ML25086A198

Final ASP Analysis - South Texas Project 1 LOOP Resulting in Unit 1 Automatic Reactor Trip and Actuation of EDGs and AFW Pumps (LER 498-2024-004) - Precursor

ML25086A198
Person / Time
Site:	South Texas
Issue date:	03/25/2025
From:	Christopher Hunter South Texas
To:	Office of Nuclear Regulatory Research
References
LER 498-2024-004
Download: ML25086A198 (12)

Text

1 Final ASP Analysis - Precursor Accident Sequence Precursor Program - Office of Nuclear Regulatory Research South Texas Project, Unit 1 Loss of Offsite Power Resulting in Unit 1 Automatic Reactor Trip and Actuation of Emergency Diesel Generators and Auxiliary Feedwater Pumps Event Date: 7/24/2024 LER:

498-2024-004 CCDP =

4x10-6 IR: 05000498/2024050 Plant Type:

Westinghouse Four-Loop Pressurized-Water Reactor (PWR) with Dry Ambient Pressure Containment Plant Operating Mode (Reactor Power Level):

Mode 1 (100% Reactor Power)

Analyst:

Reviewer:

Completion Date:

Christopher Hunter Matthew Humberstone 4/2/2025 1

EXECUTIVE

SUMMARY

On July 24, 2024, a loss of offsite power (LOOP) occurred, resulting in an automatic reactor trip and actuation of all three Unit 1 emergency diesel generators (EDGs) and all four auxiliary feedwater (AFW) pumps. All three trains of engineered safety feature (ESF) buses were energized via the EDGs, and all equipment responded as expected without any complications except for steam generator (SG) power-operated relief valve (PORV) 1C. Unit 2 experienced a partial LOOP and automatic actuation of EDG 22 and one of four AFW pumps; however, Unit 2 remained at power during the event.

This accident sequence precursor (ASP) analysis reveals that the most likely core damage sequence is a switchyard-centered LOOP initiating event with at least one EDG successfully providing power to an ESF bus. The failure of turbine-driven AFW pump to provide makeup to the SGs results in a loss of decay heat removal. Core damage will occur due to the failure of feed and bleed cooling. This accident sequence accounts for approximately 87 percent of the total conditional core damage probability (CCDP) for this event. The mean CCDP for this event is 3.6x10-6, which is likely lower than most PWRs due to South Texas having(a.) three safety-related trains of mitigating equipment, (b.) two permanently installed FLEX diesel generators on each unit, and (c.) installed passive shutdown reactor coolant pump (RCP) seals.

2 EVENT DETAILS 2.1 Event Description On July 24, 2024, a LOOP occurred, resulting in an automatic reactor trip and actuation of all three Unit 1 EDGs and all four AFW pumps. All three trains of ESF buses were energized via the EDGs, and all equipment responded as expected without any complications except for SG PORV 1C. Unit 2 experienced a partial LOOP and automatic actuation of EDG 22 and one of four AFW pumps; however, Unit 2 remained at power during the event. Additional information is provided in licensee event report (LER) 498-2024-004, Loss of Offsite Power Resulting in Unit 1 Automatic Reactor Trip and Actuation of Emergency Diesel Generators and Auxiliary Feedwater Pumps, (ML24263A145) and inspection report (IR) 05000498/2024050 South Texas Project Electric Generating Station, Units 1 and 2 - NRC Special Inspection Report 05000498/2024050 and 05000499/2024050 and Preliminary White Finding, (ML24320A137).

LER 498-2024-004 2

2.2 Cause The LOOP was caused by a failure of a shunt reactor in the switchyard that resulted in a subsequent fire, a Unit 1 main generator lockout, and loss of power from the north and south switchyard buses. The specific causes of the shunt reactor failure have not been identified yet; the licensee causal analysis is ongoing. The results of the causal analysis will be provided in a future supplement to the LER.

2.3 Sequence of Key Events Table 1 provides the sequence of key events:

Table 1. Sequence of Key Events July 24, 2024 7:02 am Unit 1 reactor trip due to fire in the switchyard. The 345 kilovolt (kV) north bus and the Unit 1 generator tripped. All EDGs automatically actuated and sequenced on a LOOP. The following busses were deenergized: 13.8 kV auxiliary busses 1F, 1G, 1H, and 1J, 13.8 kV standby busses 1F, 1H, and 1G, and 480-volt (VA) load center 1W. All four RCPs lost power.

7:03 am Report of explosion and fire in the switchyard. Plant entered off-normal procedure 0POP04-ZO-0008, Fire/Explosion.

7:35 am Operators verified natural circulation with manually opened SG PORVs.

9:25 am Fire in shunt reactor RT-2 is extinguished.

9:53 am SG PORV 1C declared inoperable and nonfunctional due to not operating in automatic or manual from the main control room (MCR).

10:54 am Energized 13.8 kV standby bus 2G from 13.8 kV auxiliary bus 2G.

12:12 pm Energized 345 kV south bus and standby transformer 2.

12:23 pm Closed 4.16 kV ESF bus E2B supply breaker. Energized 13.8 kV standby bus 1F from standby transformer 2.

12:37 pm Energized 13.8 kV auxiliary bus 1F from 13.8 kV standby bus 1F.

12:49 pm Energized 13.8 kV auxiliary bus 1J from standby transformer 2.

1:46 pm Started RCP 1D.

2:21 pm Energized 13.8kV standby bus 1G from standby transformer 2.

2:29 pm Energized 13.8 kV auxiliary bus 1G from 13.8 kV standby bus 1G.

2:42 pm Energized 4.16 kV ESF bus 1D1; offsite power fully restored to Unit 2.

3:02 pm Energized 13.8 kV standby bus 1H from standby transformer 2.

3:08 pm Energized 13.8 kV auxiliary bus 1H from 13.8 kV standby bus 1H.

July 25, 2024 12:57 am Switchyard breakers Y0520 and Y0510 closed. Unit 1 main and auxiliary transformers are energized.

3:05 am Restored offsite power to 4.16 kV ESF bus E1B.

5:14 am Restored offsite power to 4.16 kV ESF bus E1C.

9:33 am Restored offsite power to 4.16kV ESF bus E1A; offsite power fully restored to Unit 1.

LER 498-2024-004 3

3 MODELING 3.1 SDP Results/Basis for ASP Analysis The Accident Sequencer Precursor (ASP) Program performs independent analyses for initiating events. ASP analyses of initiating events account for all failures/degraded conditions and unavailabilities (e.g., equipment out for maintenance) that occurred during the event, regardless of licensee performance.1 In response to this event and the May 12th Unit 2 partial LOOP event, including repetitive issues associated with the SG PORVs, the NRC performed a special inspection per Management Directive 8.3, NRC Incident Investigation Program (ML18073A200). The results of this special inspection are documented in IR 05000498/2024050. Two Green findings associated with licensee failure to report the Unusual Event within the required time limits during the July 24th LOOP were identified. The other findings identified as part of the special inspection were associated with the May 12th Unit 2 partial LOOP; however, there are two unresolved issues associated with the repetitive SG PORV failures and the cause of the fire in shunt reactor RT-2. The LER remains open. A search of LERs identified LER 498-2024-006, Condition Prohibited by Technical Specifications and Potential Loss of Safety Function Due to Inoperable Pressurizer PORV, (ML24358A097) as a windowed event. The unavailability of pressurizer PORV 656A to operate manually is modeled explicitly in this analysis.

3.2 Analysis Type An initiating event analysis was performed using a test and limited use revision of the version 8.80 SPAR model for South Texas Project, Unit 1 created on August 27, 2024. Note that an evaluation of the partial LOOP that occurred at Unit 2 is not included in this analysis. Past ASP evaluations have shown that shorter-term partial LOOPs where no reactor trip occurs result in an increase in core damage probabilities that are below the 1x10-6 precursor threshold for degraded conditions.

The following SPAR model changes were made to support this analysis:

Credit for other steam pathways (in addition to the SG PORVs) for decay heat removal (e.g., steam dumps and SG safety valves) were provided.

The pressurizer PORV success criteria for feed and bleed cooling was changed to 1 out of 2 valves based on a review of thermal-hydraulic calculations for South Texas Project.

Event tree and fault trees associated with crediting of the FLEX mitigation strategy were revised based on a review of the South Texas Project final integrated plan. In addition, FLEX credit was activated to support this analysis.2 The reactor coolant system (RCS) pressure relief success criteria given an anticipated transient without scram (ATWS) were modified based on a review of thermal-hydraulic calculations for South Texas Project. Specifically, either both pressurizer PORVs or safety valves are required to operate to ensure that RCS pressure does not exceed 3200 psi.

1 ASP analyses also account for any degraded condition(s) that were identified after the initiating event occurred if the failure/degradation exposure time(s) overlapped the initiating event date.

2 Credit for the FLEX mitigation strategies is deactivated in the base SPAR models.

LER 498-2024-004 4

Corrections were made to the AFW electrical room cooling fault tree.

3.3 SPAR Model Modifications The following additional SPAR model modifications were made to support this analysis:

Use of Common-Cause Failure (CCF) Parameters Derived from Component-Specific Priors. The existing CCF parameters used in the SPAR models are derived using a single generic prior that includes CCF events from all components, failure modes, and causes. Since different component types and different failure causes could lead to drastically different alpha factors, the above usage of a single generic prior could result in significant uncertainty in the CCF parameter estimates. Given the uncertainties associated with using a single generic CCF prior in estimating the existing CCF parameters, prior distributions were derived for five component categories(a.) pumps, (b.) valves, (c.) strainers, (d.) EDGs, and (e.) other equipment (e.g., transformers, breakers, fans, heat exchangers, etc.). A new set of alpha factors for each applicable component and failure mode type were then calculated via a Bayesian update using the same 15-year period of CCF data (i.e., 2006-2020) as those used for the existing CCF parameter estimates.3 A review of the preliminary results indicated both EDG CCF basic events (EPS-DGN-CF-FR and EPS-DGN-CF-FS) and CCF of the 4.16 kV ESF bus feeder circuit breakers to open (EPS-CRB-CC-E1C1) could have a significant impact to the risk of this degraded condition. Therefore, the existing alpha factors for these CCF basic events were substituted using those derived from the applicable component-specific priors in the base South Texas Project SPAR model as shown in the following table:

Table 2. Applicable CCF Parameters Derived from EDG Component-Specific Prior CCF Template Event CCCG Alpha Factor 2020 CCF Parameters Generic Prior 2020 CCF Parameters Component-Specific Priors a

b Mean a

b Mean Mean EPS-EDG-FR-03A01 3

1 2.22E+02 3.25E+00 9.86E-01 3.11E+02 3.21E+00 9.90E-01 0.4%

EPS-EDG-FR-03A02 3

2 2.47E+00 2.23E+02 1.10E-02 2.38E+00 3.12E+02 7.58E-03

-31.1%

EPS-EDG-FR-03A03 3

3 7.83E-01 2.24E+02 3.48E-03 8.26E-01 3.13E+02 2.63E-03

-24.4%

EPS-EDG-FS-03A01 3

1 2.88E+02 2.13E+00 9.93E-01 3.77E+02 2.08E+00 9.95E-01 0.2%

EPS-EDG-FS-03A02 3

2 1.35E+00 2.89E+02 4.66E-03 1.26E+00 3.78E+02 3.33E-03

-28.5%

EPS-EDG-FS-03A03 3

3 7.77E-01 2.89E+02 2.68E-03 8.20E-01 3.78E+02 2.16E-03

-19.4%

ACP-CRB-4160-FTOC-03A01 3

1 1.28E+02 1.13E+00 9.91E-01 2.43E+02 1.38E+00 9.94E-01 0.3%

ACP-CRB-4160-FTOC-03A02 3

2 8.51E-01 1.28E+02 6.59E-03 1.17E+00 2.43E+02 4.79E-03

-27.3%

ACP-CRB-4160-FTOC-03A03 3

3 2.77E-01 1.29E+02 2.14E-03 2.09E-01 2.44E+02 8.55E-04

-60.0%

The CCF basic events where (a.) the CCF parameters derived from component-specific priors are nearly the same as the existing parameters and/or (b.) adjustments are unlikely to result in a significant impact on the overall CDP were not modified. For example, the CCF basic events associated with the EDG and AFW room cooling fans 3

These revised alpha factors (including comparisons with the existing CCF parameters used in the SPAR model) are provided on the publicly available Reactor Operational Experience Results and Databases Webpage.

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are present in the dominant cut sets for this analysis. However, the CCF parameters used for these CCF basic events are generic demand (failure to start) and rate (failure to run) parameters, which are nearly identical to the existing CCF parameters because the same generic CCF prior is used.

Modeling of FLEX Diesel Generators (DGs). South Texas Project has two FLEX DGs permanently mounted in separate, protected rooms (one room for each DG) on the roofs of each unit. It is relatively straightforward (i.e., breaker and switch manipulations) for operators to connect and start these DGs to restore charging to the safety-related batteries. To account for these differences, the FLEX-480 (FLEX diesel is operable and connected to buses) fault tree was modified to include the two FLEX DGs (i.e., existing FLEX-DG1 and FLEX-DG2 subtrees) under existing AND gate FLEX-4802. The FLEX-48012 OR gate and associated logic was deleted. The modified FLEX-480 fault tree is provided in Figure B-1 of Appendix B.

3.4 Analysis Assumptions The following modeling assumptions were determined to be significant for this analysis:

The probability of IE-LOOPSC (loss of offsite power - switchyard centered) was set to 1.0 because a switchyard centered LOOP occurred. All other initiating event probabilities were set to zero.

Basic event PPR-PRV-CC-PCV656 (PORV PCV-656 fails to open on demand) was set to TRUE due inability of PORV 656A to be manually opened during the event.4 A sensitivity calculation shows that this failure results an increase to the mean CCDP of approximately 5 percent.

Basic event MSS-ARV-CC-7431 (failure of SG 3 ARV-7431) was set to TRUE because SG PORV 1C failed to operate in automatic or manual from the MCR.

Offsite Power Recovery. The time required to restore offsite power to plant emergency equipment is a significant factor to the CCDP given a LOOP. The LOOP/SBO modeling within the SPAR models includes various sequence-specific power recovery factors that are based on the time available to recover offsite power to prevent core damage. For example, the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> available for accident sequences involving failure of decay heat removal (e.g., postulated SBO with a failure of the turbine-driven AFW pump) typically has a significant risk impact.

The two offsite power recovery times that also typically have a significant risk impact are the normal and extended SBO coping times. These times are associated with the depletion times of the safety-related batteries. At South Texas Project, the normal battery depletion time is 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. If an extended loss of AC power (ELAP) is declared, operators will perform a deep direct current (DC) load shed that will extend the battery depletion time to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Offsite power was recovered to the first Unit 1 ESF bus approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after the LOOP initiating event occurred. However, offsite power could have been restored to an ESF bus sooner. During a postulated SBO, the emergency operating procedures (EOPs) 4 This basic event fails both manual and automatic functions of the PORVs. However, the automatic pressure relief function is not a significant risk contributor to this analysis and, therefore, no modifications were needed for this analysis.

LER 498-2024-004 6

direct the operators to reenergize an ESF safety bus via the 138-kV emergency transformer. The licensee determined that offsite power remained available from the 138 kV transmission line via the emergency transformer and this offsite source could have provided power to an ESF bus during the event. Therefore, an Integrated Human Event Analysis System for Event and Condition Assessment (IDHEAS-ECA) evaluation of the offsite power recovery human failure events (HFEs), including the calculated human error probabilities (HEPs), is provided in Table 3:Table 3. IDHEAS-ECA Evaluation of Offsite Power Recovery HFEs HFE Definition Operators fail to reenergize an ESF bus from the 138-kV emergency transformer prior to core damage. This entire HFE is considered as a single critical task within the IDHEAS-ECA framework.

Scenario Description/

Event Context A switchyard LOOP initiating event occurs resulting in an automatic reactor trip.

Boundary Conditions The start of this HFE is when the complete LOOP initiating event resulting in an automatic reactor trip occurs (i.e., t = 0). The SBO is conservatively assumed to begin at the same time (i.e., all EDGs are assumed to fail at t = 0). The end of this HFE is successful recovery of offsite power to an ESF bus via the emergency transformer prior to core damage.

Success Criteria Operators successfully recover offsite power to an ESF bus via the emergency transformer prior to core damage.

Key Cue(s)

- Annunciators associated with loss of offsite power supply lines

- Annunciators associated with EDG and/or alternate AC source failures

- Safety-related bus voltages Procedural Guidance

- 0POP05-EO-EO00, Reactor Trip or Safety Injection

- 0POP05-EO-EC00, Loss of All AC Power CFM Selection Detection - This task requires the operators to detect the alarms and annunciators associated with LOOP initiating event and subsequent SBO.

Understanding - This task requires the operators to understand that that given a LOOP/SBO, the recovery of offsite power to ESF bus is needed to ensure decay heat removal and RCS inventory control.

Decisionmaking - Decisionmaking is not required for this task because procedures direct operators to reenergize an ESF bus from the emergency transformer given an SBO.

Action Execution - This task requires the operators to manually reenergize an ESF bus from the emergency transformer. This action is accomplished by breaker and disconnect checks/manipulations. All execution steps are performed from the MCR.

Interteam Coordination - Interteam coordination is not required for this task because multiple teams would not be involved. Therefore, this CFM is not applicable for this task.

Evaluation of PIFs for Applicable CFMs CFM1 -Failure of Detection (Base Probability = 1x10-4)

- Scenario Familiarity - No impact because operators are routinely trained on LOOP/SBO scenarios. In addition, this critical task is covered by plant procedures.

- Task Complexity - Although the context for the HFE would include a reactor trip, turbine trip, multiple system failures, and accompanying alarm conditions, these

LER 498-2024-004 7

signals all arise from the same underlying condition and are not considered to be competing. Therefore, there is no impact because the detection of SBO is obvious because: (a.) the alarms and annunciators are reinforcing in nature, (b.) additional cues (e.g., significant reduction in plant noise) further aids operators in diagnosis that an SBO occurred, and (c.) plant procedures direct the operators to check AC power status. Note the collection of information on the status of offsite power and alternate AC power sources (e.g., EDGs) is considered in the Understanding CFM.

- The other PIFs were determined to have a negligible impact on the base case HFE.

CFM2 - Failure of Understanding (Base Probability = 1x10-3)

- Scenario Familiarity - No impact because operators are routinely trained on LOOP/SBO scenarios. In addition, this critical task is covered by plant procedures.

- Information Completeness and Reliability - No impact because plant procedures require operators reenergize an ESF bus from the emergency transformer during a LOOP/SBO. Note that the MCR crew will need to contact the transmission and distribution line operators to determine if offsite power is available to the emergency transformer, this information is not necessary to understand the procedurally directed action to reenergize an ESF bus prior to core damage.

- Task Complexity - No impact because plant procedures direct operators to reenergize an ESF bus from the emergency transformer during a LOOP/SBO.

- The other PIFs were determined to have a negligible impact on the base case HFE.

CFM4 - Failure of Action Execution (Base Probability = 1x10-4)

- Scenario Familiarity - No impact because the execution steps are routinely trained.

- Task Complexity - No impact because the execution steps are straightforward (i.e., MCR switch manipulations) and proceduralized.

- The other PIFs were determined to have a negligible impact on the base case HFE.

Using these assumptions, Pc is calculated as 1.2x10-3 by summing the probabilities of CFM1 (1x10-4), CFM2 (1x10-3), and CFM4 (1x10-4).

Timing Evaluation The most limiting LOOP/SBO scenarios are those where a subsequent loss of decay heat removal (provided by AFW) or a loss-of-coolant accident (LOCA) occurs. In these scenarios, operators would have approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to restore offsite power and restore either decay heat removal or provide RCS inventory makeup. It will take operators approximately 10 minutes to get through the initial EOP steps to where they are directed to reenergize an ESF bus from the emergency transformer. Therefore, Tavail is approximately 50 minutes. It is estimated that it would take operators approximately 10 minutes to perform the require breaker and disconnect checks/manipulation required to reenergize an ESF bus from the emergency transformer. Therefore, Treqd is approximately 10 minutes.

The current IDHEAS-ECA guidance recommends using a lognormal distribution for the time estimates; however, the current IDHEAS-ECA software tool does not have this capability yet. The selection of the Treqd of 5 minutes was assumed to be the median (i.e., 50th percentile) of the lognormal distribution. Tavail of 50 minutes is treated as a single value with no distribution assigned for the base case. No guidance exists for treating the uncertainty associated with Tavail estimates, and it is noted as a key uncertainty for this evaluation. The Pt was calculated using an EF of 2 for the lognormal distribution of Treqd, which is considered to be appropriate for actions performed from the MCR based on a preliminary analysis of timing data MCR operators response to emergency events in nuclear power plant simulators, including NUREG/IA-0216, International HRA Empirical Study - Phase 1 Report: Description of

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Therefore, the probabilities associated with the following offsite power recovery basic events were set to 1x10-3:

- OEP-XHE-XL-N01HSC (operator fails to recover offsite power in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (switchyard)),

- OEP-XHE-XL-N02HSC (operator fails to recover offsite power in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (switchyard)),

- OEP-XHE-XL-N04HSC (operator fails to recover offsite power in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (switchyard)),

- OEP-XHE-XL-NR04HSC1 (operator fails to recover offsite power in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (switchyard) given failure at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />),

- OEP-XHE-XL-N06HSC (operator fails to recover offsite power in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (switchyard)),

- OEP-XHE-XL-NR08HSC (operator fails to recover offsite power in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (switchyard)), and

- OEP-XHE-XL-NR08HSC1 (operator fails to recover offsite power in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (switchyard) given failure at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />).

Basic event OEP-XHE-XL-NR24HSC (operator fails to recover offsite power in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (switchyard)) was set to TRUE because DC power will be unavailable for the required breaker manipulations to restore offsite power to an ESF bus after the safety-related batteries are depleted.

4 ANALYSIS RESULTS 4.1 Results The mean CCDP for this analysis is calculated to be 3.6x10-6. The ASP Program threshold for initiating events is a CCDP of 10-6 or the plant-specific CCDP of an uncomplicated reactor trip with a non-recoverable loss of feedwater and the condenser heat sink, whichever is greater.

This CCDP equivalent for South Texas Project is 7.3x10-7. Therefore, this event is a precursor.

The parameter uncertainty CCDP results are provided in the table below:

Overall Approach and Pilot Phase Results from Comparing HRA Methods to Simulator Performance Data (ML093380283), NUREG-2156, The U.S. HRA Empirical Study:

Assessment of HRA Method Predictions against Operating Crew Performance on a U.S. Nuclear Power Plant Simulator (ML16179A124), EPRI NP-6937-L, Operator Reliability Experiments Using Power Plant Simulators, and simulator data from other sources. This selection results in a Pt of 6.7x10-5. Therefore, Pt is a negligible contributor to the overall HEPs for all HFEs associated with offsite power recovery. A sensitivity calculation using an EF of 3, which is considered bounding for MCR actions, results in a Pt of 8x10-3 and an overall HEP of 9x10-3. A sensitivity calculation using this HEP for the 1-hour offsite power recovery basic event results in a 7 percent increase in the mean CCDP. At the time of completing this analysis, the guidance on specifying the uncertainty bounds for time estimates in IDHEAS-ECA has not been finalized.

Recovery Recovery credit is not provided for this task.

Calculated HEP HEP = 1 (1 Pc) (1 Pt) = 1 (1 - 1.2x10-3) (1 - 6.7x10-5) = 1x10-3

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Table 4. Parameter Uncertainty Results 5%

Median Point Estimate Mean 95%

9.6x10-7 2.9x10-6 3.2x10-6 3.6x10-6 8.7x10-6 4.2 Dominant Sequences5 The dominant accident sequence is switchyard centered LOOP sequence 21 (CCDP =

2.8x10-6), described in the following table, contributes approximately 87 percent of the total CCDP. No other sequences contribute at least 5 percent to the total CCDP. The event tree with the dominant sequence is shown graphically in Figure A-1 of Appendix A.

Table 5. Dominant Sequence Sequence CCDP Description LOOPSC 21 2.8x10-6 87.0%

Switchyard-centered LOOP initiating event occurs; emergency power system is successful; AFW fails; and feed and bleed cooling fails resulting in core damage.

4.3 Key Uncertainties A review of the analysis assumptions and results did not reveal key modeling uncertainties other than those associated with the use of IDHEAS-ECA to calculate the HEPs for offsite power recovery.

5 The CCDPs presented in this section are point estimates.

LER 498-2024-004 A-1 Appendix A: Key Event Tree Figure A-1. Switchyard Centered LOOP Event Tree IE-LOOPSC LOSS OF OFFSITE POWER INITIATOR (SWITCHYARD-CENTERED)

RPS REACTOR TRIP EPS FS = FTF-LOOP EMERGENCY POWER AFW AUXILIARY FEEDWATER PORV PORVS ARE CLOSED LOSC RCP SEAL COOLING MAINTAINED HPI HIGH PRESSURE INJECTION FAB FEED AND BLEED OPR-02H OFFSITE POWER RECOVERY IN 2 HRS OPR-06H OFFSITE POWER RECOVERY IN 6 HRS SSC SECONDARY SIDE COOLDOWN RHR RESIDUAL HEAT REMOVAL LPR LOW PRESSURE RECIRC FAILS CFC CONTAINMENT FAN COOLERS HPR HIGH PRESSURE RECIRC End State (Phase - CD)

AFW-L 1

OK LOSC-L 2

LOOP-1 PORV-L HPI-L 3

OK 4

OK 5

OK 6

CD 7

CD 8

OK 9

CD 10 CD CFC-L 11 OK HPR-L 12 CD CFC-L 13 CD HPI-L 14 CD AFW-L FAB-L 15 OK 16 CD 17 CD CFC-L 18 OK HPR-L 19 CD CFC-L 20 CD FAB-L 21 CD 22 SBO 23 ATWS 24 CD

LER 498-2024-004 B-1 Appendix B: Modified Fault Tree Figure B-1. Modified FLEX-480 Fault Tree

LER 498-2024-004 C-1 Appendix C: NRC Response to Licensee Comments The NRC provided the licensee, STP Nuclear Operating Company, the preliminary ASP analysis for an opportunity to provide any feedback before the analysis was finalized. STP provided the following response:

By email dated January 21, 2025, the results of NRCs ASP analysis were provided as an attachment to that email. The email stated that licensees are provided a period of 30 days to formally comment on the ASP preliminary analysis and any input received during this period will be considered prior to finalizing the ASP analysis. No response is required by the licensee; however, any information provided will aid in determining the best estimate of the risk associated with this event.

The purpose of this email is to communicate to the NRC that the 138 kV STP Offsite power source for the ESF buses via the emergency transformer, which is available for emergency response and use in the PRA, but is not credited for technical specifications compliance, remained available to power an ESF bus should that have been needed for the duration of the event. STP has procedures and training in place for its use. This power source is shown at the top center section of the attached design drawing. This information was not mentioned in the preliminary ASP analysis provided in the original email.

After discussions with Region 4 staff and additional information provided by the licensee, credit for offsite power recovery via the emergency transformer was provided in the final analysis. See Section 3.4 for additional information.