ML24183A224
| ML24183A224 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 07/01/2024 |
| From: | Christopher Hunter NRC/RES/DRA/PRB |
| To: | |
| References | |
| LER 498-2024-001 | |
| Download: ML24183A224 (6) | |
Text
1 Final ASP Analysis - Reject Accident Sequence Precursor Program - Office of Nuclear Regulatory Research South Texas Project, Unit 1 Two SG PORVs Inoperable Resulting in a Condition That Could Have Prevented Fulfillment of a Safety Function Event Date: 1/23/2024 LER:
498-2024-001 CDP =
2x10-9 IR: 05000498/2024001 Plant Type:
Westinghouse Four-Loop Pressurized-Water Reactor (PWR) with Dry Ambient Pressure Containment Plant Operating Mode (Reactor Power Level):
Mode 3 (0% Reactor Power)
Analyst:
Reviewer:
Completion Date:
Christopher Hunter John Lane 7/1/2024 1
EVENT DETAILS 1.1 Event Description On January 22, 2024, steam generator (SG) power-operator relief valve (PORV) 1A was declared inoperable due to its failure to operate in automatic or manual mode. The plant entered Technical Specification (TS) 3.7.1.6, Action A. On January 23rd, SG PORV 1C was declared inoperable due to its failure to operate in manual mode (only). The plant entered TS 3.7.1.6, Action B. Later that day, SG PORV 1A operability was restored after repairs were successfully completed, and the plant exited TS 3.7.1.6, Action B. Repairs on SG PORV 1C were successfully completed and the plant exited TS 3.7.1.6, Action A. Unit 1 was restarted on January 30th and returned to full-power operation on January 31st.
On March 1, 2024, the station entered a forced outage to replace a SG safety relief valve (SRV) spring. With the unit in Mode 4, after closing SG PORV 1C earlier in the day, operators attempted to open SG PORV 1C, but the valve would not open. The operators observed that the demand signal did not change on the controller. SG PORV 1C was declared inoperable and the plant entered TS 3.7.1.6, Action A. A subsequent licensee investigation found the same fuse blown that resulted in the valve failure identified on January 23rd, and an intermittent electrical failure on one of the A/B solenoid coils. The licensee replaced the A/B solenoid and SG PORV 1C was declared operable following post-maintenance testing on March 2nd, and the plant exited TS 3.7.1.6, Action A.
Additional information is provided in licensee event report (LER) 498-2024-001, Two SG PORVs Inoperable Resulting in a Condition That Could Have Prevented Fulfillment of a Safety Function, (ML24092A190) and inspection report (IR) 05000317/2023050, South Texas Project Electric Generating Station, Units 1 and 2 - Integrated Inspection Report 05000498/2024001 and 05000499/2024001, (ML24123A073).
1.2 Cause The licensee was unable to determine the cause of the fuse failure for SG PORV 1A. There were no additional indications of overcurrent in the circuit or distribution panel that affected other components and no other components required replacement. An intermittent condition with the servo amplifier board for SG PORV 1C was identified that caused the fuse on the servo
LER 498-2024-001 2
amplifier board to inconsistently blow under normal electrical load. A specific cause for the servo amplifier board intermittent issues causing the fuse to blow could not be identified. NRC inspectors that the diagnostic troubleshooting steps performed by the licensee on the failure of SG PORV 1C on January 23rd were minimal. In addition, the inspectors noted that after the replacement of the initial blown fuse, the replacement fuse also blew; however, there was no subsequent effort to determine the cause. The inspectors concluded that a lack of thorough investigation of SG PORV 1C failure identified in January 2024 led to licensees failure to identify the deficient condition within the electrical circuit and resulted in the second valve failure in March 2024.
2 MODELING 2.1 SDP Results/Basis for ASP Analysis The Accident Sequencer Precursor (ASP) Program uses Significance Determination Process (SDP) results for degraded conditions when available (and applicable). However, an independent ASP analysis is performed when concurrent (i.e., windowed) unavailabilities and, therefore, an ASP analysis was performed to evaluate the risk impact of the two SG PORV failures.
NRC inspectors identified a Green (i.e., very low safety significance) finding, documented in 05000498/2024001 (ML24123A073), associated with the licensees failure to identify and correct the condition adverse to quality that led to the failure of SG PORV 1C during forced outages in January and March 2024 was a performance deficiency. Specifically, the licensee failed to identify the condition that caused the failure during the January 2024 outage, having performed only limited troubleshooting and causal evaluation, which led to a second failure of the same valve on March 1, 2024. The LER is closed.
A search of South Texas Project LERs identified LER 498-23-004, Condition Prohibited by Technical Specifications Due to lnoperable Train of Essential Chilled Water, (ML24036A352) as a potential windowed event. The windowed aspect of these two events will be evaluated as part of the ASP evaluation of LER 498-23-004.
2.2 Analysis Type A degraded condition 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 June 6, 2024. This SPAR model was revised to credit other steam pathways (in addition to the SG PORVs) for decay heat removal (e.g., steam dumps and SG SRVs). In addition, evaluation-specific changes we made to allow the modeling of the SG PORV failures in either automatic or manual mode. The common-cause failure (CCF) modeling of the SG PORVs was expanded into its sub-elements to support the proper adjustments to the CCF probabilities for this analysis.
This SPAR model includes the following hazards:
Internal events, Seismic events, and High winds (including hurricanes and tornados).
Internal fire and flood scenarios are not included in the South Texas Project SPAR model. The lack of these hazards is a key uncertainty for this analysis, which is considered qualitatively in Section 3.4.
LER 498-2024-001 3
2.3 SPAR Model Modifications No additional SPAR model modifications were made to support this analysis.
2.4 Exposure Time SG PORVs 1A and 1C were last successfully operated on January 31, 2023, and February 22, 2023, respectively. Since the exact time of when these valves became unavailable is unknown, the exposure time is calculated using the following equation from Section 2.4 of Volume 1 (internal events) of the Risk Assessment of Operational Events (or RASP) Handbook (ML17348A149):
=
2 +
= 357 2 + 1 180
= 336 2 + 39 207 However, there were three different periods where either SG PORV 1A, SG PORV 1C, or both valves were failed and, therefore, the following three exposure time, using the dates and calculations provided above, were estimated for this condition analysis:
Exposure Time 1: SG PORVs 1A is failed. SG PORV 1A was failed closed by itself from July 27, 2023, until August 7, 2023 (12 days).
Exposure Time 2: SG PORVs 1A and 1C are failed. SG PORVs 1A and 1C were concurrently failed closed from August 8, 2023, until January 23, 2024 (169 days).
Exposure Time 2: SG PORV 1C is failed. SG PORV 1C was failed closed by itself from January 24, 2023, until March 2, 2024 (39 days).
2.5 Analysis Assumptions The following modeling assumptions were determined to be significant for this analysis:
Basic events MSS-ARV-CC-7411A (failure of SG 1 ARV-7411A (automatic)) and MSS-ARV-CC-7411M (failure of SG 1 ARV-7411 (manual)) were set to TRUE in Exposure Times 1 and 2 because SG PORV 1A was unable to open either in automatic or manual mode during these periods. In addition, the associated temporary events (MSS-ARV-CC-74MTMP, MSS-ARV-CC-74TMP, MSS-ARV-CC-74MTMPA and MSS-ARV-CC-74TMPA) were set to TRUE to ensure that the applicable CCF probabilities were properly adjusted.
Basic event MSS-ARV-CC-7431M (failure of SG 3 ARV-7431 (manual)) was set to TRUE in Exposure Time 2 because SG PORV 1C was unable to open either in manual mode during this period. In addition, the associated temporary event (MSS-ARV-CC-74MTMPC) was set to TRUE to ensure that the applicable CCF probabilities were properly adjusted.
LER 498-2024-001 4
Basic events MSS-ARV-CF-ALLA-AC (CCF of SG PORVs 7411 and 7431 (automatic)),
MSS-ARV-CF-ALLA-ABC (CCF of SG PORVs 7411, 7421, and 7431 (automatic)), MSS-ARV-CF-ALLA-ACD (CCF of SG PORVs 7411, 7431, and 7411 (automatic)), MSS-ARV-CF-ALLA-ABCD (CCF of SG PORVs 7411, 7421, 7431, and 7441 (automatic)), MSS-ARV-CF-ALLM-AC (CCF of SG PORVs 7411 and 7431 (manual)), MSS-ARV-CF-ALLM-ABC (CCF of SG PORVs 7411, 7421, and 7431 (manual)), MSS-ARV-CF-ALLM-ACD (CCF of SG PORVs 7411, 7431, and 7411 (manual)), and MSS-ARV-CF-ALLM-ABCD (CCF of SG PORVs 7411, 7421, 7431, and 7441 (manual)) were set to FALSE in Exposure Time 2 because CCF between SG PORVs 1A and 1C was not possible because the valves failed due to different causes.
Basic event MSS-ARV-CC-7411M (failure of SG 1 ARV-7411 (manual)) was set to TRUE in Exposure Time 3 as a surrogate for SG PORV 1C being unable to open either in manual mode during these periods. In addition, the associated temporary events (MSS-ARV-CC-74MTMP and MSS-ARV-CC-74MTMPA) were set to TRUE to ensure that the applicable CCF probabilities were properly adjusted.
3 ANALYSIS RESULTS 3.1 Results1 The overall CDP for this analysis is calculated to be 1.9x10-9, which is the sum of the three exposure times (1.8x10-10, 1.2x10-9, and 5.7x10-10). The ASP Program threshold is 1x10-6 for degraded conditions; therefore, this event is not a precursor.
3.2 Dominant Hazards The dominant hazards for this analysis are internal events (CDP = 1.9x10-9), which contribute approximately 97 percent of the total CDP. High winds (including hurricanes and tornados) and seismic hazards are minimal contributors for this analysis. The lack of internal flood and fire scenarios in the SPAR model is a key uncertainty, which is considered qualitatively in Section 3.4.
3.3 Dominant Sequences The dominant accident sequence is steam generator tube rupture (SGTR) sequence 9 (CDP =
1.8x10-9), which contributes approximately 91 percent of the total CDP. The sequences that contribute at least 5 percent to the total CDP are provided in the following table. The event tree with the dominant sequence is shown graphically in Figure A-1 of Appendix A.
Table 1. Dominant Sequences Sequence CDP Description SGTR 9 1.8x10-9 90.6%
SGTR initiating event occurs; successful reactor trip, (auxiliary or main) feedwater is successful; high-pressure injection is successful, operators successfully isolate the ruptured SG; secondary side cooldown fails resulting in unisolated leak via the SG PORVs or SRVs; and operators fails to implement Emergency Contingency Action 3.1 results in core damage.
1 The CDPs presented in the following sections are point estimates.
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Sequence CDP Description SLBOC 10-9 1.3x10-10 6.5%
Steam-line break (outside containment) initiating event occurs; an induced SGTR occurs; successful reactor trip, (auxiliary or main) feedwater is successful; high-pressure injection is successful, operators successfully isolate the ruptured SG; secondary side cooldown fails resulting in unisolated leak via the SG PORVs or SRVs; and operators fails to implement Emergency Contingency Action 3.1 results in core damage.
3.4 Key Uncertainties A review of the analysis assumptions and results reveal the following key uncertainties:
Lack of Internal Fire and Flood Modeling in the SPAR Model. The South Texas Project SPAR model does not include internal fire and flood scenarios. The dominant scenario from the hazards included in the SPAR is a SGTR initiating event. Internal fire and flood scenarios are very unlikely to result in a SGTR. In addition, internal fire and floods are unlikely to result in similar scenarios for the smaller risk contributors, which include steam line break and seismically small loss-of-coolant accidents with concurrent losses of offsite power. Given these considerations, it is not expected that this unmodeled internal fire and flood scenarios would result in overall risk of these degraded conditions to exceed the precursor threshold.
LER 498-2024-001 A-1 Appendix A: Key Event Tree Figure A-1. SGTR Event Tree IE-SGTR SG TUBE RUPTURE RPS REACTOR TRIP FW FEEDWATER SYSTEM HPI HIGH PRESSURE INJECTION SGI FAULTED STEAM GENERATOR ISOLATION SSC SECONDARY SIDE COOLDOWN CSI TERMINATE OR CONTROL SAFETY INJECTION FAB FEED AND BLEED RFL RWST REFILL CFC CONTAINMENT FAN COOLERS RHR RESIDUAL HEAT REMOVAL HPR HIGH PRESSURE RECIRC ECA DECAY HEAT REMOVAL RECOVERY (ECA-3.1/3.2)
End State (Phase - CD) 1 OK 2
OK CST-REFILL 3
CD 4
OK 5
OK 6
CD 7
OK RFL1 8
OK 9
CD 10 OK RFL1 11 OK 12 CD SGI1 SSC1 13 OK RHR-LPI 14 CD SSC1 15 CD SGI1 16 CD 17 OK 18 CD 19 CD 20 CD 21 CD 22 CD 23 ATWS