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| Start date | Reporting criterion | Title | Event description | System | LER | |
|---|---|---|---|---|---|---|
| ENS 57021 | 11 March 2024 17:37:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Manual Reactor Trip | The following information was provided by the licensee via phone and email: On March 11, 2024, at 1337 EDT, with Unit 1 in Mode 1 at 35 percent power performing power ascension activities, the reactor was manually tripped due to the 'A' reactor feed pump (RFP) tripping on low suction pressure. Due to the power level at the time, the 'B' RFP had not been placed in service. Closure of containment isolation valves (CIVs) in multiple systems and actuation of high-pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) occurred as a result of reaching the actuation setpoint on reactor water level as designed. The trip was not complex, with all safety systems responding normally post-trip. Operations responded and stabilized the plant. The 'B' RFP was placed in service and is controlling reactor water level. Decay heat is being removed by discharging steam to the main condenser using turbine bypass valves. Unit 2 is not affected. Due to the emergency core cooling system (ECCS) discharging into the reactor, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(A). Also, the Reactor Protection System actuation while critical is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Additionally, it is reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs, RCIC and HPCI. There was no impact on the health and safety of the public or plant personnel. The NRC resident inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: The cause of the 'A' RFP is under investigation. The reactor electric plant remains in a normal lineup with both emergency diesel generators available. There were no temperature or pressure technical specification limits approached. | Reactor Protection System Emergency Diesel Generator Reactor Core Isolation Cooling Emergency Core Cooling System Main Condenser | |
| ENS 56826 | 1 November 2023 10:48:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Manual Reactor Trip Due to Trip of Reactor Feed Pump | The following information was provided by the licensee via email: At 0648 EDT on 11/1/23, with Unit 2 in MODE 1 at 56 percent power, the reactor was manually tripped due to a trip of the 'B' reactor feed pump (RFP). The 'A' RFP had been previously isolated due to a leak. Closure of containment isolation valves (CIVs) in multiple systems and the actuation of high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) occurred as a result of reaching the actuation setpoint on reactor water level as designed. The trip was not complex, with all safety systems responding normally post-trip. Operations responded and stabilized the plant. Reactor water level is being maintained with RCIC. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 1 was not affected. Due to the emergency core cooling system (ECCS) discharging into the reactor this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(A). Also, the reactor protection system actuation while critical is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Additionally, it is reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs, RCIC and HPCI. There was no impact on the health and safety of the public or plant personnel. The Resident Inspector was notified. | High Pressure Coolant Injection Reactor Protection System Reactor Core Isolation Cooling Emergency Core Cooling System Main Condenser | |
| ENS 56446 | 31 March 2023 18:32:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Scram and Automatic Actuation of Containment Isolation Valves (Civs) | The following information was provided by the licensee via email: At 1432 EDT on 03/31/23, with Unit 2 in mode 1 at 97 percent power, the reactor was manually tripped due to a loss of both recirculation pumps. The cause of the recirculation pump trips is under investigation. Additionally, closure of CIVs in multiple systems occurred during the trip as a result of reaching the actuation setpoint on reactor water level as designed. The trip was not complex, with all systems responding normally post-trip. Operations responded and stabilized the plant. Reactor water level is being maintained via condensate / feedwater. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 1 is not affected. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). It is also reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. | Feedwater Reactor Protection System Main Condenser | |
| ENS 55679 | 29 December 2021 20:52:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip and Automatic Actuation of Containment Isolation Valves | This following information was conveyed by the licensee via phone and email: At 1552 EST on 12/29/21, with Unit 1 in Mode 1 at 90 percent power, the reactor was manually tripped due to reactor pressure perturbations. The cause of the reactor pressure perturbations is under investigation. Additionally, closure of (containment isolation valves) CIVs in multiple systems occurred during the trip as a result of reaching the actuation setpoint on reactor water level. The trip was not complex, with all systems responding normally post-trip. Operations responded and stabilized the plant. Reactor water level is being maintained via condensate / feedwater. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 2 is not affected. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). It is also reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. | Feedwater Reactor Protection System Main Condenser | |
| ENS 55394 | 3 August 2021 14:26:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip | At 1026 EDT on 8/3/21, with Unit 1 in MODE 1 at 100 percent power, the reactor automatically tripped due to low reactor water level. The low reactor water level condition was due to a loss of both reactor feed pumps. The cause of the loss of feed pumps is under investigation. Additionally, the low reactor water level resulted in the automatic actuation of High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems, and Containment Isolation Valves (CIVs) in multiple systems. All safety systems responded normally. Operations responded and stabilized the plant. Reactor water level is being maintained via RCIC system. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 2 is not affected. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). It is also reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the HPCI and RCIC systems and CIVs. There was no impact on the health and safety of the public or plant. The Licensee notified the NRC Resident Inspector. The Unit will proceed to Mode 4 while the cause of the loss of feed pumps is under investigation. | High Pressure Coolant Injection Reactor Protection System Reactor Core Isolation Cooling Main Condenser | |
| ENS 53953 | 24 March 2019 05:59:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Scram Due to Degrading Condenser Vacuum | At 0159 (EDT), with Unit 2 in Mode 1 at 25 percent power, the reactor was manually tripped due to degrading condenser vacuum. After the turbine was tripped, the station service electrical buses did not transfer to alternate supply resulting in loss of the condensate feedwater system and level being controlled by the RCIC system. Operators responded and stabilized the plant. Reactor water level is being maintained via the RCIC system. Pressure is being controlled and decay heat is being removed by the HPCI system in pressure control mode. Unit 1 is not affected. Additionally, an actuation of the primary containment isolation system occurred during the reactor scram. The reason for the actuation was a group II isolation signal was received on reactor water level and a group I isolation was received on decreasing vacuum. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non- emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Additionally, this event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the primary containment isolation system. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. | Feedwater Reactor Protection System Primary Containment Isolation System | |
| ENS 53893 | 23 February 2019 07:12:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Actuation of 2C Emergency Diesel Generator | At 0212 EST on February 23, 2019, with Unit 2 in Mode 5, an actuation signal for the 2C Emergency Diesel Generator (EDG) was received during the Loss of Coolant Accident / Loss of Offsite Power logic system functional test. The 2C EDG was running and tied onto the 2G 4160 emergency bus when the alternate supply breaker was closed as required per the test procedure. Immediately upon closing the alternate supply breaker, both the alternate supply breaker and 2C EDG output breaker tripped open. The 2C EDG output breaker reclosed once the 2G 4160 bus undervoltage relays sensed a deenergized bus. When the 2C EDG tied to the 2G 4160 bus, the bus voltage was noted as being high, and the 2C EDG was secured. Investigation is ongoing to determine the cause of the initial bus undervoltage and the subsequent bus excessive voltage. This event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the emergency AC power system. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. This event puts Unit 1 in a 72 hour Limiting Condition for Operation for the 1C Startup Transformer being out of service. | Emergency Diesel Generator | |
| ENS 52700 | 21 April 2017 03:45:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Valid Reactor Protection System Actuation While Shutdown | At 2345 (EDT) on 04/20/2017, the Unit 1 Reactor Mode Switch was taken to the Shutdown position to comply with Technical Specification 3.10.4 due to having no operable IRM's (Intermediate Range Monitors) in one quadrant of the reactor vessel as a result of maintenance activities. Placing the mode switch to Shutdown inserts a valid scram signal into the Reactor Protection System (RPS). All control rods had been previously inserted and no rod movement occurred when the mode switch was positioned to Shutdown. Due to this valid RPS scram, and not being a part of a preplanned evolution, this condition is reportable under criteria 50.72(b)(3)(iv)(A) as an event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) of this section except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. The licensee notified the NRC Resident Inspector. | Reactor Protection System Control Rod | |
| ENS 52558 | 16 February 2017 18:20:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Unexpected Autostart of an Emergency Diesel Generator | On February 16, 2017 at 1320 EST, the 2A Emergency Diesel Generator (EDG) started in response to a valid actuation signal due to the momentary loss of the 2C Startup Transformer (SAT). While performing maintenance activities on the 2D SAT, the alternate supply breaker tripped and reclosed, allowing the 4160 2E Emergency Bus to be momentarily de-energized. When the 4160 2E Emergency Bus de-energized, the 2A EDG received a valid autostart signal due to emergency bus low voltage. Although, the 2A EDG did autostart, it did not tie to the 4160 2E Emergency Bus as the 4160 2E Emergency Bus was re-energized from the 2C SAT. This event is reportable per 10 CFR 50.72(b)(3)(iv)(A) since the autostart of the 2A EDG was not part of a pre-planned sequence and the event resulted in the valid actuation of an emergency ac electrical power system. CR 10332134 The NRC Resident has been notified. | Emergency Diesel Generator | |
| ENS 51950 | 23 May 2016 14:09:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Plant Hatch Unit 2 Containment Isolation Valve Actuation | On May 23, 2016, at 1009 EDT, while personnel were performing turbine testing with Unit 2 offline for planned maintenance, an event resulted in the actuation of containment isolation valves in more than one system. In response to this unexpected signal, 2B21F016 (Steam Line Drain Line Inboard Isolation Valve), 2B21F019 (Steam Line Drain Line Outboard Isolation Valve), and 2B31F019 (Reactor Water Sample Inboard Isolation Valve) went closed, all of which are primary containment isolation valves actuated by Group 1 Isolation. The Group 1 Isolation signal initiated based on low condenser vacuum during the turbine testing procedure, a valid condition that was expected to have been bypassed in the logic during the performance of this procedure. Human performance is believed to be the cause of these systems having actuated in a way that was not part of the planned evolution. Although the Unit was shut down when this signal was received, and primary containment isolation was not required to mitigate the consequences of an event, this Isolation signal has been determined to have been valid due to the initiation in response to actual plant conditions or parameters which satisfy the requirements for initiation of the system. The event is reportable as required by 10 CFR 50.72(b)(3)(iv)(A)(2): (A) Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) of this section except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. (2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam Isolation valves (MSIVs). The licensee has notified the NRC Resident Inspector. | Main Steam Isolation Valve Primary containment | |
| ENS 48760 | 16 February 2013 08:10:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Reactor Protection System Scram Signal Due to Scram Discharge Volume High Level | On 2/16/13, at 0310 EST, with the reactor shutdown for a refueling outage, a full RPS actuation was received on Hatch Unit 2 due to Scram Discharge Volume High level. The Operations crew placed the Unit 2 mode switch to the Start-up/Hot Standby position per approved procedure for the purpose of performing the U2 Refueling Interlock functional test. The cause of the Scram was due to a Scram Discharge Volume high level caused by a malfunctioning SDV drain valve. Hatch Condition Report 591279 has been generated to document the event. The NRC Resident Inspector has been informed. | Reactor Protection System | |
| ENS 48738 | 10 February 2013 12:00:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Scram Inserted Due to Degrading Reactor Water Chemistry | During normal power operations, the crew observed condensate/feedwater conductivity begin to increase at approximately 0530 EST on 02/10/13. The crew responded to the associated alarm response procedures and entered abnormal operating procedure 34AB-N61-001-1 due to degrading reactor water chemistry parameters. A power reduction (from 100%) was initiated at 0555 EST in accordance with station procedures for responding to a suspected condenser tube leak. At 0700 EST, a manual reactor SCRAM (from approximately 47%) was inserted due to the elevated reactor water conductivity in accordance with station abnormal operating procedures. All rods inserted completely and no complications were encountered following the reactor SCRAM, normal feedwater injection remained available. Following the SCRAM, a Group 2 Primary Containment Isolation Signal (PCIS) was received as a result of reactor water level lowering below +3 inches. The lowest reactor water level observed was (minus) 2 inches and was restored to normal operating levels utilizing normal feedwater injection. Following restoration of reactor water level to the normal operating level, the Group 2 PCIS signal was reset. No ECCS injection systems actuated as a result of the reactor SCRAM. The SCRAM was uncomplicated and the plant is stable. Decay heat removal is to the main condenser via the turbine bypass valves. The plant is in a normal offsite electrical power shutdown alignment. Efforts are in progress to isolate the condenser in-leakage. There was no impact on Unit 2. The licensee has notified the NRC Resident Inspector. | Feedwater Primary containment Decay Heat Removal Main Condenser | |
| ENS 47369 | 24 October 2011 20:11:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Scram Due to Erratic Irm Indications During Startup | While performing a startup of HNP-2, after reaching criticality, the crew observed erratic indications on two Intermediate Range Monitors (IRMs), 2C51K601A and 2C51K601C. IRM 2C51K601A had been spiking and was subsequently bypassed. The 2C51K601C was spiking downscale and could not be bypassed due to the 2C51K601A being bypassed already. Both IRMs are in the 'A' RPS trip system. At the time when the second IRM was acting erratic, the crew identified the condition as both IRMs in the same quadrant and did not continue withdrawal of control rods. As a result of not withdrawing control rods, reactor power began to decrease and the crew conservatively inserted a manual reactor scram to shutdown the reactor. All rods did fully insert into the core. No PCIS (Primary Containment Isolation System) actuations occurred and none were expected to occur based on plant conditions following the scram. At this time, investigation is in progress, but the investigation and corrective actions have not yet been completed. The crew is maintaining HNP-2 in Hot Standby (Mode 3) at this time. The licensee informed the NRC Resident Inspector. | Intermediate Range Monitor Control Rod | |
| ENS 45850 | 16 April 2010 23:17:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Loss of Cooling Accident Signal Due to High Drywell Pressure Signal | On April 16, 2010 at 1917 hrs., Unit 1 received an ECCS (emergency core cooling system) loss of cooling accident (LOCA) signal on high drywell pressure. Based on plant data, drywell pressure reached a maximum pressure of approximately 1.25 psig, which is below the LOCA and RPS (reactor protection system) signal actuation pressure of 1.85 psig. At this time, the cause of the drywell pressure increase is under investigation. RPS logic did not initiate due to drywell pressure not reaching the actuation setpoint of 1.85 psig. Although the ECCS logic prematurely actuated, the signal is being treated as 'valid' for the ECCS actuation until further investigation is completed. All expected ECCS actions occurred as a result of the signal. The LOCA logic has been reset and all affected systems have been returned to normal or standby configuration. As a result of the LOCA system actuations, several cooling tower fans tripped and condenser vacuum began to decrease. Reactor power was reduced to approximately 86 percent as a result of decreasing condenser vacuum. Power is being maintained at approximately 86 - 88 percent at this time. There are no other plant issues or concerns at this time. The licensee notified the NRC Resident Inspector. According to the licensee, normal drywell operating pressure is .5 to 1.2 psig. Prior to the event, drywell pressure had been steady at approximately 1.0 psig. Current drywell pressure is .6 psig. According to the licensee, ECCS systems that started (but did not inject) included: Core Spray pumps, Residual Heat Removal pumps, High Pressure Coolant Injection pump, and the Diesel Generators. An event review team is assessing this event to determine the root cause.
On April 16, 2010, Hatch Unit 1 received a LOCA ECCS initiation from a high drywell pressure signal. Based on the information available at that time, a notification was made to the NRC assuming the signal to be valid until further investigation could be completed. After further review, the determination has been made that the initiation signal originated from a faulted ATTS (Analog Transmitter Trip System) card and not from a valid high drywell pressure condition. Based on this information, this condition did not require an NRC notification in accordance with 10CFR50.72 and, as such, is being retracted through this updated response. The licensee notified the NRC Resident Inspector. Notified the R2DO (Hopper) | High Pressure Coolant Injection Core Spray Residual Heat Removal | |
| ENS 45148 | 23 June 2009 07:51:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Scram Due to High Reactor Water Level | (The reactor automatically scrammed) on a Main Turbine Trip >27.6% rated thermal power. The main turbine trip was due to reactor high level. Post scram, reactor level decreased to approximately -26 inches. Reactor water level was restored with the condensate system. Both reactor recirc pumps tripped as required on EOC RPT Logic when the main turbine tripped. Both pumps have been restarted. A Group 2 isolation was received at +3 inches reactor water level with all valves closing as required. Investigation as to the cause of the transient is underway. All rods inserted during the scram. No relief valves actuated during the transient. Decay heat is being removed via turbine bypass valves to the main condenser. The plant is within normal shutdown temperature and pressure limits. The electrical grid is stable and the plant is in a normal shutdown electrical lineup. The Group 2 has been reset. There was no effect on Unit 1. The licensee has notified the NRC Resident Inspector. | Main Turbine Main Condenser | |
| ENS 45071 | 15 May 2009 09:19:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Group 1 Isolation of All Main Steam Valves While Performing a Special Procedure | At 0519 on 5/15/09, a Group 1 isolation signal was received which resulted in all eight Main Steam Isolation Valves closing. The signal was received based upon a valid main condenser low vacuum signal coincident with reactor mode switch placed in RUN position. The isolation was an unanticipated result of a special purpose procedure which was being performed as a functional test for maintenance work that had been performed on intermediate range nuclear instrumentation. The procedure had installed jumpers to bypass the Group 1 isolation for Mode Switch in Run, but did not account for low condenser vacuum isolation. The low condenser vacuum switches were in the bypass position, but this logic does not prevent Group 1 isolation in the Run mode. The Group 1 isolation was completed successfully with all MSIVs and small bore valves closing as designed. MSIV closure with Mode Switch in Run position also caused a RPS actuation / full scram. The reactor was subcritical and all control rods were already fully inserted as the reactor was being maintained in Cold Shutdown. The licensee has notified the NRC Resident Inspector. | Main Steam Isolation Valve Main Condenser Control Rod Main Steam | |
| ENS 45052 | 10 May 2009 14:41:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Intermediate Range Reactor Scram During Transition to Run | During Startup of HNP-1, after reaching greater than or equal to 7% RTP (rated thermal power), the crew placed the Reactor MODE switch to 'RUN,' in accordance with the Startup Procedure 34GO-OPS-001-1. Upon placing the MODE switch to 'RUN,' a full RPS actuation occurred due to upscale trip signals on the Intermediate Range Nuclear Instrumentation (IRM) 1C51K601A, 1C51K601D and 1C51K601H. Placing the Reactor MODE switch to 'RUN' bypasses the IRM inputs to the RPS system, so actuation of the RPS from the IRMS was not expected. All withdrawn control rods inserted properly upon receipt of the full SCRAM signal. All equipment functioned as expected, with the exception of the unexpected upscale trips of IRMs 1C51K601A, 1C51K601D and 1C51K601H and the subsequent RPS actuation from the IRMs. No reactivity changes were in progress at the time to cause the upscale trip signals. At this time, investigation is in progress, but the investigation and corrective action have not yet been completed. The shift crew is progressing to Cold Shutdown, MODE 4 at this time. The decay heat is being removed by main turbine sealing steam with makeup provided via the control rod drive system. Offsite power is provided by the normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector. | Main Turbine Control Rod | |
| ENS 45049 | 8 May 2009 19:15:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Inadvertant Main Steam Isolation While Performing Maintenance | At 1515 on 5/8/09, a Group 1 isolation signal was received which resulted in all eight Main Steam Isolation Valves closing. The signal was received based upon a valid main condenser low vacuum signal coincident with a main turbine reset signal which opened the turbine stop valves. The reset of the turbine was an unanticipated result of ongoing Mark VI turbine control system processor repair work. The reactor was maintaining hot shutdown while conducting nuclear instrumentation repair. The Group 1 isolation was completed successfully with all MSlVs and small bore valves closing as designed. The condition causing the turbine reset has been cleared and the turbine tripped with all valves closed. The Group 1 isolation signal has been reset and the MSIVs have been re-opened. The cause of the turbine reset signal is being investigated by Station Engineering and the on-site GE representative. The reactor is being taken to cold shutdown for intermediate range nuclear instrument maintenance. The licensee notified the NRC Resident Inspector. | Main Steam Isolation Valve Main Turbine Main Condenser Main Steam | |
| ENS 44679 | 22 November 2008 15:18:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Manual Reactor Scram After Feed Pump Trip | Manual Rx Scram initiated due to a loss of condensate/feedwater. Condensate Booster Pump 1A tripped due to low suction pressure and then both Reactor Feed-pumps tripped. Both HPCI and RCIC initiated on low level and restored reactor water level to normal band 5 to 50 inches. Both Reactor Water Recirculation Pumps tripped due to low level at RWL (Reactor Water Level) - 60". Lowest RWL was approximately minus 70 inches and a group two isolation occurred at RWL 3 inches. All group two 2 valves closed as required. The cause of the low condensate booster suction pressure is under investigation. Rods fully inserted on the scram. No safety or relief valves lifted after the scram. Reactor water level is being maintained with normal feed and decay heat is being removed to the main condenser. The plant is in its normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector. | Main Condenser | |
| ENS 44337 | 4 July 2008 12:39:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Scram on Turbine Trip | A Turbine Trip greater than 30% power caused a Reactor Trip (Scram), both Recirculation Pumps tripped. A low level (Reactor Vessel Water Level) of approximately 2 inches caused a Group 2 containment valve isolation signal, all valves closed as required. The cause of the Turbine Trip is under investigation All control rods fully inserted with no ECCS actuations. Unit 1 is currently stable in mode 3 (Hot Shutdown) with decay heat being removed via the bypass. Following the scram, one SRV lifted and reseated. At the time of the transient, an EHC pump autostart was in progress, however, there is no indication that this was the cause of the turbine trip. Unit 1 is in a normal shutdown electrical lineup. The licensee informed the NRC Resident Inspector. | Control Rod | |
| ENS 44046 | 7 March 2008 19:46:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Automatic Reactor Scram with Hpci/Rcic Actuation Due to Loss of Condensate Feedwater | Unit 2 RPS actuation / unplanned scram with subsequent ECCS discharge to the RCS at 1446 hrs. on 3/07/08. Unit 2 scrammed on Low RPV water level of 3 inches above instrument zero as a result of a loss of condensate feedwater. Water level decreased to approximately 60 inches below instrument zero as a result of the loss of feedwater. (Top of active fuel is approximately 150 inches below instrument zero.) The cause of the loss of feedwater is presently under investigation. At 35 inches below instrument zero, HPCI and RCIC actuated and restored water level. HPCI oscillations were experienced and the system was taken to manual control, at which time the flow oscillations abated. All other systems functioned as required. A team has been assembled to investigate and determine the cause of the initiating event of the loss of feedwater. During the scram, all rods inserted into the core. There were no safety relief valve actuations as a result of the transient. RPV level was restored and is being maintained using control rod drive flow. The electrical grid is stable with normal offsite power supplying safety loads. Decay heat is being removed using the turbine bypass valves to condenser. The licensee has notified the NRC Resident Inspector. | Feedwater Safety Relief Valve Control Rod | |
| ENS 43552 | 7 August 2007 19:06:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Reactor Scram on Low Reactor Water Level Following Partial Loss of Condensate Feedwater Flow | Unit 2 RPS actuation / unplanned scram occurred at 1506 eastern time on low reactor water level scram initiation. The unit experienced a partial loss of condensate feedwater due to the trip of 2D 4160 volt station service bus (non-safety related). The 2C 4160 volt bus remained in service supplying power to one condensate pump and one condensate booster pump. Investigation of the 2D 4kv bus trip is in progress. Also received a Group II isolation signal due to low reactor water level. The reactor is currently stable with water level at 37 inches. Normal feedwater has been used to makeup water level and decay heat is being discharged to the condenser via turbine bypass valves. All rods fully inserted. No SRVs lifted during the transient. The lowest water level reached was -5 inches. The Unit remained in a normal electrical lineup. There were no significant LCOs in effect at the time of the scram. There was no impact on Unit 1. The licensee notes that I&C activities had been in progress on the 2D 4kv bus about the time that it tripped however there is currently no specific connection between these activities and the bus trip. The licensee notified the NRC Resident Inspector. | Feedwater | |
| ENS 42096 | 29 October 2005 17:25:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Unusual Event - Main Transformer Fire | NUE declared on Hatch Unit 1 due to a fire on the main transformer lasting greater than 10 minutes. Unit 1 reactor scram on main turbine trip. Group 2 PCIV (Primary Containment Isolation Valves) isolation on low reactor water level (+3 inches). All group 2 valves closed as required. Fire extinguished at 1358 hours. Plant is stable. All control rods fully inserted on the reactor scram. The plant is in hot shutdown steaming through the turbine bypass valves to the main condenser. No safety systems are affected. Emergency electrical buses are on normal offsite power and emergency diesel generators are available if required. The onsite fire brigade responded to the fire and the fire suppression system for the main transformer functioned as expected. The licensee notified the NRC Resident Inspector.
The licensee is still in a NUE. The fire is out. The fire reflashed at 1603 when the deluge system was secured to inspect the transformer. The deluge system was restarted immediately. Offsite fire support have responded. Cleanup efforts are in progress. The licensee notified the NRC Resident Inspector. Notified IRD (Blount), R2DO (Cahill), and NRR EO (J. Hannon).
The licensee is still in a NUE. This call is to add an offsite notification per 10 CFR 72.75 (b)(2) to another government agency. The site chemistry department notified the National Response Center (Coast Guard) at 1636 that the site had discharged an unknown quantity of oil into the Altamaha River and was implementing site spill control and countermeasures procedures. The licensee also notified the Georgia Environmental Protection Division. The licensee notified the NRC Resident Inspector. Notified IRD (Blount), NRR EO (J. Hannon), and R2DO(Cahill).
The licensee reports that the fire is confirmed extinguished (i.e., no risk of reflash) based on long term monitoring of the transformer including thermography measurements. The Unit remains in an Unusual Event until assessment activities related to the transformer fire have been completed. The licensee notified the NRC Resident Inspector.
Based on the results of assessment activities related to the transformer fire, the licensee has exited the Unusual Event at 0050. The licensee notified the NRC Resident Inspector. The R2DO (Cahill), EO (Hannon), IRD (Blount), DHS (Doyle), and FEMA (Bisco) have been notified. | Emergency Diesel Generator Primary containment Main Transformer Main Condenser Control Rod | |
| ENS 41725 | 23 May 2005 21:47:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Scram Due to Condenser Hotwell Chemistry | Based on increasing conductivity in the reactor vessel and condenser hotwell, a power reduction was initiated from 100 percent power. A manual scram was inserted at 57 percent RTP and 49 percent Core Flow based on Chemistry recommendations due to sulfates and chlorides in the hotwell. Following the scram a reduction in reactor water level to -28 inches resulted in a Primary Containment Group 2 Isolation (ESF) occurring. All isolations and systems responded as expected. Current plant status is Hot Shutdown with plans to proceed to cold shutdown. All control rods fully inserted and decay heat is being removed with the bypass valves into the condenser. The licensee notified the NRC Resident Inspector.
After further review and evaluation it has been determined that the four hour call made May 23, 2005 per the guidance of 50.72(b)(2)(iv)(B) should be retracted. A review of the event with respect to NUREG 1022 Revision 2 determined that: The manual scram was part of a pre-planned sequence to shut the plant down due to an equipment problem. The manual scram was part of a pre-planned sequence. The guidance to scram the reactor was established by the plant's Abnormal Operating Procedure addressing a condenser tube leak and was part of a preplanned sequence to prevent future equipment and component failures. The Manual Scram was not inserted to protect the plant against an event that presented a challenge to an FSAR analyzed event. In other words, this was not an Anticipated Operational Occurrence, an Accident, or a Special Event as defined in section 15.1.3 of the Unit 2 FSAR. Rather it was part of a plan to shutdown the reactor to protect against future potential equipment problems due to out of limits chemistry parameters. Further justification is provided by the fact that the manual scram was not initiated in anticipation of an automatic scram. Per NUREG 1022 Rev. 2: 'The staff also considers intentional manual actions, in which one or more system components are actuated in response to actual plant conditions resulting from equipment failure or human error, to be reportable because such actions would usually mitigate the consequences of a significant event. This position is consistent with the statement that the commission is interested in events where a system was needed to mitigate the consequences of the event.' However, the reporting requirement itself indicates that actuations that result from pre-planned sequences are not reportable. An example is provided in the NUREG of an equipment problem involving the loss of recirc pumps. In this example it is stated that: 'Even though the reactor scram was in response to an existing written procedure, this event does not involve a preplanned sequence because the loss of the recirc pumps and the resultant off-normal procedure entry were event driven, not pre-planned.' This is similar to our event, however, in the NUREG example, the reactor is scrammed to protect against the possibility of a stability event and stability is an FSAR analyzed event. In our case we were shutting down for chemistry reasons, not an FSAR type event. It is concluded that when the RPS is used to shutdown the reactor as part of a plan for the resolution of equipment problems, and the RPS is not needed to mitigate the consequences of an FSAR analyzed event, i.e., one which threatens a fission product boundary (i.e., fuel cladding, RCPB, primary and secondary containments), the RPS actuation is not reportable under 50.72(b)(2)(iv)(B). The licensee notified the NRC Resident Inspector. Notified R2DO (Haag).
On May 23, 2005 a four hour report was made per the guidance of 50.72(b)(2)(iv)(B), 'Any event or condition that results in an actuation of the RPS when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' This was made per event # 41725. The report was made within the four hour time frame of 10 CFR 50.72(b)(2). The four hour report for event # 41725 was retracted on June 6, 2005. After further consideration, the retraction made on June 6, 2005 is being cancelled and the original report re-instated. The licensee notified the NRC Resident Inspector. Notified R2 DO (K. Landis) | Secondary containment Primary containment Control Rod | |
| ENS 41070 | 25 September 2004 05:06:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Group 2 Containment Isolation Actuation | Received Group 2 isolation signal on Low Reactor Water Level during initiation of manual reactor scram during planned shutdown. Reactor Water Level decreased to -0.5 inches. Group 2 isolation setpoint is +3.0 inches. All Group 2 isolation valves closed as required. During the planned shutdown, all control rods fully inserted. Decay heat is being removed to the main condenser via the main turbine bypass valves, ESF and ECCS systems remain available, and the electrical grid is stable. The licensee will notify the NRC Resident Inspector. | Main Condenser Control Rod | |
| ENS 40565 | 3 March 2004 18:45:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Swing Diesel Generator Auto Started from a Bus Undervoltage Valid Signal | At the time of this occurrence Unit 1 is in a scheduled Refueling Outage and Unit 2 is at 100% Maximum Operating Power. Also note, the 1 B Diesel Generator is a Swing Diesel Generator which is capable of supplying Unit 1 1F 4160 Volt bus and also when required 2F 4160 Volt bus. At 13:45 EST on 03/03/04, the 1B Diesel Generator auto started due to a momentary Bus Undervoltage sensed on the 1F 4160 volt bus. At the time of the occurrence the 1F 4160 Volt bus was energized with the Normal Supply Breaker racked out and the Alternate Supply Breaker closed in and supplying the 1F 4160 Volt bus. The Normal Supply Breaker was racked out for a scheduled breaker replacement. At the time of the occurrence 2 electricians were removing the Racked Out Normal Supply breaker from the cubicle. The breaker shutter mechanism (a component of the breaker) fell off of the breaker inside the cubicle causing the 1F 4160 Volt bus to sense a momentary bus undervoltage, the Alternate Supply breaker momentarily cycled open and re-closed causing the 1B Diesel Generator to auto start. Since the 1 B Diesel Generator auto started from a valid signal (Bus Undervoltage) an 8 hour report is being made. At the time of this report the 1B Diesel Generator has been Shutdown and restored to a standby Lineup. The 1B Diesel Generator remains Operable. The licensee notified the NRC Resident Inspector.
Subsequent investigation revealed the most probable cause of this event was the trip of the alternate supply breaker to the emergency bus, resulting in its momentary de-energization and an automatic start of the diesel generator on an actual bus undervoltage signal. The alternate supply breaker apparently tripped as a result of the shutter in the formal supply breaker cubicle falling against the fingers of the breaker when as the breaker was being removed from the breaker cubicle. The affected breaker was already n the racked out position. When the breaker was moved to allow its removal from the cubicle, the shutter was apparently forced upward by the movement of the breaker musing the shutter to move upward and the shutter actuating lever to pivot downward until the moc switch mechanism actuated the logic causing the alternate supply breaker to -rip and the diesel generator to start. The shutter actuating lever became separated from the shutter allowing the moc switch to return to its expected open position thereby allowing the alternate supply breaker to recluse and provide power to the bus before the swing diesel generator had sufficient permissives to tie to the bus. Even with the condition found in this breaker cubicle the breaker can be safely racked out. It is when the breaker is removed from the cubicle that there is an increased potential for the shutter and its connected lever arm to cause a logic actuation similar to that experienced in this event. The condition does not create an operability concern for the bus and at most could cause a logic actuation in the conservative direction and does not present any known operability issues for the associated 4160 volt buses. Additional inspections have been performed on 6 balance of plant 4160 volt breakers that are identical in design with acceptable clearances observed in the locations where problems were noted in the subject breaker cubicle. The normal supply breaker for the 1F 4160V bus has been inspected with no problems noted. The associated shutter and lever mechanisms for this breaker have been inspected, components replaced and the breaker returned to service. The alternate supply breaker on the safety related 4160 volt switchgear that was involved in this event was also checked and found to have acceptable clearances and no problems noted with the shutter mechanism. At this point this condition is limited to the breaker cubicle that is the subject of this notification based on extent of condition review performed up this point. There are currently no operability concerns for the affected 4160 volt switchgear or associated diesel generator. Notified R2DO (R. HAAG). |