal Register on August 29, 2022 (87 FR 52816). Accordingly, based upon the environmental assessment, the Commission has determined that issuance of this amendment will not have a significant effect on the quality of the human environment.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1.

Banker, S. P., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL 2004-02 (LDCN 19-0014), dated March 31, 2021 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML21090A18).

2.

Meyer, S. J., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant, Unit 1, Supplement to Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL-2004-02 (LDCN 19-0014), dated May 27, 2021 (ML21147A222).

3.

Meyer, S. J., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant, Unit 1, Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL-2004-02 (LDCN 19-0014), dated July 22, 2021 (ML21203A192).

4.

Meyer, S. J., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant, Unit 1, Transmittal of Documents Identified from NRC Audit of License Amendment Request Regarding Risk-Informed Approach to Closure of Generic Safety Issue 191 (EPID L-2021-LLA-0059), dated August 23, 2021 (ML21237A135).

5.

Meyer, S. J., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Third Supplement to Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL-2004-02 (LDCN 19-0014) (EPID L-2021-LLA-0059 and EPID L-2021-LLE-0021),

dated October 7, 2021 (ML21280A378).

6.

Meyer, S. J., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Fourth (Post-Audit) Supplement to Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL 2004-02 (LDCN 19-0014) (EPID L-2021-LLA-0059 and EPID L-2021-LLE-0021),

dated January 27, 2022 (ML22027A804).

7.

Mills, K. A., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Fifth (Post-Audit) Supplement to Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL 2004-02 (LDCN 19-0014) (EPID L-2021-LLA-0059 and EPID L-2021-LLE-0021),

dated March 8, 2022 (ML22068A027).

8.

Witt, T. A., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Response to Request for Additional Information Regarding Request for License Amendment and Regulatory Exemptions for Risk-Informed Approach to Address GSI-191 and Respond to Generic Letter 2004-02 (LDCN 19-0014), dated May 26, 2022 (ML22146A337).

9.

Witt, T. A., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Correction of Text Contained in Enclosures Provided with Supplements to Request for License Amendment and Regulatory Exemptions for a Risk-Informed Approach to Address GSI-191 and Respond to GL 2004-02 (LDCN 19-0014), dated September 8, 2022 (22251A343).

10, U.S. Nuclear Regulatory Commission, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors, Generic Letter 2004-02, dated September 13, 2004 (ML042360586).

11.

Ameren Missouri, Callaway Plant, Unit 1, Final Safety Analysis Report, Revision OL-25, and Technical Specification Bases, Revision 16, June 2021 (ML21195A333).

12.

Callaway Plant, Unit No. 1 - Exemptions from the Requirements of 10 CFR 50.46 and 10 CFR Part 50, Appendix A, General Design Criteria 35, 38, and 41 (EPID L-2021-LLE-0021), dated October 21, 2022 (ML22220A130 and ML22220A131).

13.

Vietti-Cook, A. L., U.S. Nuclear Regulatory Commission, memorandum to R. W. Borchardt, Staff-Requirements -SECY-10-0113-Closure Options for Generic Safety Issue - 191, Assessment of Debris Accumulation on Pressurized Water Reactor Sump Performance, SRM-SECY-10-0113, dated December 23, 2010 (ML103570354).

14.

Borchardt, R. W., U.S. Nuclear Regulatory Commission, memorandum to the Commissioners, U.S. Nuclear Regulatory Commission, Closure Options for Generic Safety Issue -191, Assessment of Debris Accumulation on Pressurized-Water Reactor Sump Performance, SECY-12-0093, dated June 9, 2012 (ML121310648).

15.

Vietti-Cook, A. L., U.S. Nuclear Regulatory Commission, memorandum to 5R. W. Borchardt, U.S. Nuclear Regulatory Commission, Staff Requirements -

SECY-12-0093 - Closure Options for Generic Safety Issue - 191, Assessment of Debris Accumulation on Pressurized-Water Reactor Sump Performance, SRM to SECY-12-0093, dated December 14, 2012 (ML12349A378).

16.

Banker, S., Ameren Missouri, letter to U.S. Nuclear Regulatory Commission, Callaway Plant Unit 1, Path Forward for Resolution of GL 2004-02, dated September 24, 2019 (ML19268A169).

17.

Regner, L. M., U.S. Nuclear Regulatory Commission letter to G. T. Powell, STP Nuclear Operating Company, South Texas Project, Units 1 and 2 - Issuance of Amendments Re: Changes to Design Basis Accident Analysis Using a Risk-Informed Methodology to Account for Debris in Containment (CAC Nos. MF2400 and MF2401), dated July 11, 2017 (ML17019A001).

18.

Westinghouse Electric Company, LLC, Comprehensive Analysis and Test Program for GSI-191 Closure (PA-SEE-1090), Topical Report (TR) WCAP-17788-NP Volume 1, dated July 2015 (ML15210A669).

19.

U.S. Nuclear Regulatory Commission, Risk-Informed Approach for Addressing the Effects of Debris on Post-Accident Long-Term Cooling, Draft Regulatory Guide 1.229, dated March 3, 2016, and January 27, 2017 (ML16062A016 and ML17025A060, respectively).

20.

U.S. Nuclear Regulatory Commission, Estimating Loss-of-Coolant Accident (LOCA)

Frequencies Through the Elicitation Process, NUREG-1829, Volume 1, Main Report and Volume 2, Appendices A through M, dated April 2008 (ML082250436 and ML081060300, respectively).

21.

U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, RG 1.174, Revision 3, dated January 2018 (ML17317A256).

22.

Chawla, M. L., U.S. Nuclear Regulatory Commission, letter to F. Diya, Union Electric Company dba Ameren Missouri, Callaway Plant, Unit No. 1 - Audit Summary For License Amendment Request and Regulatory Exemptions for A Risk-Informed Approach To Address Generic Safety Issue-191 And Respond To Generic Letter 2004-02 (EPID L-2021-LLA-0059 and L-2021-LLE-0021), dated September 14, 2021 (ML21238A138).

23.

Ruland, W. H., Nuclear Regulatory Commission, letter to Pietrangelo, A., Nuclear Energy Institute, Revised Content Guide for Generic Letter 2004-02 Supplemental Responses, dated November 21, 2007 (ML073110389).

24.

Ruland, W. H., U.S. Nuclear Regulatory Commission, letter to A. R., Pietrangelo, Nuclear Energy Institute, Revised Guidance for Review of Final Licensee Responses to Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accident at Pressurized-Water Reactors, dated March 28, 2008 (ML080230234).

25.

Westinghouse Electric Company, LLC, Evaluation of Post-Accident Chemical Effects in Containment Sump Fluids to Support GSI-191, TR WCAP-16530-NP-A, dated March 2008 (ML081150379).

26.

Nieh, H. K., U.S. Nuclear Regulatory Commission, letter to G. Bischoff, Westinghouse Electric Company, Final Safety Evaluation for Pressurized Water Reactor Owners Group (PWROG) Topical Report (TR) WCAP-16530-NP, Evaluation of Post-Accident Chemical Effects in Containment Sump Fluids to Support GSI-191 (TAC No. MD1119),

dated December 21, 2007 (ML073521072).

27.

Buschbaum, D. E., PWR Owners Group, letter to U.S. Nuclear Regulatory Commission, PWR Owner Group Transmittal of NRC Approved Topical Report WCAP-16406-P-A, Revision 1, Evaluation of Downstream Sump Debris Effects in Support of GSI-191 (PA-SEE-0195), dated March 2008 (ML081000025).

28.

U.S. Nuclear Regulatory Commission, Safety Evaluation by the Office of Nuclear Reactor Regulation Topical Report (TR) WCAP-16406-P, Revision 1, Evaluation of Downstream Sump Debris Effects in Support of GSI-191, Pressurized Water Reactor Owners Group Project No 694, dated December 20, 2007 (ML073520295).

29.

Westinghouse Electric Company LLC, Comprehensive Analysis and Test Program for GSI-191 Closure (PA-SEE-1090) - Autoclave Chemical Effects Testing for GSI-191 Long-Term Cooling, TR WCAP-17788-NP, Revision 0, Volume 5, dated July 2015 (ML15210A678; not publicly available, proprietary information).

30.

U.S. Nuclear Regulatory Commission, Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident, Regulatory Guide 1.82, Revision 4, dated March 2012 (ML111330278).

31.

U.S. Nuclear Regulatory Commission, Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident, Regulatory Guide 1.82, Revision 5, dated August 2022 (ML22145A479).

32.

U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities, Regulatory Guide 1.200, Revision 2, dated March 2009 (ML090410014).

33.

American Society of Mechanical Engineers (ASME) and American Nuclear Society (ANS), Addenda to ASME/ANS RA-S 2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, PRA Standard ASME/ANS RA-Sa-2009, February 2009, New York, NY.

34.

U.S. Nuclear Regulatory Commission, Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance, Office of Nuclear Reactor Regulation, NUREG-0800, Section 19.2, Revision, 3, dated June 2007 (ML071700658).

35.

Techncial Specifications Task Force, letter to U.S. Nuclear Regulatory Commission, Transmittal of TSTF-567, Revision 1, Add Containment Sump TS to Address GSI-191 Issues, TSTF-567, Revision 1, dated August 2, 2017 (ML17214A813).

36.

Cusumano, V., U.S. Nuclear Regulatory Commission, letter to Technical Specifications Task Force, Final Safety Evaluations of Technical Specifications Task Force Traveler TSTF-567, Revision 1, Add Containment Sump TS to Address GSI-191 Issures (EPID:

L-2017-PMP-0005), dated July 3, 2018 (ML18109A077).

37.

U.S. Nuclear Regulatory Commission, Staff Review Guidance for In-Vessel Downstream Effects Supporting Review of Generic Letter 2004-02 Responses, (ADAMS Accession No. ML19228A011), September 4, 2019.

38.

Butler, J. C., Nuclear Energy Institute letter to S. N. Bailey, U.S. Nuclear Regulatory Commission, Defense-In-Depth Measures in Support of GSI-191 Resolution Options, dated March 5, 2012 (ML120730661).

39.

Leeds, E. J. and Johnson, M. R., U.S. Nuclear Regulatory Commission, letter to All Power Reactor Licensees and Holders of Construction Permits in Active or Deferred Status, Issuance of Order to Modify Licenses with Regard to requirements for Mitigation Strategies for Beyond-design-Basis External Events, Order EA-12-049, dated March 12, 2012 (ML12054A736).

40.

Nuclear Energy Institute, Guideline for the Management of Materials Issues, NEI 03-08, Revision 4, dated October 2020 (ML20315A536).

41.

Westinghouse Electric Co., LLC, and Westinghouse Owners Group, Generic Guidance for an Effective Boric Acid Inspection Program for Pressurized Water Reactors, TR WCAP-15988-NP, dated March 2003 (ML041190170).

42.

U.S. Nuclear Regulatory Commission, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants (Generic Letter 88-05), GL 88-05, dated March 17, 1988 (ML053070383).

43.

U.S. Nuclear Regulatory Commission, Fatigue Analysis of Nuclear Power Plant Components, Regulatory Issue Summary 2008-30, dated December 16, 2008 (ML083450727).

44.

Idaho National Engineering Laboratory, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, NUREG/CR-6260, dated February 1995 (ML031480219).

45.

Electric Power Research Institute, Degradation and Failure of Bolting in Nuclear Power Plants, EPRI NP-5769, Volumes 1 and Volume 2, dated April 1988 (ML003727113).

46.

Electric Power Research Insitutute, Bolted Joint Maintenance & Applications Guide, EPRI TR-104213, dated December 1995 (ML003767012).

47.

Westinghouse Electric Company LLC, Pressurized Water Reactor Owners Group Standard RCS Leakage Action Levels and Response Guidelines for Pressurized Water Reactors, TR WCAP-16465-NP, Revision 0, dated September 2006 (ML070310082).

48.

Electric Power Research Institute, Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines, Technical Report MRP-227, Revision 1-A, dated June 2020 (ML20175A112).

49.

Electric Power Research Insitute, Materials Reliability Program: Inspection Standard for Pressurized Water Reactor Internals - 2020 Update, Technical Report, MRP-228, Revision 4, dated December 2020 (ML21019A000).

50.

U.S. Nuclear Regulatory Commission, NRC Staff Review Guidance Regarding Generic Letter 2004-02 Closure in the Area of Strainer Head Loss and Vortexing, dated March 2008 (ML080230038).

51.

Vietti-Cook, A. L., U.S. Nuclear Regulatory Commission, memorandum to L. A. Reyes, U.S. Nuclear Regulatory Commission, Staff Requirements - SECY-04-0118 - Plan for the Implementation of the Commissions Phased Approach to Probabilistic Risk Assessment Quality, SRM-SECY-04-0118, dated October 6, 2004 (ML042800369).

52.

Nuclear Energy Institute, Probabilistic Risk Assessment (PRA) Peer-Review Process Guidance, Risk Regulation, NEI 00-02, Revision 1, dated May 2006 (ML061510621 and ML061510614).

53.

BWROG and PWROG, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard, NEI 05-04, Revision 2, dated November 2008 (ML083430462).

54.

U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 3, dated December 2020 (ML20238B871).

55.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.200 Implementation, Regulatory Issue Summary 2007-06, dated March 22, 2007 (ML070650428).

56.

American Society of Mechanical Engineers/American Nuclear Society, Case for ASME/ANS-RA-Sb-2013, ASME/ANS RA-S CASE 1.

57.

Giitter, J., and Ross-Lee, J. J., U.S. Nuclear Regulatory Commission, letter to G.

Krueger, Nuclear Energy Institute, U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 07-12, and 12-13, Close-Out of Facts and Observations (F&Os), dated May 3, 2017 (ML17079A427).

58.

Nuclear Energy Institute, Performance of PRA Peer Reviews Using the ASME/ANS PRA Standard, NEI 17-07, Revision 2, date August 2019 (ML19231A182).

59.

U.S. Nuclear Regulatory Commission, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, NUREG-1855, Volume 1, dated March 2009 (ML090970525).

60.

ALION Science and Technology, Insulation Debris Size Distribution for Use in GSI-191 Resolution, ALION-REP-ALION-2806-01, Revision 4, dated May 2009 (not publicly available, proprietary information).

61.

Boska, J. P., U.S. Nuclear Regulatory Commission, letter to Entergy Nuclear Operations, Inc., Indian Point Nuclear Generating Unit Nos. 2 and 3 - Report on Results of Staff Audit of Corrective Actions to Address Generic Letter 2004-02 (TAC Nos. MC4689 and MC4690), dated July 29, 2008 (ML082050446).

62.

Westinghouse Electric Company LLC, Transmittal of Responses to NRC Request for Additional Information Re: Pressurized Water Reactor Owners Group Bases For Licensee Debris Generation Assumptions for GSI-191, dated March 5, 2010 (ML100710710).

63.

Rowley, J., U.S. Nuclear Regulatory Commission, letter to A. Nowinowski, Westinghouse Electric Compnay, Nuclear Regulatory Commission Conclusions Regarding Pressurized Water Reactor Owners Group Response to Request for Additional Information Dated January 25, 2010 Regarding Licensee Debris Generation Assumptions for GSI-191, dated March 31, 2010 (ML100570364).

64.

Choromokos, R., ALION Science and Technology, letter to U.S. Nuclear Regulatory Commission, GSI-191 Low Density Fiberglass Erosion Testing, ALION-REP-ALION-1006-04, Revision 0, dated April 8, 2010 (ML101090490; not publicly available, proprietary information).

65.

Parry, C. E., Utilities Service Alliance, letter to U.S. Nuclear Regulatory Commission, WCAP-16568-P, Jet Impingement Testing to Determine the Zone of Influence (ZOI) for DBA-Qualified/Acceptable Coatings, TR WCAP-16568-P, dated July 12, 2006 (ML061990591).

66.

Ruland, W. H., U.S. Nuclear Regulatory Commission, letter to A. Marion, Nuclear Energy Institute, Revised Guidance Regarding Coatings Zone of Influence For Review of Final Licensee Responses To Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors, dated April 6, 2010 (ML100960495).

67.

Science and Engineering Associates, Inc., Drywell Debris Transport Study, Final Report, NUREG/CR-6369, Volume 1, dated September 1999 (ML003728226).

68.

Ruland, W. H., U.S. Nuclear Regulatory Commission, letter to R. Choromokos, Alion Science and Technology, Proprietary Erosion Testing of Submerged NUKON Low-Density Fiberglass Insulation in Support of Generic Safety Issue 191 Strainer Performance Analyses, dated June 30, 2010 (ML101540221).

69.

Chawla, M., U.S. Nuclear Regulatory Commission, email to T. B. Elwood, Callaway Plant, Unit 1, Callaway Plant, Unit 1 - Final RAIs - License Amendment and Regulatory Exemptions for a Risk-Informed approach to address Genric Safety Issue-191 and Respond to Generic Letter 2004-02 (EPIDs L-2021-LLA-0059 and L-2021-LLE-0021),

April 5, 2022 (ML22096A023).

Principal Contributors: S. Smith A. Russell Date: October 21, 2022

ML22220A132

via email OFFICE NRR/DORL/LPL4/PM*

NRR/DORL/LPL4/LA*

NRR/DSS/STSB/BC*

NAME MChawla (SLingam for)

PBlechman VCusumano DATE 8/8/2022 8/16/2022 10/12/2022 OFFICE OGC - NLO*

NRR/DORL/LPL4/BC*

NRR/DORL/LPL4/PM*

NAME LShrum/DRoth JDixon-Herrity MChawla (SLingam for)

DATE 9/28/2022 10/12/2022 10/21/2022

v t e Letter Sequence Approval
EPID:L-2021-LLA-0059, TSTF-567, TSTF-567 (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request Acceptance, Acceptance, Acceptance Supplement, Supplement, Supplement, Supplement, Supplement Administration Questions 28 March 2022 3 November 2021 5 April 2022 Answers 26 May 2022 27 May 2022 Results Approval Other: ML21197A063, ML21237A136, ML21238A138, ML22068A029, ML22182A406, ML22182A411, ML22220A129, ML22220A130, ML22220A131
MONTHYEAR2021-07-23 [Table View]