ML24221A024
| ML24221A024 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 08/15/2024 |
| From: | Patricia Vossmar NRC/RGN-IV/DORS/PBA |
| To: | John Monninger Region 4 Administrator |
| Vossmar P | |
| References | |
| MD 8.3 | |
| Download: ML24221A024 (1) | |
Text
August 15, 2024 MEMORANDUM TO:
John D. Monninger, Regional Administrator THRU:
Geoffrey B. Miller, Director Division of Operating Reactor Safety FROM:
Patricia J. Vossmar, Branch Chief Projects Branch A Division of Operating Reactor Safety
SUBJECT:
MANAGEMENT DIRECTIVE 8.3 EVALUATION FOR SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION, UNIT 1 AUTOMATIC REACTOR TRIP ON JULY 24, 2024 Pursuant to Regional Office Policy Guide 0801, Management Directive 8.3 and Inspection Manual Chapter 0309 Reactive Team Inspection Decisions, Implementation, and Documentation for Power Reactors, the enclosed table provides the Management Directive 8.3 evaluation for South Texas Project Electric Generating Station, Unit 1, for an automatic reactor trip due to an electrical fault and fire in the switchyard which caused a lockout of the main generator and loss of offsite power to all three engineered safeguards (ESF) buses of Unit 1 and one ESF bus of Unit 2. Unit 2 remained operating. The licensee declared a Notification of Unusual Event due to loss of all offsite power capability to emergency buses for greater than 15 minutes. Staff performed this evaluation to determine the risk significance of the event to determine the appropriate level of NRC response. Based on this evaluation, the staff recommends a special inspection be performed for follow up of this event. The staff recommends this special inspection be accomplished by adding scope and team members to a special inspection that is already planned to occur at the facility the week of September 9, 2024.
Concur with Recommendation:
John D. Monninger Date Regional Administrator
Enclosure:
MD 8.3 Decision Documentation Form (Deterministic and Risk Criteria Analyzed)
CONTACT:
Patricia J. Vossmar, DORS/PBA 817-200-1144 Signed by Miller, Geoffrey on 08/09/24 Signed by Vossmar, Patricia on 08/08/24 Signed by Monninger, John on 08/15/24
ML24221A024 SUNSI Review By: RLB ADAMS Yes No Non-Sensitive Sensitive Publicly Available Non-Publicly Available Keyword:
NRR-123 OFFICE SPE:DORS/A SRA:DORS C:DORS/A D:DORS RIV:RA NAME RBywater RDeese PVossmar GMiller JMonninger SIGNATURE
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DATE 08/08/24 08/08/24 08/08/24 08/09/24 08/15/24
Enclosure MANAGEMENT DIRECTIVE 8.3 DECISION DOCUMENTATION FORM (Deterministic and Risk Criteria Analyzed)
PLANT:
South Texas Project, Unit 1 EVENT DATE:
July 24, 2024 RESPONSIBLE BRANCH CHIEF:
Patricia Vossmar EVALUATION DATE:
August 6, 2024 BRIEF DESCRIPTION OF THE SIGNIFICANT OPERATIONAL EVENT OR DEGRADED CONDITION:
On July 24, 2024, at 7:02 a.m. CDT, South Texas Project (STP), Unit 1, automatically tripped from full power. A failure of shunt reactor 2 in the switchyard, and a resulting fire, caused a main generator lockout, loss of power from the north and south buses, lockout of standby transformer 1, turbine trip and reactor trip. The event resulted in a loss of offsite power to each Unit 1 engineered safety features (ESF) bus and the autostart and loading of its associated emergency diesel generator (EDG). All three trains of the auxiliary feedwater (AFW) system automatically started.
The loss of the south switchyard bus also caused a loss of standby transformer 2. Unit 2 remained online with its output limited to Hillje circuit 64 and operators reduced power to 90 percent as requested by the grid operator. The Unit 2 unit auxiliary transformer remained available to provide power to Unit 2 ESF buses A and C. However, with the loss of standby transformer 2, offsite power was lost to ESF bus B, resulting in the autostart and loading of its associated EDG and the autostart of AFW train B.
The Unit 2 shift manager declared a Notification of Unusual Event (NOUE) at 7:18 a.m.
based on emergency action level (EAL) SU1 for loss of all offsite power capability to emergency buses for greater than 15 minutes, due to conditions on Unit 1, and assumed the duties of Emergency Director. Offsite fire responders arrived at the site and extinguished the fire using aqueous foam at 9:25 a.m.
Because offsite power was unavailable to operate the Unit 1 reactor coolant pumps or use the condenser as a heat sink, operators isolated the main steam lines and maintained natural circulation cooling in the reactor coolant system using AFW flow to the steam generators and the steam generator power operated relief valves (SG PORVs) as a heat sink to the atmosphere. At 9:53 am, after operators placed the SG PORV controllers in manual to keep them from cycling, they noticed that the SG 1C PORV was closed and could not be controlled in manual, nor would it operate when placed in automatic. The licensee declared the 1C PORV inoperable at 9:53 a.m. The main steam safety valve (MSSV) acoustic monitoring system was not available to indicate whether any MSSV had lifted. However, based on local observation and measured steam header pressure, the licensee concluded that at least one MSSV had lifted to reduce steam line 1C pressure.
The licensee terminated the NOUE at 11:46 a.m. 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.
2 MANAGEMENT DIRECTIVE 8.3 DECISION DOCUMENTATION FORM (Deterministic and Risk Criteria Analyzed)
PLANT:
South Texas Project, Unit 1 EVENT DATE:
July 24, 2024 The south switchyard bus and standby transformer 2 were re-energized at 12:12 p.m. This allowed the licensee to proceed with restoring offsite power to Unit 2 ESF bus B and all three Unit 1 ESF buses. Unit 1 also restored offsite power to non-ESF buses and restored operation of a reactor coolant pump at 1:46 p.m. Standby transformer 1 remained unavailable due to damage to its feeder cables from the switchyard.
At 1:50 p.m., the licensee evaluated electrical bus alignment and ESF power availability and concluded both the north and south buses were operable and all Unit 2 ESF buses were powered by the unit auxiliary transformer.
The licensee performed troubleshooting of Unit 1 PORV 1C but was unable to identify a definitive cause of its failure. However, the licensee identified abnormal indications that plant computer signals for valve operation were being received by the valves servo-amplifier circuit card but were not being transmitted beyond the card to the valve actuator. As a result, the licensee replaced the servo-amplifier and some other suspect electrical components.
Following post-maintenance testing, the licensee declared PORV 1C operable on July 28 at 2:50 p.m.
Regarding the cause of the shunt reactor failure, the licensee believes that the stormy weather at the time of the event induced large voltage differentials between ground and atmosphere. The licensee noted that during the event, several chain link fences around the protected area and switchyard were seen sparking over a period of several seconds prior to the shunt reactor failure. The licensee believes this phenomenon may have been the cause of the shunt reactor failure, resulting in grounding phases of the shunt reactor and igniting the oil-filled equipment.
On July 29, 2024, the licensee provided an update to the event notification that initially reported the NOUE. The update stated, After a review of station logs, it was determined that there was not a loss of all offsite AC power to Unit 1 An offsite power source was available through the 138 kV transmission line. This referred to the offsite power supply which provides power to the emergency transformer offsite source, which has capability to provide power to one ESF bus for each unit. The NRC staff noted that some licensee internal communications issues occurred during the event which challenged timely and accurate classification and notifications.
Unit 1 was restarted and placed online on August 1, 2024.
3 Y/N DETERMINISTIC CRITERIA Involved operations that exceeded, or were not included in, the design bases of the facility.
N Remarks: The event was within the design basis of the facility.
Involved a major deficiency in design, construction, or operation having potential generic safety implications.
N Remarks: The event did not reveal any major deficiencies, nor did it have generic safety implications.
Led to a significant loss of integrity of the fuel, primary coolant pressure boundary, or primary containment boundary of a nuclear reactor.
N Remarks: There was not a loss of any barriers during this event.
Led to the loss of a safety function or multiple failures in systems used to mitigate an actual event.
N Remarks: There was only one failure in a system used to mitigate an actual event.
Steam generator PORV 1C failed in the closed position when its controller was placed in manual. The valve would not open using manual control and the valve would not open when the controller was placed in automatic. This caused increasing pressure in the C main steam line and at least one main steam safety valve lifted. This criterion was marked No since there were not multiple equipment failures or loss of the decay heat removal safety function provided by the remaining steam generator PORVs.
Involved possible adverse generic implications N
Remarks: The trip did not have generic safety implications.
Involved significant unexpected system interactions N
Remarks: The trip did not involve significant unexpected system interactions.
Involved repetitive failures or events involving safety-related equipment or deficiencies in operations.
Y Remarks: Prior to this Unit 1 event involving a failed safety-related steam generator PORV, there were three failures of steam generator PORVs in 2024 on Unit 1 (one failure of PORV 1A and two failures of PORV 1C). There was also a failure of the Unit 2 PORV 2C during the May 12, 2024, Unit 2 event. The NRC issued a Green NCV in Inspection Report 498;499/2024001 for inadequate corrective actions for the repetitive failure of the Unit 1, PORV 1C.
Involved questions or concerns pertaining to licensee operational performance.
N Remarks: There are no known concerns regarding the operational performance of the licensee during the event. There were some communications issues involving emergency preparedness and these are addressed below.
4 Y/N DETERMINISTIC CRITERIA Involved circumstances sufficiently complex, unique, or not well enough understood, or involved safeguards concerns, or involved characteristics the investigation of which would best serve the needs and interests of the Commission.
N Remarks: This event did not involve circumstances sufficiently complex, unique, or not well enough understood; nor involve safeguards concerns. This event did not involve such unusual characteristics requiring an investigation to serve the needs and interests of the Commission.
Emergency Preparedness Deterministic Criterion - Significant failures to implement the emergency preparedness program during an actual event, including the failure to classify, notify, or augment onsite personnel.
N Remarks: There were apparent inadequacies in the implementation of the emergency preparedness program during an actual event as described below, but they did not involve the failure to classify, notify, or augment onsite personnel.
The licensee notified all appropriate State and local agencies but failed to notify them within 15 minutes and the NRC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of the NOUE declaration.
Later, the licensee determined and reported to the NRC that it had overclassified the event because the 138 kV transmission line and the associated emergency transformer remained available to provide a source of offsite power during the event.
Radiation Safety, and/or Security/Safeguards Deterministic Criteria N
Remarks: None of the radiation safety, and/or security/safeguards deterministic criteria could be answered in the affirmative for this event.
CONDITIONAL RISK ASSESSMENT IF IT IS DETERMINED THAT A RISK ANALYSIS IS NOT REQUIRED - ENTER NA BELOW AND CONTINUE TO THE DECISION BASIS BLOCK RISK ANALYSIS BY: Rick Deese DATE: August 2, 2024 Brief description for the basis of the assessment (may include assumptions, calculations, references, peer review, or comparison with licensees results):
5 For this risk assessment, the analyst used the test/limited use South Texas Project SPAR model STP-EQK-HWD-FLEX-TLU2, Version 8.80, run on SAPHIRE, Revision 8.2.10. The following modifications were made to the model to better model the plant conditions and failures:
1.
The success criteria for the feed and bleed strategy were adjusted to only requiring 1 of the 2 primary pilot operated relief valves (PORVs) to successfully implement the strategy. The analyst complemented pertinent basic events in fault tree FAB to do this.
2.
The failure probability of basic event FLX-XHE-XM-ELAP, Operators Fail to Declare ELAP when Beneficial, was adjusted from 1.0 to 1.0E-2 to give credit for use of mitigating strategies using FLEX equipment.
3.
The failure probabilities of the sites FLEX equipment were changed to reflect the failure rates based on industry data obtained by the PWR Owners Group and approved for use by the Office of Nuclear Reactor Regulation.
The event was run as an initiating events analysis using the Events and Conditions Assessment module of SAPHIRE. To estimate the risk of the event in this module, the following assumptions were made:
1.
The event was run as a switchyard-centered loss of offsite power event since offsite power to all three engineered safety features buses was lost. The initiating event frequency for a switchyard-centered loss of offsite power was set to 1.0 and the initiating event frequency for all other initiating events was set to 0.0.
2.
The failure probability of steam generator PORV C was set top TRUE, to reflect the valves failure to operate during the event.
3.
Per NRC practice for performing Management Directive 8.3 risk assessments, any out-of-service equipment must be reflected in the risk assessment. Since the licensee had all risk-significant equipment available at the time of the event, the analyst set all test and maintenance failure probabilities to 0.0.
4.
Offsite power was not restored to Unit 1 until 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 10 minutes after the event began. Basic events OEP-XHE-XL-NR01HSC, Operator Fails to Recover Offsite Power in 1 Hour (Switchyard), and OE-XHE-XL-NR04HSC, Operator Fails to Recover Offsite Power in 4 Hours (Switchyard), were set to TRUE to reflect the time taken to restore offsite power to the safety buses.
Applying these assumptions and model modifications led to an estimate for the conditional core damage probability of 4.1E-5. The dominant accident sequences leading to core damage were loss of offsite power events where the stations diesel generators failed leading to station blackout events characterized by failures to recover offsite power.
The analyst discussed these results with the licensee in a phone call on August 5, 2024.
This analysis was reviewed and concurred on by a risk and reliability analyst from the Division of Risk Assessment in the Office of Nuclear Reactor Regulation.
THE ESTIMATED CONDITIONAL CORE DAMAGE PROBABILITY (CCDP) IS:
4.1 x 10-5 WHICH PLACES THE RISK IN THE RANGE OF:
Special Inspection / AIT Overlap
6 RESPONSE DECISION USING THE ABOVE INFORMATION AND OTHER KEY ELEMENTS OF CONSIDERATION AS APPROPRIATE, DOCUMENT THE RESPONSE DECISION TO THE EVENT OR CONDITION, AND THE BASIS FOR THAT DECISION DECISION AND DETAILS OF THE BASIS FOR THE DECISION:
Region IV staff concluded that one of the deterministic criteria was met and the estimated conditional core damage probability was 4.1 x 10-5, and as a result, a reactive inspection should be considered. Considering the risk result, the repetitive equipment failure experienced, the perceived complexity of the event, and the need for inspection staff resources with electrical engineering and emergency preparedness expertise, the Region IV staff determined that a reactive inspection was recommended. In consultation with headquarters staff, Region IV determined that a Special Inspection Team is the appropriate response due to the limited number of inspection items requiring NRC follow-up, the nature of the initiating event, and the lack of a need for onsite headquarters personnel augmentation.
The staff recommended this special inspection be accomplished by adding scope and team members to a special inspection that is already planned to occur at the facility for a similar type of event the week of September 9, 2024.
BRANCH CHIEF REVIEW:
Patricia Vossmar DATE: August 6, 2024 DIVISION DIRECTOR REVIEW:
Geoffrey Miller DATE: August 8, 2024 ADAMS ACCESSION NUMBER:
EVENT NOTIFICATION REPORT NUMBER (as applicable): 57237 E-mail to NRR_Reactive_Inspection@nrc.gov