ML24102A244

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NRR E-mail Capture - Audit Question TSTF-505 and 50.69
ML24102A244
Person / Time
Site: River Bend Entergy icon.png
Issue date: 09/22/2023
From: James Drake
NRC/NRR/DORL/LPL4
To: Bradley Jones
Entergy Nuclear Operations
References
Download: ML24102A244 (19)
v • d • e


Text

From: Jason Drake Sent: Friday, September 22, 2023 1:23 PM To: Jones, Brian A. (RBS)

Cc: Crawford, Randy

Subject:

RE: RE: RE: TSTF-505/50.69 Audit Date Attachments: RBS 10 CFR 50.69 Audit Questions (APLA and APLC).docx; RBS TSTF-505 audit questions_Revised.docx

Brian,

Attached are the Draft questions for the 10/11-10/12 audit.

The audit document with the agenda and scoping will follow.

Please contact me with any questions.

Thanks, Jason

From: Jones, Brian A. (RBS) <bjone10@entergy.com>

Sent: Thursday, September 14, 2023 10:09 AM To: Jason Drake <Jason.Drake@nrc.gov>

Cc: Crawford, Randy <RCRAWFO@entergy.com>

Subject:

[External_Sender] RE: RE: TSTF-505/50.69 Audit Date

Jason,

Ive reached out to our team and everyone is available on 10/5, but 10/6 there will be a number of PRA individuals unavailable.

Just so you know most of the office workers at RBS work Monday - Thursday. If one of the review days ends up being on a Friday we will need to make arrangements with other departments like Engineering to make sure we have adequate support.

Brian

From: Jason Drake <Jason.Drake@nrc.gov>

Sent: Wednesday, September 13, 2023 8:44 AM To: Jones, Brian A. (RBS) <bjone10@entergy.com>

Cc: Crawford, Randy <RCRAWFO@entergy.com>

Subject:

RE: RE: TSTF-505/50.69 Audit Date

Brian,

Thank you for checking into this. My team is being a bit extremely difficult on scheduling. In an effort to keep it in the week of 10/2, would 10/5-10/6 work? Trying to keep options open.

Thanks, Jason

From: Jones, Brian A. (RBS) <bjone10@entergy.com>

Sent: Wednesday, September 13, 2023 9:41 AM To: Jason Drake <Jason.Drake@nrc.gov>

Cc: Crawford, Randy <RCRAWFO@entergy.com>

Subject:

[External_Sender] RE: TSTF-505/50.69 Audit Date

Jason,

I have discussed performing the audit the week of 10/9 and the RBS team is able to support.

I will be out of the office the week of 10/9, so a different individual from Reg Assurance would have to be assigned to cover the audit.

Thanks,

Brian

From: Jason Drake <Jason.Drake@nrc.gov>

Sent: Monday, September 11, 2023 1:58 PM To: Jones, Brian A. (RBS) <bjone10@entergy.com>

Cc: Crawford, Randy <RCRAWFO@entergy.com>

Subject:

RE: TSTF-505/50.69 Audit Date

EXTERNAL SENDER. DO NOT click links, or open attachments, if sender is unknown, or the message seems suspicious in any way. DO NOT provide your user ID or password.

Brian,

10/2 presents a conflict or staff. Can you support the week of 10/9?

Thanks, Jason

From: Jones, Brian A. (RBS) <bjone10@entergy.com>

Sent: Thursday, September 07, 2023 1:49 PM To: Jason Drake <Jason.Drake@nrc.gov>

Cc: Crawford, Randy <RCRAWFO@entergy.com>

Subject:

[External_Sender] TSTF-505/50.69 Audit Date

Jason,

I have discussed the proposed audit dates with our PRA group based on our conversation yesterday. Our team would like to start the TSTF-505/50.69 audit the week of 10/2/23 based on our PRA staff availability. Please let us know if this is acceptable.

Later dates could work as well, but we do have some major NRC inspections coming up such as PI&R and 95001 that may impact staff availability.

Thanks,

Brian This message is intended for the exclusive use of the intended addressee. If you have received this message in error or are not the intended addressee or his or her authorized agent, please notify me immediately by e-mail, discard any paper copies and delete all electronic files of this message.

Hearing Identifier: NRR_DRMA Email Number: 2469

Mail Envelope Properties (MN2PR09MB58038BFB84F31CED64B64F68FBFFA)

Subject:

RE RE RE TSTF-50550.69 Audit Date Sent Date: 9/22/2023 1:22:43 PM Received Date: 9/22/2023 1:22:00 PM From: Jason Drake

Created By: Jason.Drake@nrc.gov

Recipients:

"Crawford, Randy" <RCRAWFO@entergy.com>

Tracking Status: None "Jones, Brian A. (RBS)" <bjone10@entergy.com>

Tracking Status: None

Post Office: MN2PR09MB5803.namprd09.prod.outlook.com

Files Size Date & Time MESSAGE 3599 9/22/2023 1:22:00 PM RBS 10 CFR 50.69 Audit Questions (APLA and APLC).docx 43775 RBS TSTF-505 audit questions_Revised.docx 49918

Options Priority: Normal Return Notification: No Reply Requested: No Sensitivity: Normal Expiration Date:

APLA AND APLC AUDIT QUESTIONS

RIVER BEND STATION, UNIT 1, 10 CFR 50.69 LAR

APLA Audit Question 01 - Credit for FLEX Equipment and Actions

NRC memorandum dated May 6, 20221 provides the NRCs staff updated assessment of identified challenges and strategies for incorporating Diverse and Flexible Mitigation Capability (FLEX) equipment into a PRA model in support of risk-informed decisionmaking in accordance with the guidance of RG 1.2002.

Section 3.2.9 of the Enclosure of the LAR states that the sensitivity that removes FLEX credit impacts CDF by approximately twelve percent. Attachment 6 of the LAR, Disposition of Key Assumptions / Sources of Uncertainty, appears to only address one specific FLEX operator action and not the entirety of the uncertainties related to FLEX.

The NRC staff notes that a twelve percent change in risk could significantly impact SSC categorization classifications.

Provide an assessment on the impact on SSC categorizations regarding the uncertainties related to FLEX.

APLA Audit Question 02 - Open Phase Condition

Section C.1.4 of RG 1.200 states the base (e.g., Model of Record) PRA is to represent the as -

built, as-operated plant to the extent needed to support the application. The licensee is to have a process that identifies updated plant information that necessitate changes to the base PRA model.

In response to the January 30, 2012, Open Phase Condition (OPC) event at the Byron Station, the NRC issued Bulletin 2012-013. As part of the initial Voluntary Industry Initiative (VII) for mitigation of the potential for the occurrence of an OPC in electrical switchyards4,,licensees have made the addition of an Open Phase Isolation System (OPIS). In accordance with Staff Requirements Memorandum (SRM)-SECY-16-00685, the NRC staff was directed to ensure that licensees have appropriately implemented OPIS, and that licensing bases have been updated accordingly. From the revised voluntary initiative6 and the resulting industry guidance in NEI 19-

1 U.S. NRC memorandum, Updated Assessment of Industry Guidance for Crediting Mitigating Strategies in Risk Assessments, dated May 6, 2022 (ADAMS Accession No. ML22014A084).

2 U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, RG 1.200, Revision 3, December 2020 (ADAMS Accession No. ML20238B871).

3 U.S. NRC Bulletin 2012-01, Design Vulnerability in Electric Power System (ML12074A115).

4 Anthony R. Pietrangelo to Mark A. Satorius, Ltr re: Industry Initiative on Open Phase Condition -

Functioning of Important-to-Safety Structures, Systems and Components (SSCs), dated October 9, 2013 (ML13333A147).

5 U.S. NRC SRM-SECY-16-0068, Interim Enforcement Policy for Open Phase Conditions in Electric Power Systems for Operating Reactors, dated March 9, 2017 (ML17068A297).

6 Doug True to Ho Nieh, Ltr re: Industry Initiative on Open Phase Condition, Revision 3, dated June 6, 2019

027 on estimating the risk associated with an OPC and OPIS risk, it is understood that the risk impact of an OPC can vary widely, depending on electrical switchyard configuration and design.

In light of this observation, provide the following information:

a) A discussion of the impact on risk of the OPC issue at River Bend Station.

b) Discuss whether modelling of the OPC issue and any OPIS that has been installed and implemented at River Bend Station have been, or are planned to be, incorporated as part of the plant MOR. If so, provide the following:

i. The schedule for the inclusion of OPC and OPIS modeling in the MOR.

ii. The impact, if any, to key assumptions and sources of uncertainty.

iii. A discussion of the HRA methods and assumptions used for OPIS alarm manual response.

iv. The impact to external events (e.g., fire, seismic, flooding, high winds, tornado, other external events, etc.).

v. A discussion of the risk impact of inadvertent OPIS actuation and justification for its exclusion.

c) If OPC and OPIS are not planned to be included in the MOR, provide justification why the risk impact is not included by performing either a qualitative or sensitivity analysis.

APLA Audit Question 03 - Determination of Key Sources of Uncertainty for the 10CFR50.69 Categorization Process and Sensitivity Results

Sections 50.69(c)(1)(i) and 50.69(c)(1)(ii) of 10 CFR 50.69 require that a licensees PRA be of sufficient quality and level of detail to support the SSC categorization process, and that all aspects of the integrated, systematic process used to characterize SSC importance must reasonably reflect the current plant configuration and operating practices, and applicable plant and industry operational experience. The guidance in NEI 00-04 specifies that sensitivity studies be conducted for each PRA model to address uncertainty. The sensitivity studies are performed to ensure that assumptions and sources of uncertainty (e.g., human error, common cause failure, and maintenance probabilities) do not mask the importance of components. The guidance in NEI 00-04 states that additional applicable sensitivity studies from characterization of PRA adequacy should be considered.

Section 3.2.8 of the LAR Enclosure describes the process used for reviewing the PRA assumptions and sources of uncertainty. The NRC staff reviewed the uncertainty documents provided on this audits electronic portal for the internal events, internal flooding, and fire PRA and found that further clarification is necessary regarding the review of assumptions and sources of uncertainty for this application. It is unclear if additional analysis was performed and

(ML19163A176).

7 Nuclear Energy Institute (NEI) 19-02, Guidance for Assessing Open Phase Condition Implementation Using Risk Insights, Revision 0, April 2019 (ML19122A321).

documented to determine if any source of uncertainty could adversely impact any SSC categorization. In light of these observations, provide the following information:

a) Provide details of how the RBS PRA sources of uncertainty were evaluated as a potential key source of uncertainty for this application. In this response provide any documentation of this process.

b) Provide the results of sensitivity studies that determined the impact on risk for each associated source of uncertainty. Include in this discussion justification that the sensitivity results demonstrate that the associated source of uncertainty does not adversely impact any SSC categorization.

APLC Question 01 - (APLC Audit Question 01 for RBS TSTF-505 LAR applies to RBS 10 CFR 50.69 LAR)

APLC Question 02 - (APLC Audit Question 02 for RBS TSTF-505 LAR applies to RBS 10 CFR 50.69 LAR)

APLC Question 03 - Alternate Seismic Approach

Paragraph (b)(2)(ii) of 10 CFR 50.69 requires, for license amendment, a description of measures taken to assure the level of detail of the systematic processes that evaluate the plant.

This includes the internal events at power PRA required by §50.69(c)(1)(i), as well as the risk analyses used to address external events.

The staff has previously requested and reviewed information to support its decision on the technical acceptability of the PRAs used in the case studies as well as details of the conduct of the case studies. This information is included in the supplements to the Calvert Cliffs Nuclear Power Plant, Units 1 and 2, LAR for adoption of 10 CFR 50.69. The supplement to the 10 CFR 50.69 by Calvert Cliffs Nuclear Power Plant LAR dated May 10, 2019 (ADAMS Accession No. ML19130A180), contained additional information related to the alternate seismic approach including incorporation by reference docketed information related to case study Plants A, C, and D; the supplement dated July 1, 2019 (ADAMS Accession No. ML19183A012), further clarified the information related to the alternate seismic approach (see response to RAI 4); the supplement dated July 19, 2019 (ADAMS Accession No. ML19200A216), provided responses to support the technical acceptability of the PRAs used for the Plant A, C, and D case studies as well as technical adequacy of certain details of the conduct of the case studies; the supplement dated August 15, 2019 (ADAMS Accession No. ML19217A143) clarified a response in the July 19, 2019 supplement. The supplement dated July 19, 2019, included modifications to the content of the EPRI report. In addition, the licensee removed several paragraphs related to its previous seismic submittals, categorization team evaluations, and IDP's decision process from a typical Section 3.2.3.

Since the above-mentioned information was requested and reviewed by the staff for Calvert Cliffs Nuclear Power Plants LAR for adoption of 10 CFR 50.69, the staff is unable to use it for the licensees docket unless it is incorporated in the licensees LAR. The above-mentioned information is necessary for the staff to make its regulatory finding on the licensees proposed alternate seismic approach. The information is neither included in the LAR nor is it available in the EPRI report supporting the licensees proposed approach.

a) Provide the above-mentioned information to support the staffs regulatory finding on the alternate seismic approach by either incorporating the information by reference the identified supplements or responding to the RAIs in the identified supplements.

b) If differences exist between the licensees proposed alternate seismic approach and the information in the supplements stated above, identify such differences and either incorporate them in the licensees proposed approach or justify their exclusion.

c) The licensee is required to re-evaluate seismic risk to be low compared to total plant risk, due to changes of HCLPF and c values in APLC Question 01.

APLC Question 04 - External Flooding

Paragraph 50.69(b)(2)(ii) of 10 CFR requires that the quality and level of detail of the systematic processes that evaluate the plant for external events during operation is adequate for the categorization of SSCs.

In Enclosure 4 of the LAR, Table E4-1 provides the External Hazard Screening. In the external flooding section, it states External flooding events will cause no flooding damage to RBS safety-related structures, systems and components. The licensee didnt provide a list of SSCs, such as exterior doors, that are credited for this screening and must categorize as HSS based on NEI 00-04.

Provide a list of the specific exterior doors that will be assigned HSS since they are credited for screening the external flood hazard (in accordance with Figure 5-6 in NEI 00-04).

AUDIT QUESTIONS

LICENSE AMENDMENT REQUEST TO REVISE TECHNICAL SPECIFICATIONS TO

ADOPT TSTF-505, REVISION 2

ENTERGY CORPORATION

RIVER BEND STATION

DOCKET NO. 50-458

APLA Audit Question 01 - In-Scope LCOs and Corresponding PRA Modeling The NRCs safety evaluation for NEI 06-09-A specifies that the LAR should provide a comparison of the TS functions to the PRA modeled functions to show that the PRA modeling is consistent with the licensing basis assumptions or to provide a basis when there is a difference.

Table E1-1 of LAR Enclosure 1 identifies each Limiting Condition for Operation (LCO) in the TSs proposed for inclusion in the RICT program. The table also describes whether the systems and components covered by the LCO are modeled in the PRA and, if so, presents both the design success criteria and PRA success criteria. For certain LCOs, the table explains that the associated structures, systems, and components (SSCs) are not mode led in the PRAs but will be represented using a surrogate event that fails the function performed by the SSC. For some LCOs, the LAR did not provide an adequate description for the NRC staff to conclude that the PRA modeling will be sufficient.

a) Regarding TS LCO 3.3.1.A/B, Table E1-1 states that, for reactor protection system (RPS) instrumentation that an RPS failure model is planned to be incorporated into the Electronic Risk Assessment Tool (ERAT) based on NUREG/CR-5500 (Volume 3)

Reliability Study: General Electric Reactor Protection System, 1984-1995, dated May 1999. It also states that the intent of the RBS ERAT RPS model is to be used as a surrogate for unmodeled RPS SSCs. However, it is stated later that the simplified RPS model provides a more conservative result than the NUREG/CR-5500 model when a Function channel is inoperable or bypassed. Clarity is needed to understand how the RBS ERAT RPS channel modeling is more conservative than NUREG/CR-5500 base probability if the base results in exactly matching the NUREG value. The NRC staff notes that in section 5 of NUREG/CR-5500, the overall failure probability appears to include operator manual scram, control rod system, and hydraulic control unit system (scram discharge volume and solenoid operated valves (SOVs)). NUREG/CR-5500 provides the following failure rates: (1) section 3.3 states a failure rate of 3.8E-06 for the channel and trip portion of RPS, and (2) section 5 states the mean RPS unavailability as 5.8E-06. Clarity is needed to understand how the RBS RPS model incorporates all of the necessary SSCs and operator actions to represent the as-built, as-operated plant for the associated proposed RICT LCOs.

The NRC staff notes that section 5 of NUREG/CR-5500 states that the failure probabilities used were based on U.S. General Electric commercial data from 1984 through 1995, and that the 2009 American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS) PRA standard supporting requirement DA-C1 lists NUREGs that contain failure data from recognized sources. One of those sources,

NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, dated February 2007 (Reference 15),

contains recent industry data including a 2020 update. It is unclear to the staff how Capability Category (CC)-II technical acceptability is met by using the NUREG/CR-5500 data for this application, or if the RBS RPS modeling is being implemented as a surrogate for RICT calculations.

i. Provide justification that the RBS ERAT RPS model provides conservative results when compared to the NUREG/CR -5500 model. Include in this discussion of the failure probability values used from NUREG/CR -5500.

ii. Justify that all of the SSCs associated with the proposed RICT LCOs related to RPS fully represent the functionality of those LCOs. Include in this discussion the apparent disparity of SSCs mentioned in NUREG/CR -5500 to those discussed in Table E1-1 of the LAR, and how the NUREG/CR-5500 failure probability value provides an appropriate comparison for this application.

iii. Regarding the proposed RBS ERAT RPS model meeting the 2009 ASME/ANS PRA standard CC-II requirements and being used as a surrogate for RICT calculations:

1) Provide justification that the proposed RBS ERAT RPS model will meet the associated CC-II requirements. Include in this discussion how the use of NUREG/CR-5500 information meets CC-II requirements.
2) If the proposed RBS ERAT RPS cannot meet CC-II requirements, then provide justification that the use of the surrogate is either conservative or bounding when compared to a CC-II model.
3) If the proposed surrogate cannot be justified as either conservative or bounding, then propose a mechanism to ensure the RBS ERAT RPS model is conservative or bounding prior to any RICT calculation.

b) Regarding TS LCO 3.3.5.1.D Function 3.e and 3.3.5.3.D Function 4, Table E1-1 states that for the Suppression Pool Water Level (SPWL) - High channel, which is not modeled, that the Condensate Storage Tank (CST) Level Low channel, (which is modeled), will be used as a surrogate. The NRC staff notes that the stated function for this LCO is to align high pressure core spray (HPCS) and reactor core isolation cooling (RCIC) pumps suction from the CST to the suppression pool for continued operations of the HPCS/RCIC pumps. Switching from the CST on low level appears to address inventory control for the HPCS/RCIC pumps, whereas switching to the suppression pool for high level appears not to be related to inventory concerns for the pumps. It is unclear to the NRC staff how the suppression pool high level logic is related to the CST low level function and therefore how the surrogate is either bounding or conservative for this LCO.

Provide justification that the surrogate is related and bounds the suppression pool level high function.

c) Regarding TS LCO 3.3.5.1.F/G and 3.3.6.4.A, Table E1-1 states that, for automatic depression system (ADS) initiation logic and instrumentation functions not modeled, that

the each of the ADS solenoid operated valves (SOVs) in the associated train will remain closed. However, it further states that the RBS ERAT model will be updated to incorporate power dependencies for each ADS steam relief valve (SRV) pilot valve to address train specific ADS SRV instrumentation or pilot valve outages. It is unclear to the NRC staff the impact of the proposed RBS ERAT ADS model update on the proposed surrogates for these LCOs.

i. Provide justification that the proposed RBS ERAT ADS model will meet the associated ASME/ANS PRA CC-II requirements.

ii. If the proposed RBS ERAT ADS cannot meet CC-II requirements, then provide justification that the use of the surrogate is either conservative or bounding when compared to a CC-II model.

ii. If the proposed surrogate cannot be justified as either conservative or bounding, then propose a mechanism to ensure the RBS ERAT ADS model is conservative or bounding prior to any RICT calculation.

d) Regarding TS LCO 3.3.6.1.A Functions 2.a, 2.b, and 2.c, Table E1-1 states that, for reactor vessel level - low-low, Level 2, drywell pressure - high, and containment purge isolation radiation - high channels not modeled, that the primary containment isolation valves (PCIVs) associated with the affected trip system that is modeled will be used as a surrogate. The NRC staff notes that the Table E1-1 entry for TS LCO 3.6.1.3.A, PCIVs, states that not all PCIVs are modeled and for the unmodeled PCIVs that a pre-existing containment failure will be used as a surrogate. It is unclear to the staff if all the trip system functions of this LCO associated PCIVs are modeled and if the LCO 3.6.1.3.A surrogate is required.

i. Confirm that all of the PCIVs associated with the LCO 3.3.6.1.A functions are modeled.

ii. For the PCIVs associated with LOC 3.3.6.1.A that are not modeled, identify the surrogate to be used for RICT calculations. Include in this discussion justification that the surrogate bounds the associated function.

e) Regarding TS LCO 3.3.6.4.A and 3.6.1.6.A, Table E1-1 states that, for relief and low-low (LLS) instrumentation trip system or LLS valve not modeled, that the SRV fail to reclose failure probability that is modeled will be doubled and used as a surrogate. The NRC staff notes that the LLS LCO function is to have the SRVs remain open longer to prevent multiple actuations and pressure loads. It is unclear to the staff how the doubling of the SRV fail to reclose probability is either conservative or bounding.

i. Provide justification that doubling of the surrogates failure probability is conservative or bounds the LLS relief point function.

ii. If the doubling of the surrogates failure probability is determined not to be bounding or conservative, then provide an updated surrogate that is bounding or conservative for this LCO.

f) Regarding TS LCO 3.3.8.1.A, Table E1-1 states that, for loss of power (LOP) instrumentation channels not modeled, that a single event per division that represents a loss of emergency buss undervoltage will be used as a surrogate. It is unclear to the NRC staff what constitutes the single event and therefore how it is either conservative or bounding.

i. Identify the single event in the PRA model that will used to represent all of the associated functions for TS LCO 3.3.8.1.A.

ii. Provide justification that the surrogate is conservative or bounds the LLS relief point function.

g) Regarding TS LCO 3.6.1.2.C, Table E1-1 states that, for primary containment air locks not modeled, that a large pre-existing containment isolation failure that is modeled will be used as a surrogate. The NRC staff notes the associated Note 8 of Table E1-1 states that the failure probabilities of the surrogate will be increased. It is unclear to the staff how increasing the failure probability of the surrogate is either conservative or bounding.

i. Detail the intended increase in failure probability of the surrogate associated with this LCO.

ii. Provide justification that increasing the surrogates failure probability is conservative or bounds the LCO function.

iii. If the increasing of the surrogates failure probability is determined not to be bounding or conservative, then provide an updated surrogate that is bounding or conservative for this LCO.

h) Regarding TS LCO 3.6.1.3.A, Table E1-1 states that, for PCIVs not modeled, that a pre-existing large containment isolation failure that is modeled will be used as a surrogate.

The NRC staff notes the associated Note 9 of Table E1-1 states that for the redundant, unisolated valve the respective failure probability will be added. It is unclear to the staff what the added failure probability consists of and if it is either conservative or bounding.

i. Detail the intended increase in failure probability of the surrogate associated with this LCO.

ii. Provide justification that increasing the surrogates failure probability is conservative or bounds the LCO function.

iii. If the increasing of the surrogates failure probability is determined not to be bounding or conservative, then provide an updated surrogate that is bounding or conservative for this LCO.

i) Regarding TS LCO 3.8.9.A, Table E1-1 states that Division I or II AC electrical power distribution subsystems are modeled in the PRA. However, the NRC staff notes that the Comments section states, regarding unmodeled distribution panels, to see Note 13. It is unclear to the NRC staff if the column entry for this LCO that states Yes for SSCs being modeled in the PRA is accurate. The NRC staff notes the associated Note 13 of Table E1-1 states that for the unmodeled load centers, MCCs, or power panels the SSCs placed out of service are a best estimate surrogate. It is unclear to the staff how this constitutes a best estimate surrogate and if it is either conservative or bounding.

i. Confirm that all of the SSCs associated with TS LCO 3.8.9.A have a one to one relationship to the RBS PRA models used for this applicati on.

ii. Clarify what is meant by best estimate surrogate.

iii. Provide justification that the best estimate surrogate is conservative or bounds the LCO function.

iv. If the best estimate surrogate is determined not to be bounding or conservative, then provide an updated surrogate that is bounding or conservative for this LCO.

APLA Audit Question 02-Credit for FLEX Equipment and Actions NRC memorandum dated May 6, 20221 provides the NRCs staff updated assessment of identified challenges and strategies for incorporating Diverse and Flexible Mitigation Capability (FLEX) equipment into a PRA model in support of risk-informed decisionmaking in accordance with the guidance of RG 1.2002.

Section 3 of Enclosure 1 of the LAR states that a number of FLEX related sensitivities, which increased certain failure probabilities, demonstrated the impact on RICTs to be less than five percent. However, Section 3.2.9 of the RBS 10 CFR 50.69 application states that a sensitivity which removed FLEX credit impacted CDF by approximately twelve percent. The NRC staff notes that when assessing the uncertainties related to FLEX modeling the sensitivity is performed by removing FLEX credit. Given the twelve percent change associated with this uncertainty the staff notes it is possible for this source of uncertainty can significantly impact certain RICT calculations.

It is unclear exactly how the sensitivity was performed to assess FLEXs impact on the RICTs. Provide a more complete assessment and justification regarding how uncertainty in FLEX modeling could impact RICT calculations.

APLA Audit Question 03 - Determination of Key Sources of Uncertainty and Sensitivity Results

The NRC staff safety evaluation to NEI 06-09 specifies that the LAR should identify key assumptions and sources of uncertainty and to assess and disposition each as to their impact on the RMTS application.

NUREG-1855 "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk -

Informed Decision Making, Main Report," (ADAMS Accession No. ML 17062A466) presents guidance on the process of identifying, characterizing, and qualitative screening of model uncertainties.

1 U.S. NRC memorandum, Updated Assessment of Industry Guidance for Crediting Mitigating Strategies in Risk Assessments, dated May 6, 2022 (ADAMS Accession No. ML22014A084).

2 U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, RG 1.200, Revision 3, December 2020 (ADAMS Accession No. ML20238B871).

of the LAR states that eleven internal events (including internal flooding) and eighteen fire key assumptions and uncertainties were identified. For certain sources of uncertainty sensitivity studies were conducted. However, none of these twenty-nine sources of uncertainty or sensitivity results were provided in the application. The NRC staff reviewed the uncertainty documents provided on this audits electronic portal for the internal events, internal flooding, and fire PRA and found that further clarification is necessary regarding the review of these assumptions and sources of uncertainty for this application. It is unclear what additional analysis was performed and documented to determine if any source of uncertainty could adversely impact any RICT calculation. In light of these observations, provide the following information:

a) Provide details of how the RBS PRA sources of uncertainty were evaluated as a potential key source of uncertainty for this application. Include in this discussion any documentation of this process.

b) Provide the results of sensitivity studies that determined the impact on risk for each associated source of uncertainty. Include in this discussion justification that the sensitivity results demonstrate that the associated source of uncertainty does not adversely impact any RICT calculation.

APLA Question 04 - Digital Instrumentation and Control Modeling

Concerning the quality of the PRA model, NEI 06-09-A states that RG 1.174 and RG 1.200 define the quality of the PRA in terms of its scope, level of detail, and technical adequacy. The quality must be compatible with the safety implications of the proposed TS change and the role the PRA plays in justifying the change.

Regarding digital instrumentation and control (I&C), the NRC staff notes the lack of consensus industry guidance for modeling these systems in plant PRAs to be used to support risk-informed applications. In addition, known modeling challenges exist, such as the lack of industry data for digital I&C components, the difference between digital and analog system failure modes, and the complexities associated with modeling software failures including common-cause software failures. Also, though reliability data from vendor tests may be available, this source of data is not a substitute for in-the-field operational data. Given these challenges, the uncertainty associated with modeling a digital I&C system could impact the RICT program. Therefore, address the following:

a) Clarify whether digital I&C systems are credited in the PRA models that will be used in the RICT program.

b) If digital I&C systems are credited in the PRA models that will be used in the RICT program, provide justification that demonstrates the modeling uncertainty associated with crediting digital I&C systems has an no adverse impact on the RICT calculations

APLA Question 05 - Impact of Seasonal Variations

The Tier 3 requirement of Regulatory Guide (RG) 1.177, Revision 2, Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, dated January 2021, stipulates that a licensee should develop a program that ensures that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity.

Section 2.3.4 of NEI 06-09-A states, in part, that:

If the PRA model is constructed using data points or basic events that change as a result of time of year or time of cycle, then the RICT calculation shall either 1) use the more conservative assumption at all time, or 2) be adjusted appropriately to reflect the current (e.g., seasonal or time of cycle) configuration for the feature as modeled in the PRA.

of the LAR states that outside air temperatures on system requirements and severe weather conditions is addressed in the CRMP model. However, it does not appear to specify the modeling adjustments needed to account for seasonal variations and what kind of adjustments will be made. Therefore, address the following to clarify the treatment of seasonal and time of cycle variations:

a) Explain how the RICT calculations address changes in PRA data points, basic events, and SSC operability constraints as a result of extreme weather conditions, seasonal variations, or other environmental factors. Also, explain how these adjustments are made in the configuration risk management program (CRMP) model and how this approach is consistent with the guidance in NEI 06-09-A and its associated NRC final SE.

b) Describe the criteria used to determine when PRA adjustments due to extreme weather conditions, seasonal variations, other environmental factors, or time of cycle variations need to be made in the CRMP model and what mechanism initiates these changes.

APLA Question 06 - EDG Protective Trip Bypass under LOOP condition

According to Section 8.3.1.1.3.6.1.2 (Page 8.3-11) of the UFSAR of RBS, an Emergency Mode condition (LOCA or LOOP) overrides most of the protective trips on fault conditions of Standby DGs (EDGs). Therefore, the NRC staff finds that River Bend is one of the plants which will be bypassing many EDG protective trips under an actual LOOP condition. This may have an impact on the EDG recovery model, if considered in the PRA, and thus can have a significant impact on the plant CDF frequency.

Please provide discussion of impact on EDG recovery model, if considered in PRA, and any resulting impact on PRA such as plant base or increment CDF frequency due to the many EDG protective trips bypass under an actual LOOP condition.

APLC Question 01 - Seismic Risk Contribution Analysis

Section 2.3.1, Item 7, of NEI 06-09, Revision 0-A (ADAMS Accession No. ML12286A322),

states that the impact of other external events risk shall be addressed in the [Risk Managed Technical Specifications] RMTS program, and explains that one method to do this is by performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated [Risk-Informed Completion Time] RICT. The NRC staffs safety evaluation for NEI 06-09 (ADAMS Accession No. ML071200238) states that [w]here [probabilistic risk assessment] PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

In Section 3 of Enclosure 4 to the LAR, the licensee provided its seismic risk contribution analysis. The licensee concluded that RBS is more robust than was credited in the GI-199 and provided the HCLPF of 0.3g and a composite uncertainty factor (c) of 0.5 as plant level fragility.

The NRC staff noted that GI-199 shows HCLPF = 0.1g and c = 0.4 for RBS, which is consistent with an EPRI document dated March 11, 2014 (ML14080A589). The licensee provided two seismic re-evaluation documents to support its plant-level fragility (PLF), RBS-SA-11-00001, Revision 0, EC93084 and PSA-RBS-04-021, Revision 0, EC93084 on the portal for NRC staff review. The NRC staff reviewed the documents and identified the following questions:

1. The calculation RBS-SA-11-00001, Revision 0, EC93084 discusses different approaches to estimating the PLF and provides several different sets of HCLPF and c estimates in Attachments 4, 7 and 8. These approaches include the separation of variables (SOV) method, the hybrid method, and a scaling method based on the SSE to GMRS ratio.

a) The staff notes that the HCLPF and c developed based on SOV in Attachment 4 are used to support the RBS RICT program. The staff understands that the median factors of safety and variabilities provided in Kennedy et al. (1980, 1984) are used in SOV estimation of the PLF in Attachment 4. To the best of staffs understanding, SOV method is used to determine the fragility of individual systems, structures, or components (SSCs) which is then used for a SMA or seismic PRA (SPRA). It is the SMA or SPRA that provides the PLF, which is a representation of the combined behavior of all the modeled SSCs. Therefore, the PLF depends on a plant-specific mix of SSCs, and based on the staffs understanding, the contribution is usually higher from components compared to structures for seismic CDF. To the best of staffs understanding, the SOV method has not been applied to directly determine the PLF and its application by the licensee is beyond the scope of its applicability. Provide justification for the first-of-a-kind use of SOV in estimating the PLF and plant -specific basis for selecting the parameters and their values for the SOV method in the licensees calculation.

b) For the SOV method used in Attachment 4, the licensee states that the various factors and estimate values are based on the available material. However, it does not specify the available material used for estimates for various factors used in SOV. Provide the sources of information for the median factors used in the SOV method in Attachment 4.

c) In Attachment 7, the licensee also used the SOV method. Attachment 7 states that

[t]his white paper provides a basis for the HCLPF and fragility calculations performed in Reference 11. Reference 11 in the quoted statement refers to Attachment 4 discussed above. However, the staff notes that Attachment 7 uses different values for median factors than those used in Attachment 4. Justify the use of different values for median factors in the SOV method described in Attachments 4 and 7.

d) In the SOV method of estimating an HCLPF in Attachment 7, the staff found an error in the calculation of HCLPF value. Correction of the error results in a calculated HCLPF of 0.20g. This HCLPF of 0.20g is lower than the HCLPF of 0.30g developed in Attachment

4 and used in the RICT. Justify the use of an unconservative value (HCLPF of 0.30g PGA) in the RICT program.

e) Several different sets of HCLPF and c estimates are also developed using the hybrid method in Attachments 4, 7 and 8. However, justification for the use of the minimum capacity of 0.8g ground peak spectral acceleration as the screening criteria for SSCs at RBS is not provided. Provide site-specific justification for the use of 0.8g ground peak spectral acceleration as the screening criteria.

2. In Attachment 8, the licensee calculated a scaling factor of 1.3 at 1 Hz based on an SSE to GMRS demand ratio. This method, which was approved by the staff for Waterford TSTF-505 LAR, can provide an alternative to SOV and hybrid methods discussed in Item #1 above, especially for determining the PLF for seismic CDF. If this method is adopted by the licensee to determine the PLF for seismic CDF for use in the RICT LAR, provide detailed steps involved in calculations and the resulting HCLPF value and selected c.
3. As an alternative to items #1 and #2 above, the licensee may choose an option for a full-scope SMA to determine the PLF. The licensee may upgrade its reduced-scope SMA performed as part of the RBS IPEEE to a full-scope or focused-scope SMA consistent with appropriate NRC-endorsed guidance and leveraging to the extent possible, with justification, prior plant-specific walkdowns, such as those performed in response to post-Fukushima actions. If this approach is adopted by the licensee, please provide resulting reports, calculation notebooks, and conclusions for NRC staff review in a regulatory audit.
4. Re-evaluate and provide the seismic penalty based on updated HCLPF and c values, if they are different from those provided in the LAR.

APLC Question 02 - Extreme Wind or Tornado Screening Criteria

Section 2.3.1, Item 7, of NEI 06-09-A, states that the "impact of other external events risk shall be addressed in the RMTS program," and explains that one method to do this is by documenting prior to the RMTS program that external events that are not modeled in the PRA are not significant contributors to configuration risk. The NRC staffs SE for NEI 06-09 states that

"[o]ther external events are also treated quantitatively, unless it is demonstrated that these risk sources are insignificant contributors to configuration-specific risk."

The table in Enclosure 4 of the TSTF-505 LAR screens the Extreme Wind or Tornado as PS4, mean CDF is < 1E-06 per year. However, the table did not provide the high wind CDF value to meet the criteria, except for tornado missile hazard. The licensee did provide structure design criteria for straight wind and tornado. It appears this meet the criterion C1 for Event damage is

< events for which plant is designed.

Provide additional justification to screen the extreme wind or tornado hazard using criterion PS4.

EEEB Question 01 - LCO 3.8.4, Conditions A & B & LCO 3.8.9, Conditions A & C

GDC 17 requires, in part, that both offsite and onsite electrical power systems be provided. LCO 3.8.4, Conditions A and B and LCO 3.8.9, Conditions A and C are for exclusively the inoperability of Division I or II battery charger or subsystem(s), respectively. LCO 3.8.4, Condition C and LCO 3.8.9, Condition E are for just Division III subsystem(s).

USFAR R27, Sections 8.1.6.2 and 8.3.1.1.2.1 reveal that the onsite electrical system has three 4.16 kV physically and electrically independent standby buses with each serving a safety-related division (load group). UFSAR Page 8.3 -45 shows that two out of three load groups can provide the minimum safety functions to shut down the unit and maintain it in a safe shutdown condition. UFSAR Section 8.3.2 indicates that Class 1E DC systems have the same single failure criteria as the AC safety-related divisions to they provide control power. Required Action (RA) for TS LCO 3.8.4.B.1 seeks restoration of a Division I and II subsystems to operable status, as do RAs for TS LCOs 3.8.9.A.1 and C.1 for their respective Division I and II AC and DC subsystems.

Please explain why the DSC in Table E1-1 for TS LCO 3.8.4, Conditions A & B & TS LCO 3.8.9, Conditions A & C are not exclusively for Division I and II components and subsystem(s) without any reference to Division III which has separate LCOs for inoperability of its subsystem(s).

EEEB Question 02 - LCO 3.8.7, Condition A

GDC 17 requires, in part, that both offsite and onsite electrical power systems be provided. At River Bend Station, UFSAR Section 8.3.1.1.3.5 indicates the 120 -V ac uninterruptible power supplies (UPS) provide ac power for security, control, and instrumentation systems for the non-safety-related and engineered safeguard systems. LCO 3.8.7, Condition A, is for one inverter inoperable in either Division I or II.

USFAR R27, Section 8.3.1.1.3.7 reveals each UPS has an inverter as an essential component.

UPSs ENB-INV01A and ENB-INV01A1 are associated with Division I, and UPSs EN B-INV01B and ENB-INV01B1 are associated with Division II. Only one UPS per division is required to be in service at any given time to supply power to its respective distribution panel with the other UPS for that division de-energized and available as a backup. All UPSs and their associated distribution panels are completely independent (by division). Those panels associated with standby systems serve redundant safety-related equipment.

Please explain why the DSC in Table E1-1 for TS LCO 3.8.7, Condition A states that the design success criterion is met by the associated spare inverter for that division since the Division I and II inverters serve redundant loads (only one inverter required per division).

EEEB Question 03 - Table E1-1 for TS LCO 3.8.4, Condition A

GDC 17 requires, in part, that both offsite and onsite electrical power systems be provided.

UFSAR Section 8.3.2.1.1 indicates there are three Class 1E safety related 125 -Vdc systems, and each 125-Vdc system has one battery charger. UFSAR Sect ion 8.3.2.1.1 also states that a separate battery charger, powered by either a non -safety-related power source or a portable diesel generator, performs as the backup battery charger for the three safety divisions I, II, and III safety-related and three of the non-safety-related chargers. The backup chargers breaker is taken from storage and placed in position to feed the bus of battery charger removed from service. Operation of the backup charger is under strict administrative control in that credit is

taken for this charger in mitigating consequences of an accident, when used as a substitute for a Division I or II safety-related charger.

Please explain why in Table E1-1 for TS LCO 3.8.4, Condition A assumes credit of backup charger for a DSC, even though no Surveillance Requirements are specified in TS 3.8.4 for the backup charger.

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