Text

Licensee Presentation on Pressure Boundary Process
	ML23076A281
Person / Time
Site:	Limerick
Issue date:	02/23/2023
From:	; Electric Power Research Institute
To:	Rhoades D; Constellation Energy Generation
	Sreenivas V, NRR/DORL/LPLI, 415-2597
References
	EPID L-2021-LLA-0042
	Download: ML23076A281 (53)
	v • d • e

Agenda Introduction Handout #1 - Pages 4-2 thru 4-7 of 3002015999 Handout #2A - previous suggested report change pages Handout #2B - recent suggested report change pages Handout #3 - word file 50.69(c)(1)

Introduction As a result of recent NRC input the project team did a deep dive into the methodology that we had developed and the reasoning behind what was developed, and drew a number of conclusions:

10CFR50.69, NEI00-04, Reg. Guide 1.201, the ASME/ANS PRA standard and Reg. Guide 1.201 are complicated The RI-methodology contained in 3002015999 is technically robust and a win for the industry, the USNRC and the public 3002015999 could have been written with more clarity and guidance See previous RAI responses and report change pages Based on the more recent USNRC input, additional clarity/guidance is possible In general, we believe with the additional clarity/guidance, industry and NRC are on the same page 3 © 2023 Electric Power Research Institute, Inc. All rights reserved.

Problem Statement In 2017 Licensees implementing 10CFR50.69 were asking Is the categorization methodology for pressure boundary components too conservative, too resource intensive, and/or appropriate for the level of insights obtained It was determined an alternative Robust and Stable Cost Effective approach could be beneficial to the industry as well as the NRC, but it must establish a process that will be:

- Robust and Stable

Process for Streamlining the Categorization Methodology Studied the existing pressure boundary 10CFR50.69 process

- Premises & Assumptions

- Conservatisms (e.g. failure probability = 1.0)

- Process steps

- Reviewed 10CFR50.69 categorizations Explored possible alternatives

- Training enhancements

- Earlier Categorization methodologies

Enhanced Methodology The enhanced methodology for categorizing pressure boundary components contains four main features:

A Set of Prerequisites (Entrance Fee)

A Set of Pre-determined HSS Systems/Subsystems A plant-specific search for outliers that need to be upgraded to HSS Upfront / Concrete Safety improvements 6 © 2023 Electric Power Research Institute, Inc. All rights reserved.

Item #1- LAR allows ASME Class 1 to be LSS w/o Sufficient Technical Basis 3002015999, consistent with 10CFR50.69, allows for the possibility of some Class 1 components to be categorized as low safety significant (LSS)

However, 3002015999 (i.e. report change pages) cautions that the benefits of 10CFR50.69 can not be fully gained until these components are re-classified as non Class 1 RAI-01 C. response identifies some small bore ( 3/4 and 1 NPS) Class 1 exempt components as LSS Should report be updated to say:

For plants that have classified these components as Class 1 or Class 1 exempt, LSS shall not be assigned until this components has been classified as non-Class 1?

Item #2 - Criteria Inappropriately Assume Smaller Piping Has Lower Risk The Enhanced Methodology does not use pipe size to make assumptions regarding risk The intent of Criteria 3 and 4 are to assure that larger bore piping in PWR feedwater and Break Exclusion Regions are categorized as HSS even though the existing approach, as approved by USNRC, categorize this piping as LSS (e.g. CCDP < 1E-04)

BER: please see response to RAI-01 C PWR feedwater: please see ASME SXI Report 2002-02A-01 (N716-0 Technical Basis Paper)

Given the larger lines in these areas have medium consequence rank based on CCDP, smaller lines in these areas will be at worst a medium consequence rank and more likely a low consequence rank (CCDP <

Item #2 - Criteria Inappropriately Assume Smaller Piping Has Lower Risk Per RG1.200 and ASME/ANS PRA requirements, failure frequencies used in the plant-specific PRA need to reflect operating experience As will be discussed in later slides, flood source characterization as required by RG1.200 and the PRA standard includes identification of all sources of flooding, regardless of size.

Item #3 Not preserving system redundancy 2 trains equal Medium / Low The intent of Criteria 5 and 8 is to ensure that HSS is assigned if system redundancy can not be demonstrated consequence rank According to Criterion 5, any single SSC failure that would cause failure of the UHS function would be categorized as HSS That is, passive failures that result in loss of redundancy (common cause impact) are to be categorized as HSS For Criterion 5, failure of only one train of service water would leave at least one other train of service water available as well as other mitigation capabilities (e.g., SGs) that ensures CCDP < 1E-4.

For Criterion 8 - One train of CCW and other mitigation capabilities (e.g., SGs) ensures CCDP < 1E-4. At some plants, total loss of CCW is < 1E-4 so this criteria can be conservative Criteria 11, 12 and 13 assure any individual flow path not meeting criteria 1 through 10 also have a very low risk contribution including consideration of defense in depth 12 (e.g. CCDP and CLERP) © 2023 Electric Power Research Institute, Inc. All rights reserved.

Item 4 - PRA: technical basis for quantitative consequences As discussed in the changes pages to the EPRI (section 4.1, Prerequisite 1 - PRA Technical Adequacy (Pressure Boundary Failures), the Licensee needs to have a robust internal events PRA, including internal flooding, that addresses failure of all pressure boundary components (e.g. main steam line breaks, main feedwater line breaks, internal flooding events, interfacing system LOCA, etc.). As this methodology is being used in support of 10CFR50.69 applications, the plant-specific PRA needs to be sufficient to support the License Amendment Request (LAR) approval process, including consideration of PRA assumptions and sources of uncertainty.

To further address the potential for screened out components, criteria 11, 12 and 13 require that Any piping or component (including piping segments or components grouped or subsumed within existing plant initiating event groups) be accounted for in the categorization process. This type of approach in addressing screened out components has been previously approved by NRC in ASME Code Case N716-1 (RG1.147, 2014) and ASME Code Case N716-2 (RG1.147, 2021).

As highlighted in the next two slides, the USNRC endorsed PRA Standard requires the identification and characterization of plant-specific sources of internal floods that could lead to core damage. Flood source characterization, which includes identification of sources of flooding, equipment failure modes, and associated flood mechanisms, is a necessary prerequisite to the definition of flood scenarios.

Item 4 - PRA: technical basis for quantitative consequences For each flood area, the Licensee is required to identify the potential sources of flooding which may include equipment (e.g., piping, valves, pumps) located in the area that is connected to fluid systems (e.g., circulating water system, service water system, component cooling water system, fire protection system, feedwater system, condensate and steam systems, reactor coolant system, and other high energy lines. It may also include plant internal sources of flooding (e.g., tanks or pools) located in the flood area as well as plant external sources of flooding (e.g., reservoirs or rivers) that are connected through some system or structure within the plant boundary.

It is also required that for each potential flood source, the flooding mechanisms that would result in a release of water or steam from the flood source be identified. This would include failure modes of components such as pipes, tanks, gaskets, expansion joints, fittings, and seals, human-induced mechanisms that could lead to overfilling tanks or the diversion of flow-through openings created to perform maintenance, inadvertent actuation of a fire suppression system as well as other events resulting in a release into the flood area.

Item 4 - PRA: technical basis for quantitative consequences It is also noted in the USNRC endorsed PRA Standard that sources of flooding are typically expected to be water, and the requirements are generally written in terms of sources of water, but other fluid sources should also be considered as part of the IF PRA. Walkdowns are required to be conducted to assure that the analyses reflect the as built as operated plant.

This approach is consistent with other USNRC generically approved RI-categorization approaches (e.g.

N716-1 (2014) and N716-2 (2021) in that the enhanced methodology does not presuppose any SSC (safety related or non safety related) as LSS.

In summary, from a pressure boundary perspective there are no pressure boundary components that are not evaluated in a PRA (IE and IF) that meets the requirements of the USNRC endorsed PRA standard as required for use of the enhanced methodologies.

Item 4 - PRA: technical basis for quantitative consequences Criteria 11 through 13 are included to provide a means of ensuring that any plant specific locations that are important to safety are identified

- The CDF & LERF limits of 1E-6/year & 1E-7/year are suitably small and consistent with the guidelines from the EPRI Traditional RI-ISI methodology found in EPRI Report TR-112657, Rev B-A

- Components cannot be assigned to LSS population based solely on low failure likelihood unless that likelihood is remote due to the use of CCDP/CLERP metrics which provide additional balance between prevention and mitigative The methodology is more conservative and provides more safety improvement opportunities as compared to the current NRC approved approach in that all safety related and non-safety related components need to be evaluated and assigned HSS or LSS The methodology is more conservative than NRC approved N716-1 (2014) and N716-2 (2021) which have been approved for generic use in Reg Guide 1.147 (see Figures 4-1 and 4-2 of 3002015999)

Provides confidence that the goal of identifying the more risk significant locations is obtained while permitting the use of pre-determined HSS systems/subsystems to simplify and standardize the evaluation 17 © 2023 Electric Power Research Institute, Inc. All rights reserved.

Item 4 - PRA: technical basis for quantitative consequences After categorizing all safety related and all non-safety related components as HSS or LSS, proposed new section 4.3 makes it clear that a risk sensitivity study is conducted to assure that the use of these threshold values do not challenge the requirement to ensure that the impact on plant risk is small when changes in treatment as permitted by implementation of 50.69(b)(1) and (d)(2) are implemented 10CFR50.69(d)(2) requires: The licensee or applicant shall ensure, with reasonable confidence, that RISC-3 SSCs remain capable of performing their safety-related functions under design basis conditions, including seismic conditions and environmental conditions and effects throughout their service life.

The prerequisites (e.g. integrity management) are applied whether the component is determined to be HSS or LSS by the Enhanced Methodology.

Therefore, the enhanced methodology taken in total, ensures that regardless on the numeric threshold values selected, the impact on risk by implementing the enhanced methodology will be small, and more than likely positive 18 © 2023 Electric Power Research Institute, Inc. All rights reserved.

Item 5 - Criteria 11-13 dont address uncertainties and changes in pipe break frequencies In response to an earlier RAI:

- The EPRI report is being updated to reflect additional PRA Technical Adequacy guidance (see change pages reflecting update to Prerequisite

1) which requires that the peer reviewed PRA used for 50.69 categorization be assessed with respect to PRA assumptions and sources of uncertainty. The base PRAs (IE and IF) objective is to determine plant risk (i.e., quantifying of risk metrics CDF and LERF). As criteria 11, 12, and 13 of the enhanced methodology use these same metrics to identify plant specific HSS SSCs, additional assessments of PRA assumptions and source of uncertainty is not needed. That is, the conclusions drawn during the base PRA (IE and IF) review of PRA assumptions and sources of uncertainty as contained in the 10CFR50.69 LAR are also valid for meeting criteria 11, 12, and 13.

Item 5 - Criteria 11-13 dont address uncertainties and changes in pipe break frequencies Updated change pages references ML18165A162 as an acceptable example of meeting this requirement:

- LIMERICK GENERATING STATION, UNITS 1 AND 2 - ISSUANCE OFAMENDMENT NOS. 230 AND 193 TO ADOPT TITLE 10 OF THE CODE OF FEDERAL REGULATIONS SECTION 50.69, "RISK-INFORMED CATEGORIZATION AND TREATMENT OF STRUCTURES, SYSTEMS AND COMPONENTS FOR NUCLEAR POWER REACTORS" (CAC NOS.

MF9873 AND MF9874; EPID L-2017-LLA-0275)

In Table 2 of the LAR supplement dated August 14, 2017, the licensee provided the list of assumptions and sources of modelling uncertainty that were reviewed for the internal events (including internal flooding) PRA and the licensee's disposition. The NRC staff found that the dispositions for some of the assumptions and modeling uncertainties involve updating the PRA models prior to implementation of the 10 CFR 50.69 program.

Given the licensee's assessment and its proposal to update the internal events PRA model before the 10CFR50.69 program is implemented, the NRC staff finds that the licensee searched for, identified, and evaluated sources of uncertainty in its internal PRA consistent with the guidance in NUREG-1855 and EPRI document TR-1016737, and therefore, satisfied the NEI 00-04 guidance to identify additional "applicable sensitivity studies."

Item 5 - Criteria 11-13 dont address uncertainties and changes in pipe break frequencies One of the guiding principles of this process is that changes in treatment should not significantly degrade performance for RISC-3 SSCs and should maintain or improve the performance of all RISC-2 SSCs, and coupled with Prerequisite #2 in section 4.1 of this report, it is anticipated that there would be no net increase in risk.

In response to this item and related input, proposing to add a new section 4.3 to provide additional clarity and guidance.

Summary 10CFR50.69, NEI00-04, Reg. Guide 1.201, the ASME/ANS PRA standard and Reg. Guide 1.201 are complicated The RI-methodology contained in 3002015999 is technically robust and a win for the industry, the USNRC and the public 3002015999 could have been written with more clarity and guidance In general, we believe with the additional clarity/guidance, industry and NRC are on the same page 24 © 2023 Electric Power Research Institute, Inc. All rights reserved.

HANDOUT #1 - ECMPBC 4.1 Prerequisites Prior to implementing the categorization process contained in the next section, a licensee will need to assure that the following prerequisites have been met. Each requirement is listed below and explained in further detail in succeeding paragraphs.

Prerequisite 1 - PRA technical adequacy Robust internal events PRA model, including IF

Prerequisite 2 - Integrity management Robust program that addresses localized corrosion Robust program that addresses FAC Robust program that addresses erosion

Prerequisite 3 - Protective measures for IF events Prerequisite 1 - Robust internal events PRA, including IF As stated previously, the plant needs to have a robust internal events PRA, including IF. A similar requirement was imposed upon the development of RI-ISI programs. To help determine if a plant had a PRA sufficient to develop a RI-ISI program, EPRI report 1021467-A, Probabilistic Risk Assessment Technical Adequacy Guidance for Risk-Informed In-Service Inspection Programs, [9] was developed. This report identifies which portions of the PRA (that is, supporting requirements [SRs]) apply to the development of RI-ISI programs and for those portions of the PRA that do apply to (RI-ISI) programs, what level of technical adequacy is needed.

EPRI report 1021467-A has been reviewed to identify whether its technical justification and conclusions are also valid for the categorization of pressure boundary components for 10 CFR 50.69 purposes. That is, is a PRA that meets the requirements of 1021467-A sufficient to support the categorization of pressure boundary components for 10 CFR 50.69 purposes?

As it pertains to 10 CFR 50.69, insights obtained from this review of this report include the following:

RI-ISI and 10 CFR 50.69 both require a living program component (for example, 10 CFR 50.69(e) Feedback and Process Adjustment).

EPRI report 1021467-A was able to show that inclusion of external hazards (for example, seismic and internal fires) was not required in order to develop a RI-ISI program because their inclusion would not change the conclusions derived from the RI-ISI process.

Because of the broad spectrum of programs that can be impacted by 10 CFR 50.69, this conclusion may be overly optimistic for 10 CFR 50.69 categorization purposes. However, as NEI00-4 requires that external hazards be included in the overall categorization process, they do not need to be explicitly addressed as part of this new enhanced methodology for pressure boundary components. (Note: EPRI Report 3002012988, Alternative Approaches for Addressing Seismic Risk in 10CFR50.69 Risk-Informed

Categorization, has been developed as an alternative to NEI00-04 and is under review by NRC for the Calvert Cliffs application. [22])

EPRI report 1021467-A makes several statements that key assumptions and treatment of uncertainties will not significantly impact the results of the RI-ISI program. As to 10 CFR 50.69 applications, key uncertainties and assumptions are addressed as part of the LAR process, so an explicit consideration for this new methodology is not required.

[Note: NEI has developed a 10 CFR 50.69 LAR template that incorporates lessons learned from industry/NRC interactions on this topic.]

Regarding SR IF-B2, report 1021467-A noted that RI-ISI only applied to piping. 10 CFR 50.69 can also apply to tanks, gaskets, fitting, and so on. As the requirements for this SR apply to all capability categories, there is no change is needed to support 10 CFR 50.69 applications.

SR IF-C3b deals with inter-area propagation and barriers to inter-area propagation, including penetrations, doors, walls, hatchways, and heating, ventilation, and air conditioning (HVAC) ducts. One of the prerequisites of this enhanced methodology is that these barriers cannot be categorized as RISC-3 without an explicit evaluation of its impact on the pressure boundary categorization results.

SR IF-D6 deals with the consideration of human-induced floods. 10 CFR 50.69 categorization results (HSS or LSS) will not negatively or positively impact these actions.

In conclusion, PRA models meeting the guidance of EPRI report 1021467-A taken together with the overall 10 CFR 50.69 categorization process (NEI00-04, EPRI report 3002012988), and the LAR submittal and review process provides required confidence that the plant-specific internal events PRA including IF is robust and capable of identifying any plant-specific outliers that should be defined as HSS.

Prerequisite 2 Integrity management The following aspects address key issues associated with the reliability of passive SSCs:

Robust program that addresses localized corrosion. The plant shall have a robust program that addresses localized corrosion (for example, pitting and MIC) that follows the guidance contained in EPRI reports TR-103403, Service Water System Corrosion and Deposition Sourcebook [10], TR-l06229, Service Water System Chemical Addition Guideline [11], TR-102063, Guide for the Examination of Service Water System Piping

[12], 1010059, Service Water Piping Guideline [13], and 1016456, Recommendations for an Effective Program to Control the Degradation of Buried Pipe [14]. Program health can be determined via self-assessments, benchmarking, or peer review.

Robust program that addresses FAC. The plant shall have a robust program to address FAC that follows the recommendations contained in EPRI report 3002000563 Recommendations for an Effective Flow-Accelerated Corrosion Program) [15]. This may include the use of standardized health reports such as those developed out of NEI Efficiency Bulletin 16-34, Streamline Program Health Reporting [16].

Robust program that addresses erosion. The plant shall have a robust program to address erosion that follows the guidance of EPRI report 3002005530, Recommendations for an Effective Program Against Erosive Attack [17]. For a number of licensees, this may be addressed as part of a license renewal commitment. Additionally, some licensees

may include erosion within their FAC program, whereas other licensees may choose to address erosion as a separate program.

Prerequisite 3 - Protective measures for IF events Protective measures for IF events (that is, floor drains, flood alarm equipment, and barriers) shall not be categorized as LSS unless additional evaluations have been conducted to show that loss of these measures, or a subset of these measures, will not invalidate the HSS determination provided below.

4.2 Predetermined HSS Passive SSCs The following section describes the scope of systems, subsystems, and piping segments that have been predetermined to be HSS. Table 4-1 also identifies the scope of predetermined components together with a listing of additional clarifications and considerations that were used in defining this scope.

HSS components shall include the following:

(1) Class 1 portions of the RCPB, with the exception of the following:

(a) In the event of postulated failure of the component during normal reactor operation, the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system.

(b) The component is or can be isolated from the reactor coolant system by two valves in series (both closed, both open, or one closed and the other open). Each open valve must be capable of automatic actuation and, assuming the other valve is open, its closure time must be such that, in the event of postulated failure of the component during normal reactor operation, each valve remains operable and the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system only.

(2) Applicable portions of the shutdown cooling pressure boundary function. That is, Class 1 and 2 components of systems or portions of systems needed to use the normal shutdown cooling flow path in either of the following ways:

(a) As part of the RCPB from the reactor pressure vessel (RPV) to the second isolation valve (that is, farthest from the RPV) capable of remote closure, or to the containment penetration, whichever encompasses the larger number of welds (b) As part of other systems or portions of systems from the RPV to the second isolation valve (that is, farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds (3) Class 2 portions of steam generators and Class 2 feedwater system components greater than nominal pipe size (NPS) 4 (DN 100) of pressurized water reactors (PWRs) from the steam generator to the outer containment isolation valve.

(4) Components larger than NPS 4 (DN 100) within the break exclusion region (BER) for high-energy piping systems, as applicable.

(5) Portions of the ultimate heat sink (UHS) flow path (for example, service water) whose failures will fail both trains (that is, unisolable failure of the UHS function). (Note: even if piping is isolated/independent, structures such as the service water pumphouse [for example, reservoir, bay] would be expected to be HSS.)

(6) Tanks/vessels and connected piping and components up to the first isolation valve that support/provide inventory to multiple systems/functions (for example, refueling water storage tank [RWST] for PWRs, suppression pool [SP] for boiling water reactors [BWRs]).

(7) Condensate storage tank (CST) for auxiliary feedwater (AFW)/emergency feedwater (EFW) in a PWR unless there is a redundant independent reliable source (for example, auto switchover to service water supply to each train of AFW/EFW suction). This includes connected piping greater than 4 in. (101.6 mm) up to the first isolation valve in the AFW/EFW protected volume of the CST.

(8) For PWR plants, low-volume, intermediate safety systems that typically consist of two physically independent trains (for example, component cooling water [CCW]) that are, on a plant-specific basis, physically connected. For example, loss of pressure boundary integrity of train A will drain train B as well.

(9) Heat exchangers that if they fail (for example, tube or tubesheet failures) could allow reactor coolant to bypass primary containment.

(10) Other heat exchangersif not explicitly addressed in 11 through 14 below, other heat exchangers should be evaluated to determine if component failure (for example, tube or tubesheet) may impact multiple systems. If yes, the methodology and criteria of [5, 6] shall be used to determine HSS versus LSS assignment.

(11) Any piping or component (including piping segments or components grouped or subsumed within existing plant initiating event groups) whose contributions to CDF is greater than 1E-06/year, or whose contribution to LERF is greater than 1E-07/year, based upon a plant-specific PRA model that includes pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses).

(12) Any piping or component (including piping segments or components grouped or subsumed within existing plant initiating event groups) whose contributions to CDF is greater than 1E-08/year and the product of its CDF contribution times its associated CCDP is greater than 1E-08/year, based upon a plant-specific PRA of pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses). (See Figure 4-1.)

Figure 4-1 CCDP versus CDF threshold (13) Any piping or component (including piping segments or components grouped or subsumed within existing plant initiating event groups) whose contributions to LERF is greater than 1E-09/year and the product of its LERF contribution times its associated CLERP is greater than 1E-09/year, based upon a plant-specific PRA of pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses). (See Figure 4-2.)

Figure 4-2 CLERP versus LERF threshold (14) Piping/component support boundaries. Any of the following options may be used:

a) Supports (for example, component support, hanger, or snubber) may remain un-categorized until a need has been identified (for example, a significant repair/replacement or modification is required).

b) A component support, hanger, or snubber shall have the same categorization as the highest ranked piping segment within the piping analytical model in which the support is included.

c) A combination of restraints or supports such that the LSS piping and associated SSCs attached to the HSS piping are included in scope up to a boundary point that encompasses at least two supports in each of three orthogonal directions [18, 19].

Systems, subsystems, and segments that meet any of the criteria in the are to be categorized HSS.

All other safety-related and non-safety-related systems, subsystems, and components not classified as HSS in accordance with the preceding list shall be categorized LSS.

Enhanced Risk-Informed Categorization Methodology for Pressure Boundary Components 3002015999

Cost-effective. On a plant-specific basis, the new categorization methodology is applied once, no matter how many systems are selected for full 10 CFR 50.69 categorization and alternative treatment. Additionally, if a licensee were to categorize five systems in Year X and then were to categorize another five systems in Year X+1, the list of HSS systems/subsystems from a pressure boundary perspective would not change. Obviously, this would have a positive impact on the cost of pressure boundary categorization.

Additionally, as discussed previously, this would provide stability to the overall categorization scheme.

4.1 Prerequisites Prior to implementing the categorization process contained in section 4.2, a licensee will need to assure that the following prerequisites have been met. Each requirement is listed below and explained in further detail in succeeding paragraphs.

Prerequisite 1 - PRA technical adequacy

- Robust internal events PRA model, including IF Prerequisite 2 - Integrity management

- Robust program that addresses localized corrosion

- Robust program that addresses FAC

- Robust program that addresses erosion Prerequisite 3 - Protective measures for IF events Prerequisite 1 - PRA technical adequacy (Pressure Boundary Failures)IF As stated previously, the plant needs to have a robust internal events PRA, including IF, that addresses failure of all pressure boundary components (e.g. main steam line breaks, main feedwater line breaks, internal flooding events, interfacing system LOCA, etc.). As this methodology is being used in support of 10CFR50.69 applications, the plant-specific PRA needs to be sufficient to support the License Amendment Request (LAR) approval process, including consideration of PRA assumptions and sources of uncertainty.

Paragraph 50.69(c)(1 )(i) of 10 CFR requires, in part, that the PRA must be of sufficient quality and level of detail to support the categorization process, and must be subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRC.

Paragraph 50.69(b)(2)(iii) of 10 CFR requires the results of the PRA review process conducted to meet 10 CFR 50.59(c)(1 )(i) be submitted as part of the application. This can include full-scope peer review of the internal events and internal flooding PRA against RG 1.200, Revision 2 as well as a gap assessments of earlier peer reviews of the internal events and internal flooding PRA against RG 1.200, Revision 2. An example of the review of a plant-specific PRA that meets these requirements can be found in [X1].

A similar requirement was imposed upon the development of RI-ISI programs. To help determine if a plant had a PRA sufficient to develop an RI-ISI program, EPRI report 1021467, Probabilistic Risk Assessment Technical Adequacy Guidance for Risk-Informed In-Service Inspection Programs, [12] was developed. This report identifies which portions of the PRA (that is, supporting requirements [SRs]) apply to the development of RI-ISI programs and for those 4-2

portions of the PRA that do apply to (RI-ISI) programs, what level of technical adequacy is needed.

EPRI report 1021467 has been reviewed to identify whether its technical justification and conclusions are also valid for the categorization of pressure boundary components for 10 CFR 50.69 purposes. That is, is a PRA that meets the requirements of 1021467 sufficient to support the categorization of pressure boundary components for 10 CFR 50.69 purposes?

As it pertains to 10 CFR 50.69, insights obtained from this review of EPRI report 1021467 include the following:

RI-ISI and 10 CFR 50.69 both require a living program component (for example, 10 CFR 50.69(e) Feedback and Process Adjustment).

EPRI report 1021467 was able to show that inclusion of external hazards (for example, seismic and internal fires) was not required in order to develop an RI-ISI program because their inclusion would not change the conclusions derived from the RI-ISI process. Because of the broad spectrum of programs that can be impacted by 10 CFR 50.69, this conclusion may be overly optimistic for 10 CFR 50.69 categorization purposes. However, as NEI00-4 requires that external hazards be included in the overall categorization process, they do not need to be explicitly addressed as part of this new enhanced methodology for pressure boundary components. (Note: EPRI Report 3002012988, Alternative Approaches for Addressing Seismic Risk in 10CFR50.69 Risk-Informed Categorization [13], has been developed as an alternative to NEI00-04 and is under review by NRC for the Calvert Cliffs application [14].

EPRI report 1021467 makes several statements that key assumptions and treatment of uncertainties will not significantly impact the results of the RI-ISI program. As to 10 CFR 50.69 applications, key uncertainties and assumptions are addressed as part of the LAR process, so an explicit consideration for this new methodology is not required. (Note: NEI has developed a 10 CFR 50.69 LAR template that incorporates lessons learned from industry/NRC interactions on this topic.)

Regarding SR IF-B2, report 1021467 noted that RI-ISI only applied to piping. 10 CFR 50.69 can also apply to tanks, gaskets, fitting, and so on. As the requirements for this SR apply to all capability categories, there is no change is needed to support 10 CFR 50.69 applications.

SR IF-C3b deals with inter-area propagation and barriers to inter-area propagation, including penetrations, doors, walls, hatchways, and heating, ventilation, and air conditioning (HVAC) ducts. One of the prerequisites of this enhanced methodology is that these barriers cannot be categorized as RISC-3 without an explicit evaluation of the barriers impact on the pressure boundary categorization results.

SR IF-D6 deals with the consideration of human-induced floods. 10 CFR 50.69 categorization results (HSS or LSS) will not negatively or positively impact these actions.

In conclusion, PRA models meeting the guidance of EPRI report 1021467 taken together with the overall 10 CFR 50.69 categorization process (NEI00-04, EPRI report 3002012988 [2, 13]),

and the LAR submittal and review process provides required confidence that the plant-specific internal events PRA including IF is robust and capable of identifying any plant-specific outliers that should be defined as HSS.

4-3

Prerequisite 2 Integrity management In the context of developing an enhanced methodology for categorizing pressure boundary components for 10CFR50.69 purposes, it is important to note that approval to implement 10CFR50.69 does not absolve a Licensee from meeting other commitments related to pressure boundary integrity. For example, NEI-03-08 (Guidelines For The Management Of Materials Issues), Material Reliability Program (MRP), Boiling Water Reactor Vessel and Internals Project (BWRVIP), License Renewal / Subsequence License Renewal (SR/SLR).

Further, during the development of the risk-informed inservice inspection methodologies (RI-ISI) a number of reviews of various degradation mechanisms potentially operative in safety related and non-safety related systems was conducted. As a result of these efforts [X1 - X7], it was determined that for systems typically outside the scope of an ISI program the requirements identified below were the appropriate means of assuring pressure boundary integrity Systems/subsystems typically included with in a RI-ISI program (e.g. NRC approved code case N-716-1) that are also within the scope of the pre-determined set of HSS systems/ subsystems contained with the enhanced methodology would continue to be treated within the confines of the RI-ISI program.

Finally (d)(2) the 10CFR50.69 rule requires that the Licensee conduct periodic inspection and testing activities to determine that RISC-3 SSCs will remain capable of performing their safety-related functions under design basis conditions. For significant conditions adverse to quality, measures must be taken to provide reasonable confidence that the cause of the condition is determined and corrective action is taken to preclude repetition.

As such, application of the prerequisites below in the context of 10CFR50.69 will provide a robust mechanism for assuring pressure boundary integrity:

The following aspects address key issues associated with the reliability of passive SSCs:

Robust program that addresses localized corrosion. The plant shall have a robust program that addresses localized corrosion (for example, pitting and microbiologically influenced corrosion that follows the guidance contained in EPRI reports TR-103403, Service Water System Corrosion and Deposition Sourcebook [15]; 3002003190, Engineering and Design Considerations for Service Water Chemical Addition Systems; [16]; TR-102063, Guide for the Examination of Service Water System Piping [17], 1010059, Service Water Piping Guideline [18], and 1016456, Recommendations for an Effective Program to Control the Degradation of Buried Pipe [19]. Program health can be determined via self-assessments, benchmarking, or peer review.

Robust program that addresses FAC. The plant shall have a robust program to address FAC that follows the recommendations contained in EPRI report 3002000563 Recommendations for an Effective Flow-Accelerated Corrosion Program [20]. This may include the use of standardized health reports such as those developed out of NEI Efficiency Bulletin 16-34, Streamline Program Health Reporting [21].

Robust program that addresses erosion. The plant shall have a robust program to address erosion that follows the guidance of EPRI report 3002005530, Recommendations for an Effective Program Against Erosive Attack [22]. For a number of licensees, this may be addressed as part of a license renewal commitment. Additionally, some licensees may 4-4

include erosion within their FAC program, whereas other licensees may choose to address erosion as a separate program.

Prerequisite 3 - Protective measures for IF events Protective measures for IF events (that is, floor drains, flood alarm equipment, and barriers) shall not be categorized as LSS unless additional evaluations have been conducted to show that loss of these measures, or a subset of these measures, will not invalidate the HSS determination provided in section 4.2. For example, if a submarine door has been credited in preventing a flood from exiting one flood zone into another flood zone, then that submarine door shall be considered HSS unless an evaluation has been conducted showing that loss of the submarine door will not significantly increase plant risk (i.e. exceed criterion 11, 12 or 13).

4.2 Predetermined HSS Passive SSCs The following section describes the scope of systems, subsystems, and piping segments that have been predetermined to be HSS. Table 4-1 also identifies the scope of predetermined components together with a listing of additional clarifications and considerations that were used in defining this scope.

HSS components shall include the following:

1. Class 1 portions of the RCPB, with the exception of the following:

a. In the event of postulated failure of the component during normal reactor operation, the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system.

b. The component is or can be isolated from the reactor coolant system by two valves in series (both closed, both open, or one closed and the other open). Each open valve must be capable of automatic actuation and, assuming the other valve is open, its closure time must be such that, in the event of postulated failure of the component during normal reactor operation, each valve remains operable and the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system only.

Note: Depending upon the plant-specific licensing basis, the above may be classified as Class 1, Class 1 exempt, or non-Class 1 (e.g. Class 2). For plants that have classified this piping as Class 1 or Class 1 exempt, consideration should be given to re-classifying this piping as other than Class 1 in order to gain the full benefit of a 10CFR50.69 application. This change would obviously need to follow the applicable commitment change control process (e.g. 10CFR50.59).

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2. Applicable portions of the shutdown cooling pressure boundary function. That is, Class 1 and 2 components of systems or portions of systems needed to use the normal shutdown cooling flow path in either of the following ways:

a. As part of the RCPB from the reactor pressure vessel (RPV) to the second isolation valve (that is, farthest from the RPV) capable of remote closure, or to the containment penetration, whichever encompasses the larger number of welds

b. As part of other systems or portions of systems from the RPV to the second isolation valve (that is, farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds

3. Class 2 portions of steam generators and Class 2 feedwater system components greater than nominal pipe size (NPS) 4 (DN 100) of pressurized water reactors (PWRs) from the steam generator to the outer containment isolation valve.

4. Components larger than NPS 4 (DN 100) within the break exclusion region (BER) for high-energy piping systems, as applicable.

5. Portions of the ultimate heat sink (UHS) flow path (for example, service water) whose failures will fail both trains (that is, unisolable failure of the UHS function). (Note: even if piping is isolated/independent, structures such as the service water pumphouse [for example, reservoir, bay] would be expected to be HSS.)

6. Tanks/vessels and connected piping and components up to the first isolation valve that support/provide inventory to multiple systems/functions (for example, refueling water storage tank [RWST] and containment sump for PWRs, suppression pool [SP] for boiling water reactors [BWRs]).

7. Condensate storage tank (CST) for auxiliary feedwater (AFW)/emergency feedwater (EFW) in a PWR unless there is a redundant independent reliable source (for example, auto switchover to service water supply to each train of AFW/EFW suction). This includes connected piping greater than 4 in. (101.6 mm) up to the first isolation valve in the AFW/EFW protected volume of the CST.

8. For PWR plants, low-volume, intermediate safety systems that typically consist of two physically independent trains (for example, component cooling water [CCW]) that are, on a plant-specific basis, physically connected. For example, loss of pressure boundary integrity of train A will drain train B as well.

9. Heat exchangers that if they fail (for example, tube or tubesheet failures) could allow reactor coolant to bypass primary containment while the plant is at-power or during shutdown).

10. Other heat exchangersif not explicitly addressed in 11 through 13 below, other heat exchangers should be evaluated to determine if component failure (for example, tube or tubesheet) may impact multiple systems. If yes, the methodology and criteria of [5, 6] shall be used to determine HSS versus LSS assignment.

11. Any piping or component, (including piping segments or components grouped or subsumed within existing plant initiating event groups, (e.g. main feedwater breaks inside containment, main steam line breaks outside containment, service water flooding events, interfacing system LOCA) whose contributions to CDF is greater than 1E-06/year, or whose contribution to LERF is greater than 1E-07/year, based upon a plant-specific PRA model that 4-6

includes pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses).

12. Any piping or component, (including piping segments or components grouped or subsumed within existing plant initiating event groups, (e.g. main feedwater breaks inside containment, main steam line breaks outside containment, service water flooding events, interfacing system LOCA) whose contributions to CDF is greater than 1E-08/year and the product of its CDF contribution times its associated CCDP is greater than 1E-08/year, based upon a plant-specific PRA of pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses). (See Figure 4-1.)

Figure 4-1 CCDP versus CDF threshold

13. Any piping or component, (including piping segments or components grouped or subsumed within existing plant initiating event groups, (e.g. main feedwater breaks inside containment, main steam line breaks outside containment, service water flooding events, interfacing system LOCA) whose contributions to LERF is greater than 1E-09/year and the product of its LERF contribution times its associated CLERP is greater than 1E-09/year, based upon a plant-specific PRA of pressure boundary failures (for example, pipe whip, jet impingement, spray, and inventory losses). (See Figure 4-2.)

For criterion 11, 12 and 13, care should be taken in reviewing the PRA results so that total contribution to CDF and LERF are compared to the risk metrics. For example, separate scenarios of spray, moderate flood and large flood based on different plant impacts should be combined so 4-7

that the cumulative impact of the SSC is compared to each risk metric (i.e. CDF, LERF, CCDP, CLERP).

Figure 4-2 CLERP versus LERF threshold For purposes of applying criterion Nos. 11, 12 and 13, the definition of a pipe segment is not a function of whether it was categorized as HSS or LSS per criterion Nos. 1 through 10. That is, even if a piping segment, or a portion of a pipe segment, is HSS per one of the first ten of the criteria above, the impact on risk due to its postulated failure is determined consistent with industry guidance (e.g., PRA standard, EPRI 1019194).

While ASME Code Case N-660 is referenced in NEI 00-04, it should be noted that all 10CFR50.69 submittals approved to date reference the ANO2-R&R-004 methodology (RI-RRA) for categorizing pressure boundary components. The technical basis for the ANO RI-RRA methodology is EPRI TR-112657, Rev B-A which is also codified in ASME Code Case N-578 and Appendix R, Supplement 2. A streamlined version of which in contained in NRC endorsed ASME Code Case N-716.

While slightly different in wording each of these approaches as to piping segments have the same purpose. That is, to group pressure retaining items (e.g., welds, valve bodies, pipe runs, etc.) by common consequence.

In its simplest application, if postulated failure of the entire system (direct and indirect effects) had the same consequence (e.g., causes an initiating event X), then only a single segment would need to be defined. However, from a practical perspective this is typically not the case and the system would be divided into segments as the postulated consequence of failure changes. This 4-8

segmentation can be caused by a multitude of impacts such as different trains within the system (e.g., train A versus train B), piping located in different parts of the plant (e.g. flood area C versus flood area D), piping in the same train and same plant area but a portion is upstream of an isolation valve and the other portion is downstream of an isolation.

14. Piping/component support boundaries. Any of the following options may be used:

a. Supports (for example, component support, hanger, or snubber) may remain un-categorized until a need has been identified (for example, a significant repair/replacement or modification is required).

b. A component support, hanger, or snubber shall have the same categorization as the highest ranked piping segment within the piping analytical model in which the support is included.

c. A combination of restraints or supports such that the LSS piping and associated SSCs attached to the HSS piping are included in scope up to a boundary point that encompasses at least two supports in each of three orthogonal directions [23, 24].

Systems, subsystems, and segments that meet any of the above criteria in the are to be categorized HSS. All other safety-related and non-safety-related systems, subsystems, and components not classified as HSS in accordance with the preceding list shall be categorized LSS.

With respect to categorizing supports (for example, component support, hanger, or snubber) there has been considerable discussion as whether support should be included within a system boundary. The 10CFR50.69 rule allows the Licensees to define the system boundaries and then all components within that system boundary would need to be included in that systems categorization. Currently approved 10CFR50.69 LARs are using the ANO2-R&R-004 [Z]

methodology, which can be applied to Class 2 and 3 pressure retaining items or their associated supports. As such, component supports, hangers, or snubbers need not be included within a system categorization. Additionally, the example system categorization provided by ANO2 to NRC during RAIs for the relief request included pressure boundary components only. That is, component supports, hangers, or snubbers were not included within the system boundary categorization.

Consistent with this approach, the enhanced methodology does not require component supports, hangers, or snubbers be categorized as part of categorizing the pressure boundary function. The exception to this is when the enhanced methodology identifies non-safety related pressure boundary components as high safety significant. In this case once the categorization is approved by the IDP panel, 50.69(d) requires that the licensee ensure that RISC-2 SSCs perform their functions consistent with the categorization process assumptions by evaluating treatment being applied to these SSCs to ensure that it supports the key assumptions in the categorization process that relate to their assumed performance. Thus, this review should include an assessment of the supports once RISC-2 SSCs are identified.

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5.3 Criterions 11, 12 and 13 Application of criteria 11, 12 and 13 identifies plant-specific pressure boundary components that are not assigned to the generic HSS category but that may be risk-significant at a particular plant.

Criterion 11 of the enhanced methodology requires that any piping or component whose contribution to CDF (LERF) greater than 1E-6/year (1E-7/year) be assigned to the HSS category.

As discussed in the Grand Gulf and DC Cook Safety Evaluation Reports for their ASME Code Case N-716 relief requests [X, Y], these guideline values (1E-6 / 1E-7) are suitably small and consistent with the decision guidelines for acceptable changes in CDF and LERF found in NRC endorsed EPRI TR-112657, Rev B-A. Criterion 11 was added as a defense-in-depth measure to provide a method of ensuring that any plant-specific locations that are important to safety are identified. Criterion 11 is only used to add HSS segments and not, for example, to remove system parts generically assigned to the HSS in criterion 1 through 10.

To further the goal of defense-in-depth beyond that previously found acceptable, criterion 12 and 13 were developed and added to the enhanced methodology to conservatively increase the confidence that somewhat important pressure boundary components would not be missed on a plant-specific basis. By incorporating CCDP/CLERP (conditional core dame probability /

conditional large early release probability) metrics these measures also provide additional balance between prevention and mitigative. That is, components cannot be assigned to the LSS population based solely on low failure likelihood, unless that likelihood is remote. That is, less than 1E-08 CDF and less than 1E-09 LERF. Similar to criterion 11, criterions 12 and 13 were added to provide additional means of ensuring that any plant-specific locations that are important to safety are identified. Criterion 12 and 13, are used to add HSS segments and not, for example, to remove system parts generically assigned to the HSS in criterion 1 through 10. Finally, 10CFR50.69(d)(2) requires that Licensees ensure, with reasonable confidence, that RISC-3 SSCs remain capable of performing their safety-related functions under design basis conditions, including seismic conditions and environmental conditions and effects throughout their service life.

Criterion 11, 12 and 13 provides confidence that the goal of identifying the more risk-significant locations is met while permitting the use of generic HSS system parts identification to simplify and standardize the evaluation. Satisfying the guidelines in criterion 11, 12 and 13 requires confidence that the PRA (internal event PRA, internal flooding PRA) is capable of identifying the significant contributors to risk that are not included in the generic results. RG 1.200 states that meeting the attributes of an NRC-endorsed industry PRA standard may be used to demonstrate that a PRA is adequate to support a risk-informed application. RG 1.200 further states that an acceptable approach that can be used to ensure technical adequacy would trigger a peer review of the PRA. As discussed in Prerequisite #1, a robust plant-specific PRA is required to implement this enhanced methodology.

Table 5-3 below provides examples of industry experience of pressure boundary components that exceeded the 1E-6 / 1E-7 metrics. This table provides examples of safety improvements that have been brought about by voluntary implementation of criterion 11 on other risk-informed applications. It is expected that use of criterion 12 and 13 together with criterion 11 will provide additional safety improvements.

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Table 5-32 Examples of Implementation of Criterion 11 Plant Issue Action No.

1 Interfacing system LOCA exceeded metrics More refined / realistic analyses 2 Interfacing system LOCA exceeded metrics More refined / realistic analyses Failure of a fire protection line in the Auxiliary Building which was postulated to flood the Electrical Switchgear Cable Enclosure, Battery Room and Battery Plant hardware modification (piping removed from area)

Charger 3

Failures of the circulating water system in the Condenser Pit (CDF Operating Procedure update to better define human error contribution of 3.75E06). probabilities (HEPs)

Failure of a fire protection line in the Auxiliary Building which was postulated to flood the Electrical Switchgear Cable Enclosure, Battery Room and Battery Plant hardware modification (piping removed from area)

Charger 4

Failures of the circulating water system in the Condenser Pit (CDF Operating Procedure update to better define HEPs contribution of 3.75E06).

Supplementary visual inspection of the associated fire protection 5 Fire protection piping in auxiliary building piping is required every quarter and 6 UT (thickness) exams per interval.

Supplementary visual inspection of the associated fire protection 6 Fire protection piping in auxiliary building piping is required every quarter and 6 UT (thickness) exams per interval.

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Plant Issue Action No.

7 Plant service water exceeded LERF criterion More refined / realistic analyses 8 Service Water piping in the 480V switchgear room Five new inspections added looking for wall loss Class 3 nuclear service water in auxiliary feedwater pump room impacting 9 New NDE selected mechanical / electrical equipment Class 3 nuclear service water in auxiliary feedwater pump room impacting 10 New NDE selected mechanical / electrical equipment 11 Flooding caused by fire protection piping in the East DC switchgear room 3 of 10 mechanical connections selected for inspection 12 Service Water in Cable Spreading Room - loss of electrical equipment New NDE selected 13 Service Water in Cable Spreading Room - loss of electrical equipment New NDE selected 5-26

Plant Issue Action No.

Updated analysis to allow credit for operator action in response to 14 Service Water in Auxiliary building exceeded metrics the postulated flood scenario Updated analysis to allow credit for operator action in response to Service Water in Control Building exceeded metrics the postulated flood scenario Failure of fire protection in the control building (3 separate locations) can 15 Hardware (i.e. flow limiting orifice) and procedure modification cause loss of ESWG Rooms and CSR This remaining scenario involves a flood originating in the turbine building zone 16 designated TGB. The area is located at elevation 46 feet, essentially plant More refined / realistic analyses grade.

17 High Pressure Firewater in Auxiliary building exceeded metrics New NDE and/or removal of piping Raw Cooling Water in Auxiliary Building exceeded metrics New NDE and/or removal of piping 18 Failure of expansion bellows can cause loss of ESWG Rooms Hardware and NDE being investigated 5-27

18. Service Water Piping Guideline. EPRI, Palo Alto, CA: 2005. 1010059.

19. Recommendations for an Effective Program to Control the Degradation of Buried Pipe.

EPRI, Palo Alto, CA: 2008. 1016456.

20. Recommendations for an Effective Flow-Accelerated Corrosion Program (NSAC-202L-4).

EPRI, Palo Alto, CA: 2013. 3002000563.

21. NEI, Efficiency Bulletin 16-34: Streamline Program Health Reporting.

22. Recommendations for an Effective Program Against Erosive Attack. EPRI, Palo Alto, CA: 2015. 3002005530.

23. NUREG-1800, Revision 2, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, December 2010.

24. NUREG-2192, Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants, July 2017.

25. ASME/ANS RA-Sa-2009, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications.

Reference for section 4.1, Prerequisite #1 Exelon Letter Application to Implement an Alternate Defense-in-Depth Categorization Process, An Alternate Pressure boundary Categorization Process, and an Alternate Seismic Tier 1 Categorization Process in Accordance with the requirements of 10CFR50.69 Risk-informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors References for section 4.1 Prerequisite #2 Revised Risk-Informed Inservice Inspection Evaluation Procedure, EPRI, Palo Alto, CA: 1999.

TR-112657 Rev. B-A.

Nondestructive Evaluation: N761 Revision 1 Pilot Study Results and Lessons Learned. EPRI, Palo Alto, CA: 2014. 3002003029.

Application of the EPRI Risk-Informed Inservice Inspection Evaluation Procedure: A BWR Pilot Study (Volumes 1 & 2), EPRI, Palo Alto, CA: 1997. TR-107530.

Application of EPRI Risk-Informed Inservice Inspection Guidelines to CE Plants (Volumes 1 &

2), EPRI, Palo Alto, CA: 1997. TR-107531.

WCAP-14572, Westinghouse Owners Group Application of Risk-Based Methods to Piping Inservice Inspection Topical Report, Revision 1-NP-A, dated February 1999.

EC-JRC/OECD-NEA Benchmark Study on Risk Informed In Service Inspection Methodologies

[RISMET Benchmark Study - Host plant Ringhals, PWR], Report #NEA/CSNI/R(2010)13 8-2

Using the EPRI Risk-informed ISI methodology on Piping System in Forsmark 3, Research 2010:42 References for Chapter 5-3 USNRC letter from Thomas G Hiltz, Chief, Plant Licensing Branch IV, Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation to Mr. Brian S. Ford, Senior Manager, Nuclear Safety & Licensing, Entergy Operations, Inc.,

Subject:

GRAND GULF NUCLEAR STATION UNIT 1 - REQUEST FOR ALTERNATIVE GG-ISl-002 - IMPLEMENT RISK-INFORMED INSERVICE INSPECTION PROGRAM BASED ON AMERICAN SOCIETY OF MECHANICAL ENGINEERS BOILER AND PRESSURE VESSEL CODE, CODE CASE N-716, (TAC NO. MD3044), dated September 21, 2007.

USNRC letter from Travis L. Tate, Acting Branch Chief, Plant Licensing Branch 3-1, Division of Operating Reactor Licensing, Office of Nuclear Reactor Regulation to Mr. Mano K. Nazar Senior Vice President and Chief Nuclear Officer, Indiana Michigan Power Company, Nuclear Generation Group,

Subject:

DONALD C. COOK NUCLEAR PLANT, UNITS 1 AND 2 - RISK-INFORMED SAFETY-BASED INSERVICE INSPECTION PROGRAM FOR CLASS 1 AND 2 PIPING WELDS (TAC NOS. MD3137 AND MD3138), dated September 28, 2007.

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4.2 Predetermined HSS Passive SSCs The following section describes the scope of systems, subsystems, and piping segments that have been predetermined to be HSS. Table 4-1 also identifies the scope of predetermined components together with a listing of additional clarifications and considerations that were used in defining this scope.

HSS components shall include the following:

1. Class 1 portions of the RCPB. Depending upon the plant-specific licensing basis, piping as described in a and b below may have been optionally classified as Class 1 or Class 1 exempt.

Consideration should be given to re-classifying this piping as other than Class 1 in order to gain the full benefit of a 10CFR50.69 application. This change would obviously need to follow the applicable commitment change control process (e.g. 10CFR50.59). LSS shall not be assigned to the piing described in a and b below until this piping has been classified as non-Class 1with the exception of the following:

a. In the event of postulated failure of the component during normal reactor operation, the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system.

b. The component is or can be isolated from the reactor coolant system by two valves in series (both closed, both open, or one closed and the other open). Each open valve must be capable of automatic actuation and, assuming the other valve is open, its closure time must be such that, in the event of postulated failure of the component during normal reactor operation, each valve remains operable and the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system only.

Note: Depending upon the plant-specific licensing basis, the above may be classified as Class 1, Class 1 exempt, or non-Class 1 (e.g. Class 2). For plants that have classified this piping as Class 1 or Class 1 exempt, consideration should be given to re-classifying this piping as other than Class 1 in order to gain the full benefit of a 10CFR50.69 application. This change would obviously need to follow the applicable commitment change control process (e.g. 10CFR50.59).

4.3 Acceptably small increases to CDF and LERF 10CFR50.69 and NEI00-04 require that evaluations be conducted that provide reasonable confidence that for SSCs categorized as RISC-3 any potential increases in core damage frequency (CDF) and large early release frequency (LERF) resulting from changes in treatment are small.

While this evaluation is already required by NEI00-04 to be conducted, to provide a complete risk-informed pressure boundary categorization methodology, this section of the report describes the evaluations necessary to be conducted for the pressure boundary function when implementing the enhanced categorization methodology.

As discussed in section 8.1 of NEI00-04 one of the guiding principles of this process is that changes in treatment should not significantly degrade performance for RISC-3 SSCs and should maintain or improve the performance of RISC-2 SSCs, and when that principle is coupled with Prerequisite #1 in section 4.1 of this report, there is high confidence that there would be little, if any, net increase in risk as a result of implementing the enhanced methodology.

For this effort, pressure boundary components that are modeled in the IE PRA or IF PRA that have been determined to be LSS shall have their failure rates (e.g. pipe break frequency) increased by a factor of 3 and CDF and LERF re-quantified. As discussed above, due to the requirements of the ECM and the requirements that RISC-3 SSCs continue to perform their safety related functions under design basis conditions this type of degradation is extremely unlikely for any single component let alone entire groups of components so that the factor of 3 is a conservative bound as well as being consistent with NEI00-4, section 8.1.

Results of this sensitivity study shall be compared to the quantitative acceptance guidelines of Reg. Guide 1.174. Any pressure boundary component as modeled in the IE PRA or IF PRA that exceeds the acceptance guidelines of Reg. Guide 1.174 shall be candidate HSS, subject to IDP concurrence. All pressure boundary components that were determined to be LSS per section 4.2 of this report and remain below Reg. Guide 1.174 acceptance guidelines shall be categorized as LSS.

50.69(c)(1) SSCs must be categorized as RISC-1, RISC-2, RISC-3, or RISC-4 SSCs using a categorization process that determines if an SSC performs one or more safety significant functions and identifies those functions. The process must:

(i) Consider results and insights from the plant-specific PRA. This PRA As stated previously, the plant needs to have a robust internal events must at a minimum model severe accident scenarios resulting from PRA, including IF, that addresses failure of all pressure boundary internal initiating events occurring at full power operation. The PRA components (e.g. main steam line breaks, main feedwater line breaks, must be of sufficient quality and level of detail to support the internal flooding events, interfacing system LOCA, etc.). As this categorization process, and must be subjected to a peer review methodology is being used in support of 10CFR50.69 applications, the process assessed against a standard or set of acceptance criteria that plant-specific PRA needs to be sufficient to support the License is endorsed by the NRC. Amendment Request (LAR) approval process, including consideration of PRA assumptions and sources of uncertainty.

Paragraph 50.69(c)(1 )(i) of 10 CFR requires, in part, that the PRA must be of sufficient quality and level of detail to support the categorization process, and must be subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRC. Paragraph 50.69(b)(2)(iii) of 10 CFR requires the results of the PRA review process conducted to meet 10 CFR 50.59(c)(1 )(i) be submitted as part of the application. This can include full-scope peer review of the internal events and internal flooding PRA against RG 1.200, Revision 2 as well as a gap assessments of earlier peer reviews of the internal events and internal flooding PRA against RG 1.200, Revision 2. An example of the review of a plant-specific PRA that meets these requirements can be found in [X1].

(ii) Determine SSC functional importance using an integrated, The enhanced methodology is limited to categorizing the pressure systematic process for addressing initiating events (internal and boundary function. All other functions including design bases external), SSCs, and plant operating modes, including those not functions and functions credited for mitigation and prevention of modeled in the plant-specific PRA. The functions to be identified and severe accidents continue to be addressed as part of NEI00-04.

considered include design bases functions and functions credited for The enhanced methodology was built to reflect and confirm for the mitigation and prevention of severe accidents. All aspects of the pressure boundary function that the supporting analysis (e.g. IE and IF integrated, systematic process used to characterize SSC importance PRA) reflect the current plant configuration and operating practices, and applicable plant and industry operational experience (e.g.

must reasonably reflect the current plant configuration and operating prerequisite 2 (integrity management) including changes to the EPRI practices, and applicable plant and industry operational experience. report).

(iii) Maintain defense-in-depth. Piping systems in a nuclear power plant contribute to defense-in-depth in two important ways. The first is that the reactor coolant pressure boundary (RCPB) provides one of the sets of barriers in the barrier defense-in-depth arrangement. This barrier protects the release pathway from the reactor core to containment release pathways, and part of it is responsible for protecting against potential containment bypass pathways. This enhanced methodology requires that the applicable Class 1 portion of the RCPB be categorized as HSS.

Per this enhanced methodology there are no pressure boundary components categorized as LSS that could be considered part of the RCPB (criterion 1).

The second way pressure boundary components can contribute to defense-in-depth is in its role in the protection of the core through providing critical safety functions that require piping system integrity.

This was considered in developing the enhance methodology. The enhanced methodology requires that pressure boundary failures that would fail a critical safety function be categorized as HSS. These include those failures that would impact key inventory sources (criterions 6 and 7), generic lessons learned and plant-specific insights into contributors to core damage or containment performance, including consideration of common cause and balance between prevention and mitigation (criterions 3, 4, 6, 9, 11, 12 and 13), failure of the ultimate heat sink (criterion 5) and components that can have intersystem impact (for example, heat exchangers (criterion 9 and 10),

suppression pool and containment sump connections to containment (criterion 6). As such, there are no pressure boundary components categorized as LSS that would challenge these critical safety functions (please see criterions 1 through 13). Essentially, pressure boundary failures that fail a basic safety function could not meet criterion 11 through 13 for LSS, which includes consideration of common cause.

In addition, consistent with the 10CFR50.69 rule, the enhanced methodology does not alter the design basis of the plant. As such, the level of redundancy, independence, and diversity of key safety features, including fission product barriers, remains unchanged.

Further, 10CFR50.69(d)(2) requires that Licensees ensure, with reasonable confidence, that RISC-3 SSCs remain capable of performing their safety-related functions under design basis conditions, including seismic conditions and environmental conditions and effects throughout their service life assuring that defense in depth is not compromised.

(iv) Include evaluations that provide reasonable confidence that For the pressure boundary function of RISC-3 SSCs, the plant design for SSCs categorized as RISC-3, sufficient safety margins are basis is not changes and sufficient safety margins are maintained as maintained and that any potential increases in core damage the existing safety analysis and acceptance criteria in the plant frequency (CDF) and large early release frequency (LERF) resulting licensing basis are not changed and the evaluation required by section from changes in treatment permitted by implementation of §§ 8.1 of NEI00-04 assures that any potential increases in CDF and LERF 50.69(b)(1) and (d)(2) are small. resulting from changes in treatment permitted on the pressure boundary function by implementation of §§ 50.69(b)(1) and (d)(2) will be small.

The enhanced methodology requires that all systems providing a (v) Be performed for entire systems and structures, not for selected pressure boundary function be categorized.

components within a system or structure.

v t e Letter Sequence Other
EPID:L-2021-LLA-0042, TSTF-505 (Approved, Closed)
Initiation Request, Request Acceptance Supplement, Supplement Administration Meeting, Meeting, Meeting, Meeting, Meeting Questions 19 April 2022 13 May 2022 24 June 2022 Answers 30 June 2022 Results Approval, Approval, Approval, Approval, Approval Other: ML21111A031, ML21295A036, ML23076A281, ML23076A282, ML23079A188, ML23089A160, ML23094A171, ML23094A179
MONTHYEAR2022-04-19 [Table View]

ML23076A281

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