ML23243B049

VEGP Units 3 and 4, Safety Evaluation, LAR-22-002, TS 3.8.3 Inverters Operating, Completion Time Extension - Enclosure 3

ML23243B049
Person / Time
Site:	Vogtle
Issue date:	12/19/2023
From:	NRC/NRR/VPOB
To:	Southern Nuclear Operating Co
Gleaves W
Shared Package
ML23243A956	List: ML23243A968 ML23243A980 ML23243B049 ML23243B054 ML23243B057
References
EPID L-2023-LLA-0002
Download: ML23243B049 (17)

Text

Enclosure 3 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 197 TO COMBINED LICENSE NO. NPF-91 AND AMENDMENT NO. 193 TO COMBINED LICENSE NO. NPF-92 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

GEORGIA POWER COMPANY OGLETHORPE POWER CORPORATION MEAG POWER SPVM, LLC MEAG POWER SPVJ, LLC MEAG POWER SPVP, LLC CITY OF DALTON, GEORGIA VOGTLE ELECTRIC GENERATING PLANT, UNITS 3 AND 4 DOCKET NOS.52-025 AND 52-026

1.0 INTRODUCTION

By letter dated January 3, 2023, (Agencywide Documents Access and Management System (ADAMS) Accession Number ML23003A797), as supplemented by letters dated June 13, 2023, and August 31, 2023, at ML23164A270 and ML23243B058, respectively, and pursuant to 10 CFR 50.90 and 52.98(c), Southern Nuclear Operating Company, Inc. (SNC or licensee) submitted a license amendment request (LAR-22-002) to amend the combined licenses (COLs) for Vogtle Electric Generating Plant (VEGP), Units 3 and 4 (Combined License Numbers NPF-91 and NPF-92).

1.1 Description of the Proposed Changes The proposed changes would revise VEGP Units 3 and 4 Technical Specification (TS) 3.8.3, Inverters - Operating, to extend the Completion Time (CT) from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days for Required Action (R.A.) A.1 (i.e., restore inverter(s) that are inoperable in one division.) The licensee also proposed associated changes to the TS Bases. Additionally, the licensee proposed to correct a misspelled word in TS 3.3.9, Engineered Safety Feature Actuation System (ESFAS) Manual Initiation, Condition C by replacing Requried with Required.

1.2 Proposed Changes to TS Bases Consistent with Title 10 of the Code of Federal Regulations (10 CFR) Section 50.36(a)(1),

SNC submitted corresponding changes to the TS Bases that provide the reasons for the proposed TS changes. The regulation at 10 CFR 50.36(a)(1) states that a summary statement of the bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the TS. The licensee may make changes to the VEGP TS Bases in accordance with TS 5.5.6, Technical Specifications (TS) Bases Control Program.

1.3

Reason for Request

SNC indicated the change to TS 3.8.3 would provide more time for future repairs, troubleshooting, and retesting to avoid an unnecessary unplanned unit shutdown; would reduce the potential administrative burden of requesting a notice of enforcement discretion or emergency license amendment; and would enhance equipment and personnel safety by doing repairs in a more controlled environment.

The June 13, 2023, supplement responded to a request for additional information and provided additional information related to the maintenance duration for repair/replacement of inverters for TS limiting condition for operation (LCO) 3.8.3, R.A. A.1. The August 31, 2023, supplement provided additional clarifying information on the timeline for inverter diagnosis, maintenance, and repair. The supplements dated June 13, and August 31, 2023, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on March 21, 2023 (88 FR 17032).

2.0 REGULATORY EVALUATION

The NRC staff considered the following regulatory requirements in reviewing the LAR:

Title 10 of the Code of Federal Regulations (10 CFR) 52.98(f) provides that any modification to, addition to, or deletion from the terms and conditions of a COL is a proposed license amendment. These activities involve a change to COL Appendix A TS information; therefore, a license amendment is required prior to making these plant-specific proposed changes.

10 CFR Part 52, Appendix D, VIII.C.6, states that after issuance of a license, [c]hanges to the plant-specific TS will be treated as license amendments under 10 CFR 50.90. 10 CFR 50.90 addresses the application for amendment of a license, including a combined license. The licensee is requesting changes in the TS; therefore, a LAR is required to be submitted for NRC approval.

In 10 CFR 50.36, the Commission established its regulatory requirements related to the content of TS. Pursuant to 10 CFR 50.36, TS are required to include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. The regulation also states, in part, that [a] summary statement of the bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the technical specifications.

10 CFR 50.36(c)(2)(i) requires, in part, that the applicants for a license authorizing operation of a production or utilization facility include in their application proposed TSs that specify LCOs.

LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

10 CFR Part 50, Appendix A, General Design Criterion (GDC) 17, Electric Power Systems requires, in part, that an onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components [SSCs] important to safety. Each system (assuming the other system is not functioning) shall provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled, and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

10 CFR Part 50, Appendix A, GDC 18, Inspection and Testing of Electric Power Systems, requires that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing of important areas and features.

10 CFR 50.63, Loss of all alternating current power, requires that light-water-cooled nuclear power plants must be able to withstand a loss of all alternating current (AC) power for an established period and recover from a station blackout.

10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, paragraph (a)(1) requires, in part, that performance or condition of SSCs be monitored against licensee-established goals to provide reasonable assurance that SSCs as defined in 10 CFR 50.65(b) can fulfill their intended functions. When the performance or condition of an SSC does not meet established goals, appropriate corrective action shall be taken. Also, 10 CFR 50.65(a)(3) requires that licensees shall make adjustments "where necessary to ensure that the objective of preventing failures of [SSCs] through maintenance is appropriately balanced against the objective of minimizing unavailability of [SSCs] due to monitoring or preventive maintenance. Paragraph 50.65(a)(4) of 10 CFR requires licensees to assess and manage the increase in risk that may result from proposed maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance) before performing these activities.

The staff also considered the following applicable regulatory guidance in reviewing the LAR:

NRC Standard Review Plan (SRP) Section 8.3.1, Revision 3, AC Power Systems (Onsite),

provides the guidance for reviewing onsite power AC power systems compliance with GDC 17.

The SRP Section 8.3.1 states, in part, that meeting GDC 17, provides assurance that a reliable electric power supply will be provided for all facility operating modes, including anticipated operational occurrences and design basis accidents (DBAs) to permit safety functions and other vital functions to be performed, even in the event of a single failure.

Regulatory Guide (RG) 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment [PRA] in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, describes an acceptable method for licensees and the NRC to use for assessing the nature and impact of proposed changes to the licensing basis by considering engineering issues and applying risk insights. This RG also provides risk-acceptance guidelines for evaluating the results of such evaluations. Section C.1 states, in part, that licensees should affirm that a proposed change meets current regulations unless that proposed change is explicitly related to an exemption.

RG 1.177, Revision 2, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications, describes methods acceptable to the NRC for assessing the nature and impact of proposed permanent TS changes, including allowed outage times, by considering engineering issues (deterministic evaluation) and applying risk insights (risk evaluation). The traditional deterministic engineering considerations are (1) consistency with the defense-in-depth (DID) philosophy and (2) maintenance of sufficient safety margins. RG 1.177, Section C.2.2.1, states, in part, that evaluation of DID is in accordance with the seven considerations outlined in RG 1.174, Section C.2.1.1. In addition, all risk-informed applications for changes to plant TS should explicitly address the following five key principles described in RG 1.174 and RG 1.177:

Principle 1: The proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change (i.e., a specific exemption under 10 CFR 50.12).

Principle 2: The proposed change is consistent with the DID philosophy.

Principle 3: The proposed change maintains sufficient safety margins.

Principle 4: When proposed changes result in an increase in core damage frequency or risk, the increase should be small and consistent with the intent of the Commissions policy statement on safety goals for the operations of nuclear power plants (Safety Goals for the Operations of Nuclear Power Plants; Policy Statement, 51 FR 30028 (Aug. 21, 1986)).

Principle 5: The impact of the proposed change should be monitored using performance measurement strategies.

In addition to the key principles, RG 1.177 identifies a four-element, three-tiered approach to evaluating proposed changes to a plants design, operations, and other activities that require NRC approval:

Element 1: Define the Proposed Change Element 2: Perform Engineering Analysis Element 3: Define Implementation and Monitoring Program Element 4: Submit Proposed Change RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, describes one approach acceptable to the NRC staff for determining whether a base PRA, in total or in the portions that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision-making for light-water reactors.

3.0 TECHNICAL EVALUATION

The Class 1E 250 VDC and Uninterruptable Power Supply System (IDS) consists of two subsystems; the Class 1E 250 VDC subsystem and the Class 1E Uninterruptable Power Supply (UPS) subsystem. VEGP Units 3 and 4 updated final safety analysis report (UFSAR)

Section 8.3.2.1, Description, states, in part, that the IDS provides reliable power for the safety-related equipment required for the plant instrumentation, control, monitoring, and other vital functions needed for shutdown of the plant. In addition, the Class 1E DC and UPS system provides power to the normal and emergency lighting in the main control room and at the remote shutdown workstation. The Class 1E DC and UPS system can provide reliable power for the safe shutdown of the plant without the support of battery chargers during a loss of all AC power sources coincident with a DBA. The system is designed so that no single failure will result in a condition that will prevent the safe shutdown of the plant.

The Class 1E 250 VDC subsystem has four independent Divisions A, B, C and D. UFSAR Section 8.3.2.1.1.1, Class 1E DC Distribution, states, in part, Divisions A and D each have one battery bank, one switchboard, and one battery charger, but Divisions B and C each have two battery banks, two switchboards, and two battery chargers. The UFSAR further states, in part, that a 24-hour battery bank in each IDS division supplies an inverter and its instrument and control distribution panel (ICDP) needed for first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following a DBA. Similarly, a separate 72-hour battery bank in only IDS Divisions B and C supplies its respective inverter and ICDP for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after a DBA. TS Bases B 3.8.1, DC Sources - Operating, Background, states, in part, that the 24-hour loads are engineered safety features (ESF) actuation cabinets and reactor trip function whereas 72-hour loads are for emergency lighting, post-accident monitoring, and the Qualified Data Processing System. There is a spare battery bank that can be connected to only one of the Class 1E 250 VDC divisions at a time as restricted by Kirk-key interlock switches.

The Class 1E UPS subsystem is described in UFSAR Section 8.3.2.1.1.2, Class 1E Uninterruptible Power Supplies, and states, in part, that the Class 1E UPS subsystem supplies power at 208 Y/120 VAC to the four independent divisions of Class 1E instrument and control power buses. Divisions A and D each have one Class 1E inverter that powers one ICDP, and Divisions B and C each have two Class 1E inverters with each inverter supplying an ICDP.

LAR Section 2.1, System Design and Operation, states, in part, that the inverters are the designated power source for their ICDPs due to their stability and reliability. For an inoperable inverter or unavailability of its Class 1E 250 VDC input, the assigned ICDP is powered from its backup ac source, a Class 1E 480-208/120 VAC voltage-regulating transformer (VRT) for each division, automatically by the inverters static switch or manually by a separate bypass switch with the latter only used when the inverter is removed from service. LAR Section 3, Technical Evaluation, subsection Applicable Safety Analyses and Safety Margin Evaluation, states, in part, that for a loss of offsite power (LOOP), the standby diesel generators (DGs) can be used to power IDS battery chargers to supply IDS inverters or, if inverter(s) is/are unavailable, the respective VRT(s) can be used to power the ICDPs for the same purpose.

LAR Section 3, Technical Evaluation, subsection Deterministic Evaluation, states, in part, that IDS battery chargers, if onsite or offsite AC sources are available, typically power their associated IDS inverters. TS Bases B 3.8.1, DC Sources - Operating, Background, states, in part, if normal power is lost to an IDS battery charger, its DC load is automatically powered by its respective IDS battery bank. UFSAR Section 8.1.3, Safety-Related Loads, states, in part, that safety-related loads are powered by the Class 1E 250 VDC batteries and the associated Class 1E instrument and control power buses.

In the LAR, the licensee proposed revisions to the VEGP Units 3 and 4 COL Appendix A, TS 3.8.3, Inverters - Operating, to extend the Completion Time (CT) for R.A. A.1 for one or two inoperable inverter(s) within one division from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days. In addition, the licensee proposed a revision to TS 3.3.9, Engineered Safety Feature Actuation System (ESFAS)

Manual Initiation, Condition C, that would replace the misspelled word Requried with Required.

3.1 Proposed Changes to TS 3.3.9 - Engineering Safety Feature Actuation System (ESFAS)

Manual Initiation The staff reviewed the proposed change to VEGP TS 3.3.9 Condition C that would correct the misspelling of required and finds it acceptable because it is editorial, non-technical in nature, and adds clarity to the interpretation and use of the TS.

3.2 Proposed Changes to TS 3.8.3 - Inverters - Operating The proposed change would modify VEGP TS 3.8.3, R.A. A.1, by increasing the CT from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days for one or two inoperable inverters in one IDS division. LAR Section 3.0, Technical Evaluation, states, in part, that both deterministic and risk evaluations have been included to support the proposed change. The deterministic evaluation discussed in Section 3.2 of this SE addresses key Principles 2 and 3 (DID and safety margins) of the staff's risk-informed decision-making process outlined in RG 1.177. Principle 1 (change meets current regulations) is addressed in Section 3.3 of this SE, Principal 4 (change results in small increase in risk) is discussed in the PRA evaluation in Section 3.2.5 of this SE, and Principle 5 (change should be monitored using performance measurement strategies) is discussed in Section 3.3 of this SE for compliance with 10 CFR 50.65.

3.2.1 IDS Changes Due to Proposed CT Extension The LAR did not request any changes to the IDS or inverter design, function, interface, or reliability. As stated in LAR Section 4.3.1, the TS change does not alter the design, operational characteristics, or function of the inverters. Based on reviews of the LAR, UFSAR, TSs and its Bases, and the proposed change itself, the staff finds the LAR changes do not modify the inverters physically, nor affect their design, functions, or interfaces.

3.2.2 Defense-in-Depth LAR Section 3, Technical Evaluation, subsection Applicable Safety Analyses and Safety Margin Evaluation, states, in part, the initial conditions of DBA and transient analyses in UFSAR Chapters 6 and 15 assume ESF regarding IDS inverters are operable. Additionally, that section states, in part, that the IDS inverters provide the required capacity, capability, redundancy, and reliability to maintain the necessary power to the protection and safety monitoring system instrumentation and controls so that the fuel, reactor coolant system, and containment design limits are not exceeded.

LAR Section 3, Technical Evaluation, subsection Deterministic Evaluation, states, in part, that only the IDS is credited with safe shutdown for accident conditions in the event of a LOOP and loss of onsite AC power source and a worst-case single failure. The IDS consists of four independent divisions. Each division includes a VRT with a distribution panel capable of providing a regulated output to the Class 1E AC instrument and control bus through a static transfer switch or a manual bypass switch in the event of an inverter failure. The LAR also states, in part, only three of the four IDS divisions are necessary to support the minimum safety functions to shut down the reactor and maintain it in safe shutdown condition. In that hypothetical case, three IDS divisions will power their inverters and, in turn, their ICDPs, and one division will be used as a backup source for the VRT to power its ICDPs for implementation of LCO 3.8.3, Condition A. That means that all ICDPs are powered during that LCO if identified power source(s) are available based on LAR Section 3, Technical Evaluation, subsection Abnormal Operation.

If either a VRT or its ICDP were inoperable, LAR Section 3, Technical Evaluation, subsection Abnormal Operation states, in part, that the Note to TS 3.8.3, R.A. A.1 invokes applicable conditions and required actions of LCO 3.8.5 (Distribution Systems - Operating) with any instrument and control bus de-energized. TS 3.8.5, R.A. A.1 requires one inoperable AC instrument and control division to be restored within six hours. If LCO 3.8.5, Condition A were not met, then TS 3.8.5, R.A. E.1 dictates that the affected VEGP unit be in Mode 3 in six hours and Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The TS remedial actions afforded by TS 3.8.5 ensures that power is maintained to all ICDPs in a VEGP unit, or an orderly plant reduction in operating mode is required as specified in the TSs.

LAR Section 3, Technical Evaluation, states, in part, that extension of the IDS inverter CT from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days does not impact existing DID of the VEGP Units 3 and 4 electrical systems or the IDS, or the inverters themselves. Entry into TS 3.8.3 Condition A results in the unavailability of inverters in one IDS division. Based on its review, the staff finds that the proposed change to TS 3.8.3, R.A. A.1 maintains DID because of the following, which are captured in, and supported by, the COL and licensing basis: (1) assumed ESF functions for IDS inverters remain due to operable redundant equipment; (2) only three out of four of the IDS divisions are necessary to support safe shutdown; (3) SNC does not rely on compensatory measures; and (4) all ICDPs will normally be powered as required by LCO 3.8.3. Based on these findings, the staff concludes that licensee conformed with Principle 2, maintaining DID philosophy, for this risk-informed application and that the IDS inverter CT extension has no adverse impact on the layers of DID inherent to the VEGP Units 3 and 4 electrical systems, including the IDS, and is therefore, acceptable.

3.2.3 Safety Margin Safety margin is another criterion evaluated in RG 1.174 for inclusion in the deterministic evaluation of TS changes. During the proposed 14-day CT extension for TS 3.8.3, R.A. A.1, one or two inverters will be inoperable in one IDS division. In the LAR Section 3, Technical Evaluation, subsection Applicable Safety Analyses and Safety Margin Evaluation, the licensee stated, in part, that an abnormal system condition may occur because of component failures within the IDS or as the result of a fire. Potential component failures and sources of component unavailability include battery charger failure, battery failure, off-line battery recharging, inverter failure, inverter maintenance, I&C room fires, and electrical equipment room fires. If an inverter is inoperable or the IDS input to the inverter is unavailable, the power is transferred automatically to the backup AC source from the standby diesel generator-backed non-Class 1E 480 VAC bus through the Class 1E VRT. Additionally, two standby DGs are designed to provide another source of backup AC power for Divisions B and C.

Upon the failure of the Class 1E DC bus or the inverter and the backup AC power supply (VRT, or upstream equipment / source), the associated instrument and control power bus(es) will de-energize. TS 3.8.3, R.A. A.1 includes a note providing more limiting actions in the event the instrument and control bus is de-energized by requiring the entry into the applicable Conditions and R.A.s of LCO 3.8.5, Distribution Systems - Operating. These R.A.s require that each affected instrument and control bus is restored (i.e., within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) as required by LCO 3.8.5, R.A. A.1.

TS 3.8.3, R.A. A.1, which requires each affected instrument and control bus to be promptly re-energized within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, provides reasonable assurance that at least three out of four IDS divisions will be available to shut down the reactor and to maintain the reactor in a safe condition during the proposed IDS inverter CT extension period. Based on the above evaluation, the staff concludes that with the proposed change the licensee conforms with Principle 3, maintaining sufficient safety margin, for this risk-informed application and that sufficient safety margin is maintained because the VEGP Units 3 and 4 electrical systems design provides reasonable assurance of the continued availability of backup power to the IDS and is therefore acceptable.

The staff notes that the proposed CT extension does not affect the design criteria, testing methods, and acceptance criteria for the IDS inverters and their ICDPs specified in applicable codes and standards (or alternatives approved for use by the NRC), as described in the VEGP UFSAR. Therefore, since the proposed CT extension will not impact the plant safety analysis and its applicable codes and standards, the staff finds that the minimal reduction in safety margin for the duration of the LCO implementation is acceptable.

3.2.4 Evaluation of Justification for CT Extension to 14 Days TS 1.3 Completion Times establishes that LCOs are the minimum requirements for ensuring safe operation of the unit and that a CT is the amount of time for completing an R.A. For continuous operation, LCO 3.8.3 requires that all inverters in the four divisions be operable while in Modes 1 through 4, which is the lowest performance level for IDS inverters. In LAR Section 3, Technical Evaluation, subsection Industry Experience Related to Inverter Maintenance, SNC indicates that VEGP Units 3 and 4 do not currently have direct operating experience (OE) related to maintenance on the specific VEGP inverter. SNC provided industry OE examples in LAR Table 1 which approved an extended CT for an inoperable inverter. LAR Section 3, Technical Evaluation, subsection "Probabilistic Risk Assessment," states that SNC used RG 1.177 guidance to assess the impact of the CT extension from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days. RG 1.177, Section C.2, Element 2: Perform Engineering Analysis, states the following regarding NRC staff expectations:

The staff expects licensees to provide strong technical bases for any TS change.

The technical bases should be rooted in deterministic engineering and system analysis. Licensees should not submit for review TS change requests based on PRA results alone.

RG 1.177, Section C.2.3, Evaluation of Risk Impact (Principle 4), indicates that the PRA should model specific components and that their unavailability models should include test and maintenance downtimes. Further, RG 1.177, Section C.2, Element 2: Perform Engineering Analysis, states, Standard practices used in setting CTs should be followed (e.g., CTs normally are 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, 7 days, 14 days, and so on). Using such standards greatly simplifies implementation, scheduling, monitoring, and auditing.

SNC did not originally provide a sufficient deterministic justification to support the proposed 14-day CT extension since it is beyond CT extensions for inoperable inverters in the precedents noted in the LAR. Therefore, in a request for additional information (RAI) dated May 17, 2023 (ML23137A216), the staff requested a timeline, in hours or days, to perform the maintenance for an inoperable inverter in one IDS division including reasonable margin. SNC provided a response (June 13, 2023, supplement) to which the staff then issued a second round RAI to clarify SNCs original response.

The NRC staff evaluated SNCs response dated August 31, 2023, to the second round RAI. The staff evaluated the hypothetical timeline provided by SNC in that response along with its various inputs and assumptions. SNC provided a result for that hypothetical timeline of 6 days, 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> for restoring the operability of an inoperable inverter based on performance of identified specific activities. This estimate was not a bounding case because SNC stated that it was reasonable to assume a variability of plus or minus 30%. On the high end, that maintenance duration would be 8 days and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. The August 31, 2023, response identified two issues that could reflect even more variability in the estimates: (1) the time required to arrange onsite vendor support and (2) lead time for obtaining qualified replacement parts. SNC included in the estimate three days to arrange onsite vendor support but stated that this could be as high as 5 days or more depending on travel variability. SNC did not include in the estimate a lead time for procuring inverter replacement parts. The timeline in SNCs August 31, 2023, supplement was both reasonable and acceptable because it identified the reasonable significant events for inverter maintenance and practical times to complete each of them with margin.

Based on its review of SNCs LAR and supplements, the NRC staff determined that the high end of the hypothetical estimate of 8 days and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> would exceed a proposed CT of 7 days but is bounded by the proposed CT of 14 days. Therefore, the staff determined that extending the CT to 14 days would provide a reasonable amount of time to allow SNC to perform adequate analyses, develop detailed corrective action plans, and perform corrective maintenance on the inverters in one IDS division and is therefore acceptable.

3.2.5 Evaluation of PRA in Support of LAR As stated in the LAR, the VEGP Units 3 and 4 PRA models have been developed and updated in accordance with RG 1.200, Revision 2. The models including internal events, internal flooding, fire, seismic, and external events were developed and have been updated using endorsed standards and methodologies including ASME/ANS-RA-Sa 2009, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications; EPRI 1019194, Guidelines for Performance of Internal Flooding Probabilistic Risk Assessment; NUREG/CR-6850, EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities; and ANSI/ANS 58.21-2007, External Events PRA Methodology.

The licensee also stated that these models have been peer reviewed following appropriate guidance including NEI 00-02, Probabilistic Risk Assessment (PRA) Peer Review Process Guidance; NEI 05-04, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard; NEI 07-12, Fire Probabilistic Risk Assessment (FPRA) Peer Review Process Guidelines; NEI 12-13, External Hazards PRA Peer Review Process Guidelines; and EPRI 3002012994, Seismic Fragility and Seismic Margin Guidance for Seismic Probabilistic Risk Assessment.

The licensee stated that the VEGP PRA model reflects the VEGP Unit 3 design reference point of August 2018 (model freeze date). The changes to the design up to the model freeze date for the VEGP Unit 3 model have been incorporated in the PRA model. For the design changes that occurred after August 2018, a model maintenance process was used to identify, collect, and screen for any necessary model update. Walkdowns were also performed to confirm the PRA model represents the VEGP Unit 3 as-built plant conditions, and observations with potential risk-significant impact to the PRA were incorporated into the model, while observations and as-found conditions identified with low impact (not risk-significant) were dispositioned and are tracked via the model maintenance process for future incorporation. The licensee stated that none of the plant-specific differences identified during performance of walkdowns or model changes due to design changes have resulted in changes to risk insights from the VEGP Unit 3 PRA. While the licensee indicated that these activities are completed and satisfied based on the as-built activities for VEGP Unit 3 and are assumed to be representative of VEGP Unit 4, any plant-specific deviations between the units will be reconciled when completing the COL condition for VEGP Unit 4.

The staff evaluated the VEGP Units 3 and 4 PRA model and found that they have undergone several model revisions to incorporate as-built conditions and improvements. In addition, as stated by the licensee, peer review findings and observations have been updated to the extent possible, as previously noted. Since these PRA models do not yet reflect the as-built, as-operated plants, the staff issued an RAI dated August 8, 2023, to request that the licensee describe any applicable uncertainty analyses and/or sensitivity studies that were performed in support of the application to provide confidence in the results of the updated PRA and to provide assurance that the quantitative results accurately reflect plant conditions.

In the response dated August 31, 2023, the licensee indicated that a review of the key assumptions and uncertainty notebook for each quantified hazard as well as external events was performed, focusing on uncertainties relevant to the IDS, the inverter, electric power and loss of offsite power (LOOP) events with no sources or assumptions that would be impactful to the overall results presented in the LAR. Since the VEGP Units 3 and 4 Internal Events PRA model conservatively assumes no recovery from a LOOP event, a LOOP sensitivity study was performed by decreasing the LOOP frequency in both the base case and application case as a surrogate for modeling LOOP recovery. The result of the study shows a decrease in core damage frequency (CDF)/large early release frequency (LERF) as expected; therefore, the conservative unrecoverable LOOP assumption is deemed not impactful to the overall result in the application. The licensee stated that it also performed a sensitivity study to evaluate the assumption that industry/generic data used in the PRA is representative of the plant performance going forward. The study assumed higher unreliability for the inverter and resulted in a decreased risk achievement worth (RAW) value for the inverter and a lower change in CDF/LERF. When higher reliability was extended across all plant systems, the result was somewhat higher change in CDF/LERF values. The licensee stated that sensitivities related to the lack of performance and plant-specific data were not performed because the quantitative impact on incremental conditional core damage probability (ICCDP)/incremental conditional large early release frequency (ICLERF) for the proposed 14-day CT is below the RG 1.177 acceptance criteria.

Based on the above, the staff finds the VEGP Units 3 and 4 PRA models used to support this LAR application to be acceptable because the models were developed in accordance with RG 1.200 and followed NRC endorsed industry standards and guidelines, the PRA models have been updated to reflect as-built conditions to the extent possible, and risk impact reviews, gap analyses, and/or sensitivity studies were performed to address models uncertainties. Therefore, the staff concludes that the licensee has performed an acceptable analysis in support of the subject risk-informed application in accordance with Element 2 as prescribed in RG 1.177 in support of this LAR.

RG 1.174 provides that changes to TS should only result in small increases in the risk to public health and safety. RG 1.177 provides guidelines for evaluating the risk associated with the revised CT for permanent changes as follows:

a. The licensee has demonstrated that the TS CT change has only a small quantitative impact on plant risk. An ICCDP of less than 1x10-6 and an incremental conditional large early release probability (ICLERP) of less than 1x10-7 are considered small for a single TS condition entry.

b. The licensee has demonstrated that there are appropriate restrictions on dominant risk-significant configurations associated with the change.

c. The licensee has implemented a risk-informed plant configuration control program, including procedures to use, maintain, and control such a program.

As estimated by the licensee, the risk impact of extending the IDS inverters CT from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days for the most limiting conditions of two IDS inverters out of service resulted in ICCDP of 2.67E-07 and ICLERF of 8.51E-08/yr. The licensee also stated that the VEGP Units 3 and 4 Configuration Risk Management Program (CRMP) is consistent with 10 CFR 50.65(a)(4) (i.e., Maintenance Rule) and is managed to prevent entering risk-significant plant configurations for planned maintenance activities, and to take appropriate actions should unforeseen events place the plant in a risk-significant configuration during the IDS inverter CT.

Based on the above, the staff concluded that the quantitative risk increase is within the acceptance criteria of RG 1.177 for a permanent TS change, the licensee has also implemented a risk-informed plant configuration control program to prevent entering risk-significant configurations during maintenance activities, and uncertainties in the PRA models were addressed. As such, the application met Principle 4, Principle 5, and Element 3 for a risk-informed change as prescribed in RG 1.174 and RG 1.177, respectively, in support of the LAR.

3.3 Compliance with Regulatory Requirements The regulations at 10 CFR 50.36(c)(2) specify the requirements for LCOs. When an LCO is not met, 10 CFR 50.36(c)(2)(i) requires that remedial actions be taken until the LCO is met or the reactor be shut down. SNC proposed a CT extension for one or two inoperable inverter(s) in one division in TS 3.8.3, R.A. A.1 from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 14 days. During entry into Condition A of TS 3.8.3, the safety function is maintained by the inverters in the remaining three operable IDS divisions for safe shutdown. Additionally, the Note to TS 3.8.3, R.A. A.1 requires entry into applicable conditions of LCO 3.8.5 for any de-energized instrument and control buses, if an IDS division cannot supply its ICDP. The proposed change is acceptable from a safety perspective, as explained above. Therefore, the staff finds that compliance with 10 CFR 50.36 is maintained.

10 CFR Part 50, Appendix A, GDC 17 requires onsite and offsite electric power systems to permit the functions of safety-related SSCs. The proposed TS change does not decrease the existing redundancy and DID design of the onsite and offsite power systems below that threshold required for safe shutdown since the remaining three IDS divisions are sufficient to achieve that end. Therefore, the staff finds that compliance with GDC 17 is maintained.

10 CFR Part 50, Appendix A, GDC 18 requires electric power systems that are important to safety be designed to allow periodic inspection and testing of important areas or features. The proposed TS change is for online maintenance of inoperable inverters and has no impact on any existing inspection or testing of offsite and onsite power systems, including the IDS inverters. Therefore, the staff finds that compliance with GDC 18 is maintained.

10 CFR Section 50.63 requires nuclear power plants be able to withstand a loss of all AC power for an established period and recover from a station blackout. LAR Section 4.1 states, in part, that IDS batteries provide power to safety-related loads during a loss of all ac power including that of onsite standby DGs. The staff confirmed that by review of various sections of the UFSAR. Since three IDS divisions will be available when TS LCO 3.8.3 Condition A is entered, the staff finds that compliance with 10 CFR 50.63 is maintained.

10 CFR 50.65 provides the requirements for assessing and managing the increase in risk that may result from maintenance activities before performing those activities. LAR Section 3, Technical Evaluation, subsection Risk Management Measures states, in part, that the VEGP Units 3 and 4 Maintenance Rule program monitors the IDS inverters reliability and availability and confirms that appropriate management attention and goal setting are applied. The VEGP Units 3 and 4 CRMP is consistent with the Maintenance Rule and is a performance management strategy to prevent entering risk-significant plant configurations for planned maintenance activities, and to take appropriate actions if a VEGP unit is placed in a risk-significant configuration. The proposed 14-day CT does not alter the performance monitoring aspects of the VEGP Maintenance Rule and CRMP programs; therefore the NRC staff finds that SNC will continue to comply with 10 CFR 50.65(a)(4) using its existing maintenance and CRMP programs to protect required equipment and manage the risk associated with maintenance activities.

3.4 Conclusion The staff determined above that the PRA models were developed in accordance with RG 1.200 and that the proposed changes (1) will not alter physically the inverters or operation of IDS in any way; (2) will maintain required DID; (3) only minimally decrease safety margin; (4) are justified by SNCs time to complete worst-case duration for maintenance for inoperable inverter; (5) continue to comply with existing regulations; and (6) result in small increases to the ICCDP and ICLERP per RG 1.177. The licensee has also addressed all five key principles and the four-element, three-tiered approach to evaluating proposed changes to a plants design, operations, and other activities as discussed in RG 1.174 and RG 1.177 for a risk-informed application. Based on meeting these determinations, the staff concludes that there is reasonable assurance that adequate controls are in place to ensure IDS inverters retain the capability to perform their specified safety functions during the implementation of TS LCO 3.8.3, Condition A for the proposed CT extension to 14 days.

The NRC staff reviewed the proposed changes and concluded that the proposed TS changes satisfy the requirements of 10 CFR 50.36(c)(2)(i), 10 CFR 50.63, and 10 CFR 50.65. The staff also concluded that both GDC 17 and GDC 18 will continue to be met as previously discussed.

In addition, facility operations in accordance with the TS can be conducted without endangering the health and safety of the public. Therefore, the staff concludes that the licensees proposed changes are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations in 10 CFR 50.91(b), on November 8, 2023, the Commission consulted the state official. The State of Georgia had no comment.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (88 FR 17032) dated March 21, 2023. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

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

7.0 REFERENCES

1. Southern Nuclear Operating Company, Vogtle Electric Generating Plant, Units 3 and 4, License Amendment Request for Technical Specification 3.8.3, Inverters - Operating, Completion Time Extension (LAR-22-002), January 3, 2023 (ML23003A797).

2. Southern Nuclear Operating Company, Vogtle Electric Generating Plant, Units 3 and 4, Response to Request for Additional Information Regarding License Amendment Request for Technical Specification 3.8.3, Inverters - Operating, Completion Time Extension (LAR-22-002S1), June 13, 2023 (ML23164A270).

3. Southern Nuclear Operating Company, Vogtle Electric Generating Plant, Units 3 and 4, Response to Round 2 Request for Additional Information Regarding License Amendment Request for Technical Specification 3.8.3, Inverters - Operating, Completion Time Extension (LAR-22-002S2), August 31, 2023 (ML23243B058).

4. Southern Nuclear Operating Company, Email, Summary of 9.27.23 Clarification Call with Southern Nuclear Company on LAR-22-002, TS 3.8.3 Inverters - Operating Completion Time, October 2, 2023 (ML23275A100).

5. Combined License NPF-91 for Vogtle Electric Generating Plant, Unit 3, Appendix A, Vogtle Electric Generating Plant Units 3 and 4 Technical Specifications, Southern Nuclear Operating Company, February 10, 2012 (ML14100A106).

6. Combined License NPF-92 for Vogtle Electric Generating Plant, Unit 4, Appendix A, Vogtle Electric Generating Plant Units 3 and 4 Technical Specifications, Southern Nuclear Operating Company, February 10, 2012 (ML14100A135).

7. Vogtle Electric Generating Plant Units 3 and 4, Updated Final Safety Analysis Report, Revision 12, June 13, 2023 (ML23165A215).

Principal Contributors Sheila Ray, Ed Kleeh, Thinh Dinh, Charles Moulton.