ML19343A019

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Application to Adopt 10 CFR 50.69, Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors
ML19343A019
Person / Time
Site: Surry  Dominion icon.png
Issue date: 12/06/2019
From: Mark D. Sartain
Dominion Energy Virginia, Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
19-031
Download: ML19343A019 (64)
v • d • e


Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 December 6, 2019 10 CFR 50.69 10 CFR 50.90 ATTN: Document Control Desk Serial No.: 19-031 U.S. Nuclear Regulatory Commission NRA/GDM: RO Washington, DC 20555-0001 Docket Nos.: 50-280 50-281 License Nos.: DPR-32 DPR-37 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 APPLICATION TO ADOPT 10 CFR 50.69, "RISK-INFORMED CATEGORIZATION AND TREATMENT OF STRUCTURES, SYSTEMS AND COMPONENTS FOR NUCLEAR POWER REACTORS" In accordance with the provisions of 1 O CFR 50.69 and 10 CFR 50.90, Virginia Electric and Power Company (Dominion Energy Virginia) requests an amendment to the Surry Power Station (SPS) Units 1 and 2 operating licenses.

The proposed amendments would modify the SPS Units 1 and 2 licensing basis, by the addition of a License Condition, to allow the implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, "Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors."

The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with this regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety. to this letter provides the basis for the proposed change to the SPS Units 1 and 2 Operating Licenses. The categorization process being implemented through this change is consistent with NEI 00-04, "10 CFR 50.69 SSC Categorization Guideline,"

Revision 0, dated July 2005, which was endorsed by the NRC in Regulatory Guide 1.201, "Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance," Revision 1, dated May 2006. Attachment 1 of Enclosure 1 provides a list of categorization prerequisites. Use of the categorization process on a plant system will only occur after these prerequisites are met.

The PRA model described within this license amendment request (LAR) is the same as the one described within the Dominion Energy Virginia LAR that was submitted on

Serial No.19-031 Docket Nos. 50-280/281 Page 2 of 4 May 5, 2019 requesting the addition of a 24-hour completion time for an inoperable reactor trip breaker (ADAMS Accession Number ML19143A201). Dominion Energy Virginia requests that the NRC conduct their review of the PRA technical adequacy details for this application in coordination with the review of the application currently in process. This would reduce the number of Dominion Energy Virginia and NRC resources necessary to complete the review of the applications. This request should not be considered a linked requested licensing action (RLA), as the details of the PRA model in each LAR are complete, which will allow the NRC staff to independently review and approve each LAR on its own merits without regard to the results from the review of the other LAR.

Though routine maintenance updates have been applied and model upgrades have been peer reviewed, the NRC has previously reviewed the technical adequacy of the SPS Probabilistic Risk Assessment (PRA) model identified in this application for the following risk-informed applications:

  • "Surry Power Station, Unit Nos. 1 and 2 - Issuance of Amendments Regarding Relocation of Surveillance Frequencies to Licensee-Controlled Program Using Risk-Informed Justification (TSTF-425) (TAC Nos. ME3687 and ME3688),"

April 29, 2011 (ADAMS Accession Number ML110740033)

  • "Surry Power Station, Units 1 and 2 - Issuance of Amendments Regarding the Containment Type A and Type C Leak Rate Tests (TAC Nos. MF2612 and MF2613)," July 3, 2014 (ADAMS Accession Number ML14148A325)
  • "Surry Power Station, Unit Nos. 1 and 2 - Issuance of Amendments Regarding the Extension of the Emergency Service Water Pump Allowed Outage Time, Surry Power Station, Units 1 and 2 (CAC Nos. MF8145 and MF8146)," July 28, 2017 (ADAMS Accession Number ML17170A183)

Dominion Energy Virginia requests the NRC utilize the review of the PRA technical adequacy for the applications cited above when performing the review for this application.

Dominion Energy Virginia requests approval of the proposed license amendment by November 30, 2020, with the amendment being implemented within 60 days.

Serial No.19-031 Docket Nos. 50-280/281 Page 3 of 4 This letter contains proposed License Conditions for SPS Units 1 and 2 and the regulatory commitments described in Attachment 1 to Enclosure 1, as well as the additional regulatory commitments noted below.

Should you have any questions regarding this submittal or require additional information, please contact Mr. Gary D. Miller at (804) 273-2771.

Sincerely, Mark D. Sartain Vice-President - Nuclear Engineering and Fleet Support COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mark D. Sartain, who is Vice President - Nuclear Engineering and Fleet Support of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

day of ce""be..r- , 2019.

-fl.,

Acknowledged before me this Commitments made in this letter:

1. Use of the categorization process on a plant system will only occur after the prerequisites specified in Attachment 1 to Enclosure 1 have been met.
2. A sensitivity study will be performed on the independent FLEX failures using the 5th and 95th percentile values.
3. Before implementation of the categorization process, a documented basis for the screened specific failure modes and components based on Supporting Requirement SY-A15 will be performed.

Enclosures:

1. Evaluation of the Proposed Change
2. Marked-up SPS Units 1 and 2 License Pages
3. Proposed SPS Units 1 and 2 License Pages

Serial No.19-031 Docket Nos. 50-280/281 Page 4 of 4 cc: U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 Mr. Vaughn Thomas NRC Project Manager - Surry U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 04 F-12 11555 Rockville Pike Rockville, MD 20852-2738 Mr. G. Edward Miller NRC Senior Project Manager - North Anna U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector Surry Power Station State Health Commissioner Virginia Department of Health James Madison Building - 7th Floor 109 Governor Street Room 730 Richmond, Virginia 23219

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 EVALUATION OF THE PROPOSED CHANGE Virginia Electric and Power Company (Dominion Energy Virginia)

Surry Power Station Units 1 and 2

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 EVALUATION OF THE PROPOSED CHANGE TABLE OF CONTENTS 1

SUMMARY

DESCRIPTION .....................................................................................1 2 DETAILED DESCRIPTION ...................................................................................... 1 2.1 CURRENT REGULATORY REQUIREMENTS .................................................1 2.2 REASON FOR PROPOSED CHANGE.............................................................2

2.3 DESCRIPTION

OF THE PROPOSED CHANGE.............................................. 3 3 TECHNICAL EVALUATION ..................................................................................... 3 3.1 CATEGORIZATION PROCESS DESCRIPTION (10 CFR 50.69(8)(2)(1)).........5 3.1.1 Overall Categorization Process............................................................ 5 3.1.2 Passive Categorization Process ........................................................ 11 3.2 TECHNICAL ADEQUACY EVALUATION (10 CFR 50.69(8)(2)(11)) ................. 12 3.2.1 Internal Events and Internal Flooding ................................................ 12 3.2.2 Fire Hazards ...................................................................................... 12 3.2.3 Seismic Hazards ................................................................................14 3.2.4 Other External Hazards ..................................................................... 19 3.2.5 Low Power & Shutdown ..................................................................... 20 3.2.6 PRA Maintenance and Updates ......................................................... 20 3.2.7 PRA Uncertainty Evaluations .............................................................21 3.3 PRA REVIEW PROCESS RESULTS (10 CFR 50.69(8)(2)(111)) ...................... 22 3.4 RISK EVALUATIONS (10 CFR 50.69(8)(2)(1V)) ............................................. 22 3.5 FEEDBACK AND ADJUSTMENT PROCESS ................................................. 23 4 REGULATORY EVALUATION ...............................................................................24 4.1 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA ......................... 24 4.2 NO SIGNIFICANT HAZARDS CONSIDERATION ANALYSIS ....................... 25

4.3 CONCLUSION

S .............................................................................................26 5 ENVIRONMENTAL CONSIDERATION.................................................................. 27 6 REFERENCES ....................................................................................................... 27

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 LIST OF ATTACHMENTS : List of Categorization Prerequisites ........................................................ 31 : Description of PRA Models Used in Categorization ................................32 : Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items ......................................................................... 33 : External Hazards Screening ................................................................... 38 : Progressive Screening Approach for Addressing External Hazards .......45 : Disposition of Key Assumptions/Sources of Uncertainty ........................46 ii

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 EVALUATION OF PROPOSED CHANGE SURRY POWER STATION UNITS 1 AND 2 1

SUMMARY

DESCRIPTION The proposed amendment modifies the licensing basis to allow for the implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, "Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors." The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with this regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

2 DETAILED DESCRIPTION 2.1 CURRENT REGULATORY REQUIREMENTS The Nuclear Regulatory Commission (NRC) has established a set of regulatory requirements for commercial nuclear reactors to ensure that a reactor facility does not impose an undue risk to the health and safety of the public, thereby providing reasonable assurance of adequate protection to public health and safety. The current body of NRC regulations and their implementation are largely based on a "deterministic" approach.

This deterministic approach establishes requirements for engineering margin and quality assurance in design, manufacture, and construction. In addition, it assumes that adverse conditions can exist (e.g., equipment failures and human errors) and establishes a specific set of design basis events (DBEs). The deterministic approach requires that the facility include safety systems capable of preventing or mitigating the consequences of those DBEs to protect public health and safety. The Structures, Systems and Components (SSCs) necessary to defend against the DBEs are defined as "safety related," and these SSCs are the subject of many regulatory requirements, herein referred to as "special treatments," designed to ensure that they are of high quality and high reliability and have the capability to perform during postulated design basis conditions.

Treatment includes, but is not limited to, quality assurance, testing, inspection, condition monitoring, assessment, evaluation, and resolution of deviations. The distinction between "treatment" and "special treatment" is the degree of NRC specification as to what must be implemented for particular SSCs or for particular conditions. Typically, the regulations establish the scope of SSCs that receive special treatment using one of three

  • different terms: "safety-related," "important to safety," or "basic component." The terms Page 1 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 "safety-related "and "basic component" are defined in the regulations, while "important to safety," used principally in the general design criteria (GDC) of Appendix A to 10 CFR Part 50, is not explicitly defined.

2.2 REASON FOR PROPOSED CHANGE A probabilistic approach to regulation enhances and extends the traditional deterministic approach by allowing consideration of a broader set of potential challenges to safety, providing a logical means for prioritizing these challenges based on safety significance, and allowing consideration of a broader set of resources to defend against these challenges. In contrast to the deterministic approach, Probabilistic Risk Assessments (PRAs) address credible initiating events by assessing the event frequency. Mitigating system reliability is then assessed, including the potential for common cause failures.

The probabilistic approach to regulation is an extension and enhancement of traditional regulation by considering risk in a comprehensive manner.

To take advantage of the safety enhancements available through the use of PRA, in 2004 the NRG published a new regulation, 10 CFR 50.69. The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g.,

quality assurance, testing, inspection, condition monitoring, assessment, and evaluation).

For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with the regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

The rule contains requirements on how a licensee categorizes SSCs using a risk informed process, adjusts treatment requirements consistent with the relative significance of the SSC, and manages the process over the lifetime of the plant. A risk-informed categorization process is employed to determine the safety significance of SSCs and places the SSCs into one of four risk-informed safety class (RISC) categories. The determination of safety significance is performed by an integrated decision-making process, as described by NEI 00-04, "10 CFR 50.69 SSC Categorization Guideline" (Reference 1), which uses both risk insights and traditional engineering insights. The safety functions include the design basis functions, as well as functions credited for severe accidents (including external events). Special or alternative treatment for the SSCs is applied as necessary to maintain functionality and reliability and is a function of the SSC categorization results and associated bases. Finally, periodic assessment activities are conducted to make adjustments to the categorization and/or treatment processes as needed so that SSCs continue to meet all applicable requirements.

The rule does not allow for the elimination of SSC functional requirements or allow equipment that is required by the deterministic design basis to be removed from the facility. Instead, the rule enables licensees to focus their resources on SSCs that make a significant contribution to plant safety. For SSCs that are categorized as high safety Page 2 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 significant, existing treatment requirements are maintained or enhanced. Conversely, for SSCs that do not significantly contribute to plant safety on an individual basis, the rule allows an alternative risk-informed approach to treatment that provides a reasonable, though reduced, level of confidence that these SSCs will satisfy functional requirements.

Implementation of 10 CFR 50.69 will allow Dominion Energy Virginia to improve focus on equipment that has safety significance resulting in improved plant safety.

2.3 DESCRIPTION

OF THE PROPOSED CHANGE Dominion Energy Virginia proposes the addition of the following condition to the renewed operating licenses of Surry Power Station (SPS) Units 1 and 2 to document the NRC's approval of the use 10 CFR 50.69:

The licensee is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) model to evaluate risk associated with internal events, including internal flooding; the Appendix R program to evaluate fire risk; qualitative assessments of seismic insights; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 SSCs and their associated supports; and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in License Amendment No.

[XXX] dated [AMENDMENT DATE].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from an Appendix R program fire risk evaluation to a fire probabilistic risk assessment approach).

3 TECHNICAL EVALUATION 10 CFR 50.69 specifies the information to be provided by a licensee requesting adoption of the regulation. This request conforms to the requirements of 10 CFR 50.69(b)(2), which states:

A licensee voluntarily choosing to implement this section shall submit an application for license amendment under § 50.90 that contains the following information:

(i) A description of the process for categorization of RISC-1, RISC-2, RISC-3 and RISC-4 SSCs.

Page 3 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 (ii) A description of the measures taken to assure that the quality and level of detail of the systematic processes that evaluate the plant for internal and external events during normal operation, low power, and shutdown (including the plant-specific probabilistic risk assessment (PRA), margins-type approaches, or other systematic evaluation techniques used to evaluate severe accident vulnerabilities) are adequate for the categorization of SSCs.

(iii) Results of the PRA review process conducted to meet§ 50.69(c)(1)(i).

(iv) A description of, and basis for acceptability of, the evaluations to be conducted to satisfy § 50.69(c)(1 )(iv). The evaluations must include the effects of common cause interaction susceptibility, and the potential impacts from known degradation mechanisms for both active and passive functions, and address internally and externally initiated events and plant operating modes (e.g., full power and shutdown conditions).

Each of these submittal requirements are addressed in the following sections.

The PRA model described within this LAR is the same as the one described within the Dominion Energy Virginia LAR dated May 5, 2019 requesting addition of a 24-hour completion time for an inoperable reactor trip breaker (ADAMS Accession Number ML19143A201). Dominion Energy Virginia requests that the NRC conduct their review of the PRA technical adequacy details for this application in coordination with the review of the application currently in-process. This would reduce the number of Dominion Energy Virginia and NRC resources necessary to complete the review of the applications. This request should not be considered a linked requested licensing action (RLA), as the details of the PRA model in each LAR are complete, which will allow the NRC staff to independently review and approve each LAR on its own merits without regard to the review results of the other LAR.

Though routine maintenance updates have been applied and model upgrades have been peer reviewed, the NRC has previously reviewed the technical adequacy of the SPS Probabilistic Risk Assessment (PRA) model identified in this application for the following risk-informed applications:

  • "Surry Power Station, Unit Nos. 1 and 2 - Issuance of Amendments Regarding Relocation of Surveillance Frequencies to Licensee-Controlled Program Using Risk-Informed Justification (TSTF-425) (TAC Nos. ME3687 and ME3688)," April 29, 2011 (ADAMS Accession Number ML110740033)
  • "Surry Power Station, Units 1 and 2 - Issuance of Amendments Regarding the Containment Type A and Type C Leak Rate Tests (TAC Nos. MF2612 and MF2613)," July 3, 2014 (ADAMS Accession Number ML14148A325)

Page 4 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

  • "Surry Power Station, Unit Nos. 1 and 2 - Issuance of Amendments Regarding the Extension of the Emergency Service Water Pump Allowed Outage Time, Surry Power Station, Units 1 and 2 (CAC Nos. MF8145 and MF8146)," July 28, 2017 (ADAMS Accession Number ML17170A183)

Dominion Energy Virginia requests that the NRC utilize the review of the PRA technical adequacy for those applications when performing the review for this application.

3.1 CATEGORIZATION PROCESS DESCRIPTION (10 CFR 50.69(b)(2)(i))

3.1.1 Overall Categorization Process Dominion Energy Virginia will implement the risk categorization process in accordance with NEI 00-04, "10 CFR 50.69 SSC Categorization Guideline," Revision 0, as endorsed by Regulatory Guide (RG) 1.201, "Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance," (Reference 2). NEI 00-04, Section 1.5, states, "Due to the varying levels of uncertainty and degrees of conservatism in the spectrum of risk contributors, the risk significance of SSCs is assessed separately from each of five risk perspectives and used to identify SSCs that are potentially safety-significant." A separate evaluation is appropriate to avoid reliance on a combined result that may mask the results of individual risk contributors.

The process to categorize each system will be consistent with the guidance in NEI 00-04, as endorsed by RG 1.201, except for evaluation of the impact of the seismic hazard.

The SPS system categorization process will use the EPRI 3002012988 (Reference

20) approach for seismic Tier 1 sites, which includes SPS, to assess seismic hazard risk. Inclusion of the additional process steps discussed below to address seismic considerations will ensure that reasonable confidence in the evaluations required by 10 CFR 50.69(c)(1 )(iv) is achieved. RG 1.201 states, "the implementation of all processes described in NEI 00-04 (i.e., Sections 2 through 12) is integral to providing reasonable confidence," and, "all aspects of NEI 00-04 must be followed to achieve reasonable confidence in the evaluations required by §50.69(c)(1 )(iv)." However, neither RG 1.201 nor NEI 00-04 prescribe a particular sequence or order for each of the elements to be completed. Therefore, the order in which each of the elements of the categorization process (listed below) is completed is flexible, and, as long as they are all completed, they may even be performed in parallel. Note that NEI 00-04 only requires Item 3 to be completed for components/functions categorized as LSS by all other elements. Similarly, Page 5 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 NEI 00-04 only requires Item 4 to be completed for safety related active components/functions categorized as LSS by all other elements.

1. PRA-based evaluations (i.e., the internal events, internal flooding)
2. Non-PRA approaches (i.e., fire safe shutdown equipment list (SSEL), qualitative assessment of seismic insights, other external events screening, and shutdown assessment)
3. Seven qualitative criteria in Section 9.2 of NEI 00-04
4. The defense-in-depth assessment
5. The passive categorization methodology Figure 3-1 is an example of the major steps of the categorization process described in NEI 00-04; two steps have been included to highlight review of seismic insights as pertains to this application, and as explained further in Section 3.2.3:

Figure 3-1: Categorization Process Overview Page 6 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 Categorization of SSCs will be completed per the NEI 00-04 process, as endorsed by RG 1.201, which includes the determination of safety significance through the various elements identified above. The results of these elements are used as inputs to arrive at a preliminary component categorization (i.e., High Safety Significant (HSS) or Low Safety Significant (LSS)) that is presented to the Integrated Decision-Making Panel (IDP).

Note: the term "preliminary HSS or LSS" is synonymous with the NEI 00-04 term "candidate HSS or LSS." A component or function is preliminarily categorized as HSS if any element of the process results in a preliminary HSS determination in accordance with Table 3-1 below. The safety significance determination of each element, identified above, is independent of the others, and therefore the sequence of the elements does not impact the resulting preliminary categorization of each component or function. Consistent with NEI 00-04, the categorization of a component or function will only be "preliminary" until it has been confirmed by the IDP. Once the IDP confirms that the categorization process was followed appropriately, the final Risk Informed Safety Class (RISC) category can be assigned.

The IDP may direct and approve detailed categorization of components in accordance with NEI 00-04, Section 10.2. The IDP may always elect to change a preliminary LSS component or function to HSS; however, the ability to change component categorization from preliminary HSS to LSS is limited. This ability is only available to the IDP for select process steps as described in NEI 00-04 and endorsed by RG 1.201. Table 3-1 summarizes these IDP limitations in NEI 00-04. The steps of the process are performed at either the function level, component level, or both. This is also summarized in Table 3-1. A component is assigned its final RISC category upon approval by the IDP.

Table 3-1: Categorization Evaluation Summary Internal Events Base Not Allowed Yes Case - Section 5.1 Fire, Seismic and Other External Allowable No Risk (PRA Events Base Case Component Modeled) PRA Sensitivity Allowable No Studies Integral PRA Assessment - Not Allowed Yes Section 5.6 Fire and Other Component Not Allowed No External Hazards Risk (Non-modeled) Seismic Function/Com anent Allowed 2 No Shutdown - Section Function/Component Not Allowed No 5.5 Page 7 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 Core Damage -

Function/Component Not Allowed Yes Defense-in Section 6.1 Depth Containment -

Component Not Allowed Yes Section 6.2 Qualitative Considerations -

Function Allowable 1 NIA Criteria Section 9.2 Passive Passive - Section 4 Se ment/Com anent Not Allowed No Notes:

1 The assessments of the qualitative considerations are agreed upon by the /OP in accordance with Section 9.2. In some cases, a 50. 69 categorization team may provide preliminary assessments of the seven considerations for the IOP's consideration; however, the final assessments of the seven considerations are the direct responsibility of the !DP.

The seven considerations are addressed preliminarily by the 50. 69 categorization team for at least the system functions that are not found to be HSS due to any other categorization step. Each of the seven considerations requires a supporting Justification for confirming (true response) or not confirming (false response) that consideration. If the 50. 69 categorization team determines that one or more of the seven considerations cannot be confirmed, then that function is presented to the /OP as preliminary HSS. Conversely, if all the seven considerations are confirmed, then the function is presented to the /OP as preliminary LSS.

The System Categorization Document, including the Justifications provided for the qualitative considerations, is reviewed by the /OP. The /OP is responsible for reviewing the preliminary assessment to the same level of detail as the 50. 69 team (i.e., all considerations for all functions are reviewed). The

/DP may confirm the preliminary function risk and associated justification or may direct that it be changed based upon their expert knowledge. Because the Qualitative Criteria are the direct responsibility of the

/DP, changes may be made from preliminary HSS to LSS or from preliminary LSS to HSS at the discretion of the !DP. If the !DP determines any of the seven considerations cannot be confirmed (false response) for a function, then the final categorization of that function is HSS.

2

/DP consideration of seismic insights can also result in an LSS to HSS determination.

The mapping of components to system functions is used in some categorization process steps to facilitate preliminary categorization of components. Specifically, functions with mapped components that are determined to be HSS by the PRA-based assessment (i.e., Internal Events PRA or Integral PRA assessment) or defense-in-depth evaluation will be initially treated as HSS. However, NEI 00-04, Section 10.2, allows detailed categorization which can result in some components mapped to HSS functions being treated as LSS; and Section 4.0 discusses additional functions that may be identified (e.g., fill and drain) to group and consider as potentially LSS components that may have been initially associated with a HSS function but which do not support the critical attributes of that HSS function. Note that certain steps of the categorization process are performed at a component level (e.g., Passive, Non-PRA-modeled hazards -see Table 3-1). These components from the component level assessments will remain HSS (IDP cannot override) regardless of the significance of the functions to which they are mapped. Therefore, if an HSS component is mapped to an LSS function, that component Page 8 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 will remain HSS. If an LSS component is mapped to an HSS function, that component may be driven HSS based on Table 3-1 above or may remain LSS. For the seismic hazard, given that SPS is a seismic Tier 1 (low seismic hazard) plant, as defined in Reference 20, seismic considerations are not required to drive an HSS determination at the component level, but the IDP will consider available seismic information pertinent to the components being categorized and can, at its discretion, determine that a component should be HSS based on that information.

The following are clarifications to be applied to the NEI 00-04 categorization process:

  • The Integrated Decision-Making Panel (IDP) will be composed of a group of at least five experts who collectively have expertise in plant operation, design (mechanical and electrical) engineering, system engineering, safety analysis, and probabilistic risk assessment. At least three members of the IDP will have a minimum of five years of experience at the plant, and there will be at least one member of the IDP who has a minimum of three years of experience in the modeling and updating of the plant specific PRA.
  • The IDP will be trained in the specific technical aspects and requirements related to the categorization process. Training will address at a minimum the purpose of the categorization; present treatment requirements for SSCs including requirements for design basis events; PRA fundamentals; details of the plant specific PRA including the modeling, scope, and assumptions, the interpretation of risk importance measures and the role of sensitivity studies and the change-in-risk evaluations; and the defense in-depth philosophy and requirements to maintain this philosophy.
  • The decision criteria for the IDP for categorizing SSCs as high safety significant or low safety-significant pursuant to § 50.69(f)(1) will be documented in Dominion Energy Virginia procedures. Decisions of the IDP will be arrived at by consensus. Differing opinions will be documented and resolved, if possible. However, a simple majority of the panel is sufficient for final decisions regarding HSS and LSS.
  • Passive characterization will be performed using the processes described in Section 3.1.2. Consistent with NEI 00-04, an HSS determination by the passive categorization process cannot be changed by the IDP.
  • An unreliability factor of 3 will be used for the sensitivity studies described in Section 8 of NEI 00-04. The factor of 3 was chosen as it is representative of the typical error factor of basic events used in the PRA model.
  • NEI 00-04, Section 7, requires assigning the safety significance of functions to be preliminary HSS if it is supported by an SSC determined to be HSS from the PRA based assessment in Section 5 but does not require this for SSCs determined to be HSS from non-PRA-based, deterministic assessments in Section 5. This requirement is further clarified in the Vogtle SER (Reference 4) which states " ... if any SSC is Page 9 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 identified as HSS from either the integrated PRA component safety significance assessment (Section 5 of NEI 00-04) or the defense-in-depth assessment (Section 6),

the associated system function(s) would be identified as HSS."

  • Once a system function is identified as HSS, then all the components that support that function are preliminary HSS. The IDP must intervene to assign any of these HSS function components to LSS.
  • Regarding the criteria that considers whether the active function is called out or relied upon in the plant Emergency/Abnormal Operating Procedures, Dominion Energy Virginia will not take credit for alternate means unless the alternate means are proceduralized and included in Licensed Operator training.

The following two exceptions are taken to the NEI 00-04 categorization process:

1. NEI 00-04, Section 5.2, states that the fire safety significance process takes one of two forms. Either the use of Fire Induced Vulnerability Evaluation (FIVE) or a Fire PRA. However, Section 3.2.2 of this LAR describes an alternate approach, which implements the Appendix R Safe Shutdown analysis that will be used in the Dominion Energy Virginia categorization process to evaluate safety significance related to the fire hazard.
2. Dominion Energy Virginia proposes to apply an alternative seismic approach to those listed in NEI 00-04, Sections 1.5 and 5.3. This approach is specified in EPRI 3002012988 (Reference 20) for Tier 1 plants and is discussed in Section 3.2.3.

The risk analysis to be implemented for each hazard is described below:

  • Internal Event Risks: Internal events including internal flooding PRA model version SPS-R06d, December 4, 2018. This model is currently under review by the NRC in Reference 17.
  • Fire Risks: Fire Safe Shutdown Equipment List (SSEL) will be used.
  • Seismic Risks: EPRI Alternative Approach in EPRI 3002012988 (Reference 20) for Tier 1 plants with the additional considerations discussed in Section 3.2.3 of this LAR.
  • Other External Risks (e.g., tornados, external floods): Using the Individual Plant Examination for External Events (IPEEE) screening process, as approved by NRC SER dated June 29, 2000 (Reference 16), the other external hazards were determined to be insignificant contributors to plant risk.
  • Low Power and Shutdown Risks: Qualitative defense-in-depth (DID) shutdown model for shutdown configuration risk management (CRM) based on the framework for DID Page 10 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 provided in NUMARC 91-06, "Guidance for Industry Actions to Assess Shutdown Management" (Reference 3), which provides guidance for assessing and enhancing safety during shutdown operations.

A change to the categorization process that is outside the bounds specified above (e.g.,

change from a seismic margins approach to a seismic probabilistic risk assessment approach) will not be used without prior NRC approval. The SSC categorization process documentation will include the following elements:

1. Program procedures used in the categorization
2. System functions, identified and categorized with the associated bases
3. Mapping of components to support function(s)
4. PRA model results, including sensitivity studies
5. Hazards analyses, as applicable
6. Passive categorization results and bases
7. Categorization results including all associated bases and RISC classifications
8. Component critical attributes for HSS SSCs
9. Results of periodic reviews and SSC performance evaluations
10. IDP meeting minutes and qualification/training records for the IDP members 3.1.2 Passive Categorization Process For the purposes of 10 CFR 50.69 categorization, passive components are those components that have a pressure retaining function. Passive components and the passive function of active components will be evaluated using the Arkansas Nuclear One (ANO) Risk-Informed Repair/Replacement Activities (RI-RRA) methodology contained in Reference 5 (ML090930246) consistent with the related Safety Evaluation (SE) issued by the Office of Nuclear Reactor Regulation.

The RI-RRA methodology is a risk-informed safety classification and treatment program for repair/replacement activities for pressure retaining items and their associated supports. In this method, the component failure is assumed with a probability of 1.0 and only the consequence evaluation is performed. It additionally applies deterministic considerations (e.g., DID, safety margins) in determining safety significance. Component supports are assigned the same safety significance as the highest passively ranked component within the bounds of the associated analytical pipe stress model. Consistent with NEI 00-04, an HSS determination by the passive categorization process cannot be changed by the IDP.

The use of this method was previously approved for a 10 CFR 50.69 application by NRC in the final SE for Vogtle dated December 17, 2014 (Reference 4). The RI-RRA method, as approved for use at Vogtle for 10 CFR 50.69,* does not have any plant specific aspects and is generic. It relies on the conditional core damage and large early release probabilities associated with postulated ruptures. Safety significance is generally measured by the frequency and the consequence of the event. However, this RI-RRA Page 11 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 process categorizes components solely based on consequence, which measures the safety significance of the passive component given that it ruptures. This approach is conservative compared to including the rupture frequency in the categorization as this approach will not allow the categorization of SSCs to be affected by any changes in frequency due to changes in treatment. The passive categorization process is intended to apply the same risk-informed process accepted by the NRC in ANO2-R&R-004 for the passive categorization of Class 2, 3, and non-class components. This is the same passive SSC scope the NRC has conditionally endorsed in ASME Code Cases N-660 and N-662 as published in Regulatory Guide 1.147, Revision 15. Both code cases employ a similar risk-informed safety classification of SSCs in order to change the repair/replacement requirements of the affected LSS components. All ASME Code Class 1 SSCs with a pressure retaining function, as well as supports, will be assigned high safety-significant, HSS, for passive categorization which will result in HSS for its risk-informed safety classification. and cannot be changed by the IDP. Therefore, this methodology and scope for passive categorization is acceptable and appropriate for use at SPS for 10 CFR 50.69 SSC categorization.

3.2 TECHNICAL ADEQUACY EVALUATION (10 CFR 50.69(b)(2)(ii))

The following sections demonstrate that the quality and level of detail of the processes used in categorization of SSCs are adequate. The PRA model described below has been peer reviewed, and there are no PRA upgrades that have not been peer reviewed. The PRA model credited in this request is the same PRA model credited in the LAR for the addition of a 24-hour completion time for an inoperable reactor trip breaker (ADAMS Accession Number ML19143A201) (Reference 17).

3.2.1 Internal Events and Internal Flooding The SPS categorization process for the internal events and flooding hazard will use the plant-specific PRA model. The Dominion Energy Virginia risk management process ensures that the PRA model used in this application reflects the as-built and as-operated plant for each of the SPS units. Attachment 2 of this enclosure identifies the applicable internal events and internal flooding PRA model.

3.2.2 Fire Hazards The SPS categorization process will use the Fire Safe Shutdown Equipment List (SSEL) for evaluation of safety significance related to fire hazards. The Fire Safe Shutdown paths identify the safety functions and associated sets of equipment credited to achieve and maintain safe shutdown under postulated fire conditions as defined by 10 CFR 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979," and NRC Branch Technical Position CMEB 9.5-1, "Guidelines for Fire Protection for Nuclear Power," (Reference 19). The Fire SSEL identifies the credited equipment on these Fire Safe Shutdown Paths. This approach also considers regulatory Page 12 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 exemptions related to the Fire Safe Shutdown program and fire-induced Multiple Spurious Operations (MSOs) to identify any additional equipment.

The use of the Fire SSEL is a screening approach. There are no importance measures used in determining safety significance related to the fire hazard. Instead, using the Fire SSEL would identify all credited equipment as HSS regardless of their fire damage susceptibility or frequency of challenge. This approach ensures the SSCs that are credited to establish and maintain safe shutdown capability are retained as safety significant. If a component is credited on the Fire SSEL, it is considered HSS. As stated in NEI 00-04, an SSC identified as HSS by a non-PRA method to address fire "may not be re-categorized by the IDP."

Furthermore, regulatory exemptions related to the Fire Safe Shutdown program and previously identified fire-induced MSOs were reviewed, and it was concluded that no equipment in addition to the components on the Fire SSEL are relied upon to establish and maintain safe shutdown. Therefore, no additional components will be identified as HSS regarding the fire hazard. The results of this review have been documented by the site and are available for NRC audit. Figure 3-2 illustrates how the Fire SSEL is reviewed to determine if the component being evaluated is HSS.

This approach is an alternate process from the NEI 00-04 endorsed approaches. Similar to the NEI 00-04 FIVE approach, this approach uses the SSEL as a screening tool.

However, the development of the Fire SSEL is not based on a successive screening methodology and is the starting point for the FIVE methodology. Therefore, industry assessments have shown that this Fire SSEL approach leads to many additional SSCs being identified as HSS making it more conservative in determining safety significance than the NEI 00-04 FIVE approach or a Fire PRA.

The Dominion Energy Virginia Fire Safe Shutdown program is an active regulatory program that is routinely inspected by NRC. It was confirmed that this program ensures the Fire SSEL and the identification of additional equipment relied upon to establish and maintain safe shutdown reflects the current as-built, as-operated plant and that changes to the plant will be evaluated to determine their impact to the equipment list and the categorization process.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 Select SSC Identify Safety Significant Attributes of Component Figure 3-2: Safety Significance Process for Systems and Components Addressed in Fire Safe Shutdown Program Fire detection, suppression, and barriers (e.g., fire dampers) that may not be included on the SSEL will be categorized as HSS.

3.2.3 Seismic Hazards 10 CFR 50.69(c)(1) requires the use of PRA to assess risk from internal events. For other risk hazards such as seismic, 10 CFR 50.69 (b)(2) allows, and NEI 00-04 summarizes, the use of other methods for determining SSC functional importance in the absence of a quantifiable PRA (such as Seismic Margin Analysis or IPEEE Screening) as part of an integrated, systematic process. For the SPS seismic hazard assessment, Dominion Energy Virginia proposes to use a risk informed graded approach that meets the requirements of 10 CFR 50.69 (b)(2) as an alternative to those listed in NEI 00-04 sections 1.5 and 5.3. This approach is specified in Reference 20 and includes additional qualitative considerations that are discussed in this section.

SPS meets the Tier 1 criterion for a "Low Seismic Hazard/High Seismic Margin" site. The Tier 1 criterion is as follows:

"Tier 1: Plants where the GMRS [Ground Motion Response Spectrum] peak acceleration is at or below approximately 0.2g or where the GMRS is below or approximately equal to the SSE [Safe Shutdown Earthquake] between 1.0 Hz and 10 Hz. Examples are shown in Figures 2-1 and 2-2. At these sites, the Page 14 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 GMRS is either very low or within the range of the SSE such that unique seismic categorization insights are not expected."

Note: EPRI 3002012988 applies to the Tier 1 sites in its entirety except for sections 2.3 (Tier 2 sites), 2.4 (Tier 3 sites), Appendix A (seismic correlation), and Appendix B (criteria for capacity-based screening).

The Tier 1 criterion (i.e., basis) in EPRI 3002012988 is a comparison of the ground motion response spectrum (GMRS, derived from the seismic hazard) to the safe shutdown earthquake (SSE, i.e., seismic design basis capability). U.S. nuclear power plants that utilize the 10 CFR 50.69 Seismic Alternative (EPRI 3002012988) will continue to compare GMRS to SSE.

The trial studies in EPRI 3002012988 show that seismic categorization insights are overlaid by other risk insights even at plants where the GMRS is far beyond the seismic design basis. Therefore, the basis for the Tier 1 classification and resulting criterion is not that the design basis insights are adequate. Instead, it is that consideration of the full range of the seismic hazard produces limited unique insights to the categorization process. That is the basis for the following statements in Table 4-1 of the EPRI report.

"At Tier 1 sites, the likelihood of identifying a unique seismic condition that would cause an SSC to be designated HSS is very low.

Therefore, with little to no anticipated unique seismic insights, the 50.69 categorization process using the FPIE PRA and other risk evaluations along with the required Defense-in-Depth and IDP qualitative considerations are expected to adequately identify the safety-significant functions and SSCs required for those functions and no additional seismic reviews are necessary for 50.69 categorization."

The proposed categorization approach is a risk-informed graded approach that is demonstrated to produce categorization insights equivalent to a seismic PRA. For Tier 1 plants, this approach *relies on the insights gained from the seismic PRAs examined in Reference 20 along with confirmation that the site GMRS is low. Reference 20 demonstrates that seismic risk is adequately addressed for Tier 1 sites by the results of additional qualitative assessments discussed in this section and existing elements of the 10 CFR 50.69 categorization process specified in NEI 00-04.

For example, the 10 CFR 50.69 categorization process as defined in NEI 00-04 includes an Integral Assessment that weighs the hazard-specific relative importance of a component (e.g., internal events, internal fire, seismic) by the fraction of the total Core Damage Frequency (GDF) contributed by that hazard. The risk from an external hazard Page 15 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 can be reduced from the default condition of HSS if the results of the integral assessment meet the importance measure criteria for LSS. For Tier 1 sites, the seismic risk (CDF/LERF) will be low such that seismic hazard risk is unlikely to influence an HSS decision. In applying the EPRI 3002012988 process for Tier 1 sites to the 10 CFR 50.69 categorization process, the IDP will be provided with the rationale for applying the EPRI 3002012988 guidance and informed of plant SSC-specific seismic insights for their consideration in the HSS/LSS deliberations.

Reference 20 recommends a risk-informed graded approach for addressing the seismic hazard in the 10 CFR 50.69 categorization process. There are several seismic fragility fundamental concepts that support a graded approach, and there are important characteristics about the comparison of the seismic design basis (represented by the SSE) to the site-specific seismic hazard (represented by the GMRS) that support the selected thresholds between the three evaluation Tiers in the EPRI report. The coupling of these concepts with the categorization process in NEI 00-04 are the key elements of the approach defined in Reference 20 for identifying unique seismic insights.

The seismic fragility of an SSC is a function of the margin between an SSC's seismic capacity and the site-specific seismic demand. References such as EPRI NP-6041 (Reference 21) provide inherent seismic capacities for most SSCs that are not directly related to the site-specific seismic demand. This inherent seismic capacity is based on the non-seismic design loads (pressure, thermal, dead weight, etc.) and the required functions for the SSC. For example, a pump has a relatively high inherent seismic capacity based on its design, and that same seismic capacity applies at a site with a very low demand and at a site with a very high demand. At sites with lower seismic demands such as SPS, there is no need to perform more detailed evaluations to demonstrate the inherent seismic capacities documented in industry sources such as Reference 21. Low seismic demand sites have lower likelihood of seismically-induced failures and lesser challenges to plant systems. This, therefore, provides the technical basis for allowing use of a graded approach for addressing seismic hazards at SPS.

There are some plant features, such as equipment anchorage, that have seismic capacities more closely associated with the site-specific seismic demand since those specific features are specifically designed to meet that demand. However, even for these features, the design basis criteria have intended conservatisms that result in significant seismic margins within SSCs. These conservatisms are reflected in key aspects of the seismic design process. The SSCs used in nuclear power plants are intentionally designed using conservative methods and criteria to ensure that they have margins well above the required design bases. Experience has shown that design practices result in margins to realistic seismic capacities of 1.5 or more.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 The following provides the basis for establishing Tier 1 criteria in Reference 20.

a. SSCs for which the inherent seismic capacities are applicable, or which are designed to the plant SSE will have low probabilities of failure at sites where the peak spectral acceleration of the GMRS < 0.2g or where the GMRS < SSE between 1 and 10 Hz.
b. The low probabilities of failure of individual components would also apply to components considered to have correlated seismic failures.
c. These low probabilities of failure lead to low seismic CDF and LERF estimates, from an absolute risk perspective.
d. The low seismic CDF and LERF estimates lead to reasonable confidence that seismic risk contributions would allow reducing an HSS to LSS due to the 50.69 Integral Assessment if the equipment is HSS only due to seismic considerations.

Test cases described in Section 3 of Reference 20 showed that it would be unusual even for moderate hazard plants to exhibit any unique seismic insights, including due to correlated failures. The plant specific Reference 1 test case information Dominion Energy Virginia is using from the other licensees and being incorporated by reference into this application is described in Case Study A (Reference 29) and Case Study D (References 30, 31, 32). Hence, while it is prudent to perform additional evaluations to identify conditions where correlated failures may occur for Tier 2 sites, for Tier 1 sites such as SPS, correlation studies would not lead to new seismic insights or affect the baseline seismic CDF in any significant way.

The Tier 1 to Tier 2 threshold as defined in EPRI 3002012988 provides a clear and traceable boundary that can be consistently applied, plant site to plant site. Additionally, because the boundary is well defined, if new information is obtained on the site hazard, a site's location within a particular Tier can be readily confirmed. In the unlikely event that the SPS seismic hazard changes to medium risk (i.e., Tier 2) at some future time, Dominion Energy Virginia will follow its categorization review and adjustment process procedures to review the changes to the plant and update, as appropriate, the SSC categorization in accordance with 10 CFR 50.69(e).

The following provides the basis for concluding that SPS meets the Tier 1 site criteria.

In response to the NRC 50.54(f) letter associated with post-Fukushima recommendations (Reference 22), Dominion Energy Virginia submitted a seismic hazard screening report for SPS (Reference 23) to the NRC. The GMRS for SPS is below or approximately equal to the SSE between 1 Hz and 10 Hz, and therefore meets the Tier 1 criterion in Reference 20.

The SPS SSE and GMRS curves from the seismic hazard and screening response in Reference 23 are shown in Appendix B of Reference 23. The NRC's staff assessment of the SPS seismic hazard and screening response is documented in Reference 24. In Page 17 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 section 4.0 of Reference 24 the NRC concluded that the methodology used by Dominion Energy Virginia in determining the GMRS was acceptable and that the GMRS determined by Dominion Energy Virginia adequately characterizes the reevaluated hazard for the SPS site.

Section 1.1.3 of Reference 20 cites various post-Fukushima seismic reviews performed for the U.S. fleet of nuclear power plants. For SPS, the specific seismic reviews prepared by the licensee and the NRC's staff assessments are provided here. These licensee documents were submitted under oath and affirmation to the NRC.

1. NTTF Recommendation 2.1 seismic hazard screening (References 23, 24)
2. NTTF Recommendation 2.3 seismic walkdowns (References 25, 26, 27, 28)

As an enhancement to the EPRI study results, as they pertain to SPS, the proposed categorization approach for seismic hazards will include qualitative consideration of the mitigation capabilities of SSCs during seismically-induced events and seismic failure modes, based on insights obtained from prior seismic evaluations performed for SPS.

For example, as part of the categorization team's preparation of the System Categorization Document (SCD) that is presented to the IDP, a section will be included in the SCD that summarizes the identified plant seismic insights pertinent to the system being categorized and will also state the basis for applicability of the EPRI 3002012988 study and the bases for SPS being a Tier 1 plant. The discussion of the Tier 1 bases will include such factors as:

  • The low seismic hazard for the plant, which is subject to periodic reconsideration as new information becomes available through industry evaluations; and
  • The definition of Tier 1 in the EPRI study.

At several steps of the categorization process (e.g., as noted in Figure 3-1 and Table 3-1), the categorization team will consider the available seismic insights relative to the system being categorized and document their conclusions in the SCD. For HSS SSCs uniquely identified by the SPS PRA models but having design-basis functions during seismic events or functions credited for mitigation and prevention of severe accidents caused by seismic events, these will be addressed using non-PRA based qualitative assessments in conjunction with any seismic insights provided by the PRA.

For components that are HSS due to being on the Fire Safe Shutdown List but not HSS due to internal events PRA, the categorization team will review design-basis functions during seismic events or functions credited for mitigation and prevention of severe accidents caused by seismic events and characterize these for presentation to the IDP as additional qualitative inputs, which will also be described in the SCD.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 The categorization team will review available SPS plant-specific seismic reviews and other resources such as those identified above. The objective is to identify plant-specific seismic insights derived from the above sources, relevant to the components in the system being categorized, that might include potentially important impacts such as:

  • Impact of relay chatter
  • Implications related to potential seismic interactions such as with block walls
  • Seismic failures of passive SSCs such as tanks and heat exchangers
  • Any known structural or anchorage issues with a particular SSC
  • Components that are implicitly part of PRA-modeled functions (including relays)
  • Components that may be subject to correlated failures Such impacts would be compiled on an SSC basis. As each system is categorized, the system-specific seismic insights will be provided to the IDP for consideration as part of the IDP review process, as noted in Figure 3-1. As such, the IDP can challenge, from a seismic perspective, any candidate LSS recommendation for any SSC if they believe there is basis for doing so. Any decision by the IDP to downgrade preliminary HSS components to LSS will also consider the applicable seismic insights in that decision.

These insights will provide the IDP a means to consider potential impacts of seismic events in the categorization process.

Based on the above, the Summary/Conclusion/Recommendation from Section 2.2.3 of Reference 20 applies to SPS, i.e., SPS is a Tier 1 plant for which the GMRS is very low such that unique seismic categorization insights are expected to be minimal. As discussed in Reference 20, the likelihood of identifying a unique seismic insight that would cause an SSC to be designated HSS is very low. Therefore, with little to no anticipated unique seismic insights, the 10 CFR 50.69 categorization process using the Full Power Internal Events (FPIE) PRA and other risk evaluations, together with the defense in-depth and qualitative assessments by the IDP, adequately identify the safety significant functions and SSCs. Use of the EPRI approach outlined in Reference 20 to assess seismic hazard risk for 10 CFR 50.69, with the additional reviews discussed above, will provide a process for categorization of RISC-1, RISC-2, RISC-3 and RISC-4 SSCs that satisfies the requirements of 10 CFR 50.69(c).

3.2.4 Other External Hazards All other external hazards were screened for applicability to SPS per a plant-specific evaluation in accordance with GL 88-20 (Reference 6) and updated to use the criteria in Page 19 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 ASME PRA Standard RA-Sa-2009. Attachment 4 provides a summary of the other external hazards screening results. Attachment 5 provides a summary of the progressive screening approach for external hazards.

As part of the categorization assessment of other external hazard risk, an evaluation is performed to determine if there are components being categorized that participate in screened scenarios and whose failure would result in an unscreened scenario.

Consistent with the flow chart in Figure 5-6 in Section 5.4 of NEI 00-04, these components would be considered HSS.

3.2.5 Low Power & Shutdown Consistent with NEI 00-04, the SPS categorization process will use the shutdown safety management plan described in NUMARC 91-06 for evaluation of safety significance related to low power and shutdown conditions. The overall process for addressing shutdown risk is illustrated in Figure 5-7 of NEI 00-04.

NUMARC 91-06 specifies that a defense-in-depth approach should be used with respect to each defined shutdown key safety function. The key safety functions defined in NUMARC 91-06 are evaluated for categorization of SSCs.

SSCs that meet either of the two criteria (i.e., considered part of a "primary shutdown safety system" or a failure would initiate an event during shutdown conditions) described in Section 5.5 of NEI 00-04 will be considered preliminary HSS.

3.2.6 PRA Maintenance and Updates The Dominion Energy Virginia risk management process ensures the applicable PRA model used in this application continues to reflect the as-built and as-operated plant for each of the SPS units. The process delineates the responsibilities and guidelines for updating the PRA model and includes criteria for both regularly scheduled and interim PRA model updates. The process includes provisions for monitoring potential areas affecting the PRA model (e.g., due to changes in the plant, errors or limitations identified in the model, and industry operational experience) for assessing the risk impact of unincorporated changes, and for controlling the model and associated computer files.

The process will assess the impact of these changes on the plant PRA model in a timely manner but no longer than once every two refueling outages. If there is a significant impact on the PRA model, the SSC categorization will be re-evaluated.

In addition, Dominion Energy Virginia will implement a process that addresses the requirements in NEI 00-04, Section 11, "Program Documentation and Change Control."

The process will review the results of periodic and interim updates of the plant PRA that may affect the results of the categorization process. If the results are affected, adjustments will be made as necessary to the categorization or treatment processes to Page 20 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 maintain the validity of the processes. In addition, any PRA model upgrades will be peer reviewed prior to implementing those changes in the PRA model used for categorization.

3.2.7 PRA Uncertainty Evaluations Uncertainty evaluations associated with any applicable baseline PRA model(s) used in this application were evaluated during the assessment of PRA technical adequacy and confirmed through the self-assessment and peer review processes as discussed in Section 3.3 of this enclosure.

Uncertainty evaluations associated with the risk categorization process are addressed using the processes discussed in Section 8 of NEI 00-04 and in the prescribed sensitivity studies discussed in Section 5.

In the overall risk sensitivity studies, Dominion Energy Virginia will utilize a factor of 3 to increase the unavailability or unreliability of LSS components consistent with that approved for Vogtle in Reference 4. Consistent with the NEI 00-04 guidance, Dominion Energy Virginia will perform both an initial sensitivity study and a cumulative sensitivity study. The initial sensitivity study applies to the system that is being categorized. In the cumulative sensitivity study, the failure probabilities (unreliability and unavailability, as appropriate) of all LSS components modeled in all identified PRA models for all systems that have been categorized are increased by a factor of 3. This sensitivity study together with the periodic review process assures that the potential cumulative risk increase from the categorization is maintained acceptably low. The performance monitoring process monitors the component performance to ensure that potential increases in failure rates of categorized components are detected and addressed before reaching the rate assumed in the sensitivity study.

The detailed process of identifying, characterizing and qualitative screening of model uncertainties is found in Section 5.3 of NUREG-1855 and Section 3.1.1 of EPRI TR-1016737 (Reference 9). The process in these references was mostly developed to evaluate the uncertainties associated with the internal events PRA model; however, the approach can be applied to other types of hazard groups.

Each PRA element notebook was reviewed for assumptions and sources of uncertainties.

The characterization of assumptions and sources of uncertainties are based on whether the assumption and/or source of uncertainty is key to the 50.69 application in accordance with RG 1.200 Revision 2.

Key SPS PRA model specific assumptions and sources of uncertainty for this application were identified and dispositioned in Attachment 6. The conclusion of this review is that no additional sensitivity analyses are required to address SPS PRA model specific assumptions or sources of uncertainty except for the following:

  • Perform a sensitivity study for the FLEX independent failure equipment probabilities set to their 5th and 95th values.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 3.3 PRA REVIEW PROCESS RESULTS (10 CFR 50.69(b)(2)(iii))

The PRA model described in Section 3.2 has been assessed against RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, (Reference 7) consistent with NRC RIS 2007-06.

The internal events PRA model, including internal flooding, was subject to several focused scope peer reviews covering all supporting requirements that were conducted in accordance with RG 1.200, Revision 2, in 2010, 2012, 2016 and 2018. No PRA upgrades as defined by the ASME PRA Standard RA-Sa-2009 (Reference 10) have occurred since the October 2018 focused scope peer review.

A finding closure review was conducted on the identified PRA models from March 20-22, 2018. Resolved findings were reviewed and closed using the process documented in Appendix X to NEI 05-04, NEI 07-12 and NEI 12-13, "Close-out of Facts and Observations" (F&Os) (Reference 11), as accepted by the NRC in the letter dated May 3, 2017 (ML17079A427) (Reference 12). The results of this review have been documented and are available for NRC audit. The March 20-22, 2018 finding closure review was observed by the NRC (ML18095A990) (Reference 18). provides a summary of the remaining findings and open items, including:

  • Open findings and disposition of the SPS peer reviews.
  • Identification of and basis for any sensitivity analysis needed to address open findings.

The attachment identified above demonstrates the PRA is of sufficient quality and level of detail to support the categorization process and has been subjected to a peer review process assessed against a standard or set of acceptance criteria that is endorsed by the NRC as required 10 CFR 50.69(c)(1)(i).

3.4 RISK EVALUATIONS (10 CFR 50.69(8)(2)(IV))

The SPS 10 CFR 50.69 categorization process will implement the guidance in NEI 00-04. The overall risk evaluation process described in the NEI guidance addresses both known degradation mechanisms and common cause interactions and meets the requirements of §50.69(b)(2)(iv). Sensitivity studies described in NEI 00-04, Section 8, will be used to confirm the categorization process results in acceptably small increases to core damage frequency (CDF) and large early release frequency (LERF). The failure rates for equipment and initiating event frequencies used in the PRA include the quantifiable impacts from known degradation mechanisms, as well as other mechanisms (e.g., design errors, manufacturing deficiencies, and human errors). Subsequent performance monitoring and PRA updates required by the rule will continue to capture Page 22 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 this data and provide timely insights into the need to account for any important new degradation mechanisms.

3.5 FEEDBACK AND ADJUSTMENT PROCESS If significant changes to the plant risk profile are identified, or if it is identified that a RISC-3 or RISC-4 SSC can (or actually did) prevent a safety significant function from being satisfied, an immediate evaluation and review will be performed prior to the normally scheduled periodic review. Otherwise, the assessment of potential equipment performance changes and new technical information will be performed during the normally scheduled periodic review cycle.

To more specifically address the feedback and adjustment (i.e., performance monitoring) process as it pertains to the proposed SPS Tier 1 approach discussed in section 3.2.3, implementation of the Dominion Energy Virginia design control and corrective action programs will ensure the inputs for the qualitative determinations for seismic continue to remain valid to maintain compliance with the requirements of 10 CFR 50.69(e).

The performance monitoring process is described in Dominion Energy Virginia's 10 CFR 50.69 program documents. The program requires that the periodic review assess changes that could impact the categorization results and provides the Integrated Decision-making Panel (IDP) with an opportunity to recommend categorization and treatment adjustments. Station personnel from engineering, operations, risk management, regulatory affairs, and others have responsibilities for preparing and conducting various performance monitoring tasks that feed into this process. The intent of the performance monitoring reviews is to discover trends in component reliability, help catch and reverse negative performance trends, and take corrective action if necessary.

Dominion Energy Virginia has a comprehensive problem identification and corrective action program that ensures issues are identified and resolved. Any issue that may impact the 10 CFR 50.69 categorization process will be identified and addressed through the problem identification and corrective action program, including seismic-related issues.

The Dominion Energy Virginia 10 CFR 50.69 program requires that SCDs cannot be approved by the IDP until the panel's comments have been resolved to the satisfaction of the IDP. This includes issues related to system-specific seismic insights considered by the IDP during categorization.

Scheduled periodic reviews on an every two refueling cycle will evaluate new insights resulting from available risk information (i.e., PRA model or other analysis used in the categorization) changes, design changes, operational changes, and SSC performance.

If it is determined that these changes have affected the risk information or other elements of the categorization process such that the categorization results are more than minimally affected, then the risk information and the categorization process will be updated. This review will include:

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

  • A review of plant modifications since the last review that could impact the SSC categorization
  • A review of plant specific operating experience that could impact the SSC categorization,
  • A review of the impact of the updated risk information on the categorization process results
  • A review of the importance measures used for screening in the categorization process.
  • An update of the risk sensitivity study performed for the categorization In addition to the normally scheduled periodic reviews, if a PRA model or other risk information is upgraded, a review of the SSC categorization will be performed.

The periodic monitoring requirements of the 10 CFR 50.69 process will ensure that these issues are captured and addressed at a frequency commensurate with the issue severity.

The 10 CFR 50.69 periodic monitoring program includes immediate and periodic reviews that include the requirements of the regulation to ensure that all issues that could affect 10 CFR 50.69 categorization are addressed. The periodic monitoring process also monitors the performance and condition of categorized SSCs to ensure the assumptions for reliability in the categorization process are maintained.

4 REGULATORY EVALUATION 4.1 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA The following NRC requirements and guidance documents are applicable to the proposed change.

  • The regulations in Title 10 of the Code of Federal Regulations (10 CFR) Part 50.69, "Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors."
  • NRC Regulatory Guide 1.201, "Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance,"

Revision 1, May 2006.

Revision 2, April 2015.

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, March 2009.

The proposed change is consistent with the applicable regulations and regulatory guidance.

4.2 NO SIGNIFICANT HAZARDS CONSIDERATION ANALYSIS Virginia Electric and Power Company (Dominion Energy Virginia) proposes to modify the licensing basis to allow for the voluntary implementation of the provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50.69, "Risk-Informed Categorization and Treatment of Structures, Systems and Components for Nuclear Power Reactors."

The provisions of 10 CFR 50.69 allow adjustment of the scope of equipment subject to special treatment controls (e.g., quality assurance, testing, inspection, condition monitoring, assessment, and evaluation). For equipment determined to be of low safety significance, alternative treatment requirements can be implemented in accordance with this regulation. For equipment determined to be of high safety significance, requirements will not be changed or will be enhanced. This allows improved focus on equipment that has safety significance resulting in improved plant safety.

Dominion Energy Virginia has evaluated whether a significant hazards consideration is involved with the proposed amendments by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of Structures, Systems and Components (SSCs) subject to NRC special treatment requirements and to implement alternative treatments per the regulations. The process used to evaluate SSCs for changes to NRC special treatment requirements and the use of alternative requirements ensures the ability of the SSCs to perform their design function. The potential change to special treatment requirements does not change the design and operation of the SSCs. As a result, the proposed change does not significantly affect any initiators to accidents previously evaluated or the ability to mitigate any accidents previously evaluated.

The consequences of the accidents previously evaluated are not affected because the mitigation functions performed by the SSCs assumed in the safety analysis are not being modified. The SSCs required to safely shut down the reactor and maintain it in a safe shutdown condition following an accident will continue to perform their design functions.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of SSCs subject to NRC special treatment requirements and to implement alternative treatments per the regulations. The proposed change does not change the functional requirements, configuration, or method of operation of any SSC. Under the proposed change, no additional plant equipment will be installed.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The proposed change will permit the use of a risk-informed categorization process to modify the scope of SSCs subject to NRC special treatment requirements and to implement alternative treatments per the regulations. The proposed change does not affect any Safety Limits or operating parameters used to establish the safety margin.

The safety margins included in analyses of accidents are not affected by the proposed change. The regulation requires that there be no significant effect on plant risk due to any change to the special treatment requirements for SSCs and that the SSCs continue to be capable of performing their design basis functions, as well as to perform any beyond design basis functions consistent with the categorization process and results.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, Dominion Energy Virginia concludes that the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

4.3 CONCLUSION

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

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 5 ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.

However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or a significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6 REFERENCES

1. NEI 00-04, "10 CFR 50.69 SSC Categorization Guideline," Revision 0, Nuclear Energy Institute, dated July 2005.
2. NRC Regulatory Guide 1.201, "Guidelines for Categorizing Structures, Systems, and Components in Nuclear Power Plants According to their Safety Significance,"

Revision 1, dated May 2006.

3. NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management,"

dated December 1991.

4. NRC letter to Southern Nuclear Operating Company, "Issuance of Amendments Re:

Use of 10 CFR 50.69 (TAC Nos. ME9472 and ME94473)", dated December 17, 2014 (ADAMS Accession No. ML14237A034).

5. NRC Safety Evaluation Report, "Arkansas Nuclear One, Unit 2 - Approval of Request for Alternative AN02-R&R-004, Revision 1, Request to Use Risk-Informed Safety Classification and Treatment for Repair/Replacement Activities in Class 2 and 3 Moderate and High Energy Systems (TAC No. MD5250)," dated April 22, 2009 (ADAMS Accession No. ML090930246).
6. Generic Letter 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4," USNRC, dated June 28, 1991.
7. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, dated March 2009.
8. NUREG-1855, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making," Revision 1, March 2017.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

9. EPRI TR-1016737, "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments," dated December 2008.
10. ASME/ANS RA-Sa-2009, "Standard for Level I/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008," ASME, New York, NY, American Nuclear Society, La Grange Park, Illinois, dated February 2009.
11. NEI Letter to NRC, "Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close Out of Facts and Observations (F&Os)," dated February 21, 2017, (ADAMS Accession No. ML17086A431).
12. NRC Letter to Mr. Greg Krueger (NEI), "U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance 05-04, 7-12, and 12-13, Close Out of Facts and Observations (F&Os)," May 3, 2017, (ADAMS Accession No. ML17079A427).
13. NRC Letter to Mr. Oliver Martinez, "U.S. Nuclear Regulatory Commission (NRC)

Comments on Addenda to a Current ABS: ASME RA-SB - 20XX, Standard for Level 1 /Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," dated July 6, 2011 (ADAMS Accession No. ML111720076).

14. NEI 12-13, "External Hazards PRA Peer Review Process Guidelines," Revision 0, Nuclear Energy Institute, August 2012.
15. NRC Letter to Mr. Biff Bradley (NEI), "U.S. Nuclear Regulatory Commission Comments on Nuclear Energy Institute 12-13, 'External Hazards PRA Peer Review Process Guidelines,"' dated November 16, 2012 (ADAMS Accession No. ML12321A280.
16. NRC Letter to Mr. David A. Christian, "Surry Power Station, Units 1 and 2 - Review of Individual Plant Examination of External Events (IPEEE) (TAC Nos. M83681 and M83682)," dated June 29, 2000.
17. "Virginia Electric and Power Company, Surry Power Station Units 1 and 2, Proposed License Amendment Request, Addition of 24-Hour Completion Time for an Inoperable Reactor Trip Breaker," dated May 15, 2019 (ADAMS Accession No. ML19143A201).
18. U.S. Nuclear Regulatory Commission Report on Observations of Implementation of the Industry Independent Assessment Team Close-Out of Facts and Observations, dated September 6, 2018, (ADAMS Accession No. ML18095A990).
19. Branch Technical Position CMEB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," Revision 3, dated July 1981, (ADAMS Accession No. MLO? 0660454.)
20. Electric Power Research Institute (EPRI) 3002012988, "Alternative Approaches for Addressing Seismic Risk in 10CFR50.69 Risk-Informed Categorization," July 2018.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

21. EPRI NP-6041-SL, "A Methodology for Assessment of Nuclear Plant Seismic Margin, Revision 1", Electric Power Research Institute, August 1991.
22. U.S. Nuclear Regulatory Commission, "Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(F) Regarding Recommendations 2.1,2.3, And 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai ichi Accident," dated March 12, 2012, (ADAMS Accession No. ML12053A340).
23. Virginia Electric and Power Company, Surry Power Station Units 1 and 2, "Response to March 12, 2012 Information Request Seismic Hazard and Screening Report (CEUS Sites) for Recommendation 2.1," dated March 31, 2014, (ADAMS Accession No. ML14092A414).
24. Surry Power Station, Unit Nos. 1 and 2 - Staff Assessment of Information Provided Pursuant to Title 10 of the Code of Federal Regulations Part 50, Section 50.54(f),

Seismic Hazard Reevaluations for Recommendation 2.1 of the Near-Term Task Force (NTTF) Review of Insights from the Fukushima Dai-ichi Accident and Staff Closure of Activities Associated with NTTF Recommendation 2.1, "Seismic" (TAC Nos. MF3953 And MF3954)", dated December 15, 2015 (ADAMS Accession No. ML15335A093).

25. Virginia Electric and Power Company, Surry Power Station Units 1 and 2, "Report in Response to March 12, 2012 Information Request Regarding Seismic Aspects of Recommendation 2.3," dated November 27, 2012, (ADAMS Accession No. ML13017A002)
26. Virginia Electric and Power Company, Surry Power Station Units 1 and 2, "Report in Response to March 12, 2012 Information Request Regarding Seismic Aspects of Recommendation 2.3," dated August 27, 2014.
27. Staff Assessment of the Seismic Walkdown Report Supporting Implementation of Near-Term Task Force Recommendation 2.3 Related to the Fukushima Dai-ichi Nuclear Power Plant Accident (TAC No. MF0182) - Surry Power Station Unit 2, dated April 24, 2014.
28. Staff Assessment of the Seismic Walkdown Report Supporting Implementation of Near-Term Task Force Recommendation 2.3 Related to the Fukushima Dai-ichi Nuclear Power Plant Accident (TAC No. MF0181) - Surry Power Station Unit 1, dated April 17, 2014.
29. Peach Bottom Atomic Power Station Seismic Probabilistic Risk Assessment Report, "Response to NRC Request Regarding Recommendation 2.1 of the Near Term Task Force Review of Insights from the Fukushima Dai-ichi Accident," August 28, 2018 (ADAMS Accession No. ML18240A065).
30. Seismic Probabilistic Risk Assessment for Plant D Nuclear Plant, Units 1 and 2 "Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the NTTF Review of Insights from the Fukushima Dai-ichi Accident," June 30, 2017 (ADAMS Accession No. ML17181A485).

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1

31. Plant D Nuclear Plant Seismic Probabilistic Risk Assessment Supplemental Information, April 10, 2018 (ADAMS Accession No. ML17181A485).
32. Plant D Nuclear Plant, Units 1 and 2, Application to Adopt 10 CFR 50.69, "Risk informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors," November 29, 2018 (ADAMS Accession No. ML18334A363).

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 1 Attachment 1: List of Categorization Prerequisites Surry Power Station (SPS) will establish procedure(s) prior to the use of the categorization process on a plant system. The procedure(s) will contain the elements/steps listed below.

  • Integrated Decision-Making Panel (IDP) member qualification requirements.
  • Qualitative assessment of system functions. System functions are qualitatively categorized as preliminary High Safety Significant (HSS) or Low Safety Significant (LSS) based on the seven criteria in Section 9 of NEI 00-04 (see Section 3.2). Any component supporting an HSS function is categorized as preliminary HSS.

Components supporting an LSS function are categorized as preliminary LSS.

  • Component safety significance assessment. Safety significance of active components is assessed through a combination of Probabilistic Risk Assessment (PRA) and non-PRA methods, covering all hazards. Safety significance of passive components is assessed using a methodology for passive components.
  • Assessment of defense-in-depth (DID) and safety margin. Safety-related components that are categorized as preliminary LSS are evaluated for their role in providing DID and safety margin and, if appropriate, upgraded to HSS.
  • Review by the IDP. The categorization results are presented to the IDP for review and approval. The IDP reviews the categorization results and makes the final determination on the safety significance of system functions and components.
  • Risk sensitivity study. For PRA-modeled components, an overall risk sensitivity study is used to confirm that the population of preliminary LSS components results in acceptably small increases to core damage frequency (CDF) and large early release frequency (LERF) and meets the acceptance guidelines of Regulatory Guide 1.174.
  • Periodic reviews are performed to ensure continued categorization validity and acceptable performance for those SSCs that have been categorized.
  • Documentation requirements per Section 3.1.1 of the enclosure.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 1 Attachment 2: Description of PRA Model Used in Categorization Baseline Comments Units Model Baseline LERF CDF Focus Scope Peer Review (FSPR) 2010 FSPR 2012 SPS-R06d FSPR 2016 December 4, 2018 FSPR March 2018 Unit 1 Unit 1 Integrated 3.18E-06/yr 6.34E-07/yr F&O Closure Assessment 1 and 2 Model for March 2018 Internal Unit 2 Unit 2 Events and 3.33E-06/yr 7.58E-07/yr FSPR October 2018 Internal Flooding The above peer reviews Hazards cover all ASME/ANS PRA Standard RA-Sa-2009 supporting requirements conducted in accordance with RG 1.200 Revision 2.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 3 Attachment 3: Disposition and Resolution of Open Peer Review Findings and Self-Assessment Open Items Capability Finding Supporting Category Description Disposition for 50.69 Number Requirement(s)

(CC) 19-7 SC-A3 Met 2016 Focused Scope Peer Review Comment: Resolved.

(2017) Success criteria for MSLB includes the impact of failure to isolate AFW to the faulted SG with a Resolved in interim model small probability of vessel failure. The more likely SPS-R06c model update impact of failure to isolate AFW is more rapid by conservatively depletion of CST inventory. This should be considering AFW function included in the MSLB sequences. failed if main steam line isolation fails. Additionally, Proposed Resolution: no credit is given for Include the impact on CST inventory from MSLB operators throttling AFW with failure to isolate AFW to faulted SG. flow which is required per ECA-2.1, Step 2, "Control Feed Flow to Minimize RCS Cool Down."

Resolution does not impact the 50.69 LAR.

QU-F2-01 QU-F2 Met 2018 Focused Scope Peer Review Comment: Open - No application (2018) Dominion's PRA update process periodically impact.

creates a new "model of record" that addresses the requirements of QU-F2 & QU-F3. However, The full set of sensitivity interim updates are performed to maintain the studies performed to meet PRA consistent with the as-built/as-operated all QU requirements is not plant that do not address all the requirements of repeated for every Interim QU-F2 & QU-F3. This Full Scope Peer Review PRA model change; (FSPR) reviewed interim model MC.1, which did however, the results of not include the comprehensive results analysis every interim model change such as, but not limited to, the truncation level are reviewed in detail to sensitivity study required to meet the standard. ensure the new results are Page 33 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 ; Attachment 3 Capability Finding Supporting Category Description Disposition for 50.69 Number Requirement(s)

(CC) appropriate and reasonable Proposed Resolution: given the changes applied.

The full quantification analysis, which addresses Repeating all sensitivity the Supporting Requirements (SRs) for QU-F2 studies related to QU and QU-F3, should be updated to use with risk requirements is not informed submittals or peer reviews, or expected to impact any of justification should be included detailing why the risk insights generated elements of the previous quantification analysis in this analysis, so this (such as, but not limited to, the truncation level finding has no impact on sensitivity study) apply to the interim model. the acceptability of this application.

HR-A1-01 HR-A1 Met 2018 Focused Scope Peer Review Comment: Open - No application (2018) The SR states "for equipment modeled in the impact.

PRA, IDENTIFY activities ... ". The system notebooks contain: (1) a list of test and A detailed review of test maintenance procedures that are "modeled as and maintenance potential pre-initiator human error events", and procedures was performed (2) a list of other test and maintenance to determine which pre-procedures that "do not involve pre-initiator initiator human error events human error events." It is not clear what the should be included in the bases are for selection of the procedures to be model. Improving the modeled as pre-initiators. Attachment 8 to the documentation to clarify the system notebooks includes a tab "T&M link between procedures, Unavailability BEs" that lists test and T&M events, and pre-maintenance unavailability events, and a tab initiator HFEs will not "Human Actions" listing the pre-initiators defined impact the model for the system, but there is no documented link quantification, so this between procedure, T&M event and pre-initiator finding has no impact on Human Failure Event (HFE). the acceptability of this analysis.

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(CC)

Proposed Resolution:

Document the bases for the selection of the procedures to be modeled as pre-initiators and reconcile procedures, T&M unavailabilities and HFEs.

HR-81-01 HR-81 Met 2018 Focused Scope Peer Review Comment: Open - No application (2018) Screening criteria that can be used to screen impact.

components/failure modes from further consideration for pre-initiators are provided in Additional documentation Attachment 2 of NF-AA-PRA-101-2051, Revision clarifying the bases on how

4. However, the screening criteria applied to the T&M events were screened screening of procedures and activities are not out from inclusion as pre-documented. In Attachment 8 of the system initiator human error events notebooks, maintenance unavailability events will not impact model are listed in the " T&M Unavailability BEs." Each quantification, so this such activity should have a corresponding pre- finding has no impact on initiator HFE unless it can be screened out. the acceptability of this When comparing the list of T&M events to the list analysis.

in the "Human Actions" tab, it is not clear on what bases T&M activities were screened out, and it is not clear which HFEs relate to which activities.

Proposed Resolution:

Document the screening criteria applied to maintenance activities that are screened out and provide a link from procedure to activity to pre-initiator HFE.

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(CC)

IE-AG-01 IE-A6 Met 2018 Focused ScoQe Peer Review Comment: Open - No application (2018) Common cause failures of CW and SW impact.

components are not included in the initiating event fault trees. Evaluate the inclusion of Common cause failures of initiating event common causes, such as pump CW and SW components failures and traveling screen plugging in the are included in the SPS LOCW event tree. Include the events or PRA model. For a cooling document the basis for exclusion. water support system initiating event (SSIE) to ProQosed Resolution: take place, a single failure Evaluate the inclusion of initiating event common is evaluated over a mission causes, such as pump failures and traveling time of one year and screen plugging in the Loss of Circulating Water combined with failure (LOCW) event tree. Include the events or modes of the parallel document the basis for exclusion. components (including common cause) over a mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This is an industry standard method of modeling SSIEs as described in EPRI TR-1016741. Modeling a common cause failure of multiple trains of cooling water components over a mission time of one year would be excessively conservative as it would assume the first failure would be unable to be repaired during the mission time in the extensive period Page 36 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1 ; Attachment 3 Capability Finding Supporting Category Description Disposition for 50.69 Number Requirement(s)

(CC) before the subsequent failures took place.

Additional documentation justifying the current modeling of cooling water systems will not impact model quantification, so this finding has no impact on the acceptability of this analysis.

SY-A11-01 SY-A11 Met 2018 Focused ScoQe Peer Review Comment: Open - Possible (2018) SY-A11 directs the analyst to exclude application impact.

components only if the quantification criteria presented in SY-A15 are met. Although some Before implementation, a components were excluded based on the criteria documented basis for the in SY-A15, some components were excluded screened specific failure based on qualitative arguments such as "failure modes and components frequency was negligible." based on SR SY-A15 will be performed. Any ProQosed Resolution: components not screened Provide a quantitative basis for excluding based on SR SY-A15 will specific basic events in fault trees based on the be incorporated into the criteria specified in SR SY-A15. PRA FPIE model.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 Attachment 4: External Hazards Screening Aircraft impact hazard meets 1975 SRP requirements. Airports, military installations and flight corridors around Aircraft Impact y PS2 SPS have been considered. Evaluations of aircraft impact associated with these facilities find that it does not pose a si nificant hazard.

Not applicable to the site because of Avalanche y C3 climate and topography.

Plant design accounts for biological growth. Slowly developing growth can be detected and mitigated by surveillance.

The Service Water System Inspections program provides reasonable assurance Biological Event y C1, CS that corrosion (including microbiologically-influenced corrosion, MIC), erosion, protective coating failure, silting, and biofouling of service water piping and components will not cause a loss of intended function.

The area is covered by marshy wetlands Coastal Erosion y C3, CS and swamps. Therefore, erosion is not a si nificant robabilit .

The stretch of the water between Richmond and the mouth of the river is essentially a tidal estuary. There are no known or planned river control structures and the possibility of water shortage is Drought y C1, CS unlikely. However, in the case the canal level (29 ft normal level) drops the plant will be shut down when the canal level falls to the minimum level specified in Technical S ecifications.

Most external flooding hazards meet the 1975 SRP requirements or the plant is designed against the hazards.

Core damage frequency due to local C1, PS2, External Flooding y intense precipitation is bounded by 1 E-PS4 6/yr.

Core damage frequency due to hurricanes, storm surge and waves is bounded b 1 E-6/ r.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 River flooding, dam failure flooding (except sunny-day Intake Canal failure) and ice-induced flooding were evaluated and found to be within the design basis of SPS.

The Intake Canal reinforced concrete liner is a SPS design feature in place to prevent the sunny-day failure mechanism. Flood protection training and procedures against a postulated sunny-day Intake Canal failure will be implemented as part of the Dominion 10 CFR 50.54(f) response.

Seiche and river migration/diversion were evaluated as not posing a hazard to SPS.

Tsunami hazards were evaluated as being within the design basis of SPS.

As part of the NRC 10 CFR 50.54(f) request on Reevaluation of External Floods, Dominion Energy is in the process of evaluating the external hazards at SPS. As part of the reevaluation, any identified discrepancies will be tracked in the corrective action ro ram.

SPS structures are designed against loadings imposed by tornados having a maximum rotational velocity of 300 mph and a maximum translational velocity of 60 mph. This design basis tornado has a frequency less than 1 E-6/yr at SPS.

Extreme Wind or C1, PS2, y SPS is designed against large missile Tornado PS4 strikes and meet the 1975 SRP requirements.

Core damage frequency due to small and large missile strikes are bounded by 1 E-6/yr.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 In response to the NRC RIS-2015-06, Tornado Missile Protection, Dominion Energy is in the process of evaluating the tornado missile design basis at Surry. As part of the reevaluation, any identified discrepancies will be tracked in the corrective action ro rams.

SPS structures are designed against loadings imposed by tornados having a maximum rotational velocity of 300 mph and a maximum translational velocity of 60 mph. This design basis tornado has a frequency less than 1 E-6/yr at SPS.

SPS is designed against large missile strikes and meet the 1975 SRP Extreme Wind or C1, PS2, requirements.

y Tornado PS4 Core damage frequency due to small missile strike is bounded by 1 E-6/yr.

In response to the NRC RIS-2015-06, Tornado Missile Protection, Dominion Energy is in the process of evaluating the external hazards at SPS. As part of the reevaluation, any identified discrepancies will be tracked in the corrective action ro ram.

Fog can affect the frequency of occurrence of transportation accidents and impacts. The transportation Fog y C4 accident frequencies and frequency of aircraft crashes include accidents involvin fo .

Site is cleared preventing fire from Forest or Range Fire y C3 propagating onto the site.

Frost is covered under snow and ice Frost y C4 hazards.

Loss of offsite power (LOOP) events associated with hail are addressed in the Internal Events PRA and the occurrence Hail y C2, C4 frequency is enveloped by the frequency of weather-induced LOOP events.

Limited occurrence and bounded b Page 40 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 other events for which the plant is designed.

Plant is designed for this hazard.

Ventilation systems provide conditioned air in the plant to cool equipment.

High Summer Weather-induced LOOP events are y C1,CS Temperature considered in the Internal Events PRA.

Effects on the UHS are slow to develop if they develop at all because of the flow ath of the James River.

High Tide, Lake Level, High tide is covered by external flooding y C4 or River Stage considering storm surge.

Covered under Extreme Wind or Hurricane y C4 Tornado and Intense Precipitation.

Only for possible contribution to external flooding by ice dams. In addition, ice Ice Cover y C1,C5 cover hazard is screened based on developing slowly, allowing adequate time to eliminate or mitigate the threat.

Explosive hazard impacts and control room habitability impacts meet 1975 SRP requirements (RG 1.78 and 1.91).

Industrial facilities are too distant to pose Industrial or Military y PS2 a hazard to the safe operation of the Facility Accident plant. Nearby military facilities do not conduct operations that could potentially pose a hazard to the safe operation of the lant.

Internal Flooding N None SPS has an internal flooding model.

The internal fire hazard does not meet the screening criteria and will be Internal Fire N None addressed separately in the risk informed application process.

Not applicable to the site because of Landslide y C3 topography.

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Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 Lightning strikes causing loss of offsite power or turbine trip are contributors to the initiating event frequencies for these Lightning y C1 events. However, other causes are also included. The impacts are no greater than already modeled in the internal events PRA.

Low Lake Level or Screens as an event covered by drought y C4 River Stage or for drawdown due to tsunami.

The climatic characteristics of the site region are influenced by the Atlantic Ocean, the Chesapeake Bay, and the Appalachian Mountains. The Atlantic Ocean has a moderating effect on the temperature for the SPS region, whereas the Appalachians act as a barrier to Low Winter y C1 deflect Midwest winter storms to the Temperature northeast of the SPS region. Winters are mild and short, spring and fall weather is usually very comfortable. Plant is designed for the climate.

Only for possible contribution to external flooding by ice dams.

The frequency of meteorites greater than 100 lbs. striking the plant resulting in serious damage is 7E-9/yr and Meteorite or Satellite y C2, PS4 corresponding satellite impacts is Impact assumed to be similar, 7E-9/y. Site is no more likely to be struck by meteorite/satellite than any other site.

Bounding analysis performed in the IPEEE calculated a large pipeline failure at 1.28E-6/yr. Given the location of the Pipeline Accident y PS3 pipeline from the power plant, a CCDP of 0.1 is assumed and, therefore, the CDF is less than 1E-6/ r.

Control room habitability during Release of Chemicals y PS2 postulated chemical releases has been in Onsite Storage evaluated and it has been determined Page 42 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 that habitability is not threatened by this hazard as described in Regulatory Guide 1.78.

Not applicable to the site. James River River Diversion y C3 has been found to not meander and its course is stable.

Not applicable to the site because of C1 Sand or Dust Storm y location. SPS is sufficiently situated from cs sand sources.

Not applicable to the site. Seiches in the James River, Intake CanI and Discharge Canal were evaluated not to Seiche y C3 be a hazard for these bodies of water because of their geometry and locations relative to seiche inducin henomena.

The seismic hazard does not meet the screening criteria and will be addressed Seismic Activity N None separately in the risk-informed application process.

Potential flooding impacts covered under Snow y C1, C4 external flooding.

Plant is designed for this hazard. The SPS UFSAR Chapter 2.4 describes the characteristics of the area geology, soil conditions, testing, foundations and Soil Shrink-Swell y C1 backfill. Allowable bearing pressures for Consolidation soil-supported structures are greater than contact pressures as determined by backfill testing. The potential for this hazard is low.

Storm surge is covered by external Storm Surge y C4 flooding.

Toxic gas is covered by industrial or military facility accident, release of chemicals in on-site storage, and Toxic Gas y C4 transportation accident. Control room habitability during postulated chemical releases has been evaluated and it has Page 43 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 4 been determined that habitability is not threatened by this hazard.

Potential hazards meet the NRC's SRP (NUREG-0800 Section 2.3.3).

Waterways - the nearest shipping channel is 1.4 miles. An explosion on watercraft would not impact the containment or surrounding building. The Emergency Service Water Pump House is a Class I structure which can safely Transportation withstand up to 3.0 psi static pressure.

y PS2 Accident Risk from waterborne traffic is considered insignificant.

Roads - Virginia Highway 10 passes within 5 miles. Flammable vapor clouds from gasoline spill would not present an explosive impact that could impact the plant. Impact from other chemicals is less limitin as noted in UFSAR.

Tsunami is covered under external Tsunami y C4 flooding.

The SPS UFSAR calculates the probability of a rotor fracture of Turbine-Generated 6.96E-8/yr. using a methodology that y PS2 Missiles complies with the SRP acceptance criteria of NUREG 0800, Section 3.5.1.3, Turbine Missile.

Not applicable to the site because of Volcanic Activity y C3 location. There are no volcanos within the vicinit of SPS.

Waves are covered under external Waves y C4 flooding.

Note a - See Attachment 5 for descriptions of the screening criteria.

Page 44 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 5 : Progressive Screening Approach for Addressing External Hazards NUREG/CR-2300 C1. Event damage potential is <

Initial Preliminary and ASME/ANS events for which plant is Screening Standard RA-Sa-designed.

2009 C2. Event has lower mean NUREG/CR-2300 frequency and no worse and ASME/ANS consequences than other Standard RA-Sa-events analyzed. 2009 NUREG/CR-2300 C3. Event cannot occur close and ASME/ANS enough to the plant to affect it. Standard RA-Sa-2009 NUREG/CR-2300 Not used to screen.

C4. Event is included in the and ASME/ANS Used only to include definition of another event. Standard RA-Sa-within another event.

2009 CS. Event develops slowly, ASME/ANS Standard allowing adequate time to RA-Sa-2009 eliminate or mitigate the threat.

PS1. Design basis hazard Progressive ASME/ANS Standard cannot cause a core damage Screening RA-Sa-2009 accident.

PS2. Design basis for the event NUREG-1407 and meets the criteria in the NRC ASME/ANS Standard 1975 Standard Review Plan RA-Sa-2009 (SRP).

PS3. Design basis event mean NUREG-1407 as frequency is < 1E-5/y and the modified in mean conditional core damage ASME/ANS Standard probability is < 0.1. RA-Sa-2009 NUREG-1407 and PS4. Bounding mean CDF is <

ASME/ANS Standard 1E-6/yr.

RA-Sa-2009 Screening not successful. PRA NUREG-1407 and Detailed PRA needs to meet requirements in ASME/ANS Standard the ASME/ANS PRA Standard. RA-Sa-2009 Page 45 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 6 Attachment 6: Disposition of Key Assumptions/Sources of Uncertainty Assumption/ Uncertainty Discussion Disposition Equipment type code data Inclusion of successful PMT This was addressed by includes successful post demands can result in an under- performance of a sensitivity maintenance testing (PMT). estimation of the failure study that indicated inclusion of probability of a component type. the number of assumed PMT demands has a small impact on CDF and, therefore, will not require any additional sensitivity study for system cateqorization.

Common cause failures are This uncertainty potentially As directed by NEI 00-04, developed using available affects all SSCs evaluated common cause basic events are industry data. during 50.69 categorization. increased to their 95th percentile and decreased to their 5th percentile values as part of the required 50.69 PRA categorization sensitivity cases.

These results can drive a component and respective functions HSS and, therefore, the uncertainty of the common cause failure probabilities is accounted for in the categorization process.

Implementation of FLEX The NRC memoranqum dated Sensitivity studies will be Strategies for Human May 30, 2017, "Assessment of performed per NEI 00-04 to Reliability Analysis and the Nuclear Energy Institute 16 increase the human error Equipment Failure Rates 06, 'Crediting Mitigating probabilities to their 5th and 95th Strategies in Risk-Informed percentile values as part of the Decision Making,' Guidance for required 50.69 PRA Risk-Informed Changes to Plants categorization sensitivity cases.

Licensing Basis" (ADAMS Additionally, a sensitivity study Accession No. ML17031A269), will be performed on the provides the NRC's staff independent FLEX failures using assessment of identified the 5th and 95th percentile challenges and strategies for values.

incorporating FLEX equipment into a PRA model in support of risk-informed decision making in accordance with the guidance of RG 1.200. The section below this table provides an overview of the modeling of FLEX strategies in the SPS FPIE PRA model.

Page 46 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 6 Per a request made during the September 9, 2019 pre-submittal meeting, the following information provides an overview of the modeling of FLEX strategies in the SPS FPIE PRA model:

FLEX Strategies and equipment are used to mitigate the accident conditions and prevent core damage for two scenarios with the SPS Internal Events and Internal Flooding model: 1) Turbine Building (TB) flooding propagating to the emergency switchgear room (ESGR), and 2) Station Blackout with no capability of restoring offsite power.

The modeling of the FLEX strategies for SPS Unit 1 consists of a simplified logic structure which combines the modeled FLEX strategies under two top gates, U1-FLEX-FLD and U1-FLEX-SBO.

U1-FLEX-FLD Flooding the ESGR causes a loss of AC and DC power. The first strategy modeled for this scenario is to repower instrumentation at the Appendix R Remote Monitoring Panel (RMP). A 12-hour UPS allows for restoration of required instrumentation via panel switches for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The second modeled strategy involves manual control of the Auxiliary Feedwater valves to prevent SG overfill. The third modeled FLEX strategy involves providing alternate sources to replenish the Emergency Condensate Storage Tank (ECST) by aligning fire protection valves from the fire protection pumps and supply tanks. The last modeled strategy is the installation of the portable 120-volt generator to re-power the RMP panel within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

U1-SBO The first modeled FLEX strategy involves maintaining availability of vital instrumentation which includes load shedding the DC buses, which extends vital instrumentation for greater than 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. The second modeled strategy involves manual control of the Auxiliary Feedwater valves to prevent SG overfill. The third modeled FLEX strategy involves providing alternate sources to replenish the Emergency Condensate Storage Tank (ECST) by aligning fire protection valves from the fire protection pumps and supply tanks. The last modeled strategy is the installation of the portable 120- or 480-volt generator to re-power the vital AC and battery chargers.

Credited Portable Equipment Data The credited portable equipment in the FLEX strategies is the portable diesel driven generator to restore power to the RMP panel, vital AC, and/or battery chargers. The failure to start and failure to run data was developed using the Page 47 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 6 generic NUREG/CR-6928 values for a diesel driven generator. There are multiple portable diesel driven generators on site that can be used and implemented if a single generator failed. The equipment failure data will be considered as a source of uncertainty. A sensitivity study will be performed on the independent FLEX failures using the 5 th and 95 th percentile values.

Human Error Probabilities (HEPs)

FLEX-related operator actions credited in the internal events model were evaluated per ASME/ANS RA-Sa-2009 PRA standard supporting criterion HR-G3.

The EPRI HRA Calculator was used to quantify the events; explicitly addressing all performance shaping factors (PSFs) identified in HR-G3. Specific consideration of these PSFs for each HFE are documented in the SPS HRA Calculator file. A peer review was performed in September 2016 and no findings were identified.

For a loss of all AC power event, the operators initiate procedure ECA 0.0. The procedure step to initiate the FLEX Strategies contained ln ECA 0.0 is explicit and not vague or ambiguous.

Peer Review Dominion Energy Virginia evaluated the inclusion of FLEX modeling and concluded that it was an upgrade. A focus scope peer review was conducted in September 2016. The peer review concluded that the FLEX modeling met Capability Category 11 with no findings.

Page 48 of 48

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 6 Enclosure 2 MARKED-UP SPS UNITS 1 AND 2 LICENSE PAGES Virginia Electric and Power Company (Dominion Energy Virginia)

Surry Power Station Units 1 and 2

05 31 17 T. (Continued)

16. For the applicable UFSAR Chapter 14 Prior to operating above events, Surry 1 will re-analyze the 2546 MWt (98.4% RP).

transient consistent with VEPCO 1 s NRG-approved reload design methodology in VEP-FRD-42, Rev. 2.1-A.

If NRC review is deemed necessary pursuant to the requirements of 10 CFR 50.59, the accident analyses will be submitted to the NRG for review prior to operation at the uprate power level. T hese commitments apply to the following Surry 1 UFSAR Chapter 14 DNBR analyses that were analyzed at 2546 MWt consistent with the Statistical DNBR Evaluation Methodology in VEP-NE-2-A:

  • Section 14.2.7 - Excessive Heat Removal due to Feedwater System Malfunctions (Full Power Feedwater Temperature Reduction case only);
  • Section 14.2.8 - Excessive Load Increase Incident;
  • Section 14.2.10 - Loss of External Electrical Load U. Deleted by Amendment No. 289 y
4. T his renewed license is effective as of the date of issuance and shall expire at midnight on May 25, 2032.

FOR THE NUCLEAR REGULAT ORY COMMISSION Original signed by:

Samuel J. Collins, Director Office of Nuclear Reactor Regulation

Attachment:

Appendix A, T echnical Specifications Date of Issuance: March 20, 2003 Surry - Unit 1 Renewed License No. DPR-32 Amendment No. 28-9

0§ 81 17 T. (Continued)

16. For the applicable UFSAR Chapter 14 Prior to operating above events, Surry 2 will re-analyze the 2546 MWt (98.4% RP).

transient consistent with VEPCO's NRG-approved reload design methodology in VEP-FRD-42, Rev. 2.1-A.

If NRC review is deemed necessary pursuant to the requirements of 10 CFR 50.59, the accident analyses will be submitted to the N RC for review prior to operation at the uprate power level. These commitments apply to the following Surry 2 UFSAR Chapter 14 DNBR analyses that were analyzed at 2546 MWt consistent with the Statistical DNBR Evaluation Methodology in VEP-NE-2-A:

  • Section 14.2.7 - Excessive Heat Removal due to Feedwater System Malfunctions (Full Power Feedwater Temperature Reduction case only);
  • Section 14.2.8 - Excessive Load Increase Incident;
  • Section 14.2.10 - Loss of External Electrical Load U. Deleted by Amendment No. 289
4. This renewed license is effective as of the date of issuance and shall expire at midnight on January 29, 2033.

FOR THE NUCLEAR REGULATORY COMMISSION Original signed by:

Samuel J. Collins, Director Office of Nuclear Reactor Regulation

Attachment:

Appendix A, Technical Specifications Date of Issuance: March 20, 2003 Surry - Unit 2 Renewed License No. DPR-37 Amendment No. 289

INSERT V. The licensee is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) model to evaluate risk associated with internal events, including internal flooding; the Appendix R program to evaluate fire risk; qualitative assessments of seismic insights; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 SSCs and their associated supports; and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in License Amendment No.

[XXX] dated [DATE].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from an Appendix R program fire risk evaluation to a fire probabilistic risk assessment approach).

Serial No.19-031 Docket Nos. 50-280/281 10 CFR 50.69 LAR Enclosure 1; Attachment 6 Enclosure 3 PROPOSED SPS UNITS 1 AND 2 LICENSE PAGES Virginia Electric and Power Company (Dominion Energy Virginia)

Surry Power Station Units 1 and 2

T. (Continued)

16. For the applicable UFSAR Chapter 14 Prior to operating above events, Surry 1 will re-analyze the 2546 MWt (98.4% RP).

transient consistent with VEPCO's NRG-approved reload design methodology in VEP-FRD-42, Rev. 2.1-A.

If NRC review is deemed necessary pursuant to the requirements of 10 CFR 50.59, the accident analyses will be submitted to the NRC for review prior to operation at the uprate power level. These commitments apply to the following Surry 1 UFSAR Chapter 14 DNBR analyses that were analyzed at 2546 MWt consistent with the Statistical DNBR Evaluation Methodology in VEP-NE-2-A:

  • Section 14.2.7 - Excessive Heat Removal due to Feedwater System Malfunctions (Full Power Feedwater Temperature Reduction case only);
  • Section 14.2.8 - Excessive Load Increase Incident;
  • Section 14.2.10 - Loss of External Electrical Load U. Deleted by Amendment No. 289 V. The licensee is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) model to evaluate risk associated with internal events, including internal flooding; the Appendix R program to evaluate fire risk; qualitative assessments of seismic insights; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 SSCs and their associated supports; and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in License Amendment No. [XXX] dated [Amendment Date].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from an Appendix R program fire risk evaluation to a fire probabilistic risk assessment approach.)

Surry - Unit 1 Renewed License No. DPR-32 Amendment No.

4. This renewed license is effective as of the date of issuance and shall expire at midnight on May 25, 2032.

FOR THE NUCLEAR REGULATORY COMMISSION Original signed by:

Samuel J. Collins, Director Office of Nuclear Reactor Regulation

Attachment:

Appendix A, Technical Specifications Date of Issuance: March 20, 2003 Surry - Unit 1 Renewed License No. DPR-32 Amendment No.

T. (Continued)

16. For the applicable UFSAR Chapter 14 Prior to operating above events, Surry 2 will re-analyze the 2546 MWt (98.4% RP).

transient consistent with VEPCO's NRG-approved reload design methodology in VEP-FRD-42, Rev. 2.1-A.

If NRC review is deemed necessary pursuant to the requirements of 10 CFR 50.59, the accident analyses will be submitted to the NRC for review prior to operation at the uprate power level. These commitments apply to the following Surry 2 UFSAR Chapter 14 DNBR analyses that were analyzed at 2546 MWt consistent with the Statistical DNBR Evaluation Methodology in VEP-NE-2-A:

  • Section 14.2.7 - Excessive Heat Removal due to Feedwater System Malfunctions (Full Power Feedwater Temperature Reduction case only);
  • Section 14.2.8 - Excessive Load Increase Incident;
  • Section 14.2.10 - Loss of External Electrical Load U. Deleted by Amendment No. 289 V. The licensee is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 structures, systems, and components (SSCs) using: Probabilistic Risk Assessment (PRA) model to evaluate risk associated with internal events, including internal flooding; the Appendix R program to evaluate fire risk; qualitative assessments of seismic insights; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 SSCs and their associated supports; and a screening of other external hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009; as specified in License Amendment No. [XXX] dated [Amendment Date].

Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from an Appendix R program fire risk evaluation to a fire probabilistic risk assessment approach.)

Surry - Unit 2 Renewed License No. DPR-37 Amendment No.

4. This renewed license is effective as of the date of issuance and shall expire at midnight on January 29, 2033.

FOR THE NUCLEAR REGULATORY COMMISSION Original signed by:

Samuel J. Collins, Director Office of Nuclear Reactor Regulation

Attachment:

Appendix A, Technical Specifications Date of Issuance: March 20, 2003 Surry - Unit 2 Renewed License No. DPR-37 Amendment No.

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