IR 05000382/2025093
| ML25219A705 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 08/11/2025 |
| From: | John Dixon NRC/RGN-IV/DORS/PBD |
| To: | Sullivan J Entergy Operations |
| Sanchez A | |
| References | |
| IR 2025093 | |
| Download: ML25219A705 (1) | |
Text
August 11, 2025
SUBJECT:
WATERFORD STEAM ELECTRIC STATION, UNIT 3 - FINAL SIGNIFICANCE DETERMINATION OF A GREEN FINDING AND NON-CITED VIOLATION; NRC INSPECTION REPORT 05000382/2025093
Dear Joseph Sullivan:
This letter provides you with the final significance determination of the preliminary White finding discussed in our previous communication dated June 23, 2025, which included Inspection Report 05000382/2025092, Agencywide Documents Access and Management System (ADAMS) Accession No. ML25168A320. The finding involved the failure to develop and implement a replacement preventive maintenance strategy for relays in the emergency diesel generators (EDG), which resulted in the inoperability of EDG A and incurred unplanned risk during the extended outage.
You provided a written response to the U.S. Nuclear Regulatory Commission (NRC) dated July 30, 2025, to discuss your views on this issue (ML25211A356). In your written response, your staff described your assessment of the significance of the finding and the corrective actions taken to resolve it.
After considering the information developed during the inspection and the information presented in your written response, the NRC has concluded that the items that you raised for consideration to be included in the NRC SPAR model version 8.81 are generally applicable and should be reflected in the risk evaluation. These items included: (1) more appropriate failure-to-run probabilities for permanently installed FLEX components, (2) elimination of concurrent success criteria for steam generator injection and reactor coolant system makeup using the same pump, (3) realistic time-based convolution of turbine driven emergency feedwater failures-to-run for 24-hour scenarios with an associated offsite power recovery, (4) 24-hour mission time limit for FLEX sequences, and (5) shutdown credit and event initiator modeling for hurricane scenarios.
The enclosed revised risk evaluation includes consideration of these modeling issues. Based on this revised evaluation, the NRC has concluded that the finding is appropriately characterized as Green, a finding of very low safety significance. This finding involved a violation of NRC requirements, the circumstances of which are described in detail in inspection report 05000382/2025092. We are treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.
The NRC has concluded that information regarding: (1) the reason for the violation, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken, and (4) the date when full compliance will be achieved is already adequately addressed on the docket in Inspection Report 05000382/2025092 and in your letter dated July 30, 2025. Therefore, you are not required to respond to this letter unless the description therein does not accurately reflect your corrective actions or your position. Item 05000382/2025092-01 is closed.
If you contest the violation or the significance or severity of the violation documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; and the NRC Resident Inspector at Waterford Steam Electric Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the NRC Resident Inspector at Waterford Steam Electric Station.
In accordance with 10 CFR 2.390 of the NRCs Agency Rules of Practice and Procedure, a copy of this letter, its enclosure, and your response will be made available electronically for public inspection in the NRC Public Document Room and from the NRCs ADAMS, accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the public without redaction.
If you have any questions concerning this matter, please contact me at 817-200-1574.
Sincerely, John L. Dixon, Jr., Chief Reactor Projects Branch D Division of Operating Reactor Safety Docket No. 05000382 License No. NPF-38 Enclosure: Revised Detailed Risk Evaluation cc w/ encl: Distribution via LISTSERV Signed by Dixon, John on 08/11/25
ML25219A705 SUNSI Review:
ADAMS:
Non-Publicly Available Non-Sensitive Keyword:
By: AAS Yes No Publicly Available Sensitive OFFICE ES:ACES SRI:DORS/PBD RI:DORS/PBD TL:ACES RC NAME ARoberts KChambliss KCook-Smith BAlferink DCylkowski SIGNATURE
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DATE 08/08/25 08/07/25 08/11/25 08/08/25 08/11/25 OFFICE D:DORS C:DORS/PBD SRA:DORS SPE:DORS/PBD NAME GMiller JDixon CYoung ASanchez SIGNATURE
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DATE 08/11/25 08/11/25 08/11/25 08/08/25
Enclosure Revised Detailed Risk Evaluation Plant Name/Unit Number: Waterford 3 Inspection Report #: 2025-093 Enforcement Action #: EAF-RIV-2025-0126 BACKGROUND On December 11, 2024, emergency diesel generator (EDG) A was declared inoperable due to oscillations in output voltage and frequency that were observed during scheduled testing.
Subsequent troubleshooting through December 22, 2024, revealed faults associated with the automatic voltage regulator K4 relay. Following corrective maintenance, EDG A was restored to an operable condition on December 24, 2024.
PERFORMANCE DEFICIENCY The failure to develop and implement a replacement preventive maintenance strategy for the K4 relay in EDG A was a performance deficiency.
IMPACT ON SAFETY FUNCTION(S)
The analyst assumed that the performance deficiency resulted in a degraded condition where the EDG A would not have been capable of performing its design basis function for its PRA mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The safety function provided by the EDG would be necessary to mitigate any design basis event that includes a loss of offsite power (LOOP) condition.
EXPOSURE TIME The analyst reviewed results of previous surveillance testing of the EDG A conducted on November 20, 2024. The analyst assumed that reasonable assurance existed as of November 20, 2024, that the capability of the EDG A to perform its required safety function would not have been affected by the degraded condition that was subsequently revealed during the December 11 testing. The analyst assumed that a T/2 exposure time for the degraded condition would be applicable for the total T time of 21 days from November 20 to December 11. The analyst determined that a total exposure time of 10.5 days (i.e., a T/2 period) plus 13 days of repair time would be applicable for this analysis.
INFLUENTIAL ASSUMPTIONS
The analyst assumed that the performance deficiency resulted in the EDG A being in a condition where it would have failed to load and run for its required mission time during an applicable design basis event during the 10.5-day T/2 exposure time discussed above, with applicable impacts on common cause failure.
- For station blackout (SBO) sequences involving this EDG A failure condition, the analyst assumed that the safety function of the EDG A would not be recoverable.
- The analyst assumed that the use of Diverse and Flexible Coping (FLEX) Strategies for station blackout (SBO) events should be credited.
MODELING APPROACH The Waterford SPAR Model version TLU15 (based on version 8.81) along with SAPHIRE software version 8.2.11 were used for the evaluation. Using the events and conditions
assessment (ECA) workspace, the analyst determined that the risk impact of degraded condition described above would be most appropriately modeled by setting the basic event EPS-DGN-LR-DG3A (Diesel Generator 3A-S Fails to Load Run) to TRUE for the 10.5-day T/2 exposure time discussed above and by setting the basic event EPS-DGN-TM-DG3A (DG 3A-S Unavailable Due to Test and Maintenance) to TRUE for the actual 13-day outage period involving troubleshooting and corrective maintenance. Additionally, the analyst set the following basic events to FALSE to eliminate inappropriate combinations of testing/maintenance events during the 13-day maintenance period:
EPS-DGN-TM-DG3B (DG 3B-S Unavailable Due to Test and Maintenance)
EPS-DGN-TM-TEDG (Temporary Emergency Diesel Generator Unavailable Due to Test and Maintenance)
EPS-FAN-TM-3BSB (DG 3B Room Fan 3B-SB Unavailable Due to Test and Maintenance)
EFW-MDP-TM-B (EFW MDP B Unavailable Due to Test and Maintenance)
EFW-TDP-TM-AB (EFW TDP A/B Unavailable Due to Test and Maintenance)
To credit the use of FLEX during both of these time periods, the analyst adjusted the basic event FLX-XHE-XE-ELAP (Operators Fail to Declare ELAP When Beneficial) probability to 1.0E-2 for both the nominal and conditional cases.
The analyst also modified the fault trees EPS-DG3AS (Failure of Diesel Generator 3A-S) and EPS-DG3BS (Failure of Diesel Generator 3B-S) to include an additional baseline common cause failure event EPS-DGN-CF-LR (Common Cause Failure of Diesel Generators to Load Run). Given the troubleshooting and corrective maintenance involved with restoring the EDG A to a functional condition following this failure, the analyst determined that no recovery credit would be applicable to model for the case of a design basis event.
Based on a review of licensee operating procedures that do not allow the stations Permanent Temporary Emergency Diesel (PTED) to be in a non-functional condition for maintenance or testing purposes concurrently with either the A or B EDG, the analyst also added event tree post-processing rules to identify and eliminate cutset results containing mutually exclusive testing/maintenance conditions consisting of the basic event EPS-DGN-TM-TEDG (Temporary Emergency Diesel Generator Unavailable Due To Test and Maintenance) together with any of the following: EPS-DGN-TM-DG3A, EPS-DGN-TM-DG3B, EPS-FAN-TM-3ASA, or EPS-FAN-TM-3BSB.
The analyst noted that the basic events EPS-DGN-FS-TEDG (Temporary Emergency Diesel Generator Fails to Start), EPS-DGN-FR-TEDG (Temporary Emergency Diesel Generator Fails to Run), and EPS-DGN-LR-TEDG (Temporary Emergency Diesel Generator Fails to Load Run)
included failure data consistent with EDG failure data from Table 61 of Reference 1. The analyst determined that the modeled PTED failure probabilities should more appropriately be consistent with failure data from Table 69 for SBO generators. The analyst implemented the applicable updates to the failure probabilities reflected in the PTED failure basic events.
The analyst noted that the basic events FLX-DGN-FS-DG1 (FLEX DG1 Fails to Start) and FLX-DGN-FR-DG1 (FLEX DG1 Fails to Run) included failure data consistent with Portable Diesel Generator failure data from Table 6-1 of Reference 2. The analyst considered the configuration of the N FLEX DG of being permanently installed in the reactor auxiliary building, as well as licensee maintenance and testing practices, and determined that the modeled N FLEX DG failure probabilities should more appropriately be consistent with failure data from Table 69 of
Reference 1 for SBO generators. The analyst implemented the applicable updates to the failure probabilities reflected in these FLEX DG failure basic events.
The analyst noted that the basic events FLX-EDP-FR-SGP (FLEX SG Pump 1 Fails to Run) and FLX-EDP-FS-SGP (FLEX SG Pump 1 Fails to Start) reflected failure probabilities from Reference 2 associated with portable engine-driven pumps used for FLEX functions. The analyst reviewed the stations FLEX implementation strategies and associated equipment and noted that the N FLEX pump that would fulfill this function of steam generator injection is a motor-driven pump that is permanently staged in the reactor auxiliary building. The analyst determined that a lower best estimate probability for the basic event FLX-EDP-FR-SGP, with a default value of 3.106E-1, would be applicable. The analyst applied a value of 1.0E-1 for use in this analysis.
From a review of the licensees FLEX implementation procedures, the analyst noted that the FLEX-MUP (Boron Injection and RCS Makeup with FLEX Pump) function can be implemented using the stations installed charging pumps powered from a FLEX generator. The analyst updated the probabilities for the basic events FLX-EDP-FS-MUP (FLEX RCS Makeup Pump 1 Fails to Start) and FLX-EDP-FR-MUP (FLEX RCS Makeup Pump 1 Fails to Run) to values of 8.0E-4 and 2.0E-4, respectively, to reflect the use of a charging pump for this FLEX function.
The analyst noted that a modeled Extended Loss of AC Power (ELAP) event in which all on-site FLEX functions were successful included a core damage outcome if all of the following actions failed at the 72-hour point in the event: a) recover an offsite power source, b) recover an emergency diesel generator power source, or c) align and operate additional FLEX equipment delivered from a Strategic Alliance for FLEX Emergency Response (SAFER) facility. The analyst noted that this failure criteria included the basic event ACP-XHE-XA-ALTERNATE, which represents a failure to install and align SAFER AC power equipment. The analyst determined that the modeled failure probability of 3E-1 for this action was likely overly conservative. The analyst included a failure probability of 1E-1 for this analysis.
The analyst also noted that core damage sequences were modeled wherein a core damage result was reached if offsite power recovery was not accomplished within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for a LOOP or SBO event with failure of the emergency feedwater (EFW) function. The analyst noted that this 1-hour time to recover offsite power would be overly conservative in cases where an EFW failure was due to a failure-to-run condition, which could occur at any point during a 24-hour mission time. Any initial success of the EFW function would result in extended time available to recover offsite power prior to reaching a core damage state. To offset this conservatism, the analyst modified the SPAR model to include a convolution factor to reduce the risk contribution from sequences that include a turbine-driven EFW failure-to-run event and that do not already include a convolution adjustment from EDG failure-to-run event(s).
INTERNAL EVENTS RESULTS With the assumptions and modeling approach described above, the analyst obtained an increase in average annual core damage frequency (delta-CDF) result of 2.84E-7/year associated with internal events.
EXTERNAL EVENTS RESULTS The increase in risk associated with external events was also evaluated. Using the same modeling approach as described above for internal events, the analyst evaluated the risk contribution from the external events modeled in SPAR, which included hurricane (HCN),
tornado, high straightline winds (HWD), and seismic events. The analyst obtained a total result of 4.07E-7/year for delta-CDF associated with these external events. The analyst noted that 96% of this total external event risk contribution came from HCN events (2.40E-7, or 59%) and HWD events (1.50E-7, or 37%). External event risk contributions are further addressed in the qualitative considerations and sensitivity analyses sections below.
Table 1.
External Risk Category Delta-CDF (/yr)
%
Hurricane Events 2.40E-7 59%
HWD Events 1.50E-7 37%
Tornado + Seismic Events 1.72E-8 4%
External Event Total 4.07E-7 100%
Since the SPAR model did not include modeling of fire events, the analyst determined that best available information associated with the risk attributable to fire events would be obtained from the analysts review of the licensees fire PRA model results for this condition. Based on this review, as further discussed below in the licensee results section, the analyst concluded that the increase in risk for this condition associated with fire events was best estimated to be a delta-CDF of 6.17E-7/year.
DOMINANT SEQUENCES Dominant sequences contributing to the delta-CDF results for internal events involved LOOP events with failure of the EDG function (i.e., SBO events) and either: 1) failure to recover either offsite electrical power (OEP) or EDG function within two hours (i.e., ELAP events) and with FLEX strategy failures, or 2) failure of the EFW function. For external events, these same dominant sequence types resulted from hurricane and high wind event initiators.
LARGE EARLY RELEASE FREQUENCY The significance of the impact of the finding on large early release frequency (LERF) was also evaluated. The analyst evaluated the increase in LERF using Inspection Manual Chapter (IMC) 0609, Appendix H, Containment Integrity Significance Determination Process. The finding was treated as a Type A finding because it could influence the likelihood of accidents leading to core damage as well as being a contributor to LERF. Additionally, the finding was evaluated for potential increase in the likelihood of a consequential steam generator tube rupture (C-SGTR).
The analyst reviewed all sequences contributing to delta-CDF for any elements affecting LERF.
The analyst identified sequences in which the EFW function failed as representing additional core damage sequences (i.e., in addition to the plants corresponding baseline CDF risk) that involve High-Dry-Low (HDL) conditions, which have the potential to result in a C-SGTR. The analyst assumed a C-SGTR conditional probability of 2E-1 would be applicable for this category of sequences, consistent with guidance from NUREG-2195. Application of an assumed LERF factor of 1.0 per IMC 0609 Appendix H screening guidance would result in delta-LERF results of
1.60E-8/year for internal events and 1.72E-8/year for external events (not including HWD events or Fire events). The analyst assumed that 1E-11 would be a more appropriate screening value for an average LERF factor that would be applicable for this category of sequences involving a SGTR condition. Application of this factor to the total delta-CDF associated with the applicable sequences described above yielded delta-LERF results of 1.60E-9/year for internal events and 1.72E-9/year for external events (not including HWD events or Fire events). The analyst determined that best available information regarding LERF risk from Fire events and for internal events would be obtained from a review of the licensees LERF modeling results, as discussed below in the Licensee Results section. Overall, the analyst determined that risk attributable to LERF was not a dominant metric in the significance determination for this finding.
QUALITATIVE CONSIDERATIONS The analyst reviewed licensee operations procedure OP-901-521, Severe Weather and Flooding, revision 344, which contains guidance to commence a plant shutdown to Mode 3 between 16 and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> prior to the projected arrival of hurricane conditions onsite. The analyst noted that this procedure further directs that, following completion of the plant shutdown and at the discretion of plant management, a plant cooldown to Mode 4 with shutdown cooling in service may also be performed. The analyst noted that SPAR at-power PRA modeling applies for plant conditions in Modes 1, 2, 3, and 4, except for when reactor coolant system temperature conditions allow for entry to shutdown cooling (SDC) in Mode 4. The analyst noted that a recent example of a hurricane response occurred in August 2021 with Hurricane Ida making landfall near the plants location. In that event, Waterford 3 achieved shutdown conditions but experienced a LOOP event prior to entry into SDC mode. The analyst considered that risk associated with dominant sequences in this case (i.e., LOOP) would likely be somewhat lower in Mode 3 versus full power operations. To the extent that the licensee may successfully achieve Mode 4 conditions with SDC in service prior to the onset of a hurricane event, that corresponding fraction of the LOOP consequences attributable to the event could be evaluated with a shutdown risk PRA model in lieu of at-power risk. The analyst noted that shutdown risk in this scenario, particularly the risk associated with loss of power to support SDC functions, could still represent substantial risk, especially in an early period of higher decay heat load following a transition to Mode 4 and SDC conditions. Sensitivity Analysis #2 below includes consideration of the portion of total risk that is attributable to HCN-induced events for this condition, including a qualitative determination of the portion of this total that was deemed applicable for inclusion in the best-estimate result of this analysis.
The analyst also considered the basis for the current initiating event frequency (IEF) modeling for the weather-related LOOP (LOOPWR) category of LOOP initiating events in the SPAR internal events model, which includes subcategories of: a) Extreme weather events such as events involving high wind conditions, and b) Severe weather events which includes other types of weather events. The analyst noted that LOOPWR sequences represented a significant portion of internal event dominant sequences for this evaluation. The analyst also noted that external event sequences of HWD and HCN also constituted a significant portion of dominant sequences for this evaluation. The HWD and HCN sequences effectively contributed additional risk due to a LOOPWR initiating event as a result of applying conditional LOOPWR probabilities to the associated IEFs for HWD and HCN events. The analyst determined that this combination of all currently modeled initiating events potentially overestimates the frequency of high wind-related extreme weather-induced LOOP events. After consulting with staff from Idaho National 1 A basis for the selection of this LERF factor screening value is further discussed in Enclosure 3 of NRC Inspection Report 05000382/2024013 (ADAMS ML24228A261).
Laboratory (INL), the analyst determined that an applicable interim adjustment to offset this potential double-counting concern would be to exclude the currently modeled HWD external event contribution from the total risk estimate. This approach is reflected in a sensitivity analysis discussed below and is also reflected in the best estimate results for this evaluation.
Additionally, the analyst noted that the estimated risk contribution from HCN events (see paragraph above as well as Sensitivity Analysis #2 below) may also represent some degree of double-counting with regard to the currently modeled LOOPWR frequency. As such, the best estimate for HCN risk contribution in this analysis may be overconservative.
As referenced in the modeling approach section above, the analyst noted that a core damage sequence involving an ELAP event where all applicable FLEX strategies and functions are successful still resulted in a core damage outcome if another source of AC power (specifically:
either an offsite power supply, and emergency diesel generator, or a SAFER generator) is not restored within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of the event. The analyst noted that these criteria could be considered for exclusion in PRA modeling, given that a 24-hour mission time is generally applicable for mitigating functions modeled in PRA. The analyst calculated that the exclusion of this ELAP core damage sequence involving failures of additional AC power restoration actions at the 72-hour point would result in a reduction of 4.40E-8/year in the total delta-CDF result for this analysis. Although not reflected in the best-estimate quantitative result for this analysis, the analyst noted that this consideration could be applicable as a qualitative consideration.
SENSITIVITY ANALYSES Sensitivity #1:
As discussed above, the analyst determined that the risk contribution from the HWD external event likely represents a double-counting concern corresponding to a portion of the events that are reflected in the currently modeled IEF for LOOPWR internal events. The analyst determined that the exclusion of HWD events from the external event contribution resulted in a reduction of 1.50E-7/year in the total external event risk delta-CDF result.
Sensitivity #2:
Additionally, pursuant to the qualitative consideration discussed above regarding the potential risk increase due to hurricane (HCN) events, the analyst determined that the total risk contribution from HCN events for this evaluation was a delta-CDF of 2.40E-7/year, which represents 93% of the revised total external event risk after exclusion of HWD events, and which reflects an assumption that the impacts of all postulated HCN events are experienced while in an at-power operating condition. The analyst determined that the extent to which this contribution is reflected in the total best-estimate result of this analysis could result in a significance determination result of either Green or White. As discussed above, the analyst considered that some portion of this risk contribution could more appropriately be evaluated as shutdown risk versus at-power risk, corresponding to the likelihood that the station may achieve shutdown conditions, with decay heat removal being provided by the shutdown cooling function, prior to being subject to the impacts of an HCN event.
For reasons referenced above, the analyst determined that at least some portion of the estimated risk contribution from HCN events should be reflected in the best estimate of total risk. The extent to which the above total contribution is included should reflect estimates of two influential factors: 1) the probability that the station may successfully transition to a shutdown cooling condition prior to the onset of the effects of the event, and 2) the extent to which the estimated at-power risk under these circumstances may be reduced if shutdown conditions are
applicable. Based on an application of qualitative estimates for these factors, the analyst concluded that a total HCN risk contribution of 1.44E-7/year should be included in the best-estimate total delta-CDF result for this analysis. This represents a 40 percent reduction from the estimated at-power HCN risk contribution.
Sensitivity #3:
The analyst noted that credit for offsite power recovery (OPR) in the event of an SBO is provided if accomplished within the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the event, prior to a transition to ELAP/FLEX and SBO coping strategies. Based on a review of the licensees SBO, ELAP, and FLEX implementation procedures, the analyst determined that the opportunity for OPR in this scenario could potentially exist for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (contingent on the probability of timeliness and success of deep load shedding actions for one selected train as well as no other associated failures precluding this potential extended DC power availability for the selected train). The analyst evaluated the potential decrease in risk associated with a bounding case involving decreasing the following 2-hour OPR failure probabilities to reflect 12-hour failure probabilities when applied in an SBO event:
OEP-XHE-XL-NR02H (Operator Fails to Recover Offsite Power in 2 Hours)
OEP-XHE-XL-NR02HGR (Operator Fails to Recover Offsite Power in 2 Hours, Grid-Related)
OEP-XHE-XL-NR02HPC (Operator Fails to Recover Offsite Power in 2 Hours, Plant-Centered)
OEP-XHE-XL-NR02HSC (Operator Fails to Recover Offsite Power in 2 Hours, Swyd-Centered)
OEP-XHE-XL-NR02HWR (Operator Fails to Recover Offsite Power in 2 Hours, Weather-related)
Table 2.
Delta-CDF Results (/yr)
Risk Category Before With OPR Adjustment Internal Events 2.84E-07 2.06E-07 HCN Events 2.40E-07 2.40E-07 EQK and TOR Events 1.72E-08 1.72E-08 Totals 5.41E-07 4.63E-07 The analyst noted that the lack of impact of this OPR failure probability shifting on external event results is likely attributable to the fact that OPR failure probabilities modeled for the dominant LOOPWR sequences are relatively independent of time available to perform the action, for the applicable time intervals being considered in this analysis.
The analyst determined that a potential reduction in total risk attributable to this consideration would not, by itself, have the potential to reduce the total risk for this evaluation below the White significance threshold. Of the maximum possible reduction in delta-CDF results for Internal Events of 7.78E-8/yr attributable to this consideration as shown in Table 2 above, the analyst qualitatively assumed that a reduction of 7.00E-8/yr would be included in the best-estimate results for this analysis, as reflected in the results cited below in Table 4. This assumption was based on a qualitative assessment of the factors mentioned above. Specifically, the time period available to implement OPR, relative to the maximum potential available time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, would be reflective of the degree to which all associated actions involving ELAP declaration and SBO coping (e.g., deep load shedding) would be both timely and successful, as well as a dependency on no other failures or complications occurring affecting either: a) the extended availability of the selected train of DC power, or b) DC power necessary for offsite power recovery actions.
LICENSEE RESULTS The analyst reviewed risk assessment results provided by the licensee from the use of the licensees PRA model for the categories of internal events (internal flood) and fire events. These results, summarized in Table 3 below, reflected a failure-to-start condition for the EDG A for an exposure time of 10.5 days (with applicable common cause failure implications) together with a test/maintenance condition for the EDG A for an exposure time of 13 days. The analyst determined that the Fire risk results obtained from the licensees PRA model represented best available information for use in this analysis.
Table 3.
Risk category Delta-CDF (/yr)
Delta-LERF (/yr)
Internal Events 8.23E-8 2.77E-10 Fire Events 6.17E-7 1.55E-9 Totals 6.99E-7 1.83E-9 UNCERTAINTY ANALYSIS The analyst performed an uncertainty analysis using the Monte Carlo method with a sample size of 3,650 on the internal and external events results using the SAPHIRE ECA workspace.
5th %
Median Point Estimate Mean 95th %
1.74E-7 6.99E-7 9.67E-7 1.06E-6 3.08E-6
The above results reflect a simplified approach of substituting one exposure period of a failure-to-load-run condition as a surrogate to estimate the total uncertainty parameters for the approximate best-estimate total risk result for this evaluation. These results do not include the actual risk (and associated uncertainty) contribution from Fire events (which was estimated separately based on review of licensee modeling results) but do include risk contribution from HWD events to offset the Fire risk contribution that is not included in SPAR modeling.
CONCLUSION The analyst concluded that the overall risk significance of the finding was consistent with very low safety significance (Green), based on best estimates of 9.92E-7/year for total delta-CDF and 3.55E-9/year for total delta-LERF, as detailed in the summary table below. The source of best available information for the best-estimate results below for Fire risk (delta-CDF and delta-LERF) and delta-LERF risk for internal events was determined to be the analysts review of the licensees modeling results. The results in the remaining risk categories are based on the analysts use of the NRC SPAR model.
Table 4. Best-estimate results Risk category Delta-CDF (/yr)
Delta-LERF (/yr)
Internal Events 2.14E-7 2.77E-10 External Events minus HWD 1.61E-7 1.72E-9 Fire 6.17E-7 1.55E-9 Totals:
9.92E-7 3.55E-9 References:
1) INL/EXT-21-65055, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants: 2020 Update, November 2021.
2) PWROG-18042-NP, FLEX Equipment Data Collection and Analysis, Revision 1, February 2022.