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 Discovered dateReporting criterionTitleEvent description
ENS 5399914 April 2019 07:20:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip Due to Main Feedwater Pump TripAt 0320 EDT, April 14, 2019, Sequoyah Unit 1 experienced an automatic reactor trip. The event was initiated by the trip of the 1A main feedwater pump. During the automatic unit runback, an automatic reactor trip was initiated due to low-low level in Steam Generator number 3. The Auxiliary Feedwater System (AFWS) automatically actuated as required when the expected post-trip feedwater isolation actuated. Reactor Coolant System temperature is being maintained by the AFWS and the steam dump system. During this operational cycle, one control Rod Position Indicator (RPI) for core position E-5 in shutdown bank 'A' has been inoperable, and the appropriate Condition and Required Actions of (Technical Specification Limiting Condition of Operation) 3.1.7 were complied with. Due to this inoperable RPI, the associated shutdown rod is conservatively assumed to be full out and untrippable. Consequently, boration was required to establish adequate shutdown margin. All other Control and Shutdown rods fully inserted. All safety systems responded as designed. No primary or secondary safety valves actuated during or after the reactor trip. The unit is currently stable in Mode 3. Unit 1 is in a normal shutdown electrical alignment. There was no impact on Unit 2. 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) and in accordance with 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the AFW system. There was no impact on the health and safety of the public or plant personnel. The NRC Senior Resident Inspector has been notified."
ENS 5399814 April 2019 04:03:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Scram and Specified System ActuationOn April 14, 2019 at 0003 (EDT), Nine Mile Point Unit 1 experienced an automatic reactor scram during reactor startup. The cause of the automatic scram was due to high (Reactor Pressure Vessel) pressure following closure of the turbine stop valves. All control rods fully inserted and all plant systems responded per design following the scram. Following the automatic scram, the High Pressure Coolant Injection (HPCI) System automatically initiated as expected. At Nine Mile Point Unit 1, a HPCI System actuation signal on low Reactor Pressure Vessel (RPV) level is normally received following a reactor scram, due to level shrink. HPCI is a flow control mode of the normal feedwater systems, and is not an Emergency Core Cooling System. At 0004, RPV level was restored above the HPCI System low level actuation set point and the HPCI System initiation signal was reset. Pressure control was established on the Turbine Bypass Valves, the preferred system. No Electromatic Relief Valves actuated due to this scram. Nine Mile Point Unit 1 is currently in Hot Shutdown, with reactor water level and pressure maintained within normal bands. The offsite grid is stable with no grid restrictions or warnings in effect. The unit is currently implementing post scram recovery procedures. The NRC Resident Inspector has been notified. The Licensee will notify the State of New York.
ENS 5396630 March 2019 21:47:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Scram and Specified System ActuationAt 17:47 Eastern Daylight Time (EDT) on March 30, 2019, with Unit 2 in Mode 1 at approximately 23 percent reactor power and main turbine startup in progress coming out of a refuel outage, a high temperature was sensed at main turbine bearing #9. As a result of and to arrest the high temperature condition, the main control room inserted a manual reactor scram. All control rods inserted as expected during the scram. When the scram was inserted, reactor water level dropped below the Low Level 1 actuation setpoint. Per design, the Low Level 1 signal resulted in Group 2 (i.e., floor and equipment drain isolation valves), Group 6 (i.e., monitoring and sampling isolation valves) and Group 8 (i.e., shutdown cooling isolation valves) isolations. The main control room manually closed all Main Steam Isolation Valves (MSIVs), in anticipation of a low vacuum prior to the Group 1 automatic closure signal being received. High Pressure Coolant Injection (HPCI) was aligned for pressure control and Reactor Coolant Isolation System (RCIC) was aligned for level control. The Reactor Coolant Sample Line Isolation valves closed as expected on low main condenser vacuum. All systems responded as designed. This event is being reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) for RPS actuation and 10 CFR 50.72(b)(3)(iv)(A) as an event that results in valid actuations 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. At the time of notification, decay heat was being removed by the condenser through one open MSIV and a feedwater pump running.
ENS 5395324 March 2019 05:59:0010 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 VacuumAt 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."
ENS 5392310 March 2019 04:59:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Scram Resulting in Rps and Eccs ActuationAt 2259 CST on 3/9/2019, Browns Ferry Unit-3 received an automatic SCRAM on Main Generator Breaker Failure and Turbine Load Reject. Unit-3 declared a Notification of Unusual Event SU1 for loss of offsite AC power to Unit-3 specific 4kV Shutdown Boards for greater than 15 minutes. Primary Containment Isolation Systems (PCIS) Groups 1, 2, 3, 6, and 8 isolation signals were received. Upon receipt of these signals, all required components actuated as required. Main steam relief valves lifted on the initial transient. High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) initiated on low reactor water level. HPCI remains in service for reactor level and pressure control. RCIC is not in service at this time, the station is investigating low flow from the pump. All four Unit-3 Diesel Generators started and loaded as expected. Residual Heat Removal System is in service for suppression pool cooling. 4kV Station Unit Boards have been restored from the 161kV system. Actions are in progress to restore 4kV Shutdown Boards to offsite power. This event is reportable within 1 hour in accordance with 10 CFR 50.72(a)(1)(i) for declaration of the Licensees Emergency Plan. Complete as documented on EN 53922. This event requires a 4 hour report per 10 CFR 50.72(b)(2)(iv)(B), 'Any event or condition that results in actuation of the reactor protection system (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 event also requires an 8 hour report per 10 CFR 50.72(b)(3)(iv)(A). 'Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), (1) Reactor protection system (RPS) including: reactor scram or reactor trip, (2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs), (4) ECCS (Emergency Core Cooling System) for boiling water reactors (BWRs) including: core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system, (5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection system, and (8) Emergency AC electrical power systems, including: Emergency diesel generators (EDGs).' The NRC resident inspector has been notified. As of the event report, the MSIVs were opened and decay heat was being removed via the bypass valves to the condenser.
ENS 539062 March 2019 09:17:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Reactor Trip Due to Feedwater Isolation Valve ClosureAt 0317 CST, the Unit 2 Reactor tripped due to Feedwater Isolation Valve (FWIV) 2-04 going closed. All Auxiliary Feedwater Pumps started due to steam generator Lo-Lo levels. Unit 2 is being maintained in Hot Standby (Mode 3) in accordance with Integrated Plant Operating Procedure IPO-007B. The Emergency Response Guideline Procedure Network has been exited. Decay heat is being rejected to the Main Condenser via the Steam Dump Valves. The cause of the FWIV going closed is currently under investigation. All control rods fully inserted and the reactor trip was uncomplicated. Unit 2 is in a normal post-trip electrical line-up. There was no impact on Unit 1 due to the Unit 2 reactor trip. The licensee notified the NRC Resident Inspector.
ENS 5389423 February 2019 20:58:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Scram After Turbine Control Valve Fast ClosureActuation of RPS (Reactor Protection System) with the reactor critical. Reactor scram occurred at 1458 (CST) on 2/23/2019 from 100% power. The cause of the scram was due to Turbine Control Valve Fast Closure. All control rods are fully inserted. Currently reactor water level is being maintained by the Condensate Feedwater System in normal band and reactor pressure is being controlled via Main Turbine Bypass valves to the main condenser. No ECCS (Emergency Core Cooling System) initiation signals were reached and no ECCS or Diesel Generator initiation occurred. The Low-Low Set function of the Safety Relief Valves actuated upon turbine trip. This was reset when pressure was established on main turbine bypass valves. The cause of the turbine trip is still under investigation. There were no complications with scram response. The licensee notified the NRC Resident Inspector. There was no maintenance occurring on the main turbine at the time of the scram.
ENS 538111 January 2019 05:00:0010 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material
10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident
Gland Seal Exhauster - Automatic Trip Function InoperableOn January 1, 2019 at approximately 0454 EST, while performing planned maintenance activities on the Feedwater Distributed Control System (FW DCS), it was discovered that the automatic trip instrumentation of the Gland Seal Exhauster (GSE) was inoperable. The automatic GSE trip is assumed in the safety analysis for the Control Rod Drop Accident (CRDA) and is required when Thermal Power is less than or equal to 10%. The automatic trip function of the GSE was inoperable for 1 minute, 19 seconds. No Control Rod movement occurred while the automatic trip of the GSE was inoperable. There was no adverse impact to public health and safety or to plant employees and there was no radiological release. This report is being made pursuant to 10CFR50.72(b)(3)(v)(C) and 10CFR50.72(b)(3)(v)(D). The NRC Resident Inspector has been notified."
ENS 5373210 November 2018 05:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Reactor Scram on High Reactor Pressure

At 0046 CST, River Bend Station experienced an automatic reactor scram on high reactor pressure. Initial indications are that the cause of the scram was an uncommanded closure of the #3 turbine control valve. The plant is stable with reactor water level in the normal level band of 10-51 inches being maintained with feedwater and condensate. Reactor pressure is in the prescribed band of 500-1090 psig, being maintained with turbine bypass valves and steam line drains. No injection systems were actuated either manually or automatically as a result of the event. The reactor scrammed on a Reactor Pressure High scram signal. A Reactor Level 3 signal resulted from the normal post-scram water level response. All systems responded as designed.

This event is being reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) as an automatic RPS actuation with the reactor critical. All control rods fully inserted. The Unit is in a normal shutdown electrical alignment. All control rods inserted properly and all systems functioned as designed. The licensee is investigating the cause of the event. The licensee notified the NRC resident inspector.

ENS 5370329 October 2018 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationManual Reactor Trip Due to Inadequate Feedwater FlowOn October 29, 2018 at 1317 EDT, with St. Lucie Unit 1 in Mode 1 at 100% power, the reactor was manually tripped due to inadequate feedwater flow to both 1A and 1B Steam Generators (S/Gs). The trip was uncomplicated with all systems responding normally post-trip. (All control rods fully inserted and there were no specified system actuations.) Operators responded and stabilized the plant in Mode 3. The cause of the inadequate feed flow to the 1A and 1B Steam Generators is currently under investigation. Decay Heat removal is being accomplished through forced circulation with stable conditions from Main Feedwater and the Steam Bypass Control System to the Main Condenser. Currently maintaining Pressurizer pressure at 2250 psia and Reactor Coolant System temperature at 532 degrees F. St. Lucie Unit 2 was unaffected and remains in Mode 1 at 100% power. This report is submitted in accordance with 10CFR50.72(b)(2)(iv)(B) for the reactor trip. The NRC Senior Resident Inspector has been notified."
ENS 5369828 October 2018 05:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Reactor Scram During a Reactor ShutdownAt 0445 (CDT), with reactor power less than 1% rated thermal power on Instrument Range Monitor (IRM) ranges 6 and 7, Clinton Power Station received an automatic Reactor Protection System (RPS) actuation. The Reactor Scram Off Normal procedure was entered and all control rods were verified to be fully inserted. The apparent cause of the scram is cold water injection causing an upscale trip of the IRMs due to Motor Driven Reactor Feedwater Pump (MDRFP) Feedwater Regulating valve 1FW004 valve coming off the full shut seat momentarily. All systems responded appropriately following the scram and the plant is currently stable. Clinton Power Station will be proceeding to Mode 4 to support the planned Maintenance Outage. The NRC Senior Resident Inspector has been notified."
ENS 5367719 October 2018 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Turbine Steam Seal Header Pressure MalfunctionOn 10/19/18 at 2202 EDT, at 19 (percent) Reactor power, a malfunction of (the) Turbine Steam Seal Header pressure control caused a loss of Condenser vacuum, resulting in an automatic trip of the Main Turbine and a manual reactor trip (RPS Actuation). Just prior to the reactor trip, Emergency Feedwater was manually initiated to mitigate the potential loss of Main Feedwater. Condenser vacuum was recovered after the reactor trip and Main Feedwater remained in operation. Due to the RPS actuation while critical, this event is being reported as a 4-hour non-emergency per 10CFR50.72(b)(2). Also, due to the manual initiation of Emergency Feedwater, this event is also being reported as an 8-hour non-emergency per 10CFR50.72(b)(3). Following the reactor trip, all systems responded as expected with no complications. Emergency feedwater was secured at 2300. Unit 1 is in Mode 3 and stable, continuing to cooldown for a refueling outage. The NRC Resident Inspector has been notified.
ENS 5367619 October 2018 05:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip Due to Feedwater Regulating Valve Failing ClosedAt 1725 CDT, a Feedwater Regulating valve failed closed, resulting in a reactor level transient, which initiated a reactor trip, Primary Containment Isolation System signals to valves in Groups 2, 3, and 4 and initiation of High Pressure Coolant Injection and Reactor Core Isolation Cooling. All control rods inserted and level has been restored to normal. The cause of the feedwater valve failure is under investigation. All other systems responded as expected. This report is being made under 10 CFR 50.72 (b)(2)(iv)(B), (b)(3)(iv)(A) and (b)(2)(iv)(A). The Senior Resident Inspector has been informed. Decay heat is being removed via the main condenser and reactor vessel water level is being maintained by the condensate and feedwater systems.
ENS 5366512 October 2018 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Reactor TripOn October 12, 2018 at 1353 EDT, St. Lucie Unit 2 experienced an automatic RPS actuation and Reactor Trip due to a fault on the 2A1 6.9kv bus during a transfer of the bus power supply from the 2A Auxiliary Transformer to the 2A Startup Transformer. The bus fault caused a fire in the 2A1 6.9kv switchgear that has been extinguished. Offsite support was not required to extinguish the fire. The specific cause of the fault is currently under investigation. Following the reactor trip, both Steam Generators are being supplied by main feedwater. All (Control Element Assemblies) (CEAs) fully inserted into the core. Decay Heat removal is being accomplished through forced circulation. Main Feedwater and Steam Bypass Control Systems are maintaining stable conditions in Mode 3. St. Lucie Unit 1 was unaffected and remains in Mode 1 at 100 percent power. This report is submitted in accordance with 10 CFR 50.72(b)(2)(iv)(B) for the Reactor Trip. The fire was extinguished within 28 minutes. Plant loads are being supplied by the 2B Auxiliary Transformer. The licensee notified the NRC Resident Inspector.
ENS 536485 October 2018 04:00:0010 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 Low Reactor Water LevelOn Friday, October 5, 2018 at 1209 hours, with the reactor at 100 percent core thermal power, Pilgrim Nuclear Power Station (PNPS) automatically tripped due to reactor water level perturbation and receipt of a low reactor water level Reactor Protection System (RPS) signal. The cause of the low reactor water level is under investigation. The plant is in hot shutdown. All other plant systems responded as designed. Pressure is being controlled using the Mechanical Hydraulic Control System and Main Condenser. Reactor water level is being maintained with the feedwater and condensate system. During the automatic reactor scram the plant experienced the following isolation signals as designed: Group 2 Isolation: Miscellaneous containment isolation valves Group 6 Isolation: Reactor Water Clean-up Reactor Building Isolation System Actuation Due to the RPS actuation while critical, this event is being reported as a four-hour, non-emergency notification in accordance with 10 CFR 50.72(b)(2)(iv)(B), 'any event that results in actuation of the reactor protection system (RPS) when the reactor is critical.' This notification is also being made in accordance with 10 CFR 50.72(b)(3)(iv)(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 ... ' (B)(2) 'General containment isolation signals affecting containment isolation valves in more than one system.' This event has no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. The licensee will notify the Massachusetts Emergency Management Agency.
ENS 5361118 September 2018 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip Due to a Steam Leak on a High Pressure Feedwater HeaterDue to a steam leak on the reheater line to 36C Feedwater Heater, operators initiated a manual trip of the reactor, verified the reactor trip, and closed all Main Steam Isolation Valves. The plant is currently stable in Mode 3 with the steam leak isolated. The Auxiliary Feedwater System actuated following the trip as expected. This is reportable under 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.72(b)(2)(iv)(B). The unit remains on offsite power in Hot Standby at normal operating temperature and pressure. Decay heat is being removed from the steam generators via the Auxiliary Feedwater System and atmospheric steam dumps. Unit 2 was unaffected and remains at 100 percent power. The licensee notified the NRC Resident Inspector, the State of New York, and the local transmission company.
ENS 5358419 March 2018 04:00:0010 CFR 50.73(a)(1), Submit an LERInvalid Specified System ActuationPursuant to 50.73(a)(1) the following information is provided as a sixty (60) day telephone notification to the NRC. This notification, reported under 50.73(a)(2)(iv), is being provided in lieu of the submittal of a written LER (Licensee Event Report) to report a condition that resulted in an invalid actuation of the high pressure coolant injection (HPCI). At Nine Mile Point Unit 1, HPCI is a flow control mode of the normal feedwater system and is not an emergency core cooling system. On March 19, 2018 Nine Mile Point Unit 1 (NMP1) was at 0 percent power and in cold shutdown in support of a planned maintenance outage. At approximately 0118 (EDT), a reactor water level transient initiated by the fill and vent of 12 Reactor Recirculation Pump (12 RRP) occurred. During the fill and vent, Reactor Pressure Vessel (RPV) level lowered quickly from the initial level of 68 inches and a low level alarm was received. Control Room Operators reduced Reactor Water Clean-Up (RWCU) reject flow to turn the level trend and clear the low level alarm generated off of the compensated, GEMAC, level instrumentation. RWCU reject flow was reduced by 50 percent which caused RPV level to start to rise. RPV level was raised to approximately 72 inches at which time the Reactor Operator began to raise reject flow to reestablish the normal level band. During the RPV level transient, with actual water level at 74 inches on the GEMAC, the Yarway level instrumentation, which is not density compensated and therefore invalid, reached 92 inches causing an invalid high RPV water level turbine trip signal and associated invalid HPCI initiation signal. At no point in time did actual RPV water level reach the high RPV water level turbine trip set point of 92 inches. The potential for a turbine trip signal to occur due to shutdown activities was understood and tags were hung to lockout the Feedwater Pumps to prevent the HPCI start signal. Therefore, no HPCI injection occurred. The Licensee has notified the NRC Resident Inspector."
ENS 5357631 August 2018 05:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationManual Reactor Scram Due to Main Condenser DegradationThis notification is being provided in accordance with 10 CFR 50.72(b)(2)(iv)(B). On August 31, 2018 at 2105 CDT, Unit 2 Reactor Manual Scram signal was inserted due to Main Condenser vacuum degrading. The turbine was tripped following the scram. Main Condenser vacuum is at 6 inches of backpressure slowly improving following the scram and turbine trip. During the scram, one Control Rod (30-31) did not fully insert. Control Rod 30-31 has been manually inserted to position 00 with the first position identified as position 24. Plant is in a stable condition with reactor pressure being maintained by the Turbine Bypass valves. Reactor water level is being controlled with feedwater. Investigation into the cause of the elevated condenser in leakage is in progress. The Senior NRC Resident has been notified."
ENS 5356527 August 2018 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationEn Revision Imported Date 8/29/2018

EN Revision Text: AUTOMATIC SCRAM DUE TO A GENERATOR TRIP At 0033 EDT Nine Mile Point Unit 2 experienced an automatic scram on high reactor pressure due to a turbine trip. The cause of the turbine trip was due to a generator trip. All control rods inserted. There were no safety system actuations. The cause of the generator trip is being investigated. This is a 4-Hour report for 10CFR50.72(b)(2)(iv)(B) RPS Actuation. The NRC Resident Inspector has been notified. Decay heat is being removed via the main condenser. Reactor vessel water level is being maintained by the condensate and feedwater systems. The licensee will be notifying the state of New York.

  • * * UPDATE FROM DANIEL CIFONELLI TO HOWIE CROUCH AT 1653 EDT ON 8/28/18 * * *

After further review, the licensee has determined that the cause of automatic scram was due to turbine control valve fast closure as a result of the turbine trip, not high reactor pressure, as originally reported. The licensee has notified the NRC Resident Inspector. Notified R1DO (Lilliendahl).

ENS 5346320 June 2018 05:00:0010 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an AccidentHigh-Pressure Core Spray InoperableOn June 20, 2018, at 1145 hours (CDT), during panel walkdown, it was identified that High-Pressure Core Spray (HPCS) injection valve 1E22F004 was in the open position. Valve 1E22F004 is normally closed for containment integrity purposes. Operations personnel verified that the valve was open locally and that the plant computer indicated the valve is in the 'not closed' position. No alarms or status lamps indicated why the valve would be open and there was no valid demand signal. Reactor power, pressure, level, and feedwater parameters remain steady and unchanged, with no indication of HPCS injection having occurred or in progress. A low-water level signal, or a high drywell pressure signal, or manual operation initiates HPCS. When a high-water level in the reactor vessel is detected, HPCS injection is automatically stopped by a signal to close injection valve 1E22F004. With valve 1E22F004 in the open position without a demand signal, closure on a high reactor water level condition was not assured. Therefore, HPCS was declared inoperable. The following Technical Specifications were entered: 3.5.1, Emergency Core Cooling Systems (ECCS) - Operating and 3.6.1.3, Primary Containment Isolation Valves (PCIVs). Subsequently, HPCS injection valve 1E22F004 was observed to be cycling without operator action. The valve was deactivated in the closed position to assure the containment isolation function. The cause of valve 1E22F004 cycling without operator action is under investigation. HPCS is a single train safety system that consists of a single motor-driven pump, a spray sparger in the reactor vessel, and associated piping, valves, controls and instrumentation. HPCS is part of the ECCS network, which also includes Low-Pressure Core Spray, Low-Pressure Coolant Injection, and the Automatic Depressurization system. This event is being reported as an 8-hour non-emergency notification per 10 CFR 50.72(b)(3)(v) as, 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.' The licensee notified the NRC Resident Inspector.
ENS 5345916 June 2018 05:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip During StartupAt 1121 CDT on June 16, 2018, Arkansas Nuclear One, Unit 1 (ANO-1) performed a manual reactor trip due to a Turbine Bypass valve failing open on reactor startup. At the time, ANO-1 was in Mode 2 at approximately 2 percent power. The failed Turbine Bypass valve resulted in an overcooling event and the Overcooling Emergency Operating Procedure (EOP) was entered. Main Steam Line Isolation (MSLI) automatic actuation occurred on 2 of the 4 channels of Emergency Feedwater Initiation and Control during the overcooling event in the 'B' Steam Generator. The remaining channels of MSLI were manually actuated by the control room staff from the control room. Overcooling was terminated after the closure of the Main Steam Isolation Valve (MSIV) and reactor coolant parameters were stabilized as directed by the Overcooling EOP. Additionally, Gland Sealing Steam was lost to the main turbine due to the closure of the 'B' Steam Generator MSIV and Loss of Condenser Vacuum Abnormal Operating Procedure was entered. This is a 4-hour non-emergency 10 CFR 50.72 (b)(2)(iv)(B) notification due to a Reactor Protection System actuation (scram) and an 8-hour non-emergency 10 CFR 50.72 (b)(3)(iv)(A) notification for safety system actuation." All control rods fully inserted into the core during the trip. Heat removal is via the Atmospheric Dump Control valves to atmosphere. The NRC Resident Inspector has been notified. The licensee also notified the State of Arkansas.
ENS 534434 June 2018 14:20:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationManual Reactor Trip on Lowering Steam Generator Water LevelAt 0920 CDT, Braidwood Unit 1 reactor was manually tripped due to lowering steam generator water levels following a trip of the 1C main feedwater pump. The cause of the 1C main feedwater pump trip is unknown at this time and is under investigation. Both trains of Braidwood Unit 1 auxiliary feedwater started automatically following the reactor trip to maintain steam generator water levels. All systems responded as expected. Steam generator power operated relief valves lifted momentarily and reseated as designed in response to the secondary transient due to the reactor trip. The main steam dump valves are in service to the main condenser to provide heat sink cooling. The plant is being maintained at normal operating pressure and temperature. AC power is being provided by offsite power with the diesel generators in standby and all safety systems available. There is no impact to Unit 2. This report is being made per 10CFR50.72(b)(2)(iv)(B) for a RPS actuation, 4-hr. notification, and per 10CFR50.72(b)(3)(iv)(A) for an automatic actuation of the auxiliary feedwater system, 8-hr. notification. All rods inserted into the core during the trip. Concerning the relief valves momentarily lifting and reseating, there is no known primary-to-secondary leakage. The licensee has notified the NRC Resident Inspector.
ENS 533877 May 2018 07:36:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Rx Trip Due to High-High Level in Moisture Separator Drain TankOn May 7, 2018 at 0336 (EDT), DC Cook Unit 2 Reactor was manually tripped due to a high-high level experienced in the East Moisture Separator Drain Tank (MSDT) of the Moisture Separator Reheater (MSR). This notification is being made in accordance with 10 CFR 50.72(b)(2)(iv)(B), Reactor Protection System (RPS) actuation as a four (4) hour report, and under 10 CFR 50.72(b)(3)(iv)(A), specified system actuation of the Auxiliary Feedwater System, as an eight (8) hour report. The NRC Resident Inspector has been notified. Unit 2 is being supplied by offsite power. All control rods fully inserted. All Aux Feedwater Pumps started properly. Decay heat is being removed via the Steam Generator Power Operated Relief Valves following Main Steam Stop Valve closure at 0431 due to a slow RCS (Reactor Coolant System) cooldown. Preliminary evaluation indicates all plant systems functioned normally following the Reactor Trip. DC Cook Unit 2 remains stable in Mode 3 while conducting the Post Trip Review. No radioactive release is in progress as a result of this event.
ENS 5337130 April 2018 16:24:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip Following Turbine TripAt 1124 CDT, Braidwood Unit 1 experienced an automatic Reactor Trip. The cause of the Reactor Trip was a Turbine Trip with reactor power greater than P-8. The turbine trip was actuated as a result of a Turbine Motoring Generator Trip. The cause of the generator trip is unknown at this time and is under investigation. After the Reactor Trip occurred, the 1A Auxiliary Feedwater pump was manually started to provide feedwater flow to all four steam generators. The 1A Auxiliary Feedwater pump was subsequently secured and placed in standby when the Startup Feedwater pump was placed in service. Train A Main Control Room Ventilation Filtration system shifted to Makeup Mode due to a spurious actuation signal. No secondary relief valves lifted and no secondary steam was released as a result of the Reactor Trip. The Main Steam dump valves are in service to the Main Condenser to provide heat sink cooling. The plant is being maintained at normal operating pressure and temperature. AC power is being provided by Offsite Power with the Diesel Generators in standby and all safety systems available. There is no impact to Unit 2. This report is being made per 10 CFR 50.72(b)(2)(iv)(B) for a RPS actuation, 4-hr notification, and per 10 CFR 50.72(b)(3)(iv)(A) for a manual actuation of the Auxiliary Feedwater system, 8-hr notification. The licensee notified the NRC Resident Inspector and Illinois Emergency Management Agency.
ENS 5336526 April 2018 20:31:0010 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge
10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident
Inadvertent Injection of High Pressure Core SprayRiver Bend Station experienced an inadvertent initiation and injection of High Pressure Core Spray (HPCS) at 1531 (CDT) on 4/26/2018 while operating at 100 percent power. During replacement of Level Transmitter B21-LTN081C 'Reactor Vessel Low Water Level 1', Main Control Room received an inadvertent initiation and injection of High Pressure Core Spray. The HPCS injection valve was open for approximately 40 seconds before the operators manually closed the valve. Feedwater Level Control responded per design and maintained Reactor Water Level nominal values. The Division 3 Diesel Generator (DG) also automatically started in response to the actuation signal. The DG did not automatically connect to the Division 3 switchgear since there was not a low voltage condition on the bus. The manual closure of the injection isolation valve caused the system to be incapable of responding to an automatic actuation signal. The manual override of the injection isolation valve was reset approximately 16 minutes after the event, restoring the system to its standby condition. This event is being reported in accordance with 10 CFR 50.72(b)(2)(iv)(A) as a condition that caused ECCS (Emergency Core Cooling System) discharge to RCS (Reactor Coolant System) and 10 CFR 50.72(b)(3)(v)(D) as a condition that caused the loss of function of the HPCS System. The Senior NRC Resident inspector has been notified.
ENS 5334820 April 2018 01:07:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip Due to Turbine IssueWhile performing a turbine startup, a turbine control anomaly caused a steam generator level transient. The rise in steam generator level above the setpoint caused the turbine to automatically trip. The high steam generator level of 73 percent caused a feedwater isolation signal at 2107 EDT, which also tripped both Main Boiler Feed Pumps. The tripping of the Main Boiler Feed Pumps auto started the motor driven Aux Boiler Feed Pumps 21 and 23. The reactor was manually tripped at 2108 EDT in accordance with AOP-FW-1 Loss of Main Feedwater. All control rods inserted. Electrical power is being provided from offsite via the Station Aux Transformer. Decay heat removal is being provided via the Atmospheric Dump Valves. An investigation into the cause of the turbine control anomaly is underway. The NRC Resident Inspector has been notified. The event did not have an affect on Unit 3 and there is no primary to secondary leakage.
ENS 5332913 April 2018 06:27:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationManual Reactor Trip Following Main Feedwater Control ProblemOn 4/13/2018 at 0227 (EDT), the Oconee Unit 1 Reactor was manually tripped from 24 percent power due to the inability to control main feedwater flow through the Main Feedwater Control Valves using the Integrated Control System. Due to the RPS actuation while critical, this event is being reported as a 4-hour Non-Emergency per 10 CFR 50.72(b)(2)(iv)(B). Following the reactor trip, multiple Main Steam Relief Valves failed to reseat at the expected pressure. Using procedure guidance, Main Steam Pressure was lowered by 115 psig, resulting in the closing of all Main Steam Relief Valves. All other post-trip conditions are normal and all other systems performed as expected. Unit 1 is currently in Mode 3 and stable. Decay heat is being removed by the steam generators discharging steam to the main condenser using the turbine bypass valves. Units 2 and 3 are not affected by the Unit 1 reactor trip. The licensee notified the NRC Resident Inspector.
ENS 533197 April 2018 12:36:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip and Pcis Actuation During Stator Cooling System Testing

On April 7, 2018, at 0836 EDT, with Unit 1 in Mode 1 at approximately 100 percent power, the reactor automatically tripped during testing of the stator cooling system. The trip was uncomplicated with all systems responding normally. No safety-related equipment was inoperable at the time of the event. Due to the Reactor Protection System (RPS) actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B).

Operations responded using Emergency Operating Procedures and stabilized the plant in Mode 3. Reactor water level being maintained via normal feedwater system. Decay heat is being removed through the bypass valves.

Reactor water level reached low level 1 (LL1) as a result of the reactor trip. The LL1 signal causes a Group 2 (i.e., floor and equipment drain isolation valves), Group 6 (i.e., monitoring and sampling isolation valves) and Group 8 (i.e., shutdown cooling isolation valves) isolations. The LL1 isolations occurred as designed; the Group 8 valves were closed at the time of the event. Due to the Primary Containment Isolation System (PCIS) actuation, this event is also being reported as an eight-hour, non-emergency notification in accordance with 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the PCIS. Unit 2 was not affected. There was no impact on the health and safety of the public or plant personnel. The safety significance of this event is minimal. The automatic reactor trip was not complicated and all safety-related systems operated as designed. Investigation of the cause of the Reactor Protection System actuation is in progress. The licensee notified the NRC Resident Inspector.

ENS 533187 April 2018 08:51:0010 CFR 50.72(b)(3)(iv)(A), System ActuationAutomatic Actuation of Auxiliary Feedwater System (Afw)On April 7, 2018 at 0451 EDT, with Unit 1 in Mode 3 at 0 percent power, an auto actuation of 'A' and 'B' Motor Driven Auxiliary Feedwater (MDAFW) pumps occurred during the shutdown of Unit 1 for Harris Nuclear Plant's refueling outage. Plant Operators successfully took control of the AFW flow and noted the 'B' Main Feed pump was still running with proper suction and discharge pressures of 430 lbs. and 1000 lbs. The 'A' and 'B' Motor Driven Auxiliary Feedwater (MDAFW) pumps automatically started as designed when the 'Loss of Both Main Feedwater Pumps' signal was received. The cause of the actuation is still being evaluated. 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 Auxiliary Feedwater system. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 5326918 March 2018 16:58:0010 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 Turbine Control Valve ClosureAt 1158 CDT on March 18, 2018, the Unit 1 reactor automatically scrammed due to a Reactor Protection System (RPS) signal generated from High Reactor Steam Dome Pressure in response to Turbine Control Valve Closure. The reactor had been operating at 100 percent power. Investigation is in progress. All control rods fully inserted into the core. Main Steam Isolation Valves remained open with Main Steam Relief Valves (MSRVs) operating on the initial transient as expected. Main Turbine Bypass Valves are currently controlling reactor pressure. Reactor Feedwater pumps remained in service to control reactor water level. Primary Containment Isolation Signals Groups 2, 3, 6, and 8 containment isolation and initiation signals were received. Upon receipt of these signals all required components actuated as required. All safety system operated as expected. At no time was public health and safety at risk. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the Reactor Protection System (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.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(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' and requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified.
ENS 5326515 March 2018 19:24:0010 CFR 50.72(b)(3)(ii)(B), Unanalyzed ConditionFailure to Meet Appendix R RequirementsAt 1524 (EDT) on Thursday, March 15, 2018, Operations was notified of a failure to meet Appendix R requirements for Peach Bottom Atomic Power Station (PBAPS) Unit 2 and Unit 3. Valves associated with the feedwater system for both units were not properly considered as Hi-Lo Pressure interface valves as required by the Appendix R program. This results in the susceptibility to a hot short condition that could open valves, diverting flow from the reactor, damage piping and prevent injection. U3 (Unit 3) Fire Safe Shutdown Credited Reactor Core Isolation Cooling (RCIC) System is affected. U2 (Unit 2) is affected by a potential leak path through the Reactor Water Cleanup system. This event is being reported as an occurrence of an event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety under 10 CFR 50.72(b)(3)(ii). The Station (PBAPS) is performing hourly fire watches for the impacted areas and is also evaluating this condition for corrective action. The licensee notified the NRC Resident Inspector.
ENS 5321716 February 2018 15:14:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip During Solid State Protection System TestingAt 1014 (EST) hours on 2/16/18, with Unit 1 in Mode 1 at approximately 100 percent power, the reactor automatically tripped when the Reactor Trip Breakers opened during Train B Solid State Protection System (SSPS) testing. The trip was uncomplicated with all systems responding normally post-trip. Operations manually started the motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump (TDCAP) auto-started on low steam generator level. A Feedwater Isolation occurred as designed due to the Reactor Trip and Lo Tave condition. Operations stabilized the plant. Decay heat is being removed by the condenser. Unit 2 is not affected. Due to the Reactor Protection System actuation while critical, actuation of the TDCAP and motor driven auxiliary feedwater pumps along with the Feedwater Isolation, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B) and an 8 hour non-emergency notification per 10 CFR 50.72(b)(3)(iv)(A). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 531921 February 2018 16:57:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationManual Reactor Scram

At 1057 CST on February 1, 2018 with the unit in Mode 1 at approximately 27% power, a manual actuation of the Reactor Protection System (RPS) was initiated due to an unexpected trip of the B Recirc Pump with A Recirc Pump in fast speed. B Recirc Pump tripped during transfer from slow to fast speed resulting in single loop operation. Operators were unable to reconcile differing indications of core flow. This resulted in a conservative decision to initiate a manual scram. The cause of the B Recirc Pump trip and the apparent issues with core flow indication are under investigation. The plant is currently stable in Mode 3. The plant response to the scram was as expected. All control rods (fully) inserted as expected; the feedwater system is maintaining reactor vessel water level in the normal control band and reactor pressure is being maintained with steam line drains and main turbine bypass valves. The NRC Senior Resident (Inspector) has been notified.

  • * * RETRACTION AT 1015 EDT ON 03/22/2018 FROM DAVID DABADIE TO OSSY FONT * * *

This event was initially reported under 10 CFR 72(b)(2)(iv)(B) as a manual actuation of the RPS due to an unexpected trip of the B Reactor Recirculation Pump with the A Reactor Recirculation Pump running in fast speed (Single Loop Operations). Operations was unable to reconcile differing indications of core flow and made the conservative decision to perform a planned shutdown in accordance with normal operating procedures. Therefore, this event 'resulted from and was part of a pre-planned sequence during testing or reactor operation' as specified in 10 CFR 50.72(b)(2)(iv)(B), 10 CFR 50.73(a)(2)(iv)(A) and NUREG-1022 Section 3.2.6. Consequently, this event is not reportable as an actuation of RPS. The NRC Resident Inspector has been notified. R4DO (Groom) has been notified.

ENS 5317618 January 2018 17:02:0010 CFR 50.72(b)(3)(iv)(A), System ActuationEmergency Diesel Generator Actuation Due to Loss of One of Two Offsite Power Supplies

This event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A) as an event that resulted in a valid actuation of the Emergency Diesel Generator.

On January 18, 2018 at 1202 EST, V.C. Summer Nuclear Station (VCSNS) lost one of its two redundant offsite power supplies. The loss of the 115kV power supply created an undervoltage condition on the normal incoming Engineered Safety Features power supply to safety related bus 1DA. The 'A' Emergency Diesel Generator started and loads sequenced as designed. The 'A' Residual Heat Removal pump started but did not inject any water into the Reactor Coolant System. The 'A' Emergency Feedwater Pump started and ran for approximately 2 minutes. Other plant equipment and systems also responded as expected.

The loss of the 115kV power supply occurred due to an issue with a component in a switchyard, external to VCSNS. The cause of the event is still under investigation.

All loads have been transferred back to the offsite 115kV power supply at 1318 EST. The diesel generator was secured at 1321 EST, reset and is ready to auto-start.

The NRC Resident Inspector has been notified.

ENS 5316210 January 2018 15:28:0010 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 Turbine Control Valve Fast Closure Scram SignalAt 0928 CST on January 10, 2018, the Unit 3 reactor automatically scrammed due to a Reactor Protection System (RPS) signal generated from Turbine Control Valve Emergency Trip System pressure low. The reactor had been operating near 73 percent power for an emergent issue for Turbine Control Valve (TCV) No. 3. With TCV No. 3 out of service and closed, the unit was operating with RPS in a half scram condition. A subsequent failure of the TCV No. 2 sensing line resulted in RPS coincidence logic being met for TCV fast closure SCRAM. The investigation of the TCV No. 2 sensing line failure continues. All control rods fully inserted into the core. Main Steam Isolation Valves remained open with Main Turbine Bypass Valves controlling reactor pressure. Reactor Feedwater pumps remained in service to control reactor water level. Primary Containment Isolation Signals Groups 2, 3, 6, and 8 containment isolation and initiation signals were received. Upon receipt of these signals all required components actuated as required. Neither High Pressure Coolant Injection nor Reactor Core Isolation Cooling initiation signals were received. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the Reactor Protection System (RPS) when the reactor is critical except when the actuation results from and is part of a preplanned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident inspector has been notified.
ENS 5309126 November 2017 02:25:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip Due to Loss of Main Feed WaterAt time 2025 (CST) on 11/25/17, Unit 2 reactor was manually tripped due to a loss of all Main Feedwater. Operators observed both Main Feed Pumps tripped and SG (Steam Generator) levels decreasing, resulting in the direction for a manual reactor trip. The reactor trip actuated a turbine trip, both Motor Driven Auxiliary Feedwater Pumps started on the loss of both Main Feed Pumps, and Steam Generator Lo Lo levels started the Turbine Driven Auxiliary Feedwater Pump. All systems responded as expected. There was no work in progress at the time of the incident. Currently Unit 2 is being maintained in Hot Standby (Mode 3) in accordance with Integrated Plant Operating Procedure IP0-0078 and the Emergency Response Guideline Procedure Network has been exited. Decay Heat is being rejected to the Main Condenser via Steam Dump Valves. The licensee has notified the NRC Resident Inspector.
ENS 530608 November 2017 00:57:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip on Turbine Trip

On 11/7/2017 at 1957 (EST), VC Summer Nuclear Station automatically tripped due to a turbine trip. The cause of the turbine trip is under investigation at this time. All systems responded as expected. All Control Rods fully inserted and all Emergency Feedwater pumps started as required. The plant is stable in Mode 3. This event is reportable per 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A). The unit is currently stable in Mode 3 with decay heat removal via the Main Steam to the Main Condenser. The NRC Resident Inspector has been notified. The licensee will notify the South Carolina State Emergency Management Division, the Fairfield, Richland, Lexington and Newberry Counties.

  • * * UPDATE FROM BETH DALICK TO VINCE KLCO ON 11/8/17 AT 1409 EST * * *

All systems responded as expected, with the exception of 'B' Steam Generator Feedwater Isolation Valve XVG1611 B-FW. This valve did not appear to automatically close and was slow to indicate closed from the Main Control Board. All Control Rods fully inserted and all Emergency Feedwater pumps started as required. The plant is stable in Mode 3. Notified the R2DO (Musser).

ENS 5303626 October 2017 06:12:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip Following a Loss of LoadOn October 26, 2017 at 0212 EDT St. Lucie Unit 2 experienced a reactor trip due to a loss of load event resulting in an RPS (Reactor Protection System) actuation. The cause of the loss of load is currently under investigation. Following the reactor trip, an Auxiliary Feedwater Actuation Signal occurred due to low level in the 2A Steam Generator. One of the two Main Feed Isolation Valves to the 2A Steam Generator did not close on the Auxiliary Feedwater Actuation Signal. 2A Steam Generator level was restored by Auxiliary Feedwater. The 2B Steam Generator level is being maintained by Main Feedwater. All CEAs (Control Element Assemblies) fully inserted into the core. Decay heat removal is being accomplished through forced circulation with stable conditions from Auxiliary Feedwater/Main Feedwater and Steam Bypass Control System. Currently maintaining pressurizer pressure at 2250 psia and Reactor Coolant System temperature at 532 degrees F. St. Lucie Unit 1 was unaffected and remains in Mode 1 at 100 percent power. This report is submitted in accordance with 10 CFR 50.72(b)(2)(iv)(B) for the reactor trip and 10 CFR 50.72(b)(3)(iv)(A) for the Specified System Actuation. The licensee notified the NRC Resident Inspector.
ENS 5296010 September 2017 22:55:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip on Lowering Steam Generator Water LevelOn 09/10/17 at 1855 (EDT), (Turkey Point) Unit 4 reactor was manually tripped from 88% RTP (Rated Thermal Power) due to a failure of 4C Steam Generator main feed regulating valve causing lowering S/G (Steam Generator) level. All other systems operated normally. Auxiliary Feed Water initiated as designed to provide S/G water level control. EOP's (Emergency Operating Procedures) have been exited and General Operating procedures (GOP'S) were entered. Unit 4 is stable in Mode 3 at NOT/NOP (Normal Operating Temperature/Normal Operating Pressure). The licensee is investigating the failure of the feed regulating valve. Offsite power is available. Decay heat is being removed via main feedwater with steam discharged to atmosphere using the ADVs (Atmospheric Dump Valves). There is no known primary-secondary steam generator tube leakage. The licensee informed the NRC Resident Inspector.
ENS 529506 September 2017 15:57:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Scram on Low Reactor Vessel Water LevelOn September 6, 2017 at 1157 (EDT), Nine Mile Point Unit 1 experienced an automatic reactor scram with a Main Steam Isolation Valve (MSIV) and Containment isolation. The scram was due to reactor vessel low water level. The cause of the reactor vessel low water level is under investigation. All control rods fully inserted. Following the scram, pressure was momentarily controlled through the use of the Emergency Condenser (EC) system. At 1205, pressure control was established through the main steam lines to the condenser through the turbine bypass valves. All plant systems responded per design following the scram. The reactor scram is a 4-hour report per 10 CFR 50.72(b)(2)(iv)(B). The following systems automatically actuated after the scram as expected. These system actuations are an 8-hour report per 10 CFR 50.72(b)(3)(iv)(A): 1. The High Pressure Coolant Injection (HPCI) system. HPCI initiated at 1157 and was reset at 1158 when RPV level was restored above the HPCI system low level actuation set point. HPCI is a flow control mode of the normal feedwater systems, and is not an Emergency Core Cooling System. 2. The Core Spray system actuated, but did not discharge to the Reactor Coolant system. The Core Spray system was secured at 1216. 3. Containment and MSIV isolation on reactor vessel low-low water level signal. Nine Mile Point Unit 1 is currently in Hot Shutdown, with reactor vessel water level and pressure maintained within normal bands. Decay heat is being removed via steam to the main condenser using the turbine bypass valves. The offsite grid is stable with no grid restrictions or warnings in effect. The licensee has notified the NRC Resident Inspector. No safety relief valves lifted during the transient. The main steam isolation valves were opened after the isolation signal cleared to facilitate decay heat removal. Offsite power is supplying all plant loads. There was no effect on Unit 2. The licensee notified New York State Department of Environmental Protection and will be issuing a press release.
ENS 5293228 August 2017 12:37:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Reactor Trip on Turbine TripOn 8/28/2017 at 0837 (EDT), VC Summer Nuclear Station automatically tripped due to a turbine trip. The turbine trip was caused by the Main Generator Differential Lockout due to a fault on the center phase lightning arrester on the Main Transformer (XTF-001). There were no complications with the trip. All control rods fully inserted. Balance of Plant (BOP) buses automatically transferred to their alternate power source XTF 31/32. All Emergency Feedwater pumps started as required. All systems responded as required. The plant is stable in Mode 3. Station personnel are investigating the cause of the fault on the main transformer lightning arrester. This event is reportable per 10 CFR 50. 72(b)(2)(iv)(B) and 10 CFR 50. 72(b)(3)(iv)(A). The NRC Resident Inspector has been notified. The unit is currently stable in Mode 3 with decay heat removal via the Main Steam to the Main Condenser. The licensee will inform both State and local authorities.
ENS 5291820 August 2017 23:05:0010 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 a Rise in Main Condenser Back Pressure

On August 20, 2017 at 1605 PDT, Columbia Generating Station was manually scrammed from 100 percent power due to a rise of Main Condenser back pressure. Manual scram of the unit is procedurally required upon a loss of Main Condenser back pressure. Preliminary investigations indicate that the Main Condenser air removal suction valve (AR-V-1) closed, resulting in the Condenser back pressure rising to within 1.0 inch Hg of the setpoint with reactor power greater than 25 percent. Further investigations continue. All control rods fully inserted. In addition to the closure of the air removal suction valve, one of two Reactor Feedwater startup flow control valves did not adequately operate to control Reactor vessel level and resulted in a high-level (Level-8) actuation tripping the Reactor Feedwater System. All other systems operated as expected. Reactor water level is currently being controlled manually with the start-up level control isolation valve. AR-V-1 has been manually opened with a jumper and temporary air supply. Reactor decay heat is being removed via bypass valves to the Main Condenser. This event is being reported under the following: 10 CFR 50.72(b)(2)(iv)(B), which requires a four-hour notification for any event or condition that results in actuation of the Reactor Protection System when the reactor is critical. The licensee notified the NRC Resident Inspector. The licensee plans to issue a press release.

  • * * UPDATE ON 8/24/17 AT 1937 EDT FROM MATT HUMMER TO DONG PARK * * *

The licensee is updating the notification to include an 8 hour notification under 10 CFR 50.72(b)(3)(iv)(A) for a specified system actuation due to a Level 3 isolation signal which occurred approximately 20 minutes after the scram. The licensee is currently in cold shutdown to repair the Reactor Feedwater startup flow control valve. The licensee has notified the NRC Resident Inspector. Notified R4DO (Farnholtz).

ENS 5291519 August 2017 01:55:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Scram While at 100 Percent PowerAt 2055 CDT on August 18, 2017, an automatic actuation of the reactor protection system occurred while the plant was operating at 100 percent power. No plant parameters requiring the actuation of the emergency diesel generators or the emergency core cooling system were exceeded. The main feedwater system remained in service following the scram to maintain reactor water level, and the main condenser remained available as the normal heat sink. The scram occurred after a planned swap of the main feedwater master controller channels in preparation for scheduled surveillance testing. When the channel swap was actuated, the feedwater regulating valves moved to the fully open position. The scram signal originated in the high-flux detection function of the average power range monitors, apparently from the rapid increase in feedwater flow. The cause of the apparent feedwater controller malfunction is under investigation. The NRC Resident Inspector has been notified. No safety relief valves opened. Decay heat is being removed via steam to the main condenser using the bypass valves and steam drains. The licensee intends to go to Cold Shutdown to investigate the malfunction.
ENS 5289811 August 2017 16:24:0010 CFR 50.72(b)(3)(iv)(A), System ActuationComanche Peak Automatic Turbine Trip from 10 Percent PowerAt 1124 CDT on 11 August 2017, CPNPP (Comanche Peak Nuclear Power Plant) Unit 2 experienced an automatic turbine trip and trip of both main feedwater pumps on high steam generator water level (P-14, 81.5 percent level) in steam generator 2-02. Following the turbine trip, the auxiliary feedwater system actuated as required. The plant was stabilized at 2-3 percent reactor power with auxiliary feedwater feeding all steam generators with all levels within their normal bands. The cause of the high steam generator level appears to be a mechanical malfunction of steam generator 2-02 flow control valve bypass valve 2-LV-2163 (SG 2-02 FW BYP CTRL VLV) to close when demanded. Troubleshooting and repair of 2-LV-2163 is in progress. This event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A) for an actuation of auxiliary feedwater. The NRC Resident Inspector has been notified.
ENS 528896 August 2017 02:35:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Reactor Scram During TestingAt 2235 (EDT) Nine Mile Point Unit 2 experienced an automatic scram on high reactor pressure. Turbine stop valve testing was in progress at the time of the scram. All control rods inserted. Pressure control is via the turbine bypass valves. The cause of the scram is being investigated. This is a 4-Hour report for 10CFR50.72(b)(2)(iv)(B) RPS (Reactor Protection System) Actuation. The NRC Resident Inspector has been notified. Reactor water level is being maintained with normal feedwater flow. No safety or relief valves lifted. The plant is in its normal shutdown electrical lineup.
ENS 5286317 July 2017 21:17:0010 CFR 50.72(a)(1)(i), Emergency Class Declaration
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)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor
Unusual Event Declared Due to Loss of Offsite Power

During a rain and lightning storm, plant operators observed arcing from the main transformer bus duct and notified the control room. The decision was made to trip the main generator which resulted in an automatic reactor trip. The plant entered EAL SU.1 as a result of the loss of offsite power for greater than fifteen minutes. Plant safety busses are being supplied by both emergency diesel generators while the licensee inspects the electrical system to determine any damage prior to bringing offsite power back into the facility. Offsite power is available to the facility. No offsite assistance was requested by the licensee. During the trip, all rods inserted into the core. Decay heat is being removed via the atmospheric dump valves with emergency feedwater supplying the steam generators. The main steam isolation valves were manually closed to protect the main condenser. There were no safeties or relief valves that actuated during the plant transient. There is no known primary-to-secondary leakage. Reactor cooling is via natural circulation. All safety equipment is available for the safe shutdown of the plant. The licensee has notified the NRC Resident Inspector, Louisiana Department of Environmental Quality and the local Parish emergency management agencies. Notified DHS SWO, FEMA, DHS NICC, FEMA National Watch Center (email) and Nuclear SSA (email).

  • * * UPDATE ON 7/17/17 AT 2007 EDT FROM MARIA ZAMBER TO DONG PARK * * *

This notification is also made under 10 CFR 50.72(b)(3)(v)(D). This is a non-emergency notification from Waterford 3. On July 17, 2017 at 1606 CDT, the reactor automatically tripped due to a loss of Forced Circulation, which was the result of Loss of Offsite Power (LOOP) to the electrical (safety and non-safety) buses. Both 'A' and 'B' trains of Emergency Diesel Generators (EDGs) started as designed to reenergize the 'A' and 'B' safety buses. The LOOP caused a loss of feedwater pumps, resulting in an automatic actuation of the Emergency Feedwater (EFW) system. Prior to the reactor trip, at 1600 CDT, personnel noticed the isophase bus duct to main transformer 'B' glowing orange due to an unknown reason. Due to this, the main turbine was manually tripped at 1606 CDT. Following the turbine trip, the electrical (safety and non-safety) buses did not transfer to the startup transformers as expected due to an unknown reason. The plant entered the Emergency Operating Procedure for LOOP/Loss of Forced Circulation Recovery. At 1617 CDT, an Unusual Event was declared due to Initiating Condition (IC) SU1 - Loss of all offsite AC power to safety buses (greater than) 15 minutes. All safety systems responded as expected. The plant is currently in mode 3 and stable with the EDGs supplying both safety buses and with EFW feeding and maintaining both steam generators. Offsite power is in the process of being restored. The licensee has notified the NRC Resident Inspector, Louisiana Department of Environmental Quality and the local Parish emergency management agencies.

  • * * UPDATE FROM ADAM TAMPLAIN TO HOWIE CROUCH AT 2203 EDT ON 7/17/17 * * *

The licensee terminated the Notification of Unusual Event at 2056 CDT. The basis for terminating was that offsite power was restored to the safety busses. The licensee has notified Louisiana Department of Environmental Quality, St. John and St. Charles Parishes, Louisiana Homeland Security Emergency Preparedness, and will be notifying the NRC Resident Inspector. Notified IRD (Stapleton), NRR (King), R4DO (Hipschman), DHS SWO, FEMA, DHS NICC, FEMA National Watch Center (email) and Nuclear SSA (email).

  • * * UPDATE FROM SCOTT MEIKLEJOHN TO HOWIE CROUCH AT 1724 EDT ON 7/19/17 * * *

This update is being reported under 10 CFR 50.72(b)(3)(v)(B). During the event discussed in EN# 52863, at 1642 CDT (on July 17, 2017), Condensate Storage Pool (CSP) level lowered to less than 92% resulting in entry to Technical Specification (TS) 3.7.1.3. Level in the CSP was lowered due to feeding from both Steam Generators with EFW. Normal makeup to the CSP was temporarily unavailable due to the LOOP. Filling the CSP commenced at 1815 CDT (on July 17, 2017), and TS 3.7.1.3 was exited on July 18, 2017 at 0039 CDT. The licensee notified the NRC Resident Inspector. Notified R4DO (Hipschman).

  • * * UPDATE FROM SCOTT MEIKLEJOHN TO HOWIE CROUCH AT 1233 EDT ON 9/14/17 * * *

Waterford 3 is retracting a follow up notification made on July 19, 2017 for EN# 52863, concerning the loss of safety function associated with the Condensate Storage Pool (CSP) per 10 CFR 50.72(b)(3)(v)(B). The Condensate Storage Pool was performing its required safety function by providing inventory to the Emergency Feed Water pumps when the required Tech Spec level (T.S. 3.7.1.3) dropped below 92%. The Technical Specification was entered at 1624 (CDT) on July 17, 2017 and exited after filling at 0039 on July 18, 2017. The total allowed outage time allowed by Tech Spec 3.7.1.3 is 10 hours to be in Hot Shutdown if not restored. The Condensate Storage Pool level was restored to greater than 92% prior to exceeding the allowed outage time. Based on level being restored and the Condensate Storage Pool performing its required safety function, 10 CFR 50.72(b)(3)(v)(B) does not apply. Prior to the automatic reactor trip, Condensate Storage Pool level was greater than 92%. The NRC Resident Inspector has been notified of the retraction. Notified R4DO (Groom).

ENS 528393 July 2017 14:15:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Scram on Low Condenser VacuumAt 1015 (EDT) a manual reactor scram was inserted due to degrading main condenser vacuum. All rods inserted into the core as expected and all systems functioned as expected during the scram. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the Reactor Protection System (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.' At 1033 (EDT) an automatic reactor scram occurred on low reactor water level. Due to the previous manual reactor scram, all rods were (already) inserted. This event is reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(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 preplanned sequence during testing or reactor operation. (1) Reactor protection system (RPS) including : Reactor scram and reactor trip.' Decay heat is being removed using main feedwater and the turbine bypass valves. The licensee notified the NRC Resident Inspector. This event was characterized as a "configuration control event" where a valve misposition allowed the offgas line to flood.
ENS 5283329 June 2017 12:57:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Automatic Trip Due to a Loss of Normal Feedwater Flow to B Steam Generator

On 6/29/2017 at 0857 (EDT), VC Summer Nuclear Station automatically tripped due to a loss of normal feed water flow to the B Steam Generator.

There were no complications with the trip. All control rods fully inserted. All emergency feedwater pumps automatically started and recovered steam generator levels. The plant is stable in Mode 3. Station personnel are investigating the cause of the loss of normal feedwater to the B Steam Generator. This is reportable per 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A). The NRC Resident Inspector has been notified. The licensee notified the State of South Carolina as well as Fairfield, Lexington, Richland and Newberry Counties regarding the event.

ENS 5282926 June 2017 04:00:0010 CFR 50.72(b)(2)(iv)(B), RPS System Actuation
10 CFR 50.72(b)(2)(xi), Notification to Government Agency or News Release
10 CFR 50.72(b)(3)(iv)(A), System Actuation
Manual Reactor Trip Due to Loss of Main FeedpumpOn June 26, 2017, at 1531 (EDT), Indian Point Unit 2 inserted a manual reactor trip prior to Steam Generator levels reaching the automatic reactor trip setpoint. Steam Generator water level perturbation resulted from a loss of 22 Main Boiler Feed Pump. All Control Rods verified inserted. The Auxiliary Feedwater System started as designed and supplied feedwater to the Steam Generators. Heat removal is via the Main Condenser through the High Pressure Steam Dumps. Offsite power is being supplied through the normal 138kV feeder 95332. The cause of the 22 Main Boiler Feed Pump loss is currently under investigation. Entergy is issuing a press release/news release on this issue. Unit 2 is stable and in Mode 3. There was no impact on Unit 3. The licensee notified the State of New York and the NRC Resident Inspector.
ENS 5282524 June 2017 01:18:0010 CFR 50.72(b)(2)(iv)(B), RPS System ActuationAutomatic Reactor Scram on Main Generator TripWhile performing a scheduled generator voltage regulator test, River Bend Station experienced an automatic scram when the main generator tripped. It is unknown at this time why the main generator tripped. There were no equipment issues that materially impacted post scram operator response. The intention at this time is to go to cold shutdown while the cause of the trip is investigated. All rods inserted during the scram. Reactor water level is being maintained via normal feedwater with decay heat being removed via turbine bypass valves to the main condenser. The electrical grid is stable and supplying plant loads via the normal shutdown electrical lineup. The licensee has notified the NRC Resident Inspector.