ML24093A250
| ML24093A250 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 04/24/2024 |
| From: | John Dixon NRC/RGN-IV/DORS/PBD |
| To: | John Monninger Region 4 Administrator |
| References | |
| Download: ML24093A250 (1) | |
Text
April 23, 2024 MEMORANDUM TO: John D. Monninger, Regional Administrator THRU: Geoffrey B. Miller, Director Division of Operating Reactor Safety FROM: John L. Dixon, Jr., Chief Project Branch D Division of Operating Reactor Safety
SUBJECT:
MANAGEMENT DIRECTIVE 8.3 EVALUATION FOR WATERFORD STEAM ELECTRIC STATION, UNIT 3, MAIN TRANSFORMER FIRE AND RESULTING AUTOMATIC REACTOR TRIP ON MARCH 21, 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 determining that no additional inspection will be conducted at Waterford Steam Electric Station, Unit 3, for the main transformer fire resulting in an automatic reactor trip, safety injection, and containment isolation. The branch will use baseline inspection procedures for follow up inspection of this event.
Concur with Recommendation:
John D. Monninger Date Regional Administrator
Enclosures:
MD 8.3 Decision Documentation Form (Deterministic and Risk Criteria Analyzed)
CONTACT: John Dixon, DORS/PBD 817-200-1574 Signed by Monninger, John on 04/23/24
ML24093A250 SUNSI Review ADAMS: Non-Publicly Available Non-Sensitive Keyword:
By: ASanchez No Publicly Available Sensitive NRC-002 Yes OFFICE DORS:SPE DORS:SRA DORS: PDB DORS:DD RA NAME ASanchez RDeese JDixon GMiller JMonninger SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/
DATE 04/02/24 04/02/24 04/02/24 04/08/24 04/23/24 MANAGEMENT DIRECTIVE 8.3 DECISION DOCUMENTATION FORM (Deterministic and Risk Criteria Analyzed)
PLANT: Waterford 3 EVENT DATE: 03-21-2024 RESPONSIBLE John Dixon EVALUATION 03-28-2024 BRANCH CHIEF: DATE:
BRIEF DESCRIPTION OF THE SIGNIFICANT OPERATIONAL EVENT OR DEGRADED CONDITION:
On March 21, 2024, at 11:28 p.m. CDT, Waterford Steam Electric Station, Unit 3, was operating at 98 percent power when an automatic reactor trip occurred following a fire in main transformer B that also resulted in the failure of startup transformer B.
At 11:37 p.m. CDT, the shift manager declared an Unusual Event due to a fire on the main transformer inside the protected area that required offsite assistance to extinguish. NOTE:
On March 27, 2024, the licensee retracted the emergency declaration because although the Hahnville fire department responded to the site, the site fire brigade was able to put out the fire without assistance.
The trip resulted in an emergency feedwater actuation signal, safety injection actuation signal, containment isolation actuation signal, and both emergency diesel generators automatically started (due to the safety injection actuation signal). The main feedwater regulating valves shifted to the manual position (for full power operations) which resulted in continued feedwater injection and cooldown of the primary reactor coolant system. The cooldown resulted in safety injection and containment isolation from low reactor system pressure at 1684 psia. The response of the main feedwater regulating valves was not as expected; however, the operators restored control of the feedwater regulating valves and prepared to cooldown the unit to Mode 5.
All control rods fully inserted as expected, and all other plant equipment functioned as expected. Forced reactor coolant system circulation remained with one reactor coolant pump per loop running. Decay heat removal was via the main condenser. The train A safety bus remained powered by offsite power, and the train B safety bus was powered by emergency diesel generator B. Emergency diesel generator A was secured as a result of running unloaded.
The resident inspector responded to the station to follow-up on the stations actions in response to the fire and reactor trip and understand the cause(s) of the event.
Following a main generator exciter failure on May 16, 2019, the main feedwater regulating valves shifted to the manual position and resulted in an automatic reactor trip, and a main feedwater isolation signal actuation due to high steam generator water levels. The direct cause was not identified, but the licensee concluded there were multiple factors which affected the sensed level via the pressure transmitter(s) [LER 05000382-2019-005-01]. The licensee stated that the steam generator level transmitter deviation margin would be increased to provide more margin, the two level transmitters would be calibrated to be equal
Enclosure MANAGEMENT DIRECTIVE 8.3 DECISION DOCUMENTATION FORM (Deterministic and Risk Criteria Analyzed)
PLANT: Waterford 3 EVENT DATE: 03-21-2024 at steady state power, and the transmitter response time would be changed to provide additional smoothing of the level inputs to the feedwater control system.
The licensee did increase the level deviation from roughly 10 inches to 20 inches; however, they were not able to increase it to the desired setpoint as planned because they were not able to calibrate the system to reliably perform at the higher value.
The feedwater level transmitters response during both of these electrically induced events (main exciter failure and main transformer failure) are nearly identical in that the main feedwater regulating valves shifted to the manual as-is position (full power operation) which resulted in the plant experiencing a further transient.
Enclosure Y/N DETERMINISTIC CRITERIA
Involved operations that exceeded, or were not included in, the design bases of the facility N Remarks: Fires affecting major plant equipment, reactor trips, partial loss of offsite power, safety injections, containment isolations, etc., are all part of the design basis of the facility. No condition occurred during this event that was beyond the design basis.
Involved a major deficiency in design, construction, or operation having potential generic safety implications N Remarks: There has not been any identification of a major deficiency or generic 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 integrity of fuel, reactor coolant pressure boundary, or containment. While there was a safety injection actuation, no water from the safety injection system was injected into the reactor coolant system.
Led to the loss of a safety function or multiple failures in systems used to N mitigate an actual event Remarks: There was no loss of safety function and multiple failures did not occur.
Involved possible adverse generic implications N Remarks: The sequence of events and preliminary causes does not appear to have any generic implications.
Involved significant unexpected system interactions N Remarks: The loss of the main transformer B, startup transformer B, and subsequent sequence of events are understood based on the plant conditions and setpoints.
Y Involved repetitive failures or events involving safety-related equipment or deficiencies in operations
3 Y/N DETERMINISTIC CRITERIA
Remarks: The main feedwater regulating valves experienced a similar shift to the manual position during the main exciter reactor trip in 2019. The licensee was not able to determine a direct cause of the condition other than an overall electrical transient resulted in the steam generator level deviation and subsequent shift of the regulating valves to manual control. The corrective actions from the 2019 event may not have been implemented as originally intended and they did not prevent the situation from occurring again. This may be a deficient operation of the main feedwater regulating valves or of the corrective action program for a risk significant component.
Involved questions or concerns pertaining to licensee operational performance Remarks: The repetitive nature of the main feedwater system regulating valves Y response to steam generator water level deviations due to an electrical transient raise questions as to whether additional troubleshooting or corrective actions should have been put into place. For example, the step in the response procedures where operators check main feedwater, since they could not achieve the intended higher deviation setpoint, etc.
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 N Commission Remarks: This event is understood based on the plant conditions and setpoints that existed, does not involve safeguards concerns, and involves characteristics that can be addressed through normal NRC inspection and response.
Further, none of the Emergency Preparedness, Radiation Protection, and/or Security/Safeguards Deterministic Criteria could be answered in the affirmative for this event
3 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 Rick Deese DATE: March 28, 2024 BY:
Brief description for the basis of the assessment (may include assumptions, calculations, references, peer review, or comparison with licensees results):
The analyst utilized the Waterford plant-specific SPAR model, Version 8.81, run on SAPHIRE, Revision 8.2.9, to estimate the risk associated with this event. The following assumptions were made:
- 1. The failure of the main transformer resulted in a reactor trip. The analyst used the Events and Conditions Assessment (ECA) Workspace in SAPHIRE to run an initiating events analysis for a transient.
- 2. The fire in the main transformer led to the failure of startup transformer 3B. Startup transformer 3A was considered far enough away from the failed main transformer that the probability of a common cause failure of startup transformer 3A from the fire event was not adjusted. Basic event ACP-TFM-FC-SUT3B, Failure of Startup Transformer from Switchyard to 4.16 kV Bus 3B2, was set to 1.0.
- 3. Main feedwater pump B was unavailable as a result of the loss of startup transformer 3B. The analyst confirmed that the SPAR model logic reflected that failure of startup transformer 3B rendered main feedwater pump B unavailable.
- 4. The non-safety auxiliary feedwater pump was unavailable as a result of the loss of startup transformer 3B. The analyst confirmed that the SPAR model logic reflected that failure of startup transformer 3B rendered the auxiliary feedwater pump unavailable.
- 5. The analyst assumed no other mitigating equipment was out of service at the time and applied the zero test and maintenance change set.
The analyst quantified the SPAR model using the above assumptions to obtain a conditional core damage probability of 1.7 x 10-6. The dominant core damage sequences included failures of offsite power, emergency feedwater, and the safety relief valves. This evaluation includes consideration of risk from internal events only and does not include consideration of additional risk from external events. The licensee ran the same conditions in their model and obtained similar results.
THE ESTIMATED CONDITIONAL CORE DAMAGE 1.7 x 10-6 PROBABILITY (CCDP) IS:
WHICH PLACES THE RISK IN THE RANGE OF: No additional inspection / Special inspection overlap
4 5RESPONSE 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:
Based on the sequence of events being understood, relative to the plant conditions and setpoints, and the need for the licensee to complete troubleshooting and testing to determine causal and contributing factors, the branch recommends baseline inspection.
Since the licensee is still in process of completing the failure modes effects investigations into the causes of the main transformer failure which cascaded into the subsequent sequence of events, sending a special inspection team would not provide answers to why the main transformer failed and why the main feedwater system observed a level deviation. The branch currently does not have any concern with the actions the licensee is taking to resolve and understand these failures, hence the recommendation for baseline inspection.
BRANCH CHIEF REVIEW: DATE: 04/02/2024 DIVISION DIRECTOR REVIEW: DATE: 04/08/2024 ADAMS ACCESSION NUMBER:
EVENT NOTIFICATION REPORT NUMBER (as applicable):
E-mail to NRR_Reactive_Inspection@nrc.gov Signed by Dixon, John on 04/02/24 Signed by Miller, Geoffrey on 04/08/24